Exhibit 99.2
Guidance Update and Our Properties
Guidance Update
Primarily due to previously announced curtailments related to hurricanes and facilities constraints, we have updated the guidance that we issued in August of 2005 relating to the fourth quarter of 2005. We now anticipate the following ranges will apply to the fourth quarter: our production rate will range from 113–118 MMcfe/day; our lease operating costs will be from $.98–$1.08 per Mcfe; our workover costs are expected to be between $.12 and $.15 per Mcfe; and our general and administrative costs are estimated to be between $.85 to $.90 per Mcfe. In addition, we expect our production and ad valorem taxes to average between 7 and 7½% of our revenue from oil and gas. We expect our income taxes to be 98% deferred and expect our state and federal tax rate to be 39%.
Our Properties
The December 31, 2005 estimated proved reserve data included herein is based on estimates prepared by our internal engineers and professionals in accordance with the Securities and Exchange Commission (SEC) guidelines and have not been evaluated by an independent petroleum engineering firm. Furthermore, our internal reserve estimates for the pending Winwell Stock Purchase and Asset Purchase and certain acquisitions made in 2005 are based upon data available to us that may not be as complete as data available on our other properties.
Although our internally estimated December 31, 2005 proved reserves were prepared in accordance with SEC guidelines, they may differ materially from the independent reserve estimates we expect to disclose in our Annual Report on Form 10-K for 2005 as a result of the estimation process employed by Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm.
The following table sets forth, by operating area, a pro forma summary of our internally estimated net proved reserve information as of December 31, 2005, the estimated average net daily production for December 2005, and budgeted capital expenditures for 2006, after giving effect to the pending North Louisiana Acquisitions.
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| | | | | December | | | |
| | | Estimated Net Proved Reserves at | | | 2005 | | | |
| | | December 31, 2005(1) | | | Estimated | | | |
| | | | | | Average Net | | | Budgeted | |
| | | | | % of | | | | | Pre-Tax | | | Daily | | | 2006 Capital | |
| Area | | Total | | | Total | | | Gas %(2) | | | PV-10(3) | | | Production | | | Expenditures | |
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| | | (Bcfe) | | | | | | | (Millions) | | | (MMcfe/d) | | | (Millions) | |
| Permian | | | 158.2 | | | | 29 | % | | | 66 | % | | $ | 386.8 | | | | 24.9 | | | $ | 18.2 | |
| East Texas/North La (4) | | | 126.9 | | | | 23 | | | | 96 | | | | 330.8 | | | | 21.3 | | | | 51.4 | |
| Gulf Coast | | | 83.6 | | | | 15 | | | | 53 | | | | 355.4 | | | | 32.0 | | | | 42.7 | |
| South Texas | | | 72.2 | | | | 13 | | | | 91 | | | | 258.8 | | | | 30.4 | | | | 67.2 | |
| Anadarko | | | 59.0 | | | | 11 | | | | 78 | | | | 181.2 | | | | 13.5 | | | | 25.5 | |
| Gulf of Mexico (5) | | | 25.9 | | | | 5 | | | | 72 | | | | 87.4 | | | | 10.9 | | | | 0.0 | |
| Arkoma | | | 17.7 | | | | 3 | | | | 90 | | | | 49.1 | | | | 4.7 | | | | 5.0 | |
| Other Basins | | | 7.0 | | | | 1 | | | | 42 | | | | 21.6 | | | | 3.4 | | | | 0.0 | |
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| | Total | | | 550.5 | | | | 100 | % | | | 76 | % | | $ | 1,671.1 | | | | 141.1 | | | $ | 210.0 | |
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| (1) | Based on internal estimates prepared using constant prices and costs in accordance with SEC guidelines. |
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| (2) | Natural gas liquids, or NGLs, are included in natural gas reserves. |
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| (3) | Based on spot market prices of $60.84 per Bbl of oil and $10.075 per MMbtu of natural gas as of December 31, 2005, adjusted for estimated basis and quality differentials. Certain regional basis differential information for natural gas prices at December 31, 2005 was not available as of the date of this document and has been estimated by us for purposes of preparing estimated proved reserves and associatedPV-10 as of December 31, 2005. |
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| (4) | Includes estimated proved reserves of approximately 106 Bcfe, 16 MMcfe/d of December 2005 production, $264.1 million pre-taxPV-10 and $35 million in budgeted 2006 capital expenditures, all related to the North Louisiana Acquisitions. |
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| (5) | We intend to divest substantially all of our properties in the Gulf of Mexico area and, accordingly, have not budgeted any capital expenditures for this area in 2006. If we do not divest these properties, related capital expenditures of approximately $15 million could be incurred in 2006. |
In the Permian Basin, our principal properties are in the Waddell Ranch field in Crane County, Texas, the TXL field located in Ector County, Texas and the Jalmat field in Lea County, New Mexico. Since the acquisition of our Permian Basin assets, we have extensively examined and evaluated these properties. Our objective is to determine if unevaluated proved reserves and additional upside opportunities exist within these long-lived, multi-pay fields.
