Clayton Williams Energy Announces 2016 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, 2016.

Highlights

Fiscal 2016 Results

• Oil and Gas Production of 13.7 MBOE/d
• Cash flow from operating activities of $10.7 million
• Liquidity of $671.1 million

Year-End 2016 Reserves

• Total Proved Reserves of 34.8 MMBOE
• 84% Oil and NGL and 63% Proved Developed

Recent Transactions

• Announced Proposed Merger with Noble Energy, Inc.
• Purchase of Net Mineral Acres in Southern Reeves County, Texas
• Sale of Giddings Area assets for $400 million

Financial Results for Fiscal Year 2016

The Company reported a net loss for fiscal 2016 of $292.2 million, or $20.87 per share, as compared to net loss of $98.2 million, or $8.07 per share, for fiscal 2015. Adjusted net loss1 (non-GAAP) for 2016 was $127.7 million, or $9.12 per share, as compared to adjusted net loss1 (non-GAAP) of $70.4 million, or $5.78 per share, for 2015. Cash flow from operations for 2016 was $10.7 million as compared to $52.2 million for 2015. EBITDAX2 (non-GAAP) for 2016 was $54.6 million as compared to $112.1 million for 2015.

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

• Oil and gas sales, excluding amortized deferred revenues, decreased $54.1 million to $158.8 million in 2016 from $212.9 million in 2015. Production variances accounted for $30.7 million of the decrease and price variances accounted for $23.4 million of the decrease. Average realized oil prices were $38.58 per barrel in 2016 versus $44.76 per barrel in 2015, average realized gas prices were $2.31 per Mcf in 2016 versus $2.52 per Mcf in 2015, and average realized natural gas liquids (“NGL”) prices were $13.26 per barrel in 2016 versus $13.07 per barrel in 2015. Amortized deferred revenue in 2016 totaled $1.5 million as compared to $4.5 million in 2015.
• Oil, gas and NGL production per barrel of oil equivalent per day (“BOE/d”) decreased 14% in 2016, to 13,652 BOE/d, as compared to 15,818 BOE/d in 2015, with oil production decreasing 15% to 9,899 barrels per day, gas production decreasing 16% to 13,369 Mcf per day, and NGL production increasing 1% to 1,525 barrels per day. Oil and NGL production accounted for approximately 84% of the Company’s total BOE production in 2016 versus 83% in 2015. After giving effect to the sale of substantially all of the Company’s assets in the Giddings Area in East Central Texas in December 2016, the sale of interests in certain wells in Glasscock County, Texas in July 2016 and the sale of selected leases and wells in South Louisiana in September 2015, oil, gas and NGL production per BOE/d increased 1% in 2016 as compared to 2015. See accompanying tables for additional information about the Company’s oil and gas production.
• Production costs in 2016 were $70.9 million versus $87.6 million in 2015 due to lower oilfield service costs and decreased activity. After giving effect to a 14% decrease in total production, production costs on a BOE basis, excluding production taxes, decreased 4% to $12.68 per BOE in 2016 versus $13.23 per BOE in 2015.
• Interest expense for 2016 was $93.7 million versus $54.4 million for 2015. The increase was due primarily to $44.3 million of incremental interest expense on funded indebtedness incurred under a second lien term loan credit facility issued in connection with a refinancing in March 2016 (the “Refinancing”). For the second and third quarters of 2016, the Company elected to pay interest on the term loan facility in-kind and resulted in an increase in the principal amount of the term loan to $377.2 million.
