Filed by Forest Oil Corporation
Pursuant to Rule 425 of the Securities Act of 1933, as amended,
And deemed filed pursuant to Rule 14a-12 of the Securities Exchange Act of 1934
Subject Company: The Houston Exploration Company
Commission File No.: 333-140532
The following is a transcript of the Forest Oil Corporation earnings conference call held on February 27, 2007.
FOREST OIL
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Moderator: Patrick Redmond
02-27-07/1:00 pm CT
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Moderator: Patrick
Redmond
February 27, 2007
1:00 pm CT
Operator: Good afternoon. My name is (Molly) and I will be your conference operator today. At this time I would like to welcome everyone to the Forest Oil’s Fourth Quarter Earnings Conference Call. All lines have been placed on mute to prevent any background noise.
After the speaker’s remarks there will be a question and answer session. If you would like to ask a question during this time, simply press star then the number one on your telephone keypad. If you would like to withdraw your question, press star then the number two. Thank you. Mr. Redmond, you may begin your conference.
Patrick Redmond: Good morning. I want to thank you for participating in our fourth quarter 2006 earnings call. We have joining us today Craig Clark, President and CEO, and Dave Keyte, Executive Vice President and CFO. Before we get started, I’d like to take a moment to advise you about our forward-looking statements within the meaning of Section 27a of the Securities Act of 1933 and Section 21e of the Securities Act of 1934.
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All statements other than statements of historical fact that address activities that Forest assumes, plans, expects, believes, projects, estimates, or anticipates and other similar expressions, will, should or may occur in the future are forward-looking statements. The forward-looking statements provided in this press release are based on the current belief of management of Forest based on current available information as to the outcome and timing of future events.
Forest cautions that their respective future natural gas and liquids productions, revenues and expenses and other forward looking statements are subject to all the risks and uncertainties normally incident in the exploration for and development and production and sale of oil and gas.
These risks include but are not limited to price, volatility, inflation, or lack of availability of goods and services, environmental risks, drilling, and other operating risks, regulatory changes, the uncertainty inherent in estimating future oil and gas production or reserves and other risks as described in Forest’s 2005 annual report on Form 10K as filed with the Securities and Exchange Commission.
Also, the financial results of Forest’s foreign operations are subject to currency exchange rate risks. Any of these factors could cause actual results and plans of Forest to differ materially from those in the forward-looking statements.
Forest and Houston Exploration will fill - will file materials relating to the proposed transaction with the SEC, including one or more registration statements that contain a joint proxy statement prospectus.
Investors and security holders of Forest and Houston Exploration are urged to read the definitive joint proxy statement/prospectus if and when they become
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available and other relevant documents filed with the SEC as well as any amendments or supplements to those documents because they will contain important information about Forest Houston Exploration and the acquisition.
A definitive joint proxy statement/prospectus will be sent to security holders of Forest and Houston Exploration seeking their approval of the acquisition. Investors and security holders may obtain these documents free of charge at the SEC’s website at www.SEC.gov.
In addition, the documents filed with the SEC by Forest may be obtained free of charge from Forest’s website at www.forestoil.com or by calling Forest’s Investor Relations department at 303-812-1400. The documents filed by the SEC - that will be filed with the SEC by Houston Exploration may be obtained free of charge from Houston Exploration’s website at www.houstonexploration.com, or by calling Houston Exploration’s Investor Relations Department at 713-830-6800.
Investors and security holders are urged to read the joint proxy statement/prospectus and other relevant materials when they become available for making any voting or investment decisions with respect to the proposed acquisition. I will now turn the call over to Dave Keyte. Thank you.
Dave Keyte: Thanks, Pat. We’ve now reached a new record in our legal disclosure of five minutes and I think that we can certainly see why US is becoming less competitive in the capital markets.
All right, with that, welcome from Denver where the snow will return tomorrow. I guess after some warm weeks in January there still is a little winter left. Before we start, I want to update you on the status of the THX acquisition.
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We have been advised that the SEC will be reviewing our S-4, which will delay things 60 to 90 days. As previously disclosed, we still anticipate a late second quarter close, but we are now on SEC time, which of course we can’t control. But we did not get the no review we had hoped for and the accelerated closing. We are now back on the regular timetable we had anticipated.
To matters more closely at hand, 2006 was a good year for the industry but a great year for Forest. During the year, we hit several milestones. One, we had flat year over year FD&A costs, despite significant cost increases and shortages from the service industry.
We also reported record earnings for Forest’s 90-year history. And that’s despite shedding 40% of our production because of a $1 billion distribution of our shareholders in the first quarter. That is not a Remainco record. That is a Forest all in total record.
We generated and closed the largest capital markets transaction in Forest’s history with the issuance of non-recourse notes in our Alaska business to finance our core business in the US. We virtually replaced 100% of the proved reserves contributed to Mariner for the $1 billion distribution as well as our production for the year through our investment activities.
As a result of the activity in 2006, our shareholders now have the benefit of a more highly focused asset base with a more predictable lower risk and repeatable investment profile. We believe we’ve been investing capital wisely, allocating it to the highest risk weighted return projects. We also think that we’ve been operating our production in the most economic way possible as demonstrated by our very good cost metrics. And we think we’ve correctly
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financed our investments to drive more value to our equity holders in a tax efficient manner.
Four-point strategy embarked upon in 2003 was meant to lay the predicate for long-term rewards for our shareholders. And 2006 is the first year where highly visible and tangible results were demonstrated.
Now for a few comments on our latest quarter before Craig provides you with a recap of some of the exciting developments in the fourth quarter operations. In the fourth quarter we reported adjusted earnings of 40 cents per basic share versus 56 cents in ‘05. The decreased earnings reflect 12% higher production volumes, but they were more than offset by lower gas prices and higher interest expense and a higher deferred tax rate than in 2005.