Waddell Ranch is the largest field in West Texas and produces primarily from the Queen, Grayburg, San Andres, Clear Fork, and Ellenburger formations at depths from 3,000 to 15,000 feet. The Waddell Ranch field complex is comprised of over 75,000 acres and is productive from over fifteen different reservoirs. The development opportunities in this field complex (13% working interest and 15% net revenue interest) continue to evolve through technical evaluation. Our staff has implemented a rigorous engineering and geological study over the past nine months. The results of this field study are the identification of over 1,000 additional potential drilling locations. This project has resulted in the addition of net proved reserves at year end 2005,
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with the potential of continued reserve additions in future years. After review of this study with our working interest partners, we concluded that the 2006 capital budget would be increased by 100% over the 2005 level of approximately $26 million gross and is currently planned to include the drilling of 30 new wells and 90 recompletions.
The TXL field located in Ector County, Texas is a unitized field in the Clearfork Tubb formation at approximately 5,600 feet. As a result of our ongoing evaluation, over 100 additional drill sites have been evaluated which we believe will lead to additional proved reserves as well as upside potential. As many as 20 wells are planned in 2006 in this field, where we own a 20% working interest and 25% net revenue interest.
The Jalmat field in Lea County, New Mexico is slated for an aggressive development drilling program in the Seven Rivers formation which contains over 55 proved developed locations and over 90 probable locations. We plan activity for at least 26 locations during 2006 (10 new wells and 16 recompletions) and may accelerate this program if additional drilling rigs can be secured. Our extensive evaluation of this area has resulted in the identification of significant waterflood potential in the Queen sand, a reservoir that has had excellent waterflood results from numerous offsetting units. The Company owns a 96% working interest and 83% net revenue interest in this field.
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| East Texas/North Louisiana |
Our properties in the East Texas basin produce primarily from the Cotton Valley and Travis Peak/ Hosston formations, which range in depth from approximately 6,500 to 10,000 feet. We own significant interests in the South Carthage, North Beckville and Blocker fields in Panola and Harrison Counties, Texas. Our working interest in these fields is between 47% and 100%. The producing formations of this area tend to contain multiple producing horizons and are typically low permeability sands that require fracture stimulation to achieve optimal producing rates. This type of fracture stimulation usually results in relatively high initial production rates that decline rapidly during the first year of production and subsequently stabilize at fairly low, more easily predictable annual decline rates. Much of our production in this area is from wells that have been producing for several years and are in the latter, more stable stage of production, resulting in a relatively long reserves-to-production ratio.
The properties to be acquired in the North Louisiana Acquisitions are located in the Elm Grove and Caspiana fields in North Louisiana. Current production is approximately 16 MMcfe/d from the Cotton Valley and Hosston formations. We have identified 250 drilling locations on the 27,400 acre block and plan a multi-year in-fill development program. In 2006, we have budgeted $35 million for development drilling on these properties. One drilling rig currently being utilized in the field is operated. We expect to add a second operated drilling rig in the spring of 2006.
We have been actively acquiring acreage in the developing James Lime horizontal play and in the Travis Peak and Cotton Valley vertical plays in Nacogdoches, Shelby and Angelina Counties, Texas. Over 14,000 net acres have been acquired to date and we anticipate adding significant additional acreage to our position through additional leasing and farm out negotiations. The initial well is expected to spud during the first quarter of 2006. We plan on maintaining a one-rig program in this area throughout 2006 with the intent to add a second rig pending drilling success and rig availability.
