Southwestern Energy Company Fourth Quarter 2006 Earnings Teleconference Call
CORPORATE PARTICIPANTS
Harold Korell
Southwestern Energy - CEO, President, Chairman
Richard Lane
Southwestern Energy - President, E&P
Greg Kerley
Southwestern Energy - EVP, CFO
CONFERENCE CALL PARTICIPANTS
Bob Christensen
Buckingham Research - Analyst
Gil Yang
Citigroup - Analyst
Jeff Hayden
Prichard Capital Partners - Analyst
Scott Hanold
RBC - Analyst
Amir Arif
Friedman, Billings, Ramsey - Analyst
Michael Scialla
A.G. Edwards - Analyst
Joseph Allman
J.P. Morgan - Analyst
Marshall Carver
Pickering Energy - Analyst
Richard Moorman
Capital One Southcoast - Analyst
Jason Gammel
Prudential - Analyst
Ken Carroll
Johnson Rice - Analyst
Travis Anderson
Gilder, Gagnon, Howe - Analyst
Operator
Good day, everyone, and welcome to the Southwestern Energy Company Fourth Quarter and Year-End 2006 Earnings Conference. At this time, I would like to turn the conference over to the President, Chairman, and Chief Executive Officer, Mr. Harold Korell. Please go ahead, sir.
Harold Korell - Southwestern Energy - CEO, President, Chairman
Good morning, and thank you for joining us. With me today are Richard Lane, the President of our E&P segment, and Greg Kerley, our Chief Financial Officer.
If you've not received a copy of the press release we announced yesterday regarding our fourth quarter and year-end 2006 financial results, you may call [Annie] at 281-618-4784, and she'll fax a copy to you.
Also, I would like to point out that many of the comments during this conference call may be regarded as forward-looking statements that involve risk factors and uncertainties that are detailed in our SEC filings. These forward-looking statements are subject to risks and uncertainties, many of which are beyond our control. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.
Well, as we look back at 2006, it was an amazing year. For the fourth consecutive year, we set new records for annual production volumes, year-end reserves, earnings, and cash flow, and our balance sheet is in great shape.
Despite operational challenges, we successfully grew our Fayetteville Shale production volumes from about 9 million a day to 100 million a day by year-end. Today, our Fayetteville Shale volumes are approximately 120 million cubic feet per day gross and could reach up to 300 million cubic feet per day by year-end 2007.
During the year, we also created our own drilling company, which now operates 13 newly built drilling rigs in our Fayetteville Shale program. This allowed us to go from three rigs operating in the play at the beginning of the year to 19 at year-end 2006.
Our operational challenges and the hiring of nearly 500 new employees to help carry out our increased operating activities impacted our cost structure and our results during 2006. However, the investments we made to accelerate the play have set the stage for substantial growth in our production and reserves in 2007.
In the Fayetteville Shale play, we are now producing gas over an area that encompasses approximately 45% of our acreage position, which is roughly 890,000 acres. So we know it's a very large resource. We will continue to aggressively assess and develop our acreage in the play during '07 as we invest about $875 million to drill between 400 and 450 horizontal wells and shoot 3D seismic over a large portion of our acreage. The result of all of this, we believe, will be stimulating growth in our production and reserves. We look forward to relating our progress to you as the year unfolds.
I'll now turn the conference over to Richard for an update on our operations and then to Greg for a discussion of our financial results.
Richard Lane - Southwestern Energy - President, E&P
Good morning. As Harold said, in 2006, we set new records for our annual production and reserve additions. Gas and oil production totaled 72.3 Bcfe, up 19% from 2005. Our Fayetteville Shale production alone was 11.8 Bcf in 2006, up substantially from the 1.8 produced in 2005. Production for the fourth quarter of 2006 was 20.7 Bcfe. That's up 32% from the 15.7 in the fourth quarter of 2005. Our production from the Fayetteville Shale increased to 5.5 Bcf during the quarter, up from 0.6 in the fourth quarter of 2005.
We estimate that our first quarter 2007 production will be between 20 and 21 Bcfe and that the full-year 2007 production will be 105 to 110 Bcfe.