Oil and gas sales were down 9% to $184 million compared to $203 million in 2005 due to a 36% decrease in realized gas prices. Sequential natural gas differentials improved 21% to $1.10 due to a decrease in NYMEX prices while sequential liquids differentials deteriorated 7% as Canadian differentials widened seasonally.
As previously release for the quarter, production was up 1% sequentially and 12% year over year. All in lease operating expense increased sequentially 8% due primarily to non-operated costs and workovers in Alaska. The increase, sequentially due to the Alaskan cost increases, was 15 cents per MCFE on a consolidated basis, so they accounted for more than the increase sequentially.
Year over year lease operating expense results were about flat. General administrative expenses continued their run, excluding stock based compensation. They were only $9.6 million in the first quarter versus $11.6 in ‘06. The decrease is primarily due to decreased insurance costs, but also
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demonstrates the ability of this company to rapidly adjust cost structure to fit circumstances such as the Mariner divestiture where 40% of our production left the company.
We believe we’ll be equally adept at cutting costs in the Houston Ex deal when it is closed. The tax rate for the quarter was in excess of 42%. The increased rate was caused by some adjustments to our state net operating loss carry forwards expiring.
Overall cash costs in the fourth quarter were down 1% from 2005 levels as decreased production costs and G&A expenses offset a rise an interest in cash taxes. This is a remarkable trend in this year. On a full year basis we reported earnings of $162 million. And as I said before, that is a record for any year in our last 90 years.
On our Remainco only basis, EBITDA was up 20%. Discounted cash flow was up - I’m sorry, discretionary cash flow was up 16% compared to 2005. Production was up 14% for the year driven by continued success at our big projects at Buffalo Wallow, Wild River, and in East Texas.
Production expense and G&A expense per unit were down 3% and 27%, respectively, for the year in a very tough cost environment. All-in cash costs decreased for the year a remarkable 4%.
Overall, 2006 was an exceptional year, particularly in the setting in which it was performed. Lab production costs in a rising cost environment improved all-in F&D costs in an environment of escalating acquisition costs, escalating rig costs, and decreased prices generating negative reserve revision, improved G&A costs in the year in which we shrank our assets substantially or in order to provide our shareholders $ 1 billion of value, and good overall
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and organic production growth generated without stretching our balance sheet. A good year for ‘06.
‘07 — the start in ‘07 continues the momentum from 2006. We have already announced the largest acquisition and the largest property sale in our history, which when combined, will result in an approximate net 2007 reserve replacement of about 400% at an estimated net cost of under $2.50 per MCFE without drilling a single well so far.
The result of these transactions will be to create an asset base with even more focus with a better cost structure and with a substantial inventory of low risk repeatable drilling opportunities to invest in. Much improved over where we started 2006.
The guidance that we published anticipated approximately a $5 million capex budget. This reflects a 15% reduction from 2006 level. And Craig will get into the details of that reduction in his comments. However, on a broad brush, we are attempting to prepare for the integration of THX. We anticipate significant cuts in their spend rate and a reallocation of capital between the two company’s projects.
As a result, we have continued to push the pedal to the metal on our large drilling projects, but have cut back on some of our up and comers to prepare for the acquisition. Production is expected to be between $320 and $340 million a day, up 3 to 10% driven from growth in the big three. I guess it’s now four, including Katy.
Gas differentials for the year are projected at $1.25 to $1.50. We have now split the liquids differentials into oil and NGLs to try to assist people in more accurately projecting our liquids differentials. Oil differentials are projected at
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$6 to $8 per barrel. NGLs are projected at 50% of NYMEX. This results in a blended liquids differential projection of 10 to $13 as is what we presented in our guidance.
G&A expense without stock comp expense is estimated at $38 to $42 million. Our stock compensation expense, which of course is non-cash, is estimated at $13 million for the year. FD&A on a per unit basis is estimated at $2.20 to $2.30.
Obviously all of these amounts will change when THX is acquired and Alaska is sold, but we’ll revise guidance at that time with what we believe to be an A report card now on the books for 2006. Let me turn it over to Craig for his comments.
Craig Clark: Thanks, Dave. And thanks to those who joined us today and earlier this year on our Houston Exploration acquisition announcement. We’re pleased to close the books on a very good 2006 for Forest.
In fact, 2006 may be remembered as one of the most successful years in our company’s history in terms of what we accomplished, a year in which we again took action to upgrade the assets in our company while providing our shareholders with a significant monetary dividend.
I’m extremely proud of our management team and employees and that they took action in many areas and didn’t sit on their hands just because commodity prices were favorable again in 2006. This is obvious by looking at the 2006 accomplishment in both acquisitions and divestitures and noting that we were never complacent about cost control. Our operating expenses and finding costs speak for themselves.
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I will break my remarks into three parts today. First I will cover our 2006 results followed by operations highlights, and then lastly we’ll comment on our 2007 plan that Dave gave guidance for.
For the year 2006, our major highlights are as follows - and I do mean major because every one of these accomplishments were big steps for our company. In terms of acquisition and divestitures, we completed or negotiated four transactions which will help transform this company.
Our innovative exit from the Gulf of Mexico in the Mariner transactions the first. The second is the East Texas Cotton Valley acquisition that was specifically designed to rebuild Southern. The split-out and separate financing of our Alaska subsidiary which makes it easy to sell in the future, and of course the recent announcement of the acquisition of Houston Exploration in early 2007.
We replaced reduction by 372% from all capital activities, 258% organically at very profitable F&D cost. We essentially replaced the reserves sold to Mariner in only nine months.
Our 2006 production, as Dave said grew by 14% while records were set in all of the big three fields, Buffalo Wallow, Wild River in East Texas but also for us in places like Katy, Tex-Mex, Martin and Ansell.
