EXHIBIT 99.1
CLAYTON WILLIAMS ENERGY, INC.
FINANCIAL GUIDANCE DISCLOSURES FOR 2015
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, 2015. 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:
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| (a) | production which may be obtained through future exploratory drilling; |
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| (b) | dry hole and abandonment costs that may result from future exploratory drilling; |
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| (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; |
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| (d) | gains or losses from sales of property and equipment unless the sale has been consummated prior to the filing of financial guidance; |
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| (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 |
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| (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, 2015. Each range of values provided represents the expected low and high estimates for such financial or operating factor.
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| | | Actual | | Actual | | Estimated Ranges | | Estimated Ranges |
| | | Three Months Ended | | Three Months Ended | | Six Months Ending | | Fiscal Year Ending |
| | | March 31, 2015 | | June 30, 2015 | | December 31, 2015 | | December 31, 2015 |
| (Dollars in thousands, except per unit data) | | | | | | | | |
| Average Daily Production: | | | | | | | | |
| Oil (Bbls) | | 13,100 | | 12,363 | | 10,600 to 10,800 | | 11,600 to 11,800 |
| Gas (Mcf) | | 15,622 | | 16,066 | | 14,000 to 16,000 | | 14,000 to 16,000 |
| Natural gas liquids (Bbls) | | 1,489 | | 1,560 | | 1,350 to 1,550 | | 1,350 to 1,550 |
| Total oil equivalents (BOE) | | 17,193 | | 16,601 | | 14,283 to 15,017 | | 15,283 to 16,017 |
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| Price Differentials to NYMEX: | | | | | | | | |
| Oil | | 90% | | 92% | | 90% to 95% | | 90% to 95% |
| Gas | | 94% | | 94% | | 90% to 100% | | 90% to 100% |
| Natural gas liquids (based on oil) | | 27% | | 26% | | 25% to 35% | | 25% to 35% |
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| Other Costs and Expenses: | | | | | | | | |
| Production expenses: | | | | | | | | |
| Direct costs ($/BOE) | $ | 13.26 | $ | 13.02 | $ | 13.50 to 14.50 | $ | 13.50 to 14.50 |
| Production taxes (% of sales) | | 5% | | 5% | | 5% to 6% | | 5% to 6% |
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| General and administrative: | | | | | | | | |
| Excluding non-cash compensation | $ | 7,829 | $ | 5,558 | $ | 12,000 to 14,000 | $ | 26,000 to 28,000 |
| Non-cash compensation | $ | 1,314 | $ | 5,770 | $ | 1,000 to 2,000 | $ | 8,000 to 10,000 |
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| DD&A: | | | | | | | | |
| Oil and gas ($/BOE) | $ | 25.13 | $ | 25.32 | $ | 24.00 to 26.00 | $ | 24.00 to 26.00 |
| Other | $ | 3,771 | $ | 3,864 | $ | 6,000 to 8,000 | $ | 14,000 to 16,000 |
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| Exploration costs: | | | | | | | | |
| Abandonments and impairments | $ | 1,623 | $ | 2,508 | $ | 2,000 to 4,000 | $ | 6,000 to 8,000 |
| Seismic and other | $ | 866 | $ | 105 | $ | 500 to 1,000 | $ | 1,500 to 2,000 |
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| 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 (175 to 275 bps) | | LIBOR plus (175 to 275 bps) | | LIBOR plus (175 to 275 bps) |
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| Effective Federal and State Income | | | | | | | | |
| Tax Rate: | | | | | | | | |
| Current | | 0% | | 0% | | 0% | | 0% |
| Deferred | | 35.2% | | 35.4% | | 33% to 37% | | 33% to 37% |
Estimated average daily production for the first six months ending December 31, 2015, as shown in the above table, includes incremental production from our core developmental drilling programs. In July 2015, we resumed drilling activities with one rig in the Eagle Ford and one rig in the Delaware Basin. Our model assumes an Eagle Ford rig can drill 12 wells per year, and a Delaware Basin rig can drill six wells per year.
The following table sets forth certain information regarding our model well economics assuming NYMEX product prices of $60 per barrel of oil and $3 per MMBtu of natural gas.
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| | | | Eagle Ford | | | Wolfcamp |
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| Gross estimated ultimate reserves (EUR) (MBOE) | | | 250 | | | | 650 | |
| Drilling and completion costs (In thousands) | | $ | 4,000 | | | $ | 6,600 | |
| Estimated first year gross production (MBOE) | | | 67 | | | | 119 | |
| Undiscounted payout (In years) | | | 2.5 | | | | 3.1 | |
| ROI | | | 30 | % | | | 26 | % |
| Company estimated WI/NRI % | | | 100% / 75% | | | | 100% / 75% | |
Capital Expenditures
The following table sets forth, by area, our actual expenditures for the first six months of 2015 and our planned capital expenditures for the year ending December 31, 2015.
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| | | Actual | | | Planned | | |
| | | Expenditures | | | Expenditures | | 2015 |
| | | Six Months Ended | | | Year Ending | | Percentage |
| | | June 30, 2015 | | | December 31, 2015 | | of Total |
| | | (In thousands) | | |
| Drilling and Completion: | | | | | | | |
| Permian Basin Area: | | | | | | | |
| Delaware Basin | $ | 26,100 |
| | $ | 42,100 |
| | 31% |
| Other | | 8,600 |
| | | 14,400 |
| | 11% |
| Austin Chalk/Eagle Ford Shale | | 22,900 |
| | | 46,300 |
| | 34% |
| Other | | 5,300 |
| | | 6,900 |
| | 5% |
| | | 62,900 |
| | | 109,700 |
| | 81% |
| Leasing and seismic | | 14,700 |
| | | 24,800 |
| | 19% |
| Exploration and development | $ | 77,600 |
| | $ | 134,500 |
| | 100% |
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We currently plan to spend approximately $134.5 million on exploration and development activities during fiscal 2015. Our actual expenditures during 2015 may vary significantly from these estimates since our plans for exploration and development activities may change during 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 2015.
Accounting for Derivatives
The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2015. The settlement prices of commodity derivatives are based on NYMEX futures prices.
Swaps
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| | Oil |
| | MBbls | | Price |
| Production Period: | | | |
| 3rd Quarter 2015 | 697 | | | $ | 55.65 | |
| 4th Quarter 2015 | 592 | | | $ | 55.65 | |
| | 1,289 | | | |
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 2015 through December 2019 are shown below.
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| | Oil | | Gas |
| | Bbls | | Mcf |
| Production Period: | | |
| 2015 | 43,300 | | 29,381 |
| 2016 | 64,808 | | 112,928 |
| 2017 | 56,785 | | 96,792 |
| 2018 | 49,455 | | 84,734 |
| 2019 | 43,820 | | 72,874 |
| | 258,168 | | 396,709 |
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