We reached a significant milestone as we ended 2006 with just over 1 trillion cubic feet equivalent of total proved oil and gas reserves, up 24% from 827 at year-end '05. Of the year-end 2006 reserves, approximately 37% are in East Texas, 27% in the Conventional Arkoma Basin, 29% in the Fayetteville Shale, and 7% in other areas.
In 2006, we added 365.5 of proved reserves and replaced 386% of our 2006 production at a finding and development cost of $2.75 per Mcfe, which includes 86 Bcfe of negative revisions and excludes the capital that we invested in drilling rigs.
The downward proved reserve revisions were primarily due to our comparative decrease in year-end gas prices, combined with performance revisions in our East Texas and Arkoma Basin properties. These were partially offset by upward performance revisions in our Fayetteville Shale properties.
Excluding revisions, our finding and development cost was $2.10 per Mcfe. Proved developed reserves accounted for approximately 65% of our total reserves at year-end '06.
In 2006, we invested $767 million in our primary expiration and production business activities and participated in drilling 382 wells. Additionally, we invested $94 million related to the purchase of drilling rigs, which were sold in December of 2006 as part of a sale and leaseback transaction.
Of the 382 wells, 230 were successful, 9 were dry, and 143 were in progress at year-end, for an overall success rate of 96%. Of the $767 million invested in 2006, approximately 617 million was for drilling wells, 70 for leasehold acquisition and seismic, 18 million was for producing property acquisitions, and 62 million was in other capitalized costs. Excluding the capital we invested in new drilling rigs, approximately 80% of our 2006 E&P investments went to drilling wells.
In our Fayetteville Shale play in 2006, we invested approximately $388 million, including 316 to spud 196 wells, 29 million for leasehold acquisition, 14 million for seismic, and 29 million in capitalized costs. At the end of 2006, we held a total of approximately 892,000 net acres in the play area, of which 51,000 net acres are held by Fayetteville Shale production and 125,000 net acres are held by conventional production in our Arkoma Basin fairway area. Excluding the fairway acreage, our acreage position has an average lease term of 7 years and an average royalty interest of 15%, and our cumulative all-in average cost is $95 per acre.
Gross production from our operated wells in the Fayetteville Shale play increased from approximately 9 million cubic feet per day at the beginning of 2006 to approximately 100 million cubic feet per day by year-end and, as Harold said, could reach near 300 million cubic feet per day by the end of 2007.
As of February 26, our production rate has increased to approximately 120 million cubic feet per day, on track with our plan. We currently expect our total 2007 net production from the Fayetteville Shale to range from 45 to 50 Bcf. This compares to 11.8 Bcf during 2006.
Our total proved gas reserves in the Fayetteville play at year-end 2006 were 300 Bcf, compared to 101 at the end of 2005. Proved developed reserves from our horizontal wells ranged from 0.2 Bcf to 2.8 Bcf per well, and the average gross proved undeveloped reserves per well included in our year-end reserves was approximately 1.15 Bcf per well. That's 20% up from the 0.95 Bcf per well at the end of 2005.
We currently estimate that the average ultimate gross production for these wells will be 1.3 to 1.5 Bcf. We currently have three completion rigs -- crews operating in the area which are keeping pace with our drilling operations. We've continued to test various completion techniques, including using crosslinked gel and slickwater fluid treatments, as well as various downhole mechanical equipment. Not all of these techniques have proven to be successful and have impacted the performance of some of our recent wells. However, we continue to experiment with the new completion techniques, fluid systems, and longer lateral lengths to further optimize the performance of our wells. In the first quarter, we planned to drill a number of wells with lateral lengths greater than 3,000 feet, as compared to our average 2006 lateral length of about 2,200 feet.
In yesterday's earning release, we included an update of our normalized average daily production data through February 26, 2007 for the Company's horizontal wells using slickwater or crosslinked gel fluids. The light blue curve includes all wells, and the dark blue curve excludes the 9 wells, which had significant mechanical issues.
The normalized production curves provide a qualitative measure of the Company's Fayetteville Shale well's performance but should not be used to estimate any individual well's estimated ultimate recovery.
The 1.3 and 1.5 Bcf-type curves shown on the graph reflect the range of the Company's current estimates of the expected performance of the average horizontal well completed in the Fayetteville Shale and are based on production history that's currently available.
