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CWEI > SEC Filings for CWEI > Form 10-Q on 6-Nov-2012All Recent SEC Filings

Show all filings for CLAYTON WILLIAMS ENERGY INC /DE

Form 10-Q for CLAYTON WILLIAMS ENERGY INC /DE


6-Nov-2012

Quarterly Report


Item 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-Q and in our Form 10-K for the year ended December 31, 2011. Unless the context otherwise requires, references to "CWEI" mean Clayton Williams Energy, Inc., the parent company, and references to the "Company", "we", "us" or "our" mean Clayton Williams Energy, Inc. and its consolidated subsidiaries.

Forward-Looking Statements

The information in this Form 10-Q includes "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, could or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current expectations and belief, based on currently available information, as to the outcome and timing of future events and their effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All statements concerning our expectations for future operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties, many of which are beyond our control, and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in our Form 10-K for the year ended December 31, 2011 and in this Form 10-Q.

Forward-looking statements appear in a number of places and include statements with respect to, among other things:

estimates of our oil and gas reserves;

estimates of our future oil and gas production, including estimates of any increases or decreases in production;

planned capital expenditures and the availability of capital resources to fund those expenditures;

our outlook on oil and gas prices;

our outlook on domestic and worldwide economic conditions;

our access to capital and our anticipated liquidity;

our future business strategy and other plans and objectives for future operations;

the impact of political and regulatory developments;

our assessment of counterparty risks and the ability of our counterparties to perform their future obligations;

estimates of the impact of new accounting pronouncements on earnings in future periods; and

our future financial condition or results of operations and our future revenues and expenses.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, 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;


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the availability of capital on economic terms to fund our capital expenditures and acquisitions;

our level of indebtedness;

the impact of the past or future economic recessions 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 revolving 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;

hurricanes and other weather conditions;

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

the other risks described in our Form 10-K for the year ended December 31, 2011 and in this Form 10-Q.

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, these revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered.

As previously discussed, should one or more of the risks or uncertainties described above or elsewhere in the Form 10-K for the year ended December 31, 2011 and in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We specifically disclaim all responsibility to publicly update or revise any information contained in a forward-looking statement or any forward-looking statement in its entirety after the date made, whether as a result of new information, future events or otherwise, except as required by law.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Overview

We are engaged in developmental drilling in two primary oil-prone regions, the Permian Basin and Giddings Area, where we have a significant inventory of developmental drilling opportunities. One core area of the Permian Basin is our Bone Springs/Wolfcamp play ("Wolfbone") located in the Delaware Basin on the western edge of the Permian Basin. Also included in the Permian Basin is our Wolfberry drilling program. We are also continuing to exploit Eagle Ford Shale drilling opportunities on our extensive acreage position in the Giddings Area of East Central Texas. During the nine months ended September 30, 2012, we spent $359.1 million on exploration and development activities.

Key Factors to Consider

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for the third quarter of 2012 and the outlook for the remainder of 2012.


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Our oil and gas sales increased $1.9 million, or 2%, from the third quarter 2011. Production variances accounted for $6.3 million of the increase and price variances accounted for a $6.9 million decrease. In addition, oil and gas sales includes $2.5 million of amortized deferred revenue attributable to the volumetric production payment ("VPP") granted March 1, 2012 to finance the merger consideration payable in connection with the mergers of each of 24 limited partnerships of which Southwest Royalties, Inc. ("SWR") was the general partner into SWR ("SWR Mergers").

Our oil production increased 5% compared to the third quarter 2011 while gas production declined 8%. Our combined oil and gas production for the third quarter of 2012 increased 5% on a barrels of oil equivalent ("BOE") basis compared to the same period in 2011. The increase in oil production and the decline in gas production are indicative of our current emphasis on the development of oil reserves in the Permian Basin.

Production costs increased 34% or $8.3 million for the third quarter of 2012 compared to the third quarter of 2011 due primarily to a combination of more producing wells and rising costs of field services, including salt water disposal costs.

We recorded a $21.9 million net loss on derivatives in the third quarter of 2012, consisting of a $20.5 million unrealized loss for changes in mark-to-market valuations and a $1.4 million realized loss on settled contracts. For the same period in 2011, we recorded a $92.3 million net gain on derivatives, consisting of a $91.1 million unrealized gain for changes in mark-to-market valuations and a $1.2 million realized gain on settled contracts. Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.