LOE was essentially was held in check and on a per unit basis actually decreased; a pretty unique accomplishment these days in the industry. We added undeveloped acreage in all our growth areas. Some of this is highlighted in the individual areas in the operations release.
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While our new ventures group has established an excellent position in several unconventional plays, most notably in the Barnett Shale where they’ve had first sales.
We took over complete operations of Katy Field from Exxon just like an acquisition. We took over operations from them in August and we had our land yard drilling subsidiary that now has 11 rigs with a 2006 footage estimated at approximately 700,000 feet drilled mostly for Forest Oil.
Expanding on some of these highlights in the order I’ve just mentioned them, we have to start with our reserve replacement success. The 372% all in reserve replacement ratio and 258% organic replacement ratio are the best we’ve done recently. The $2.15 per Mcfe all in finding cost and on the organic side $2.08 per Mcfe; are favorable, as well, especially considering we projected in mid-2006 flat F&D cost despite continued industry cost pressure.
We also did this without increasing our proved undeveloped location percentage and were able to offset downward revisions of approximately 40 Bcfe due to lower gas prices with our improvements.
I want to note that we were more than able to offset the revisions due to gas prices, as just everybody saw with our cost control, field studies, well performance and the acquisitions exploitation work that we always highlight in our look-backs.
Let’s be clear that our revisions category was not adding PUDs, but it came from the hard work from our business units staff. I guess this is another reason that cost control really matters, as well.
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In terms of capital spending, we were very close to our revised guidance at $589 million for the year on F&D activity. We drilled a total of 382 gross wells, 146 net wells at the highest I’ve seen since I’ve been here, 98% success rate; an all-time high in terms of net well.
Be advised the gross well counts includes 149 gross wells drilled in the low 2% San Juan Basin units. And if you remember we traded part of that late year. So we had more activity on the net well side because of the less low interest San Juan wells.
Folks now get some idea of the quality of our drilling inventory going forward with the 98% success rate. We also performed over 500 additional operations projects in 2006 which was the major source of our positive reserve revisions in the business units.
Overall, 2006 was a good year in terms of reservings. I am a little shocked by some of the industry finding cost numbers I read about lately.
But let’s be clear about our strategy. If drilling is cheaper, we drill. If acquisitions are cheaper, you can acquire. Fortunately, the past few years we’ve proven Forest Oil can do both well.
Our Houston Exploration acquisitions metrics, in fact, had been cheaper than all recently announced asset deals and quite frankly cheaper than a lot of announced F&D costs for 2006.
Our annual net production as Dave mentioned for the year increased 14% year-over-year to an average of 310 million equivalents a day. Our big three growth drivers were performing as we projected a year ago and when we
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acquired them with one exception, the East Texas acquisition, is ahead of the forecasted production.
We did see some down time in late 2006 and now in early 2007 which was a result of the severe winter weather and snow or ice. This affected our field operations with things like well or pipeline freeze-ups and the inability to move rigs — this was the biggest issue — from wells to well on icy roads in the mid-continent and Texas areas.
Recent refinery fire at Valero, McKee refinery in the Texas panhandles has cost some shut-ins in the mid-continent for us and others most notably our Buffalo Wallow field due to high crude or condensate tank inventories since most of our crude went there and Cushing is now backed up.
We have highlighted this in our 2007 guidance. It probably hurt our fourth quarter production by 2 million to 3 million a day in terms of the weather, however, even with all the late 2006 downtime like the snow, we still pretty much hit the mid-point of our guidance.
Another bright spot in 2006 was our cost control in the area of operating cost. On a per unit basis, no matter how you slice and dice the categories, lease operating expense which includes work-overs, total production expense, which include taxes, our total cash cost, our 2006 number were below full year 2005. This was quite an accomplishment for our business units and field personnel.
I do believe in the theory that starting our cost control initiatives early was the key to our successful cost control efforts in 2006. And as Dave highlighted with each quarter, we’ll tell you what caused the fluctuation sequentially. In the fourth quarter it was obviously Alaska non-operating properties.
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Now that we’ve held the line on cost control in 2006, we can now lead the way down on future reductions if service prices moderate in 2007.
Our project focus cost initiative started several years ago is now winging its way to Canada next and then on to the newly acquired Houston Exploration fields upon closing.
Also with the planned sale of Alaska and the addition of the Houston Exploration gas assets, our LOE per unit should improve in the combined company portfolio even more.
I will now cover the operations projects most of which were covered in the press release.
In 2006 in the Western Business Unit, they drilled 265 gross wells adding 99% success rate. Still trying to find where that dry hole was. As I noted earlier, 149 of those gross wells were the low interest San Juan wells. However, be advised that most of the net wells and the big gross wells was Buffalo Wallow.
We drilled 13 more in the fourth quarter at Buffalo Wallow bringing the total for 2006 to 57% at 100% success rate. We have yet to drill a dry hole at Buffalo Wallow. In fact, we’ve recently drilled our 100th well at Buffalo Wallow early this year.
We had another record quarter in terms of net production despite the weather at 40 million equivalents a day, and we increased our gross acreage throughout 2006 37% to the current 45,000 acres.
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As mentioned last quarter, we’ve ventured south of the main field to the deeper part of the play and we’re two for two in terms of completions. We call this the Frye Ranch area, and the wells are highlighted in our release at 4.4 million a day and 2.7 million a day.
Throughout our last year of drilling at Buffalo Wallow and Frye Ranch, we have now identified drill sites and increased this from 400 at the end of last year to over 650 locations at the end of 2006.
What we thought was a 5-year inventory has now increased to 7 to 10 years using the current rig program.
