Clayton Williams Energy (CWEI) 8-K Regulation FD Disclosure

EXHIBIT 99.1

CLAYTON WILLIAMS ENERGY, INC.

FINANCIAL GUIDANCE DISCLOSURES FOR 2016

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, 2016. 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 Financial Accounting Standards Board Accounting Standards Codification (ASC 815 - Derivatives and Hedging);

(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, 2016. 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		Three Months Ended		Six Months Ending		Fiscal Year Ending
		March 31, 2016		June 30, 2016		December 31, 2016		December 31, 2016
(Dollars in thousands, except per unit data)
Average Daily Production:
Oil (Bbls)		9,868		9,835		9,700 to 10,000		9,800 to 10,100
Gas (Mcf)		14,242		12,890		12,000 to 13,000		12,500 to 13,500
Natural gas liquids (Bbls)		1,396		1,593		1,450 to 1,550		1,450 to 1,550
Total oil equivalents (BOE)		13,638		13,576		13,150 to 13,717		13,333 to 13,900
Price Differentials to NYMEX:
Oil		84%		89%		85% to 95%		85% to 95%
Gas		87%		83%		80% to 90%		80% to 90%
Natural gas liquids (based on oil)		27%		31%		25% to 35%		25% to 35%
Other Costs and Expenses:
Production expenses:
Direct costs ($/BOE)	$	12.97	$	13.81	$	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	$	4,959	$	4,629	$	10,000 to 13,500	$	20,000 to 23,000
DD&A:
Oil and gas ($/BOE)	$	28.03	$	27.79	$	27.00 to 29.00	$	27.00 to 29.00
Other	$	3,829	$	3,831	$	6,000 to 8,000	$	13,600 to 15,600
Exploration costs:
Abandonments and impairments	$	990	$	34	$	1,000 to 2,000	$	2,000 to 3,000
Seismic and other	$	111	$	318	$	0 to 500	$	400 to 900
Interest expense (cash rates):
$600 million Senior Notes due 2019		7.75%		7.75%		7.75%		7.75%
Bank credit facility (1)		LIBOR plus 250 to 350 bps		LIBOR plus 250 to 350 bps		LIBOR plus 250 to 350 bps		LIBOR plus 250 to 350 bps
$350 million Second Lien Credit Agreement (2)		12.5%		15%		12.5% / 15%		12.5% / 15%
Effective Federal and State Income
Tax Rate:
Current		0%		0%		0%		0%
Deferred		35.1%		35.1%		33% to 37%		33% to 37%

^{(1)  We currently do not expect to have any amount drawn on the Bank Credit Facility at December 31, 2016.} 

^{(2)  Interest on loans under the Second Lien Credit Agreement are payable quarterly in cash at 12.5% per annum, or we may elect to pay interest each quarter in-kind at 15% per annum. We elected to pay interest in kind for the third quarter of 2016. Future quarterly elections must be made at least 30 days prior to the beginning of each calendar quarter.}  

Capital Expenditures

The following table sets forth, by area, our planned capital expenditures for the year ending December 31, 2016.

	Actual Expenditures Six Months Ended June 30, 2016		Planned Expenditures Year Ending December 31, 2016		2016 Percentage of Total
	(In thousands)
Drilling and Completion:
Delaware Basin	$	16,800	$	71,300	68	%
Austin Chalk/Eagle Ford Shale	1,400		2,600		2	%
Other	700		2,000		2	%
	18,900		75,900		72	%
Leasing and seismic	15,600		29,600		28	%
Exploration and development	$	34,500	$	105,500	100	%

We currently plan to spend approximately $105.5 million on exploration and development activities in 2016, an increase of $36 million over our prior estimate. We plan to continue utilizing one rig in Reeves County for the remainder of 2016. With recent improvements in drill times, we now expect to have drilled ten wells by the end of the year, with seven wells on production and three wells in various stages of completion. Our actual expenditures during 2016 may vary significantly from these estimates since our plans for exploration and development activities may change during the year. Changes in operating margins could increase our actual expenditures during fiscal 2016.

Accounting for Derivatives

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2016.  In May 2016, we entered into costless collars covering 287 MBbls of oil production for the period from January 2017 through December 2017 at a floor price of $45.00 and a ceiling price of $55.00.In August 2016, we entered into a swap agreement covering 153 MBbls of oil production for the period from August 2016 through December 2016 at a price of $42.05. Settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Oil
	MBbls	Price
Production Period:
3rd Quarter 2016	615	$	41.13
4th Quarter 2016	619	$	41.18
2017	316	$	44.30
	1,550

Costless Collars:

	Oil
		Weighted		Weighted
		Average		Average
	MBbls	Floor Price		Ceiling Price
Production Period:
2017	1,415	$	42.27	$	51.66
	1,415

We did not designate any of our commodity derivatives 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, were recorded as other income (expense) in our consolidated statements of operations and comprehensive income (loss).