As of February 26, 2007, we had 19 drilling rigs running in our Fayetteville Shale play area, 15 which are capable of drilling horizontal wells and 4 smaller rigs that are used to drill the vertical section of the horizontal wells. We have been able to mitigate a portion of higher service costs through the utilization of the [service hole] drilling program and have increased efficiencies from new fit-for-purpose drilling rigs.
In 2006, the Company averaged 18 days from reentry to reentry, utilizing the combination of the smaller and larger rigs, and we expect this time to be reduced to approximately 16 days during 2007.
We currently plan to continue to utilize at least 19 rigs in the play area through 2007, and we anticipate well costs for completed horizontal wells drilled during the year will be approximately 2.3 million per well.
While drilling several of our Fayetteville Shale wells, we have begun to encounter conventional sand reservoirs. At our South Rainbow pilot, the [Louie Prince] 122 well was duly completed in the upper and lower [Hale] reservoirs and is currently producing 2.7 million cubic feet per day. We anticipate that the data we receive from our 3-D seismic program will be a beneficial tool toward uncovering more of these conventional targets.
In 2007, we plan to invest $875 million in our Fayetteville Shale play, which includes drilling between 400 and 450 horizontal wells, shooting 3D seismic over a large portion of our acreage. We currently have two seismic crews in the field and have begun collecting that data.
Based on our previously acquired 3D pilot programs, we believe 3D seismic has the potential to optimize well performance, minimize geologic risk, and better guide extended lateral length drilling, as well as the conventional target expiration I mentioned. We also plan to drill up to 7 horizontal wells in the Moorefield Shale and one in the Chattanooga Shale.
Moving to our conventional Arkoma Basin activity, in 2006, we invested approximately $97 million, drilling 84 wells, of which 54 were successful and 26 were in progress at year-end. We added 51.6 Bcf of proved reserves in the Basin, and our 2006 production was 20.1 Bcfe, relatively flat compared to 2005 production of 20.2 Bcfe, while proved reserves totaled 277 Bcf at year-end, up slightly from 2005.
At our Ranger Anticline area located in Logan and Yell Counties, Arkansas, we successfully completed 27 out of 29 wells during the year, excluding 17 wells that were in progress at year-end. Much of our drilling last year at Ranger Anticline focused on the area located between the main producing part of the field and the Eastern extension, where we drilled several wells in 2005.
One well of note in this area is the Smith 112 well, which has produced approximately 1 Bcf gross since being put on production in August. We operate this well, which is currently producing 4.5 million cubic feet per day, with a 75% working interest.
Additionally, we are currently completing the Bryant 1-7 well in that area, and that well has tested at rates of 7 million cubic feet per day. We expect to put this well, which we operate with a 48% working interest, on production within the next few weeks.
Since drilling our first successful well at Ranger in 1997, we have successfully drilled the 104 out of 118 wells, adding about 96 net Bcfe of reserves at a finding cost of $1.52 per Mcfe, including revisions. We believe that Ranger holds significant future development potential and could have more than 150 remaining potential locations.
During 2006, we drilled five offsets to the USA 124, one of our 2005 discovery wells on our Midway Prospect. Four of these wells are producing, while the remaining wells are waiting on pipeline connection. At December 31, '06, we held approximately 28,650 gross acres in our Midway Prospect area, and depending on the performance of the newest drilled wells, we plan to drill up to 15 there in 2007. Midway is located in Logan County, approximately 11 miles north of the Ranger Anticline, and we operate all these wells with an average working interest of 60%.
In 2007, we plan to invest approximately $115 million in the Conventional Arkoma program and drill approximately 100 to 110 wells, of which 50 to 60 wells will be at Ranger Anticline.
In East Texas in 2006, we invested approximately $204 million and drilled and completed 78 wells. Of this, 155 million was invested in our Overton Field, where we drilled and completed 66 wells. The remaining 12 wells were drilled and completed in our Angelina River Trend play.
In East Texas, we added 92.8 Bcf of proved reserves during the year. Production was 32 Bcfe, or 13% greater than the 28.2 Bcfe we produced in 2005. We continue to maintain a 100% success rate at Overton after drilling over 300 wells since we acquired the field in 2000.
