8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 8‑K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): August 4, 2014

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of Registrant as specified in its charter)

Delaware	001-10924	75-2396863
(State or other jurisdiction of	(Commission File	(I.R.S. Employer
incorporation or organization)	Number)	Identification Number)

6 Desta Drive, Suite 6500, Midland, Texas	79705-5510
(Address of principal executive offices)	(Zip code)

Registrant's Telephone Number, including area code:   (432) 682-6324

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2 (b) under the Exchange Act (17 CFR 240.14d-2 (b))

o Pre-commencement communications pursuant to Rule 13e-4 (c) under the Exchange Act (17 CFR 240.13e-4 (c))

Item 7.01-    Regulation FD Disclosure

The Company hereby incorporates by reference into this Item 7.01 of Form 8-K the Financial Guidance Disclosures for 2014 attached as Exhibit 99.1. This Exhibit 99.1 is being furnished to provide public disclosure of certain financial and operating estimates in order to permit the preparation of models to forecast the Company’s operating results for the fiscal year ending December 31, 2014. The Company cautions users of this information that the estimates provided in this Exhibit 99.1 are based on information available to the Company as of the date of this filing, and actual results may vary materially from these estimates. The Company does not undertake any obligation to update these estimates as conditions change or as additional information becomes available.

Item 9.01-Financial Statements and Exhibits

(d)Exhibits

The following exhibit is provided as part of the information furnished under Item 7.01 of this report.

Exhibit
Number	Description
99.1	Clayton Williams Energy, Inc. Financial Guidance Disclosures for 2014

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.

CLAYTON WILLIAMS ENERGY, INC.

Date:	August 4, 2014	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Executive Vice President and Chief
			Operating Officer

Date:	August 4, 2014	By:	/s/ Michael L. Pollard
			Michael L. Pollard
			Senior Vice President and Chief Financial
			Officer

EX-99.1

EXHIBIT 99.1

CLAYTON WILLIAMS ENERGY, INC.

FINANCIAL GUIDANCE DISCLOSURES FOR 2014

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, 2014. 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, 2014. 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, 2014		June 30, 2014		December 31, 2014		December 31, 2014
(Dollars in thousands, except per unit data)
Average Daily Production:
Oil (Bbls)		11,233		11,451		12,700 to 12,900		12,000 to 12,300
Gas (Mcf)		15,711		15,154		14,000 to 15,000		15,000 to 16,000
Natural gas liquids (Bbls)		1,622		1,582		1,550 to 1,650		1,500 to 1,600
Total oil equivalents (BOE)		15,474		15,559		16,583 to 17,050		16,000 to 16,567
Price Differentials to NYMEX:
Oil		95%		93%		94% to 97%		94% to 97%
Gas		105%		98%		90% to 100%		90% to 100%
Natural gas liquids (based on oil)		40%		31%		30% to 40%		30% to 40%
Other Costs and Expenses:
Production expenses:
Direct costs ($/BOE)	$	14.89	$	13.41	$	14.00 to 15.00	$	14.00 to 15.00
Production taxes (% of sales)		5%		5%		5% to 6%		5% to 6%
General and Administrative:
Excluding non-cash compensation	$	8,394	$	8,401	$	15,500 to 17,500	$	32,300 to 34,300
Non-cash compensation	$	3,424	$	12,950	$	1,000 to 3,000	$	17,400 to 19,400
DD&A:
Oil and gas ($/BOE)	$	23.93	$	25.20	$	24.00 to 26.00	$	24.00 to 26.00
Other	$	2,914	$	3,263	$	6,000 to 7,000	$	12,000 to 14,000
Exploration costs:
Abandonments and impairments	$	3,839	$	2,887	$	3,000 to 5,000	$	9,700 to 11,700
Seismic and other	$	1,483	$	225	$	1,000 to 3,000	$	2,700 to 4,700
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 (150 to 250 bps)		LIBOR plus (150 to 250 bps)		LIBOR plus (150 to 250 bps)
Effective Federal and State Income
Tax Rate:
Current		0%		0%		0%		0%
Deferred		36%		36%		37%		37%

Current estimates of our average daily production, as indicated by the mid-point of ranges set forth in the above table for the year ending December 31, 2014, differ from the corresponding mid-points shown in our previous guidance, as follows: Oil - down 350 Bbls; Gas - up 500 Mcf; NGL - up 50 Bbls; and Total - down 217 BOE. The 3% downward revision in estimated 2014 oil production was driven by production shortfalls in certain step-out or delineation wells in our Delaware Basin and Eagle Ford Shale plays. We believe the causes of these production shortfalls are isolated and can be corrected through improved completion techniques.

Supplemental Analysis

The following table compares our estimated 2014 average daily production to our 2013 production, with both periods adjusted on a pro forma basis for the sale of our Andrews County assets in April 2013 and certain non-core Eagle Ford Shale/Austin Chalk assets in March 2014.

	Average Daily Production (BOE)
	As Reported	Pro Forma	Pro Forma	Pro Forma %
	2013	2013	2014 (E)	Change
Delaware Basin	2,730	2,730	4,800	76%
Eagle Ford Shale	1,168	551	2,800	408%
	3,898	3,281	7,600	132%
Other	10,501	9,935	8,600	(13)%
	14,399	13,216	16,200	23%

Capital Expenditures

The following table sets forth, by area, our actual expenditures for the first six months of 2014 and our planned capital expenditures for the year ending December 31, 2014.

	Actual		Planned
	Expenditures		Expenditures		2014
	Six Months Ended		Year Ending		Percentage
	June 30, 2014		December 31, 2014		of Total
	(In thousands)
Drilling and Completion:
Permian Basin Area:
Delaware Basin	$	74,600	$	175,900	40%
Other	11,400		21,300		5%
Austin Chalk/Eagle Ford Shale	59,600		182,000		41%
Other	4,900		9,500		2%
	150,500		388,700		88%
Leasing and seismic	25,700		51,300		12%
Exploration and development	$	176,200	$	440,000	100%

We currently plan to spend approximately $440 million on exploration and development activities during fiscal 2014, up 5% from our previous guidance of $418.7 million. This increase is attributable to our plans to add a fourth drilling rig in the Delaware Basin in September 2014. Our actual expenditures during 2014 may vary significantly from these estimates since our plans for exploration and development activities may change during the remainder of the year. Factors, such as changes in operating margins and the availability of capital resources and other factors, could increase or decrease our actual expenditures during the remainder of fiscal 2014.

Accounting for Derivatives

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2014. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Oil
	Bbls	Price
Production Period:
3rd Quarter 2014	530,200	$	96.87
4th Quarter 2014	503,200	$	96.92
	1,033,400

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. The scheduled remaining volumes for production months from July 2014 through December 2019 are shown below.

	Oil	Gas
	Bbls	Mcf
Production Period:
2014	49,590	22,771
2015	88,954	60,218
2016	64,808	112,928
2017	56,785	96,792
2018	49,455	84,734
2019	43,820	72,874
	353,412	450,317