We’re even seeing some horizontal drilling surprise in the Granite Wash by industry north and east of us, similar to what’s going on in East Texas. Add this to the deeper objectives we’ve talked about and the undeveloped acreage and we’ve established a bona fide legacy asset for Forest in terms of the Buffalo Wallow area.
In the greater Haley/Vermejo area, we increased our acreage last year over 50% currently 46,000 gross acres. During the fourth quarter we took over an old well bore for salvage from an offset operator, re-entered it and made an Atoka well at 1.1 million a day; pretty low cost operation.
We still have one exploratory well, the well we’re redrilling and three more reentries identified in 2007. We will continue with the reentry program, well bores permitting, and finish shooting our large 3-D seismic by mid-2007. We’re about halfway done. We will spend less in Haley/Vermejo in 2007 since we won’t do as many grass roots of drilling wells until the seismic can be interpreted midyear.
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In the Central Permian Basin in West Texas, our shallow oil and step-out drilling continue to be successful with record rates for us at Tex-Mex and Martin fields. The oil rates from these shallow wells are 50 barrels a day up to a real good one at 376 barrels of oil a day.
We did acquire additional offset acreage at Tex-Mex and as we mentioned last quarter we closed our acquisition of Conoco’s 50% in the Martin field and we ramped up drilling in both areas.
We now have identified over 1,200 drill sites in the Central Permian Basin primarily in these fields so we’ve got a long-term inventory here just like Buffalo Wallow. None of these approximate 1,200 locations are currently booked.
In the Southern business unit, they drilled 56 gross wells with 89% success rate. Let’s start with the East Texas Cotton Valley area where net production reached a record for us of 21 million a day. When we made this acquisition, we told people we would average in 2007 approximately 20 million a day, so we’re already at this rate and therefore ahead of our forecast.
We have increased production 54% since making this acquisition on April 1 of last year is when we took over. We began using the new Forest low pressure gathering system in January, as promised, which increases our net back pricing in NGL recoveries. Dave talked about NGL differentials but remember we’ve added quite a bit of NGL extraction capacity here and in Canada in ‘06 and on into ‘07.
We’re also in the process of starting our first horizontal Cotton Valley well in East Texas. At yearend, our East Texas identified drill sites now stood at 250
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locations; those are all vertical at this time. And this is the area where we think we have the best fit with the Houston Exploration assets.
I am glad we used East Texas as the acquisition to rebuild Southern when we did last year. It would be pretty tough to get in now.
In only five months of operatorship in the Katy Field, we took over in August in South Texas. We’ve increased gross production from 13 million a day from early in ‘06 to 20 million a day currently.
The shallow Frio program, they’re only about 4,000 feet added five wells which average now 900 mcf per day.
We recently completed our first grass roots Middle Wilcox well which tested 2.5 million a day and that is after frac and the field is the Middle Wilcox. We are currently drilling a second Middle Wilcox well which will be followed by a nine-well reentry re-completion program in the Wilcox followed by some Yegua activity above it.
Remember we had quite a few set-in well wars when we took over Katy. We plan to focus on the Yegua after the Wilcox and the Frio, as well.
We have identified approximately 20 drill sites thus far in the Wilcox. We’re using our new Lantern rig 10 for this activity because it was built in Houston; this field is nearby, so we’re just getting started here, but this field has already joined the ranks as Dave mentioned of our growth assets, the big 4 in 2007.
Certainly more capital will be allocated to Katy in 2007. It doesn’t hurt that the same geologic formations in Katy are what most of the Houston
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Exploration operations assets are completed in in South Texas. The experience will serve us well.
In the Barnett Shale in Hill County Texas we had our first well go on production and completed at a rate of 2.1 million equivalents a day. It was even more slick that we had the pipeline there, we cleaned the well up right into the pipeline, but note this well is cleaning up the frac fluid still upcasing while flowing against line pressure so this pipe might improve.
This should not come as a surprise since our acreage has been essentially surrounded with wells that by our calculations are coming in at around 1.7 a day to 3.7 million a day.
We believe this area, the Barnett Shale has good shale thickness - came in as predicted. Gas content - remember we drilled a vertical well early, and the added benefit of a good barrier below us to help us stay away from the water.
We did take over operations on the second drilling well, which is currently drilling. Right now we plan to share a rig with our East Texas Program because we had those rigs available, particularly Lantern rigs, so we may have to dedicate a rig to the Barnett Shale for this full time based on the early success. Several of our rigs will fit this application both vertically and horizontally.
Since we have essentially been surrounded in Hill County now, we’ve now identified over 100 potential locations horizontally in the Hill County area on our gross acres position; I think it’s around 14,000 acres.
As a side note on the large Sabine acreage block in South Louisiana, Southwest Louisiana is 150,000 gross acres, we had a nice discovery which
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came on land early this year at 5.2 million equivalents a day; however, let me remind you that we’re shooting a proprietary 3D site and survey on the north part of this large acreage block that’s also expected to be finished in mid-2007; a lot of Geophysicists are going to be busy I guess this summer.
In the Canadian business unit, in 2006, they drilled 60 gross wells with 100% success rate. I can’t remember the last time these guys drilled a dry hole, so they’re kind of on a run. The Canada business unit wins the Organic Growth Award in 2006; their production increased 18% for the year.
Certainly, the Wild River Field led the way in production growth with another quarter of record production at 37 million equiv - 37 million a day equivalents in the fourth quarter. We averaged 3 million a day from the wells drilled in the fourth quarter, our best average to date. This can be attributed to the improved frac techniques.
We had to perform major compression repairs during the fourth quarter at Wild River and plus continued construction in the new processing plant which will improve our margin and NGL recoveries beginning in the second quarter of 2007, so there’s those NGLs again; so they had a lot of construction activity at Wild River starting in December.