• The Company accounts for the warrants issued in connection with the Refinancing as derivative instruments and carries the warrants as a non-current liability at their fair value. The Company recorded a $230 million loss on change in fair value in 2016 due primarily to the impact on the valuation model of a 730% increase in the market price of the Company’s common stock from $14.37 at March 15, 2016 to $119.26 at December 31, 2016.
• Loss on commodity derivatives for 2016 was $20.3 million (including a $7.4 million loss on settled contracts) versus a gain on commodity derivatives in 2015 of $12.5 million (including a $12.5 million gain on settled contracts). See accompanying tables for additional information about the Company’s accounting for commodity derivatives.
• Lower commodity prices negatively impacted our results of operations due to asset impairments. The Company recorded impairments of property and equipment of $7.6 million in 2016, of which $5.2 million related primarily to impairments of proved non-core properties located in North Dakota, Oklahoma, California and the Cotton Valley area of Texas and $2.4 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 impairments of property and equipment of $41.9 million in 2015, 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.
• The Company recorded a net gain of $118.8 million on sales of assets and impairment of inventory in 2016 compared to a net loss of $3 million in 2015. The 2016 gain related primarily to the sale of substantially all of the Company’s assets in the Giddings Area in East Central Texas in December 2016 and the sale of interests in certain wells in Glasscock County, Texas in July 2016. The 2015 loss related primarily to the write-down of inventory to reduce the carrying value to the estimated fair value offset by gains on the sale of selected leases and wells in South Louisiana in September 2015, the release of sales proceeds previously held in escrow pending resolution of title requirements associated with the sale of certain non-core Austin Chalk/Eagle Ford assets sold in March 2014, the sale of leases in Oklahoma in May and June 2015, and the sale of selected wells in Martin and Yoakum Counties, Texas in March 2015.
• The Company recorded an $8.4 million charge to fully impair the carrying value of the Company’s investment in Dalea Investment Group, LLC in 2016, as compared to a partial impairment of this investment of $2.6 million in 2015.
• General and administrative (“G&A”) expenses for 2016 were $23 million versus $22.8 million for 2015. G&A expense increased due primarily to increases in salary and personnel expense. Changes in compensation expense related to the Company’s APO Reward Plans accounted for a $7.9 million decrease ($7.9 million credit in 2016 versus a negligible credit in 2015) which was due primarily to reductions in previously accrued compensation associated with the APO Reward Plans affected by the Giddings sale. Compensation expense related to issuances of restricted stock and stock options under the Company’s long-term incentive plan (“LTIP”) accounted for a $5.7 million increase.
• The Company redeemed $100 million of 7.75% Senior Notes due 2019 (“2019 Senior Notes”) in a tender offer in August 2016 and recorded a gain on early extinguishment of long-term debt during 2016 of $4 million.