New wells drilled in the field during 2006 averaged approximately 2.3 million to drill and complete and had average initial production rates of approximately 3 million cubic feet per day and had average estimated ultimate gross reserves of 1.6 Bcf per well.
Most of our 2007 Overton drilling program will focus on drilling proved, undeveloped locations. In addition to Overton, we continue to expand our holdings at the Angelina River Trend, which is primarily in Nacogdoches County in Texas.
At year-end '06, we held approximately 69,000 gross undeveloped acres and 6,400 gross developed acres. This acreage includes a new [farm-in] that we negotiated in late 2006 for approximately 16,500 gross acres from a major oil company. Our first test of this farm-in block, which we call our Jebel prospect, is scheduled for the second quarter of this year.
Through the end of last year, we had drilled a total of 28 wells in the Angelina River Trend, primarily targeting the Travis Peak formation. This play consists of eight separate blocks of acreage. During 2006, a large part of our activity there consisted of trying to evaluate our acreage position, where we defined some areas that were better and some that were poorer and which ultimately lowered our well performance but helped us define the areas that we're going to be focusing on in 2007.
In one of our high-graded areas, such as Doyle Creek, we completed wells in 2006 with average reserves of 1.5 Bcf per well. We expect our 2007 results to be better as we continue to high-grade that program.
In total, in 2007, we plan to invest approximately $163 million in East Texas, including drilling approximately 39 wells at Overton and 28 wells in the Angelina River Trend.
In expiration and new ventures, along with our Fayetteville Shale play and our ongoing East Texas and Arkoma Basin programs, we continue to develop new prospects for future development. At the end of 2006, we held approximately 89,600 net undeveloped acres associated with these other conventional/unconventional plays.
In 2006, we invested approximately $46 million and drilled a total of 7 expiration wells, of which 2 tested gas, 2 were dry, and 3 were in progress at year-end. The 2 dry holes were in conventional tests in the Rocky Mountain areas.
In 2006, we completed 2 wells in our Permian Basin Barnett Shale play, where we hold approximately 50,000 acres in Culberson County, Texas. One well was shut in for a pressure build-up after testing non-commercial quantities of gas. The other well is currently waiting on a pipeline connection to prior conducting some extended production tests to determine the viability of more drilling there. We expect to have better determined the prospectivity of that acreage by the end of this year. Three (3) remaining wells which were in progress at year-end were in our Silver Water Coalbed Methane Project in Caldwell Parish, Louisiana. Here, we have approximately 11,000 net acres in the project area, and we're targeting tertiary-age lower Wilcox coals at a depth of approximately 2,800 feet.
In addition to these plays, we're developing what looks to be a sizable non-operated position in the Woodford Shale play in Eastern Oklahoma. We hold about 21,000 net prospective acres in that play and have already participated in three wells.
In 2007, we plan to invest approximately $58 million in our expiration and new venture projects, including drilling up to 10 wells in the Woodford Shale in Oklahoma and 30 wells in our Silver Water project.
In summary, we are very pleased with our record results in 2006, and we continue to be very encouraged by our success in the Fayetteville Shale project, and our programs in the Arkoma Basin and East Texas are performing well. We're looking forward to continued strong results in 2007, including meeting or exceeding our PVI target, 40 to 50% of production growth, and significant increases in proved reserves.
I will now turn it over to Greg Kerley, who will discuss our financial results.
Greg Kerley - Southwestern Energy - EVP, CFO
Thank you, Richard, and good morning. We reported record net income of 162.6 million in 2006, up 10% from the prior year.
Our operating cash flow, defined as cash flow from operating activities before changes in operating assets and liabilities, also set a new record, increasing to 413.5 million, up 29% from 2005, largely driven by a 19% increase in our production volumes.
We also ended the year with an extremely strong balance sheet as our outstanding debt represented only 9% of our total booked capitalization.
Our earnings for the fourth quarter were 33.8 million, or $0.20 a share, down from 48.9 million, or $0.29 a share, in 2005, as the positive effects on our earnings of an increase in production was more than offset by a 19% decline in natural gas prices and increases in operating costs.