Wild River is a perfect example of us identifying drill sites on our potential locations maps, actually drilling them as opposed to making projections on potential they’ll never achieve and then seeing it in the production curve; I’m pretty proud of this project.
The Sundance/Ansell area is shaping up nicely since we get to drill a dry hole in the last two exploratory wells gilded 2 and 2.6 million a day. The predictability now seems to resemble Wild River. We added five sections of
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land in the fourth quarter for the deep price, raising our gross acreage to near Wild River’s acreage to 26,000 acres.
The Hinton area which is further south of Ansell and Wild River has yielded our best well to date in this field. A second exploratory well was completed at 6.5 million a day and will be placed to sales in early 2007. As a reminder, we hold 9,000 acres in the Hinton area.
So Canada had a pretty good year as did the rest of the business units. It should be mentioned that all Remainco business units grew reserves in 2006 and all but Alaska grew production, both in total and organically.
About our 2007 plan, I’m going to talk strictly about Forest standalone since we’ve not closed The Houston Exploration acquisition yet. We have reduced our E&D capital spending by approximately $90 million or 50% as Dave discussed. We did this mainly to stay within our cash flow but also to avoid overpaying for service costs as we expect service prices to moderate somewhat compared to 2006. Remember, this is a point in the four-point strategy. This does not imply our inventory is falling short, simply to remain disciplined in spending so we can go up from here if needed.
We truly believe that the key to good control on F&D costs in 2005 and 2006 was our capital discipline. We demonstrated this the last several years and we hope to do it again in 2007.
The major spending in order - in this order will be Buffalo Wallow, Wild River, East Texas, and Katy. We are not reducing spending on these fields in 2007; in fact, these four fields alone will take almost 60% of our capital budget and, of course, as you - we’ve noted, Katy gets a big increase.
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It should be no surprise that these fields comprised the big four growth assets in 2007 with I would guess the Barnett Shale, Ansell in Canada, and Haley pressing them for the up and comer category. This is the kind of disciplined capex program we expect to employ on The Houston Exploration assets after we close in the second quarter. We do plan to use the Atlanta rigs on The Houston Exploration assets as well.
We would like to see well cost in general decrease 10% to 15% in 2007, but please note we’re not including this savings in our capital plan. This capital program will generate organic growth in 2007, basically close to the same growth ring we got initially a year ago despite the lower capital budget. Be aware, these numbers do include the Alaska business unit for all of 2007 in both production cost and capital.
The next big focus in our 2007 plan will be continued cost control. Note that we guided lower per unit operating expenses in 2007 just like we lowered our guidance again in mid-2006.
Obviously, the major - the new major objective for 2007 is to close The Houston Exploration acquisition and fill our Alaska-producing assets. This is a lot of work but we believe again would upgrade the asset base of the combined company. The Alaska data room will start in mid-March and bid to produce sometime in April 2007.
So 2007 gets started with great fanfare with The Houston Exploration announcement. We now estimate that we ought to have over 5,600 projects in inventory on the combined asset base which could potentially yield as much as - as potential of 2.9 Tcfe.
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We certainly don’t have to worry now about turning around the hand we were dealt from several years ago. Folks, this is no longer a turnaround story. This is about moving forward and taking the next step in creating value. In fact, taking the next step is the theme of this year’s Annual Report, and you all see the footprints. We’re excited about 2007 and we’re anxious to welcome The Houston Exploration people and asset into the fold.
Thanks again for listening to our conference call today and for your support. Operator, we’re prepared to take the questions.
Operator: At this time, we would like to remind everyone, in order to ask a question, please press star, then the number 1 on your telephone keypad now.
Your first question comes from Subash Chandra.
Subash Chandra: Yeah, hi. Good morning. I was wondering if you had your PV10 schedules for 2006; if specifically, if you had your pretax PV10 number?
David Keyte: Yeah, I think it’s, what, 3.3 billion, Mike?
Michael Kennedy: Correct.
David Keyte: As pretax.
Subash Chandra: Okay. And do you have the future net revenue number by any chance?
David Keyte: Not handy, no.
Subash Chandra: Got it. Okay. A couple questions, first on Vermejo and Ansell. What are the current production rates?
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Craig Clark: Ooh, I don’t know. I think the - I know we don’t operate Ansell. Haley I think is in the low 20s…
Subash Chandra: Okay.
Craig Clark: …for gross. But I don’t know Ansell, we don’t operate that.
Subash Chandra: Okay. And at Ansell, I think you were just as curious at production history from wells you have drilled as you are for well results, you know, for the wells - one you just announced. Any comments on kind of the production history, decline rates, and so on on the wells you drilled thus far, what it might say for future drilling?
Craig Clark: Well, my first concern is did it have the repeatability of Wild River and so far so good. My second concern was if you remember, we’re not completing the multiple zones at Ansell, that sometimes we get as many as four zones at Wild River and, therefore, would one zone by itself support that program. Probably had a - that - making the kind of single well zones that are equivalent to maybe the combing those zones at Wild River have kind of sort of given me some confidence that we’re okay. But the wells have been on about a year.
Last quarter, I think they drilled a six or seven million a day well and, obviously, you’re going to drill as many of them as you can get your hands on. They’re not in the development phase though, Subash; they’re still trying to delineate one well per section. If we get to go offset, I hope we offset that seven million a day first. But it looks like they’re doing it on a per well basis as good as average and, of course, we haven’t drilled a dry hole yet.
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Subash Chandra: Uh-huh. Okay. And Barnett, any more flavor for maybe the pace of development and what this well might say for the acreage that you have?
Craig Clark: Well, the pace of development is a little bit because of the drilling rig not performing and then we changed it out and did it again and we operate. I think the pace of development could be accelerated.