Financial Results for the Fourth Quarter of 2016

The Company reported net loss for the fourth quarter of 2016 (“4Q16”) of $27.2 million, or $1.54 per share, as compared to a net loss of $47.2 million, or $3.88 per share, for the fourth quarter of 2015 (“4Q15”). Adjusted net loss1 (non-GAAP) for 4Q16 was $26.2 million, or $1.49 per share, as compared to adjusted net loss1 (non-GAAP) of $22.1 million, or $1.82 per share, for 4Q15. Cash flow from operations for 4Q16 was $2.8 million as compared to $(2.8) million for 4Q15. EBITDAX2 (non-GAAP) for 4Q16 was $13.3 million as compared to $20.7 million for 4Q15.

The key factors affecting the comparability of financial results for 4Q16 versus 4Q15 were:

• Oil and gas sales for 4Q16, excluding amortized deferred revenues, increased $7.9 million to $46.6 million in 4Q16 from $38.7 million in 4Q15. Price variances accounted for $8.5 million of the increase and production variances accounted for $0.6 million of the decrease. Average realized oil prices were $44.87 per barrel in 4Q16 versus $36.91 per barrel in 4Q15, average realized gas prices were $2.70 per Mcf in 4Q16 versus $2.09 per Mcf in 4Q15, and average realized NGL prices were $16.72 per barrel in 4Q16 versus $13.00 per barrel in 4Q15. Amortized deferred revenue in 4Q16 totaled $0.4 million as compared to $0.3 million in 4Q15.
• Oil, gas and NGL production per BOE/d decreased 4% in 4Q16 to 13,441 BOE/d as compared to 13,939 BOE/d in 4Q15, with oil production decreasing 1% to 9,957 barrels per day, gas production decreasing 15% to 12,359 Mcf per day, and NGL production decreasing 1% to 1,424 barrels per day. Oil and NGL production accounted for approximately 85% of the Company’s total BOE production in 4Q16 versus 83% in 4Q15. After giving effect to the sale of substantially all of the Company’s assets in the Giddings Area in East Central Texas in December 2016 and the sale of interests in certain wells in Glasscock County, Texas in July 2016, oil, gas and NGL production per BOE/d increased 11% in 4Q16 as compared to 4Q15. See accompanying tables for additional information about the Company’s oil and gas production.
• Production costs in 4Q16 were $16.8 million versus $20.4 million in 4Q15 due to lower oilfield service costs and decreased activity. Production costs on a BOE basis, excluding production taxes, decreased 17% to $11.71 per BOE in 4Q16 versus $14.07 per BOE in 4Q15.
• Interest expense for 4Q16 was $23.5 million versus $14 million for 4Q15. The increase was due primarily to $13.1 million of incremental interest expense on funded indebtedness incurred under a second lien term loan credit facility issued in connection with the Refinancing.
• The Company accounts for the warrants issued in connection with the Refinancing as derivative instruments and carries the warrants as a non-current liability at their fair value. The Company recorded a $75 million loss on change in fair value in 4Q16 due primarily to the impact on the valuation model of a 40% increase in the market price of the Company’s common stock from $85.44 at September 30, 2016 to $119.26 at December 31, 2016.
• Loss on commodity derivatives for 4Q16 was $6.3 million (including a $5 million loss on settled contracts) versus a gain on commodity derivatives in 4Q15 of $2.1 million (including a $7.9 million gain on settled contracts). See accompanying tables for additional information about the Company’s accounting for commodity derivatives.
• Lower commodity prices negatively impacted our results of operations due to asset impairments. The Company recorded impairments of property and equipment of $4.2 million in 4Q16, of which $1.8 million related primarily to impairments of proved non-core properties in North Dakota and $2.4 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 impairments of property and equipment of $36.3 million in 4Q15, 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.
• The Company recorded a net gain of $110.8 million on sales of assets and impairment of inventory in 4Q16 compared to a net loss of $3.9 million in 4Q15. The 4Q16 gain related primarily to the sale of substantially all of the Company’s assets in the Giddings Area in East Central Texas in December 2016 and the 4Q15 loss related primarily to the write-down of inventory to reduce the carrying value to the estimated fair value.
• G&A expenses were negligible for 4Q16 versus a $2.3 million credit for 4Q15. G&A expense increased due primarily to increases in salary and personnel expense. Changes in compensation expense related to the Company’s APO Reward Plans accounted for a decrease of $8.5 million ($15.2 million credit in 4Q16 versus a $6.7 million credit in 4Q15) which was due primarily to reductions in previously accrued compensation associated with the APO Reward Plans affected by the Giddings sale. Compensation expense related to issuances of restricted stock and stock options under the Company’s LTIP accounted for a $4.9 million increase.

Balance Sheet and Liquidity

As of December 31, 2016, total long-term debt was $848 million, consisting of $352.5 million (net of $24.7 million of original issue discount and debt issuance costs) under the second lien term loan credit facility and $495.5 million (net of $4.5 million of original issue discount and debt issuance costs) of 2019 Senior Notes. The borrowing base established by the banks under the revolving credit facility and the aggregate lender commitment was $100 million at December 31, 2016. The Company had $98.1 million of availability under the revolving credit facility after allowing for outstanding letters of credit of $1.9 million. Liquidity, consisting of cash and funds available on the revolving credit facility, totaled $671.1 million.

Subsequent Events

Proposed Merger with Noble Energy, Inc.

On January 16, 2017, the Company and Noble Energy, Inc. (“Noble Energy”) announced that the Boards of Directors of both companies unanimously approved and executed a definitive agreement under which Noble Energy will acquire all of the outstanding common stock of the Company for $2.7 billion in Noble Energy common stock and cash. The merger is expected to close in the second quarter of 2017.