Net income for the fourth quarter of 2006 also included a 3.3 million loss accrual related to the settlement of outstanding litigation.
Our operating cash flow was 108.7 million in the fourth quarter, up from 102.8 million in 2005, as our production growth more than offset the effects of lower gas prices and higher cash operating costs.
Operating income for our E&P segment was 237.3 million in 2006, compared to 234.8 million in 2005. We produced a total of 72.3 Bcf equivalent in 2006, and approximately 94% of our production was natural gas.
The average price realized for our gas production, including the effects of hedges, was $6.55 in Mcf in 2006, compared to $6.51 a year ago. Our hedging activities increased our average gas price realized during the year by $0.18, compared to a decrease of $1.22 in 2005. Our current hedge position, which consists of fixed-price swaps and costless collars, provides us with support for a strong level of cash flow in 2007. Since our last conference call, we have significantly increased our hedge position and currently have approximately 80 Bcf hedged in 2007 and 57 Bcf in 2008.
In 2007, the average price of our natural gas fixed-price swaps is $7.81 per Mcf, and the average floor price of our collars is approximately $7, both of which provide a solid base for our projects, while the average ceiling price of our collars is over $12, allowing us to retain considerable up side. Approximately 75 to 80% of our 2007 targeted gas production is currently hedged.
In 2008, the average price of our natural gas fixed-price swaps is $8.26 per Mcf, and the average floor price of our collars is approximately $8.
Our average realized oil price in 2006 was $58.36 a barrel, compared to an average price of $42.62 in 2005. Our lease operating expenses per unit of production were $0.66 per Mcf in 2006, up from $0.48 in 2005. The increase was due primarily to increases in gathering and other costs related to our operations in the Fayetteville Shale. We expect our pertinent lease operating costs to range between 82 and $0.87 per Mcf in 2007 due to the increased production volumes from the Fayetteville Shale play.
Taxes other than income taxes were $0.30 per Mcf in 2006, down from $0.37 in the prior year, and in 2007, we expect our rate to range between 21 and $0.26 per unit of production.
General and administrative expenses per unit of production were $0.58 in 2006, compared to $0.46 in 2005. The increase in the unit rate was due primarily to increased payroll costs due to the expansion of our E&P operations related to the Fayetteville Shale play.
We hired a total of 494 new employees during 2006, including approximately 300 at our drilling company. We expect our general and administrative expenses per unit of production to decrease in 2007 and range between 41 and $0.46 per Mcf as a result of our projected production growth.
Our full cost pool amortization rate averaged $2.16 per Mcf in the fourth quarter and averaged $1.90 for the full year. The increased earning 2006 was primarily due to higher finding and development costs. We expect our amortization rate to range between $2.15 and $2.25 per Mcf in 2007. Going forward, our finding and development costs and amortization rate are both expected to be heavily impacted by the timing and amount of reserve bookings in our Fayetteville Shale play.
Operating income for our Midstream Services segment was $4.1 million in 2006 compared to $5.7 million in 2005. The decrease was primarily due to increased operating costs and expenses related to our rapidly expanding gas gathering activities and a decline in the margin generated by our gas marketing activities. We expect our Midstream Services segment to generate approximately $10 million to $12 million of operating income in 2007 as our gas gathering activities in our Fayetteville Shale play continue to expand.
During 2006, we entered into several firm transportation agreements aimed at ensuring market access for our growing Fayetteville Shale production volumes. Our agreements with Ozark Gas Transmission System increased to 270,000 MMBtu per day over the next two years. For the long-term, we are arranging for transportation on two newly proposed pipeline laterals and related facilities in Texas [inaudible]. Once the new pipelines have been approved, we will enter into firm transportation agreements that will enable us to transport up to 500,000 MMBtu with the option to acquire up to 300,000 MMBtu of additional capacity on top of that.
Depending on regulatory approvals, the expected in-service date for the laterals is January 1, 2009 and our agreements would have initial terms of 10 years. Operating income for utility was 4.5 million in 2006, down from 4.9 million last year. The decrease primarily resulted from warmer weather and increased operating costs, partially offset by increased rates implemented in October of 2005. Our utility filed an application for a general rate increase last fall and any increase approved is expected to take effect in July of this year.