But remember, we kept our Atlanta rig and other rigs in reserve in East Texas in case we needed to yank one over there which is exactly what we’re doing. So we have the flexibility to increase the pace. The pace initially was a one-rig program going from well to well and that’s what we got budgeted right now.
Subash Chandra: And so there’s no other constraints to the program other than that?
Craig Clark: No. Now there is some 3D required on our acreage out West and South, but you’ve got enough to keep a rig busy for a while. And to know we’re not waiting on pipeline, we didn’t on this one. Remember, we picked this acreage for pipeline access in part.
Subash Chandra: Right. And one final one, any update on the sale of your New Albany position?
Craig Clark: I haven’t announced the sale of our New Albany position. I think we drilled a couple of wells over there and everybody else drilled a couple of wells. We took notice. And we wanted to see all the data from the new completions and fracs to go with ours. And so we are sharing information with two other operators. We haven’t announced the sell of the Kentucky position.
Subash Chandra: Oh, got it. Okay. Well, thank you very much.
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Craig Clark: Okay.
Operator: Your next question comes from Brian Singer from Goldman Sachs.
Brian Singer: Thanks. Good afternoon.
Craig Clark: Hey, Brian.
Brian Singer: I just wanted to follow-up on the Ansell question. How much did your Ansell recent exploratory wells cost? And I guess if you just take a step back, it sounded like from the previous question, that you were cautiously optimistic, and take a step back and look at the play overall. Where do you think we are and when do you think you’ll have greater confidence or lack of confidence?
Craig Clark: Well, I think our - the operator had a press release I think it was last quarter that announced there were roughly 25 locations and I believe that’s four offsets to the six wells drilled roughly. So, you know, with each well, you’ve got offsets, so you’re probably starting to get closer to development than you were a year ago. So the confidence is good because all the sections are proving up and the wells seem to be coming in on average.
In terms of the well costs, they’re a little more expensive than Wild River to drill but less on the completion side simply because of the lack of multiple zones being completed and I believe that’s about 2 to 2.5 million a piece, say 2.5 million.
Brian Singer: Great. And you highlighted the additional locations you have in the Permian Tex-Mex Central Midland Basin, what do you see as the impediment towards increasing drilling over there?
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Craig Clark: Really nothing. They’re land and rig so it’s up to us. But we’ve been doing - with - well, with two things, with - we’ve been stepping out, as you know, in any water flood in these fields, some of these fields are not flooded. We wanted to find the oil in place, so we’ve been progressively stepping out in Tex-Mex which was the new Permian acquisition about two years ago and then you go to the in-fielding next.
On Martin, we bought our partner out or traded our partner out so we could get more work done there; that was probably the impediment and so get after it.
Brian Singer: Great. And I don’t recall if you put out a location number in the past with regards to the 1,200 locations there. Was there something you saw very recently that’s given you increased confidence there?
Craig Clark: Well, actually at the Analysts Conference last year, we put a location count out that was lower than that and with the new acres, the drilling, and also the field studies, we increased that and these are drilling down spacing the 40s and 20s like you typically do in East Texas and hope that water flooding is coming afterwards. But we did the studies but we also drilled, I don’t know, 50-60 wells on the step-out that helped us as well. And most of those 1,200 are in-fill and they’re all not booked.
Brian Singer: Great, thank you.
Operator: Your next question comes from David Tameron.
David Tameron: Hey, good afternoon. A couple questions. If you could get back to the Barnett, you know, with this well, I mean what are your targets going forward? I mean
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are you targeting 2 Bs a well, you know, well cost of 2 million; I mean what are your ranges now that you’ve drilled the well out there?
Craig Clark: The well cost was high because of the rig performance but typically, we were in the pre-drills at 2 - actually less than 2 million a day but most everybody in this part of the world run 2 million a day and 2 Bcf type wells with well costs around 2.5 million.
David Tameron: Okay. And then Craig in Buffalo Wallow you mentioned a couple of numbers that I missed. You said drilling inventory is now at 7 to 10 years. How many locations did you say, did you mention?
Craig Clark: Six fifty.
David Tameron: And that’s up from...
Craig Clark: Four hundred.
David Tameron: Okay. A year ago.
Craig Clark: Yeah.
David Tameron: All right. And then you briefly alluded to it, the horizontal well had just been drilled. You know, I asked them on the conference call. They did not deny the 6 million a day was an accurate rate. Have you seen — is that an isolated incident? Or have other people drilled horizontals out there? Kind of what’s your plan going forward? Can you give — just expand on that a little more?
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Craig Clark: We have a small interest in that well. But I look for Chesapeake to do the release on that. There is activity by several operators but we’re in one of their wells on the Oklahoma side of the border.
David Tameron: Okay.
Craig Clark: I don’t know the specifics of it. But they operate it. We have a small interest in that well derived from some of our ownership in years past. So we get to see it.
And then there has been some activity on the border. There’s also activity and even some divestiture packages north of us that’s in one of the five members of the Granite Wash. I think they’re named by letters — A, B, C, D, E, F. And what they’re doing is they’re picking the best one and going horizontal. And the rights have been better than the averages that we average. Better than — I think the average somebody said was 3 feet a day, but I can’t confirm that. But there’s actually some divestiture packages out there now.
The bottom line is you can probably pick the best zone in the Granite Wash. Will that be a better well than commingling 5? I don’t think this is probably as good as East Texas because all of the 5s seem to be of equal quality. But we’re just going to watch it because it’s north of us and east of us right now.
David Tameron: All right. And then jumping over to Katy. Remind us again when you bought this acquisition obviously you talked about the Middle Wilcox or when you took over operatorship you talked about the Middle Wilcox. And you said you drilled — the well you drilled 2-1/2 million a day. How does that compare to your expectations? What does that well cost? You know, where are the recompletes going to cost versus re-entry? I mean, is it all — can you just give us more detail on that?