The Gueydan field in Vermilion Parish, Louisiana is our largest field in the Gulf Coast region and was acquired as part of the acquisition of Proton Oil & Gas Corporation. Production in this field is from 2,500 to 10,000 feet in depth. Our working interest ranges from 50% to 100%, and we plan to drill ten wells in 2006 at Gueydan. We have enjoyed significant success during 2005 with our drilling program in this field. In addition to the development of the 2,700-foot Sands with the Alliance #45, #50 and #51 (100% working interest, 78% net revenue interest), drilling has continued in deeper Alliance Sand wells at approximately 9,500 feet. Most recently, the Noble #1 (50% working interest and 39% net revenue interest) has been completed and is producing at a gross rate of 3.0 MMcfe/d. In addition, the Alliance #47 (98% working interest and 81% net revenue interest) was logged and confirmed 45 feet of high quality pay sand. We have also leased
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approximately 2,000 additional acres within the area, and are in the process of conducting a new 3-D seismic survey to confirm additional prospects. In 2006, six shallow exploratory wells, three 9,500-foot Alliance Sand developmental wells, and one 16,000-foot deep Miocene exploratory well are budgeted.
Other significant fields in this region include South Bayou Boeuf in LaFourche Parish, Louisiana, Reddell in Evangeline Parish, Louisiana and North Leroy in Vermilion Parish, Louisiana.
Our properties in South Texas produce primarily from the Vicksburg, Wilcox and Frio formations, which range in depth from approximately 5,500 to 15,000 feet. We believe that the South Texas region will continue to be a key area for us for potential growth via our drilling program. Also, we are expanding our exploration activities in South Texas through joint ventures with other experienced operators covering up to 800 square miles. This program involves the merging and reprocessing of multiple 3-D seismic data sets and is designed to identify, evaluate and drill deeper objectives within the Wilcox, Vicksburg and Frio trends in this core exploration area. We estimate that we will own and be the operator of approximately 50% of the working interest associated with this program.
In the Lions field, located in Goliad County, we put three new high rate wells on production during the fourth quarter of 2005. These wells, the Petrohawk Weise #2 (50% working interest and 38% net revenue interest), Wright Materials #3 ST2 (28% working interest and 20% net revenue interest) and Weise GU “A” #1 (32% working interest and 24% net revenue interest), were all completed from multiple Lower Wilcox sands and had combined early production rates of 41 MMcfe/d gross and 13 MMcfe/d net. Production is currently constrained due to limitations imposed by treatment facilities in the field. These facilities are in the process of being upgraded and should allow for a significant increase in production from the field. Two to four additional wells are planned during 2006 in the Lions field, with continued development beyond 2006. Additionally, we are in the process of acquiring a high density 3-D seismic survey to better image the complexities of the field. Gross reserve potential for the field is estimated to be in the range of 50-100 Bcfe.
The La Reforma field, located in Starr and Hidalgo Counties, is a significant Vicksburg formation field, and we own between 25% and 50% working interest in this area. We are continuing our successful drilling program in the Lower Vicksburg formation in this field. The Guerra “D” #2 (50% working interest and 38% net revenue interest) was recently completed from multiple Vicksburg sands which resulted in early production rates in excess of 9 MMcfe/d. We and our partners intend to maintain an aggressive drilling program in this field through 2006, partially supported by the acquisition of significant additional acreage within our area of mutual interest by virtue of a recently announced farm-in. Additionally, we have merged and reprocessed over 100 square miles of 3-D seismic data within this field area and are actively pursuing the acquisition of additional leases. The Vicksburg formation in this area is complexly faulted and 3-D seismic data is extensively utilized to identify optimal structural targets. Wells in this field typically produce at initial rates of over 10 MMcfe/d. Other Vicksburg/Frio fields in which we own a meaningful interest include Los Indios, Nabors, Ann Mag and McAllen Ranch.
