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| 8-K - 8-K - CLAYTON WILLIAMS ENERGY INC /DE | cwei8kguidance11713.htm |
EXHIBIT 99.1
CLAYTON WILLIAMS ENERGY, INC.
FINANCIAL GUIDANCE DISCLOSURES FOR 2013
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, 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 Desta Drilling, L.P., a wholly-owned subsidiary of the Company which provides contract drilling services for the Company and third parties. |
Although we are currently seeking to monetize certain of our Permian Basin producing properties through one or more transactions, which may include divestitures, joint venture arrangements or similar structures, the accompanying guidance does not assume any such monetization transactions since none have 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.
Estimated Ranges | ||
Year Ending | ||
December 31, 2013 | ||
(Dollars in thousands, except per unit data) | ||
Average Daily Production: | ||
Oil (Bbls) | 10,300 to 10,500 | |
Gas (Mcf) | 20,000 to 22,000 | |
Natural gas liquids (Bbls) | 1,300 to 1,400 | |
Total oil equivalents (BOE) (a) | 14,933 to 15,567 | |
Price Differentials to NYMEX: | ||
Oil (b) | 95% to 97% | |
Gas | 110% to 130% | |
Natural gas liquids (based on oil) | 40% to 50% | |
Other Costs and Expenses: | ||
Production expenses: | ||
Direct costs ($/BOE) | $ | 18.00 to 19.00 |
Production taxes (% of sales) | 5% to 6% | |
General and Administrative: | ||
Excluding non-cash compensation | $ | 26,000 to 28,000 |
Non-cash compensation | $ | 2,000 to 4,000 |
DD&A: | ||
Oil and gas ($/BOE) | $ | 21.00 to 23.00 |
Other | $ | 5,000 to 7,000 |
Exploration costs: | ||
Abandonments and impairments | $ | 2,000 to 4,000 |
Seismic and other | $ | 5,000 to 7,000 |
Interest expense (cash rates): | ||
$350 million Senior Notes due 2019 | 7.75% | |
Bank credit facility | LIBOR plus (175 to 275 bps) | |
Effective Federal and State Income | ||
Tax Rate: | ||
Current | 0% | |
Deferred | 36% | |
(a) | The lower end of the range for 2013 production on a BOE basis is comparable to our estimated production of 15,000 BOE per day for the fourth quarter of 2012. |
(b) | The estimated price differential for oil assumes a Midland-Cushing basis differential of approximately $12 per barrel for the first half of 2013 and approximately $2 per barrel for the last half of 2013. However, the estimated range in our guidance gives effect to the terms of an oil sales contract that we entered into with a purchaser effective December 1, 2012 that eliminates the Midland-Cushing differential on approximately 70% of our 2013 Permian Basin oil production in exchange for a flat price per barrel of approximately $1.75. |
Capital Expenditures
The following table sets forth, by area, our planned capital expenditures for the year ending December 31, 2013.
Planned | |||||||
Expenditures | 2013 | ||||||
Year Ending | Percentage | ||||||
December 31, 2013 | of Total | ||||||
(In thousands) | |||||||
Drilling and Completion: | |||||||
Permian Basin Area: | |||||||
Delaware Basin | $ | 80,200 | 35 | % | |||
Other | 28,400 | 12 | % | ||||
Austin Chalk/Eagle Ford Shale | 71,300 | 31 | % | ||||
Other | 11,700 | 5 | % | ||||
191,600 | 83 | % | |||||
Leasing and seismic | 34,000 | 15 | % | ||||
Exploration and development | 225,600 | 98 | % | ||||
Facilities and other | 3,600 | 2 | % | ||||
Total capital expenditures | $ | 229,200 | 100 | % | |||
We currently plan to spend approximately $225.6 million on exploration and development activities during fiscal 2013 as compared to approximately $430 million during fiscal 2012. 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 December 31, 2012. The settlement prices of commodity derivatives are based on NYMEX futures prices.
Swaps:
Oil | Gas | ||||||||||||
Bbls | Price | MMBtu (a) | Price | ||||||||||
Production Period: | |||||||||||||
1st Quarter 2013 | 665,000 | $ | 93.70 | 400,000 | $ | 3.34 | |||||||
2nd Quarter 2013 | 648,000 | $ | 93.94 | 390,000 | $ | 3.34 | |||||||
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 | — | $ | — | |||||||
2,513,000 | 1,480,000 | ||||||||||||
(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.
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 January 2013 through December 2019 are shown below.
Oil | Gas | ||||
Bbls | Mcf | ||||
Production Period: | |||||
1st Quarter 2013 | 30,488 | 7,533 | |||
2nd Quarter 2013 | 29,616 | 7,506 | |||
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 | |||
522,775 | 506,557 | ||||