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			Estimated Ranges		Estimated Ranges
		Three Months Ended			Nine Months Ending		Fiscal Year Ending
		March 31, 2016			December 31, 2016		December 31, 2016
(Dollars in thousands, except per unit data)
Average Daily Production:
Oil (Bbls)		9,868			8,700 to 9,100		8,900 to 9,300
Gas (Mcf)		14,242			12,000 to 14,000		12,000 to 14,000
Natural gas liquids (Bbls)		1,396			1,200 to 1,400		1,200 to 1,400
Total oil equivalents (BOE)		13,638			11,900 to 12,833		12,100 to 13,033
Price Differentials to NYMEX:
Oil		84%			80% to 90%		80% to 90%
Gas		87%			85% to 95%		85% to 95%
Natural gas liquids (based on oil)		27%			25% to 35%		25% to 35%
Other Costs and Expenses:
Production expenses:
Direct costs ($/BOE)	$	12.97		$	13.00 to 14.00	$	13.00 to 14.00
Production taxes (% of sales)		5%			5% to 6%		5% to 6%
General and administrative:
Excluding non-cash compensation	$	4,959		$	14,000 to 18,000	$	19,000 to 23,000
Non-cash compensation	$	(1,068	)	$	750 to 2,500	$	0 to 1,500
DD&A:
Oil and gas ($/BOE)	$	28.03		$	27.00 to 29.00	$	27.00 to 29.00
Other	$	3,829		$	9,000 to 12,000	$	12,800 to 15,800
Exploration costs:
Abandonments and impairments	$	990		$	1,000 to 2,000	$	2,000 to 3,000
Seismic and other	$	111		$	375 to 1,125	$	500 to 1,300
Interest expense (cash rates):
$600 million Senior Notes due 2019		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
$350 million Second Lien Credit Agreement (2)		12.5%			12.5% / 15%		12.5% / 15%
Effective Federal and State Income
Tax Rate:
Current		0%			0%		0%
Deferred		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 second 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		Planned
	Expenditures		Expenditures		2016
	Three Months Ended		Year Ending		Percentage
	March 31, 2016		December 31, 2016		of Total
	(In thousands)
Drilling and Completion:
Delaware Basin	$	2,000	$	42,900	62%
Austin Chalk/Eagle Ford Shale	1,000		1,700		2%
Other	800		2,000		3%
	3,800		46,600		67%
Leasing and seismic	8,100		22,900		33%
Exploration and development	$	11,900	$	69,500	100%

We currently plan to spend approximately $69.5 million on exploration and development activities in 2016 primarily to drill five wells and participate in two non-operated wells in the Delaware Basin. 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 March 31, 2016.  In addition, we granted an option on 739 MBbls of oil production from July 2016 through December 2016 at $40.25 per barrel exercisable by the counterparty by June 30, 2016. In April 2016, we entered into crude oil costless collars covering 1,128 MBbls of our oil production for the period from January 2017 through December 2017 at a weighted average floor price of $41.57 and a weighted average ceiling price of $50.81. Settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Oil
	MBbls	Price
Production Period:
2nd Quarter 2016	518	$	40.47
3rd Quarter 2016	176	$	42.70
4th Quarter 2016	167	$	42.70
2017	315	$	44.30
	1,176

Swaps Subject to Optional Extension:

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

Crude Oil Costless Collars:

	Oil
		Weighted		Weighted
		Average		Average
	MBbls	Floor Price		Ceiling Price
Production Period:
2017	1,128	$	41.57	$	50.81
	1,128

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).