We are in the process of completing our first well in the Provident City field in Colorado County. The Petrohawk Garrett #1 (55% working interest and 43% net revenue interest) encountered multiple Lower Wilcox sands between 13,300 and 15,700 feet. The well is anticipated to be on production in January. Additionally, we are currently merging and reprocessing 3-D seismic data covering 200 square miles with the anticipation of further enhancing the area’s exploration potential, as well as actively acquiring leases covering additional prospective areas in this complex Lower Wilcox trend. We intend to drill one to two additional wells in this area in 2006.
In Matagorda County, we recently reached total depth on the Petrohawk Doss #1 (50% working interest and 40% net revenue interest) and anticipate initiating completion operations on this well in early January, with initial production expected in mid-February. This well is located within a large amplitude anomaly in the Lower Frio formation, which we believe has potential for a significant discovery. We are in the process of merging and reprocessing 3-D seismic data covering in excess of 300 square miles, as well as actively acquiring leases covering other prospective areas within this trend. Two additional wells are budgeted for 2006.
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The Heard Ranch field, located in Bee County, was acquired in the Proton transaction and produces from the Frio formation at depths of 3,500 to 4,000 feet. We own between a 77% and 89% working interest with between 56% and 65% net revenue interest at Heard Ranch and plan to drill up to four proved undeveloped and two probable locations in 2006. In the San Miguel Creek field in McMullen County, we anticipate drilling six Wilcox formation wells in 2006. We also plan Lower Wilcox formation development wells during 2006 in the Dry Hollow field, located in Lavaca County. On our Ricardo Prospect in the KRB Zuni field in Kleburg County, we have drilled two 14,000-foot Vicksburg formation wells in the fourth quarter. The first well is currently waiting on pipeline connection and the second well is waiting on completion. These wells are offsetting highly productive wells drilled by another operator. We have one additional well scheduled for the first quarter and could drill up to four additional wells in 2006. We own a 25% working interest and 19% net revenue interest in these wells.
The West Edmond Hunton Lime Unit, or WEHLU, is our largest property in this region, covering 30,000 acres (approximately 47 square miles) primarily in Oklahoma County, Oklahoma. The WEHLU field, originally discovered in 1942, is the largest Hunton Lime formation field in the state of Oklahoma. The field has 58 oil and natural gas wells (28 currently producing) with stable production holding the entire unit. We own a 98% working interest and 80% net revenue interest at WEHLU and currently operate the field. We have an agreement with a private company to jointly develop additional reserves and production in a portion of WEHLU. The area of mutual interest created by the agreement covers 5,680 acres located in the central-northwest portion of the field and we own a 40% working interest and 33% net revenue interest in this area. Two successful horizontal wells were drilled in 2005 and we expect to drill as many as six additional horizontal wells in WEHLU in 2006.
In the Lipscomb field in Lipscomb County, Texas the Tyson “A” #4H (38% working interest and 30% net revenue interest) has been recently completed as a horizontal well in the Cleveland sand and is producing approximately 3 MMcfe/d. We expect to drill six additional wells in this field during 2006.
We own interests in 28 blocks in the federal waters of the Gulf of Mexico. Our largest fields in this region are High Island A-553, Ship Shoal 208/239, South Marsh Island 142, High Island A-334 and Ship Shoal 246. The majority of our interests in the Gulf of Mexico are non-operated. Production from our Gulf of Mexico properties was approximately 15 MMcfe/d in September 2005 when Hurricane Rita required all of these properties to be shut-in. Since October 2005, the majority of our Gulf of Mexico properties have returned to production with the remainder expected to be back on line in early 2006, subject to third party pipelines and onshore processing plants being returned to full operating status. We did not sustain any significant damage to any of our offshore properties in either Hurricane Katrina or Hurricane Rita. Our current estimated production from the Gulf of Mexico region is approximately 11 MMcfe/d.
In West Cameron Block 39, drilling operations are anticipated to resume in early January, after hurricane-related delays, on the 21,000-foot MD Lower Miocene test being operated by Norsk-Hydro. We own a 10% working interest (8.5% net revenue interest) in the well and anticipate reaching total depth prior to the end of the second quarter of 2006. This interest is not included in the package of properties in the Gulf of Mexico currently being marketed by us.
