Clayton Williams Energy Provides Financial Guidance For 2013

Clayton Williams Energy, Inc. (NASDAQ-NMS: CWEI) today filed a Form 8-K with the Securities and Exchange Commission to provide financial guidance disclosures for the year ending December 31, 2013.

A copy of these disclosures accompanies this release or may be obtained electronically by accessing the Company’s website at

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 oil and natural gas 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 environment 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.




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, 2013. 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, 2013. Each range of values provided represents the expected low and high estimates for such financial or operating factor.
  Actual   Estimated Ranges   Estimated Ranges
Six Months Ended Six Months Ending Fiscal Year Ending
June 30, 2013 (c) December 31, 2013 December 31, 2013
(Dollars in thousands, except per unit data)
Average Daily Production:
Oil (Bbls) 9,972 9,100 to 9,300 9,500 to 9,700
Gas (Mcf) (a) 17,823 16,000 to 18,000 16,000 to 18,000
Natural gas liquids (Bbls) (a) 1,514 1,400 to 1,500 1,400 to 1,500
Total oil equivalents (BOE) 14,457 13,167 to 13,800 13,567 to 14,200
Price Differentials to NYMEX:
Oil (b) 98% 97% to 99% 97% to 99%
Gas 93% 90% to 100% 90% to 100%
Natural gas liquids (based on oil) 34% 30% to 40% 30% to 40%
Other Costs and Expenses:
Production expenses:
Direct costs ($/BOE) $18.34 $18.50 to 19.50 $18.50 to 19.50
Production taxes (% of sales) 5% 5% to 6% 5% to 6%
General and Administrative:
Excluding non-cash compensation $17,472 $13,000 to 15,000 $30,000 to 32,000
Non-cash compensation $(7,101) $0 to 1,000 $(6,000) to (7,000)
Oil and gas ($/BOE) $25.84 $25.00 to 26.00 $25.00 to 26.00
Other $7,306 $6,000 to 8,000 $13,000 to 15,000
Exploration costs:
Abandonments and impairments $2,371 $2,000 to 4,000 $4,000 to 6,000
Seismic and other $3,364 $500 to 2,500 $4,000 to 6,000
Interest expense (cash rates):
$350 million Senior Notes due 2019 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)
Effective Federal and State Income
Tax Rate:
Current 0% 0% 0%
Deferred 37% 36% 36%


(a) Prior to 2013, certain purchasers of our casing head gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, we began separating these products for a portion of our gas production.

(b) Through multiple marketing arrangements, we have effectively limited our exposure to the Midland-Cushing differential to less than $2 per barrel on more than 75% of our Permian Basin oil production.

(c) In April 2013, we sold 95% of our interest in certain properties in Andrews County, Texas. Average daily production related to those properties for the six months ended June 30, 2013 were as follows: Oil – 814 Bbls; Natural gas – 902 Mcf; NGL – 179 Bbls; and 1,143 BOE.

Capital Expenditures

The following table sets forth, by area, our actual capital expenditures for the first six months of 2013 and our planned capital expenditures for the year ending December 31, 2013.
Actual   Planned  
Expenditures Expenditures 2013
Six Months Ended Year Ending Percentage
June 30, 2013 December 31, 2013 of Total
(In thousands)
Drilling and Completion:
Permian Basin Area:
Delaware Basin $ 39,300 $ 118,200 43%
Other 24,200 34,000 12%
Austin Chalk/Eagle Ford Shale 38,500 59,600 22%
Other 5,900 10,600 4%
107,900 222,400 81%
Leasing and seismic 27,900 47,400 17%
Exploration and development 135,800 269,800 98%
Facilities and other 3,700 5,000 2%
Total capital expenditures $ 139,500 $ 274,800 100%

We currently plan to spend approximately $269.8 million on exploration and development activities during fiscal 2013, as compared to our previous estimate of $246.7 million. The net increase of $23.1 million relates primarily to the following:
  • Increase in the estimated net working interest in the Delaware Basin wells from 75% to 100%;
  • Reduction in the number of Eagle Ford Shale wells expected to be drilled in the last half of 2013 from six to two; and
  • Increase in expected leasing costs in the Delaware Basin and the Eagle Ford Shale.

The reduction in the number of Eagle Ford Shale wells relates to our current plans to temporarily suspend horizontal drilling in the Eagle Ford Shale late in the 3rd quarter of 2013 to allow for a higher allocation of available resources to the Delaware Basin in order to meet certain drilling commitments. We are currently seeking a joint venture partner for a portion of our Reeves County Wolfbone project and expect to resume drilling in the Eagle Ford Shale when the terms of a suitable joint venture arrangement are determined.

Our actual expenditures during 2013 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 could increase or decrease our actual expenditures during the remainder of fiscal 2013.

Accounting for Derivatives

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2013. The settlement prices of commodity derivatives are based on NYMEX futures prices.

    Oil   Gas
Bbls   Price MMBtu (a)   Price
Production Period:
3rd Quarter 2013 300,000 $ 104.60 360,000 $ 3.34
4th Quarter 2013 300,000 $ 104.60 330,000 $ 3.34
2014 600,000 $ 99.30 - $ -
1,200,000 690,000
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

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 2013 through December 2019 are shown below.
    Oil   Gas
Bbls Mcf
Production Period:
3rd Quarter 2013 28,793 8,550
4th Quarter 2013 28,045 10,030
2014 102,011 45,392
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
462,671 491,518

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