We've recently completed a couple of key financings that have further strengthened our financial condition and liquidity. In December, we entered into a sale and leaseback transaction through which we sold 13 drilling rigs and related equipment owned by us to various financial institutions, and then leased these rigs and equipment back, along with two additional new drilling rigs and equipment that we had ordered. We received $127.3 million in cash for the 13 rigs and related equipment and recorded deferred gain of 7.4 million, which will be amortized over the lease term.
Also, earlier this month, we amended our unsecured revolving credit facility, increasing our borrowing capacity from $500 million to $750 million and lowering our borrowing costs to 87.5 basis points over LIBOR. The amount available under the credit agreement can also be increased up to an additional $250 million in the future. Our new credit agreement substantially decreases our current borrowing costs and provides us with flexibility in executing our planned capital investment program over the next few years.
At December 31, we had total indebtedness of only $138 million and we had no borrowings under our
revolving credit facility. Our capital structure at year end consisted of 9% debt and 91% equity. That concludes my comments, so now we'll turn back to the operator who will explain the procedure for asking questions.
QUESTION AND ANSWER SESSION
Operator: (Operator Instructions.) Bob Christensen, Buckingham Research. Please go ahead.
Bob Christensen: Yes, guys. Two questions. Compression - how much horsepower have you put in the field in the Fayetteville Shale play last year and this year [in thousands] of horsepower, [if I might ask]?
Richard Lane: Yes, Bob. This is Richard. I want to say that we've increased from about 15,000 horsepower to over 40 units, which is about 42,000 horsepower in--during '06.
Harold Korell: I think we put about 35,000 out there in '06. I remember some slides we just saw the other day.
Bob Christensen: And how much would be going in, in 2007? I see 86 million being spent on sort of the Midstream.
Richard Lane: I don't have the exact horsepower adds there. It's designed to keep pace with our production and all our takeaway needs and then also then that capital. There's the pipe going in the ground for the gathering as well.
Harold Korell: There's several steel laterals planned for 2007.
Greg Kerley: Our answer is we don't have the horsepower here with us, Bob.
Bob Christensen: Okay, fine. We'll get back to you. The second question, if I may, looks like you're getting more excited about the deeper shales out there with seven wells certainly planned, horizontal for the Moorefield. How--refresh me. How thick is the Moorefield? What is the standard cubic feet of gas per ton? And on the seven wells you plan to do in the Moorefield, are they tightly spaced or is it over a wide area?
Greg Kerley: Bob, well, it's--a few different parts to your question there. I think the thickness in the Moorefield we've seen is about 75 feet, a little bit thicker further east. The spacing that we'll be doing there, we think we have about 125,000 perspective acres within our subset of data of our acreage and so it will be--tests throughout that acreage, there's not any one point that we'll be concentrating on. And we don't really have a lot of data gathered on the Moorefield yet--have a really good handle on the kind of gas in [place] and things yet, but that will be part of what we will be doing this year.
Harold Korell: I would say just [notionally] in-house, we are no more excited about it as a target than we are the Fayetteville, but it is one more shale that exists there that we have drilled a vertical and horizontal well in that have looked pretty darn good. And we need to just kind of pursue trying to understand it. And the plan for this year is to drill enough wells and begin starting to develop some performance from it, because the one horizontal we have is just not enough to assess it fully for sure.
Operator: And we'll take our next question from Gil Yang, Citigroup. Please go ahead.
Gil Yang: Good morning, gentlemen. Can you talk a little bit about the write-downs in terms of how much was PUD write-downs, how much was [sales] and how much was the performance and what the performance issues were? And then, I have a second question about the Hale.
Richard Lane: Yes, Gil. This is Richard. We had a little bit more than half of the numbers that you have there were related to performance, a little less than half was just the year-on-year price differences. And the performance piece is made up primarily of downward revisions in East Texas and the Arkoma Basin where we, for the most part, we're dealing with proven developed producing wells, so it's not really an undeveloped location thing.