Purchase of Net Mineral Acres in Southern Reeves County, Texas

In January 2017, the Company purchased approximately 1,900 net mineral acres in Southern Reeves County, Texas from a private seller, for cash consideration totaling $44.3 million. The acreage is located in and around the Company’s existing contiguous acreage block. Also included in the deal was a non-operated gross working interest of approximately 26% in an existing horizontal well.

Reserves

The Company reported total estimated proved oil and gas reserves as of December 31, 2016 of 34.8 million barrels of oil equivalent (“MMBOE”), consisting of 24.3 million barrels of oil, 4.8 million barrels of NGL and 33.6 Bcf of natural gas. On a BOE basis, oil and NGL comprised 84% of total proved reserves at year-end 2016 versus 83% at year-end 2015. Proved developed reserves at year-end 2016 were 22 MMBOE, or 63% of total proved reserves, versus 36.3 MMBOE, or 78% of total proved reserves, at year-end 2015. 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 $204.4 million at year-end 2016 versus $442.8 million at year-end 2015. 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 2016 on an MMBOE basis:

The Company replaced 82% of its 2016 oil and gas production through extensions and discoveries. Most of the 4.1 MMBOE of reserve additions in 2016 are attributable to the Company’s Delaware Basin program in Southern Reeves County, Texas. Oil and NGL accounted for 85.1% of the 2016 reserve additions.

The 0.2 MMBOE of net downward revisions in proved reserves resulted from a combination of (1) net upward revisions of 11.6 MMBOE related to performance in the Company’s Delaware Basin reserves in Southern Reeves County, Texas, and (2) downward revisions of 11.8 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 2016 were $42.75 per barrel of oil and $2.49 per MMBtu of natural gas, as compared to $50.28 per barrel of oil and $2.58 per MMBtu of natural gas for 2015. 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 $36.60 per barrel of oil, $13.60 per barrel of NGL and $2.36 per Mcf of natural gas for year-end 2016, as compared to $45.75 per barrel of oil, $15.84 per barrel of NGL and $2.52 per Mcf of natural gas for year-end 2015.

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.

Adjusted net 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 loss is not an alternative to net loss presented in conformity with GAAP.

The Company defines adjusted net loss as net loss before changes in fair value of commodity derivatives and common stock warrants, abandonments and impairments, impairments of property and equipment, net (gain) loss on sales of assets and impairment of inventory, gain on early extinguishment of long-term debt, amortization of deferred revenue from volumetric production payment, impairment of investments, 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 loss (GAAP) to adjusted net loss (non-GAAP):

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 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 loss before interest expense, income taxes, exploration costs, net (gain) loss on sales of assets and impairment of inventory, gain on early extinguishment of long-term debt and all non-cash items in the Company's statements of operations, including depreciation, depletion and amortization, impairment of property and equipment, accretion of asset retirement obligations, amortization of deferred revenue from volumetric production payment, certain employee compensation, changes in fair value of commodity derivatives and common stock warrants, impairment of investments and certain non-cash and unusual items.

The following table reconciles net loss to EBITDAX:

The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to December 31, 2016. Settlement prices of commodity derivatives are based on NYMEX futures prices.

The following table sets forth the Company’s estimated quantities of proved reserves as of December 31, 2016 and 2015, all of which are located in the United States.

PV-10 totaled $204.4 million at December 31, 2016 versus $442.8 million at December 31, 2015. Commodity prices used at December 31, 2016 and 2015 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 $42.75 per barrel of oil and $2.49 per MMBtu of natural gas for 2016 and $50.28 per barrel of oil and $2.58 per MMBtu for 2015. 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 $36.60 per barrel of oil, $13.60 per barrel of NGL and $2.36 per Mcf of natural gas for 2016 and $45.75 per barrel of oil, $15.84 per barrel of NGL and $2.52 per Mcf of natural gas for 2015.

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.

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