Depreciation, depletion and amortization expense increased 45% to $37.7 million in the third quarter of 2012 versus $25.9 million in the third quarter of 2011 due primarily to a 33% increase in the average depletion rate per BOE of production. Most of the increase related to the Company's Wolfbone play in Reeves County, Texas.

General and administrative ("G&A") expenses were $5.8 million in the third quarter of 2012 compared to $7.1 million in the third quarter of 2011. Non-cash employee compensation expense from incentive compensation plans accounted for a credit to expense of $2.2 million in the third quarter of 2012 versus $1.1 million expense in the third quarter of 2011. G&A expenses, excluding non-cash employee compensation expense, increased to $8 million in the third quarter of 2012 from $6 million in the third quarter of 2011 due primarily to higher personnel costs and a $1 million contribution to a 527 organization.

Recent Exploration and Development Activities

Overview

Since the second quarter of 2009, we have been primarily committed to drilling developmental oil wells in the Permian Basin and the Giddings Area. We currently plan to spend approximately $428.9 million on exploration and development activities during fiscal 2012, excluding expenditures for mid-stream facilities. Our actual expenditures during 2012 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 drilling results, 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 2012.

Core Areas

Permian Basin

The Permian Basin is a sedimentary basin in West Texas and Southeastern New Mexico known for its large oil and gas deposits from the Permian geologic period. The Permian Basin covers an area approximately 250 miles wide and 350 miles long and contains commercial accumulations of oil and gas in multiple stratigraphic horizons at depths ranging from 1,000 feet to over 25,000 feet. The Permian Basin is characterized by an extensive production history, mature infrastructure, long reserve life, multiple producing horizons and enhanced recovery potential. Although many fields in the Permian Basin have been heavily exploited in the past, higher product prices and improved technology (including deep horizontal drilling) continue to attract high levels of drilling and recompletion activities. We gained a significant position in the Permian Basin in 2004 when we acquired Southwest Royalties, Inc. This acquisition provided us with an inventory of potential drilling and recompletion activities.

We spent $260.8 million in the Permian Basin during the first nine months of 2012 on drilling and completion activities and $48.6 million on leasing and seismic activities. We drilled and completed 71 gross (65.2 net) operated wells in the Permian


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Basin and conducted various remedial operations on other wells during the first nine months of 2012. We currently plan to spend approximately $362.7 million on drilling and leasing activities in this area during fiscal 2012. Following is a discussion of our principal assets in the Permian Basin.

Wolfbone

We have a significant acreage position in the Wolfbone play located in the Delaware Basin on the western edge of the Permian Basin. A Wolfbone well is a well that commingles production from the Bone Springs and Wolfcamp formations which are typically encountered at depths of 8,000 to 13,000 feet. These Permian aged formations in the Delaware Basin are comprised of limestone and sandstone. In March 2011, we entered into a farm-in agreement with Chesapeake Exploration, L.L.C. ("Chesapeake") in southern Reeves County, Texas with a term of five years. For each well that we drill in the farm-in area that meets certain specified requirements (each, a "carried well"), Chesapeake, or its successors to this agreement, will retain a 25% carried interest, bearing none of the costs to drill and complete a carried well, and we will earn an undivided 75% interest in 640 net acres within the farm-in area. Under the farm-in agreement, we are obligated to drill or commence drilling operations on at least 20 carried wells each year during the term of the agreement to a maximum of 100 carried wells. Excess wells drilled during any year may be applied towards our drilling obligations in the next year. To date, we have drilled 44 carried wells under this agreement.

We spent approximately $183.6 million on drilling and completion activities and $37.1 million for leasing activities in the Wolfbone play during the first nine months of 2012. To date, we have accumulated more than 60,000 net acres in Reeves County through a combination of acreage earned from the Chesapeake farm-in and direct leasing activities and have commenced drilling operations on 64 vertical and 11 horizontal wells. We plan to spend approximately $217.8 million on drilling and completion activities and $43.1 million on leasing activities in the Wolfbone play during 2012. We are currently utilizing four rigs in this area and plan to reduce the rig count to two through the remainder of 2012.