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Craig Clark: Yeah, well let’s just take it from the top down. The workovers, recompletions and re-entries out of the 75 existing wells are a couple hundred thousand a piece, cheap, cheap, cheap. And we’re trying to use existing well bores although we’ve made a concerted attempt to try and restore those well bores. And that’s part of the initial production increase we had last quarter.
The second thing is drilling wells with tubing less completion. In the frio they’re 4,000 feet. They cost $300,000. And you perforate them and no stimulation is required. That’s the 900 Mcf per day average well.
The next meat is the Yegua. It’s about 6,000-7,000 feet. That’s where most of the field made 6 Tcf out of. And those would be cheaper but they don’t require, excuse me, more expensive but pretty cheap and they do not require stimulation as well. So that’s a conventional gas play from about 7 or 8,000 foot up. And there’s a lot of bypass pay.
The Middle Wilcox well out there is about 10,000 feet. They cost around $2-1/2 million. They do require fracing but not in stages. And we were running those economics on 1-1/2 million a day on average. And I don’t know the reserve number. But the 2-1/2 is, you know, one of our better wells.
David Tameron: All right. Good recap. And then finally you gave out mid-year reserve numbers in December of ‘06. You come back and despite what I would assume are some pricing related revisions you still manage to hit those number of hits your up and down. Is the implication that if we had no more pricing the number would have been a lot higher? Or were you intentionally conservative? Can you guys just reconcile that for us and then talk a little bit about how you’re booking, you know, puds as far as when you drill a location you book a one offset pud or do you book more than that?
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Craig Clark: Well back up. We were talking about F&D cost. We weren’t — we didn’t release reserves mid-year.
David Tameron: Okay.
Craig Clark: But we’re trying to say we’re going to be flat based on the optimism that we had more than half the year. And so, you know, we hit that and that had cost control in it as well. And most people, you know, I sent a rig or two home late in the year just because they were going up in price. But capital discipline was part of that as well.
Secondly, on the revisions I believe we had about — oil price didn’t really change that much during the year. But on gas we lost about 40 Bcf on price that you could add that back in there. However I really can’t cipher that out. I know some people are doing that to explain their high F&D. In our case if we were to cut LOE we may have offset and mitigated that somewhat or exploited the property or whatever.
So yeah, we would have done slightly better. But we were able to, you know, hold the line. And then in terms of conservatism I’m naturally conservative. And in terms of puds we drill one book one.
David Tameron: Okay. So first at Buffalo Wallow you drill one well you book one pud so in theory there’s more puds out there than what’s showing on your book today.
Craig Clark: Not that we booked. But you have...
David Tameron: Yeah.
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Craig Clark: A lot of the locations we’ve got in the company may qualify but we drill one, book one, and tried to keep our inventory in front of us instead of behind us.
David Tameron: Okay.
Craig Clark: We try to do that on acquisitions as well.
David Tameron: Okay. And one, two more questions and I’ll shut up. And I guess, Dave, for taxes you’re at 42%. What’s a good run rate for ‘07 for standalone Forest?
Dave Keyte: I think 37% or 38% is just fine with the typical 1% cash rate.
David Tameron: Okay. And then is there any hang up in selling Alaska as far as it relates to THX or is that free and clear? No — there’s no strings attached between those two.
Dave Keyte: There’s no relationship between the two.
David Tameron: Okay. Thanks.
Craig Clark: Yep. Thanks, Dave.
Operator: Your next question comes from Ray Deacon.
Ray Deacon: Yeah. Hey, Craig. I had a question about the Sabine wells. What was the target there, what formation, and how many wells do you think you’ll be drilling there this year?
Craig Clark: Gosh, I don’t know the number of wells. There’s going to be some analysis to this one. It was in the Yegua.
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Ray Deacon: Okay, okay.
Craig Clark: Some people would call it upper Yegua pressure, similar to what we’ve targeted in the past. And there’ll be — there’s some offsets for it. We don’t operate the well. But we pulled our unit with us, and our partners.
The — you’re not going to get a lot drilled until you get that big 3D, because that thing covers about the north half of that 150,000 acres and it’s proprietary.
Ray Deacon: Right.
Craig Clark: So, you know, and you might get a couple more drilled by the end of the year. But I’m not targeting any locations until I get to see that seismic survey.
Ray Deacon: Got it. Okay. And are you curtailed at all in really in Canada. Cabot had talked about having to field some transportation out and being curtailed. What — how high do you think you could get your Canadian production?
Craig Clark: I’m not — I don’t know about how high. I can’t tell you we’re not curtailed.
Ray Deacon: Okay.
Craig Clark: However the...
Ray Deacon: Really I’m talking about...
Craig Clark: The Wild River expansion, for example, is to just accomodate the high rate.
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Ray Deacon: Right.
Craig Clark: But I want to emphasize having that infrastructure up there is a strategic advantage some time in, you know, it may be as important to have the pipeline in the road as it is to have the acreage.
Dave Keyte: Cabot’s remote, though.
Dave Keyte: Cabot’s remote from things like pipelines.
Craig Clark: I’m not familiar with their work except the Hinton area that they’re active near us is — I think they waited on pipeline for some time. But us and our partner had it put in pretty quick. We’re in that area, so we may have been just lucky. But we’re in that area with them. But we don’t have any curtailments elsewhere.
Ray Deacon: Okay.
Craig Clark: That I’m aware of.
Ray Deacon: Got it. All right. And it sounds like you’re planning to keep at least one rig busy in the Barnett for the foreseeable future. Is that...