We are currently in the process of divesting substantially all of our Gulf of Mexico properties. Due to market conditions and other factors, there can be no assurance that we will receive acceptable offers for any or all of these properties nor can the closing date of this possible divestment, if any, be predicted.
In the Arkoma region, our properties produce primarily from the Atoka formation at depths of 2,500 to 6,000 feet. We own significant interests in the Hichita, Pine Hollow, Kinta, and Cedars fields in Pittsburg, Haskell and McIntosh Counties, Oklahoma. Our working interest in these fields is between 23% and 100%.
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We believe that the Pine Hollow field in Pittsburg County, Oklahoma has multiple drilling opportunities for the Company. We intend on participating with a 25% working interest in up to 25 horizontal wells in the Hartshorne Coal Bed Methane play in 2006. Additionally, we anticipate that Newfield Exploration will continue its development of the horizontal Woodford Shale play in which we have working interest ranging from five percent to 20%.
In the Hichita field in McIntosh County, Oklahoma we own an approximate 75% working interest in over 15,000 gross acres that are within the Caney Shale play. We intend on testing the Caney Shale with a horizontal well during 2006. In addition to the Caney Shale, we believe the Hartshorne Coal is prospective for horizontal development in this area and we are currently evaluating its potential.
We plan to spud the initial two exploratory wells on the 120,000-gross acre block we control in the eastern area of the Arkoma Basin during the second quarter of 2006. Both wells on our Flower Prospect (76% working interest, 60% net revenue interest) are planned to examine numerous potential objectives. The first well’s primary objective is expected to be the Jackfork formation at approximately 12,700 feet. The second well is expected to target typical Arkoma Basin Atokan objectives at depths between 7,000 and 10,000 feet.
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FORWARD-LOOKING STATEMENTS
The information contained in this 8-K includes forward-looking statements within the meaning of the federal securities laws.
These forward-looking statements include, among others, the following:
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| | • | estimates regarding future net revenues from oil and natural gas reserves and the present value thereof; |
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| | • | planned capital expenditures (including the amount and nature thereof); |
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| | • | increases in oil and natural gas production; |
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| | • | the number of wells we anticipate drilling in 2006; |
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| | • | estimates, plans and projections relating to acquired properties; |
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| | • | the number of potential drilling locations; and |
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| | • | our financial position, business strategy and other plans and objectives for future operations. |
Forward-looking statements are typically identified by use of terms such as “may”, “will”, “expect”, “anticipate”, “estimate”, “hope”, “plan”, “believe”, “predict”, “envision”, “intend”, “will”, “continue”, “potential”, “should”, “confident”, “could” and similar words or expressions, although some forward-looking statements may be expressed differently. You should be aware that our actual results could differ materially from those contained in the forward-looking statements. You should consider carefully factors that could cause our actual results to differ from those set forth in the forward-looking statements, and the following factors:
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| | • | the possibility that our acquisitions may involve unexpected costs; |
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| | • | the volatility in commodity prices for oil and gas; |
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| | • | the accuracy of internally estimated proved reserves; |
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| | • | the presence or recoverability of estimated oil and gas reserves; |
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| | • | the ability to replace oil and gas reserves; |
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| | • | the availability and costs of drilling rigs and other oilfield services; |
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| | • | environmental risks; |
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| | • | drilling and operating risks; |
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| | • | exploration and development risks; |
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| | • | competition; |
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| | • | the inability to realize expected value from acquisitions; |
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| | • | the ability of our management team to execute its plans to meet its goals; |
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| | • | general economic conditions, whether internationally, nationally or in the regional and local market areas in which we are doing business, that may be less favorable than expected; and |
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| | • | other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our businesses, operations or pricing. |
Additional factors that could cause actual results to differ materially from those expressed in the forward-looking statements are discussed in reports filed by us with the SEC.
Forward-looking statements speak only as of the date of this 8-K. All subsequent written and oral forward-looking statements concerning matters addressed in this 8-K and attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section. Except to the extent required by applicable law or regulation, we do not undertake any obligation to update forward-looking statements to reflect events or circumstances after the date of this 8-K or to reflect the occurrence of unanticipated events.
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