Wolfberry

Another focal point in the Permian Basin is the drilling of Wolfberry wells in the Midland Basin. Wolfberry is a term applied to the combined production from the Spraberry and Wolfcamp formations, which are generally found at depths of 7,500 to 10,500 feet. These formations are comprised of a sequence of basinal, interbedded shales and carbonates. We spent approximately $53.5 million on Wolfberry drilling and completion activities and approximately $900,000 on leasing activities during the first nine months of 2012. We currently have one of our rigs drilling Wolfberry wells and plan to spend approximately $59.9 million during 2012 for drilling, completion and leasing activities.

East Permian Basin

We have approximately 40,000 net acres in Glasscock and Sterling Counties, Texas that are prospective for horizontal drilling to the Cline Shale formation. Initially leased as a Wolfberry play, we have drilled and completed 12 vertical Wolfberry wells to date and plan to drill additional wells in selected areas of the field. In October 2012, we completed the Foster 240H, a horizontal Cline Shale well in Glasscock County. We are currently evaluating the initial flow rates from this well to determine the if this acreage block will be prospective for a Cline Shale developmental drilling program.

Giddings Area

Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Giddings Area. Most of our wells in the Giddings Area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas. Hydrocarbons are also encountered in the Giddings Area from other formations, including the Cotton Valley, Deep Bossier, Eagle Ford Shale, and Taylor formations. During the first nine months of 2012, we spent approximately $31.7 million in the Giddings Area on drilling and leasing activities and currently plan to spend approximately $39.2 million on similar drilling activities in this area during 2012. Following is a discussion of our principal assets in the Giddings Area.

Austin Chalk

We have concentrated our recent drilling activities in the Giddings Area on the Austin Chalk formation, an upper Cretaceous geologic formation in the Gulf Coast region of the United States that stretches across numerous fields in Texas and Louisiana. The Austin Chalk formation is generally encountered at depths of 5,500 to 7,000 feet. Horizontal drilling is the primary technique used in the Austin Chalk formation to enhance productivity by intersecting multiple


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zones. Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations. The existing spacing between some of our wells in this area affords us the opportunity to tap additional oil and gas reserves by drilling new wells between existing wells, a technique referred to as in-fill drilling. These in-fill wells are considered lower risk as compared to exploratory wells. We initiated a water fracturing program on certain wells in June 2011 to enhance productivity on certain wells. We are currently evaluating further opportunities for Austin Chalk production in the Giddings Area.

Eagle Ford Shale

The Eagle Ford Shale is a formation immediately beneath the Austin Chalk formation. In 2010, we drilled and completed four producing wells in Burleson and Lee Counties, Texas using various low-cost fracturing techniques. Production from these wells did not meet our expectations for a successful developmental drilling program. We then drilled and completed two wells in Wilson County, the Hosek #1 in the fourth quarter of 2011 and the Ortmann Unit #1 in the second quarter of 2012. We completed the Wilson County wells utilizing a cemented liner and a large, multi-stage fracturing technique and achieved significantly improved results. In the third quarter of 2012, we completed the Balcar Unit #1 in Lee County in a similar manner to the Wilson County wells. We are currently evaluating the production rates from the Balcar Unit #1 to assess the economic viability of a multiple well Eagle Ford Shale drilling program across our significant acreage position in Robertson, Burleson and Lee Counties.

South Louisiana

In the first nine months of 2012, we drilled and completed the Hassinger ETAL #1, an exploratory well in Jefferson Parish, Louisiana which is currently producing. Storm damage repairs from Hurricane Issac are progressing and should be completed mid-November. We plan to spend $9.9 million for 2012 in connection with drilling and leasing activities in South Louisiana.

Facilities

We have completed construction on the core sections of our gas pipeline, oil pipeline and salt water disposal systems in Reeves County, Texas. Most of our wells in this area are currently connected to the gas pipeline and salt water disposal system, and we expect to activate the oil pipeline late in the fourth quarter of 2012. These facilities will be expanded to accommodate new wells as we continue our development in the area. We spent $21.9 million in the first nine months of 2012 and expect to spend $24.5 million during 2012 on these systems.