Craig Clark: At least the plan with our partner was to take — we’ve got to find a good rig. We haven’t got there yet. But I bet it has a Lantern logo on it. But the — to take that rig and go from well to well and out the pipelines there and on the south portion there’s some 3D. And by the time you’re ready it’s just fortuitous and the other — our other competitors have been a lot more public. We’ve been surrounded 360 degrees by activity.
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So it’s just a matter of how fast you want to drill the wells and where the pipeline is located. But I was pretty adamant. I wanted that well on and flowing into the pipeline instead of waiting. And we accomplished that goal with the other operator cooperating.
Ray Deacon: Okay. Got it. Just one more quick one, a couple of recent conference calls I feel like I’ve heard numbers all over the place on a Cotton Valley well, you know, between 1.8 and .8 Bcf. What do you encounter on average with just a straight vertical Cotton Valley well?
Craig Clark: It does vary by that. But I believe our average was somewhere around 1.2-1.3 Bs equivalent.
Ray Deacon: Okay.
Craig Clark: We made the acquisition, but it does vary. There’s a couple of B, wells in there all the way to 8/10 of a B, which is probably stretching a little bit on economics, unless it’s shallow. We’re in the heart — we’re in the shallower part of the basin so we’ll see a little lower Wilcox. We are extracting liquids which helps.
We have grabbed a Bozier in a few because it’s kind of like the Atoka at Buffalo Wallow, which might give us another 1/10 or 2/10 of a B. But it’s not mind boggling. And of course we’ve seen greater variation in the horizontal rates that ranged from 1 million a day to over 10. Boy that’s a wide range. So let’s be very clear. We’re going to pick our best rate area to drill our horizontal in, not the worst.
Ray Deacon: Right. Got it. And you don’t feel like the Petit is attractive on your acreage?
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Craig Clark: Oh it’s there. I’m just telling you. Most of the — if you look at our math to the southwest part of the Central East Texas basin it feels like Blocker and Carthage and Willow Springs, that acreage is pretty much on the line on a string between Tyler and Shreveport. To the southwest is where most of the new Petit activity has been. And that’s of course a fractured limestone in fields like Minden and in counties like Rusk and Cherokee, in those areas.
Ray Deacon: Right.
Craig Clark: Houston Ex has a position there as well. Our position is not as large down on the south. However, the Petit is above us when we’re going to the Cotton Valley.
Ray Deacon: Okay.
Craig Clark: We don’t have any Petit production in the Forest operated assets currently though.
Ray Deacon: Okay. Got it. And you didn’t quite book as much, a question on reserves. You didn’t book as much as THX announced in their year-end numbers. And I guess the haircut came, you know, given the comment you made in the (S-4) came out of the Uintah so you don’t see the economics being I guess as viable there. Is that...
Craig Clark: Well the — our haircut wasn’t a haircut. We’re talking about haircutting capital up there in terms of the economics. But our reserves were based on 9-30 estimates, including 9-30 pricing. They had the obligation to close their year-end as they saw fit. So they closed their year-end and that would reflect some of their fourth quarter activity. And I’m encouraged that their number was higher than ours.
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Ray Deacon: Got it. Okay.
Craig Clark: So we’ll take a shot at those wells and the number when we have some performance when we close it looks like in the second quarter. Suffice it to say I’m encouraged that they were higher than we were.
Ray Deacon: Okay. Thanks a lot.
Craig Clark: Okay.
Operator: Your next question comes from William O’Malley, Jr.
William O’Malley: Hi, fellows. Could you re-identify the number of acres that you have in the Barnett, who your operators are, and how many wells you plan on drilling this year?
Craig Clark: In terms of the Barnett we’re the operator currently of our acreage out there.
William O’Malley: How much?
Craig Clark: And in terms of the acreage, I believe it’s around 20,000 gross acres. And most of it’s in the east side as opposed to the west side.
In terms of wells that we would drill this year, if you took a one rig program that would be 12.
William O’Malley: And who are your partners?
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Craig Clark: Just one partner currently, Westside who is the operator of the North part of the Hill County acreage. And that’s it. Everything else is 100%.
William O’Malley: Thank you.
Operator: Your next question comes from Duane Grubert.
Duane Grubert: Yeah, Craig, in terms of giving investors confidence about the pace of integrating Houston Ex, I was wondering if you could comment a little bit about the Wiser experience and if maybe there was anything about the Wiser integrations have went slower than you had hoped. Or really at the root of my question, what did you learn from integrating other assets that might impress us in terms of the pace of integrating Houston Ex going forward?
Craig Clark: Well with Wiser we were on schedule. It was pretty easy. And we targeted when we would integrate their Dallas office, move their Dallas office to Denver or West Texas. In their Calgary office we actually moved into their office. So there were — we were on schedule, in fact on rate, above schedule.
So I think that experience serves us well as we’ve highlighted on the road, coupled with the fact that we reduced our operating cost by 40% and their G&A by 70%. I will note that Calgary per Wiser was easier than Dallas because we didn’t close Calgary. And therefore Houston expiration should be somewhat easier because we’re going to inherit their Houston office and keep it open.
So you don’t have the moving hassles. It is big nonetheless. But I think the integration will be easier because we’re going to keep their Houston office. And they have a small Denver office that can be consolidated.
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And I’m not exaggerating. It is across the street. We’ll just welcome them across the street to our coffee pot. So I have a lot of, you know, with the Houston office being left open and the fact that we wanted a Houston office I think the integration will be somewhat easier, although the size may take longer. But there were no issues with Wiser and we hit most of our numbers as well.
Duane Grubert: Real good. Thank you.
Operator: There are no further questions at this time.
Patrick Redmond: Thank you. This concludes our conference call. I want to thank everybody for their interest and participation in our call. If you have any further questions please feel free to contact us.
Thank you.
Operator: Thank you for participating in today’s conference call. You may now disconnect.
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