Exhibit

EXHIBIT 99.1

CLAYTON WILLIAMS ENERGY, INC.

FINANCIAL GUIDANCE DISCLOSURES FOR 2015

Overview

Clayton Williams Energy, Inc. and its subsidiaries have prepared this document to provide public disclosure of certain financial and operating estimates in order to permit the preparation of models to forecast our operating results for the year ending December 31, 2015. These estimates are based on information available to us as of the date of this filing, and actual results may vary materially from these estimates. We do not undertake any obligation to update these estimates as conditions change or as additional information becomes available.

The estimates provided in this document are based on assumptions that we believe are reasonable. Until our actual results of operations for this period have been compiled and released, all of the estimates and assumptions set forth herein constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this document 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, could or may occur in the future, including such matters as production of oil and gas, product prices, oil and gas reserves, drilling and completion results, capital expenditures, operating costs and other such matters, are forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties, and other factors that may cause our actual results, performance, or achievements to be materially different from the results, performance, or achievements expressed or implied by such forward-looking statements. Such factors include, among others, the following: the volatility of oil and gas prices; the unpredictable nature of our exploratory drilling results; the reliance upon estimates of proved reserves; operating hazards and uninsured risks; competition; government regulation; and other factors referenced in filings made by us with the Securities and Exchange Commission.

As a matter of policy, we generally do not attempt to provide guidance on:


(a)	production which may be obtained through future exploratory drilling;


(b)	dry hole and abandonment costs that may result from future exploratory drilling;


(c)	the effects of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” superseded by topic 815-10 of the Financial Accounting Standards Board Accounting Standards Codification;


(d)	gains or losses from sales of property and equipment unless the sale has been consummated prior to the filing of financial guidance;


(e)	capital expenditures related to completion activities on exploratory wells or acquisitions of proved properties until the expenditures are estimable and likely to occur; and


(f)	revenues and operating expenses related to Drilling Rig or Midstream Services.

The accompanying guidance does not include any divestitures, joint venture arrangements or similar structures that have not been consummated.

Summary of Estimates

The following table sets forth certain estimates being used to model our anticipated results of operations for the fiscal year ending December 31, 2015. Each range of values provided represents the expected low and high estimates for such financial or operating factor.



		Actual		Actual		Estimated Ranges		Estimated Ranges
		Three Months Ended		Nine Months Ended		Three Months Ending		Fiscal Year Ending
		September 30, 2015		September 30, 2015		December 31, 2015		December 31, 2015
(Dollars in thousands, except per unit data)
Average Daily Production:
Oil (Bbls)		11,152		12,198		10,500 to 10,700		11,700 to 11,900
Gas (Mcf)		17,283		16,330		14,000 to 15,000		15,500 to 16,500
Natural gas liquids (Bbls)		1,543		1,531		1,400 to 1,600		1,400 to 1,600
Total oil equivalents (BOE)		15,576		16,451		14,233 to 14,800		15,683 to 16,250

Price Differentials to NYMEX:
Oil		93%		92%		90% to 95%		90% to 95%
Gas		99%		96%		90% to 100%		90% to 100%
Natural gas liquids (based on oil)		24%		26%		20% to 30%		20% to 30%

Other Costs and Expenses:
Production expenses:
Direct costs ($/BOE)	$	12.68	$	12.99	$	13.00 to 14.00	$	13.00 to 14.00
Production taxes (% of sales)		5%		5%		5% to 6%		5% to 6%

General and administrative:
Excluding non-cash compensation	$	7,310	$	20,697	$	7,000 to 9,000	$	27,000 to 29,000
Non-cash compensation	$	(2,679)	$	4,405	$	1,000 to 2,000	$	5,500 to 6,500

DD&A:
Oil and gas ($/BOE)	$	23.26	$	24.60	$	24.00 to 26.00	$	24.00 to 26.00
Other	$	3,523	$	11,158	$	3,000 to 4,000	$	14,000 to 15,000

Exploration costs:
Abandonments and impairments	$	874	$	5,005	$	2,000 to 4,000	$	7,000 to 9,000
Seismic and other	$	239	$	1,210	$	500 to 1,000	$	1,700 to 2,200

Interest expense (cash rates):
$600 million Senior Notes due 2019		7.75%		7.75%		7.75%		7.75%
Bank credit facility		LIBOR plus (175 to 275 bps)		LIBOR plus (175 to 275 bps)		LIBOR plus (175 to 275 bps)		LIBOR plus (175 to 275 bps)

Effective Federal and State Income
Tax Rate:
Current		0%		0%		0%		0%
Deferred		34.8%		35.2%		33% to 37%		33% to 37%

We drilled two wells in the Eagle Ford and one well in the Delaware Basin during the third quarter of 2015. We currently do not plan to drill any more wells in these two core areas during the remainder of 2015. During the third quarter of 2015, we sold substantially all of our producing properties in South Louisiana.

Following is a summary of the average daily production related to interests in the properties sold.



	Three Months Ended	Nine Months Ended
	September 30,	September 30,
	2015	2015
Average Daily Production:
Oil (Bbls)	174		178
Natural gas (Mcf)	2,433		2,052
Total (BOE)	580		520

The following table sets forth certain information regarding our model well economics assuming NYMEX product prices of $60 per barrel of oil and $3 per MMBtu of natural gas.



		Eagle Ford		Wolfcamp

Gross estimated ultimate reserves (EUR) (MBOE)		250		750
Drilling and completion costs (In thousands)	$	4,000	$	6,000
Estimated first year gross production (MBOE)		68		121
Undiscounted payout (In years)		3.0		2.9
ROI		24%		29	%
Company estimated WI/NRI %		100% / 75%		100% / 75%

Capital Expenditures

The following table sets forth, by area, our actual expenditures for the nine months of 2015 and our planned capital expenditures for the year ending December 31, 2015.



	Actual		Planned
	Expenditures		Expenditures		2015
	Nine Months Ended		Year Ending		Percentage
	September 30, 2015		December 31, 2015		of Total
	(In thousands)
Drilling and Completion:
Permian Basin Area:
Delaware Basin	$	32,600	$	36,000	30%
Other	12,300		15,600		13%
Austin Chalk/Eagle Ford Shale	31,600		35,800		29%
Other	7,300		7,600		6	%
	83,800		95,000		78	%
Leasing and seismic	21,800		26,900		22	%
Exploration and development	$	105,600	$	121,900	100%

We currently plan to spend approximately $121.9 million on exploration and development activities during fiscal 2015. Our actual expenditures during 2015 may vary significantly from these estimates since our plans for exploration and development activities may change during the year. Factors, such as changes in operating margins and the availability of capital resources could increase or decrease our actual expenditures during the remainder of fiscal 2015.

Accounting for Derivatives

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to September 30, 2015. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps



	Oil
	MBbls	Price
Production Period:
4th Quarter 2015	592	$	55.65
	592

We did not designate any of the derivatives shown in the preceding table as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, will be recorded as other income (expense) in our statement of operations and comprehensive income (loss).

Volumetric Production Payment

In March 2012, we entered into a volumetric production payment (“VPP”) with a third party. Under the terms of the VPP, we conveyed a term overriding royalty interest covering approximately 725,000 barrels of oil equivalents (“BOE”) of estimated future oil and gas production from certain properties related to production months from March 2012 through December 2019. In August 2015, we terminated the VPP for approximately $13.7 million and will recognize the portion of deferred revenue in oil and gas sales based on the original volumes of BOE per production month.