Desta Drilling

Through our wholly owned subsidiary, Desta Drilling, L.P. ("Desta Drilling"), we operate 14 drilling rigs, 12 of which we own, and two of which we lease under long-term contracts. We believe that owning our own rigs helps control our cost structure and provides us flexibility to take advantage of drilling opportunities on a timely basis. The Desta Drilling rigs are primarily reserved for our use, but are available to conduct contract drilling operations for third parties from time to time. We were using five of our rigs to drill wells in our developmental drilling programs, three rigs were working for third parties and the remaining six rigs were in the yard as of October 26, 2012. We currently plan to spend $15.1 million in 2012 to refurbish rigs and upgrade our drilling equipment.

Known Trends and Uncertainties

We have an extensive acreage position within the Permian Basin with a large portion of that acreage currently held by production. We are continuously seeking other opportunities for growth in the Permian Basin, and believe that our holdings in this region provide us with many viable possibilities for exploration and development activities beyond our current drilling programs.

Our developmental drilling programs are very sensitive to oil prices and drilling costs. We attempt to control costs through drilling efficiencies by the use of our own rigs, purchasing casing and tubing at periods when we believe prices are suitable and working with service providers to receive acceptable unit costs. We plan to continue these programs as long as oil prices remain favorable. In order to continue drilling in these areas, we must be able to realize an acceptable margin between our expected cash flow from new production and our cost to drill new wells. If any combination of falling oil prices and rising drilling costs occur in future periods, we may discontinue a program until margins return to acceptable levels.


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Supplemental Information

The following unaudited information is intended to supplement the consolidated
financial statements included in this Form 10-Q with data that is not readily
available from those statements.

                                                              Three Months Ended September 30,
                                                                  2012                 2011
Oil and Gas Production Data:
Oil (MBbls)                                                            993                   945
Gas (MMcf)                                                           2,010                 2,195
Natural gas liquids (MBbls)                                            115                    61
Total (MBOE)                                                         1,443                 1,372

Average Realized Prices (a) (b):
Oil ($/Bbl)                                                $         89.48       $         89.36
Gas ($/Mcf)                                                $          3.29       $          5.46
Natural gas liquids ($/Bbl)                                $         31.37       $         54.36

Gain (Loss) on Settled Derivative Contracts (b):
($ in thousands, except per unit)
Oil: Net realized loss                                     $        (1,390 )     $        (3,292 )
  Per unit produced ($/Bbl)                                $         (1.40 )     $         (3.48 )
Gas: Net realized gain                                     $             -       $         4,481
  Per unit produced ($/Mcf)                                $             -       $          2.04

Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin                                                       2,018                   170
Other                                                                5,247                 6,152
Austin Chalk/Eagle Ford Shale                                        3,199                 3,458
Other                                                                  329                   492
Total                                                               10,793                10,272

Gas (Mcf):
Permian Basin Area:
Delaware Basin                                                       1,449                    27
Other                                                               12,246                12,885
Austin Chalk/Eagle Ford Shale                                        1,793                 1,958
Other                                                                6,360                 8,989
Total                                                               21,848                23,859

Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin                                                         257                     -
Other                                                                  711                   366
Austin Chalk/Eagle Ford Shale                                          232                   215
Other                                                                   50                    82
Total                                                                1,250                   663
                                           (Continued)


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                                                              Three Months Ended September 30,
                                                                  2012                 2011
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana                                            $            32       $            16
Deep Bossier                                                           111                     -
Permian Basin                                                           53                   642
Other                                                                  110                   598
Total                                                                  306                 1,256

Seismic and other                                                    2,710                 1,842
Total exploration costs                                    $         3,016       $         3,098

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion                                      $        35,145       $        25,042
Contract drilling depreciation                                       2,082                   669
Other depreciation                                                     434                   190
Total depreciation, depletion, and amortization            $        37,661       $        25,901

Oil and Gas Costs ($/BOE Produced):
Production costs                                           $         22.57       $         17.70
Production costs (excluding production taxes)              $         18.99       $         13.84
Oil and gas depletion                                      $         24.36       $         18.25

General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation                   $         8,024       $         6,001
Non-cash employee compensation (c)                                  (2,194 )               1,141
Total                                                      $         5,830       $         7,142

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