And it has to do with really slight -- the majority of it has to do with slight changes to the terminal decline rate of those wells and I do mean slight. In some instances it's only like a half a percent. Yet, with a lot of wells, it has some effect. I would say that the present value of that piece layout later in the life of the well is pretty darn minimal. Yet looking at it at year end and doing our best work to get the right proven number, we think that was the thing to do. On a positive note, we have actually upward performance stuff going on in the Fayetteville Shale which is real good and that's where the bulk of the reserve adds are going to be coming from near-term.
Gil Yang: Okay. Is it fair to say that if you had not had to do the write-downs because of lower price, that the performance revisions would have also been much more modest?
Richard Lane: Well, they would have been half -- the performance revisions make up a little over half and they would have still [multiple speakers]. When we breakout price, that is the total piece for price.
Gil Yang: Can you talk a bit about the Hale? The $2.7 million was combined production rate or just from Hale? And can you talk--can you describe the Hale in terms of acreage and thickness and all that kind of stuff?
Richard Lane: Well, it was from two zones that we dueled in the Hale. It doesn't include the Fayetteville, so it's stand-alone conventional production. Pretty nice rates. It's not the only well we've encountered that conventional zones. We've seen it in several other wells. I know we have another well producing conventionally out there and to describe the distribution of it to you right now is kind of hard to do.
In the Fairway, there are channelized sands and then what they're going to be exactly over here we'll have to see. We're mapping on that. We're encountering them basically now during our Fayetteville Shale drilling, but our 3-D program that we've started and we've collected data and we'll have a lot more data in by year end, we're hoping will help guide us towards that and be a benefit.
Harold Korell: I might add, Gil, just a little bit in terms of the bigger -- the big picture on it is that of course, the old conventional producing area of the Arkoma Basin has been what we call the Fairway and off to the west. And in this area in which we've taken all these new leases to try to pursue the Fayetteville Shale, there's been very little conventional production over there. But occasionally, someone would put together a little prospect and drill on a structural feature and they would encounter some gas.
It's been kind of an interesting question over the years as to -- I remember when I first looked at the Arkoma Basin, I said, well, why does production end here? Well, as Richard mentioned, to the west in the Fairway, you have multiple sand horizons -- sand channels that pass through that part of the basin and you have faulting features and structures therefore that allow to trap the gas and make it a big producing area.
The question has been why hasn't that happened over to the east. The general, I'd say, conventional wisdom is that, of course, the sands--there are sands present. But conventional wisdom is that you haven't had the traps. And probably the greatest reality of it is that over the years, the focus in the eastern part of the basin had been on the Arbuckle and people drilling structural features deeper at the Arbuckle level. Those were the wells that gave us the original confidence to be able to pursue the Fayetteville Shale. So here we are now out drilling Fayetteville Shale wells and, of course, you all know that we drill the vertical part of the hole with a small rig using air. Therefore, it's much like drilling with cable tools.
When you drill down -- when you encounter gas, you're going to see gas flaring at the surface. And what's happening now in our -- as we're drilling Fayetteville Shale wells, when we're drilling the vertical part of the hole, occasionally we will drill into one of these gas pockets, which is a conventional type of sand channel play and we'll flow some pretty high rates out of them. Now, could you make plays out of this successfully? In the old conventional way of shooting a coarse grid of seismic, no, you can't.
Now think about -- now what we're getting is we're drilling--we're getting pinholes all over the place because we're drilling Fayetteville Shale wells and we're getting a free look at what otherwise you wouldn't get to look at with these shallow zones, these conventional sand zones and some of them could produce at pretty good rates.
In addition to that, as Richard mentioned the 3-D seismic, now as we're shooting the seismic program over the whole area, it's going to open up for us the prospect of conventional plays here, those two items, one, simply because we're getting data points because we're drilling, and two, we're going to be able to map structural features. And so on top of the Fayetteville Shale play--yes, say, on top--either shallower as in this couple few wells we've encountered gas in, but potentially even deeper later on and getting a better understanding of this basin, you might have reservoirs that will be deeper.
But basically we're in a virgin basin here. There's been very little drilling and so--there -- it's something we try not to get too excited about because it's going to come right alongside of whatever we're doing in the Fayetteville.
Operator: And we'll got next to Jeff Hayden, Prichard Capital Partners. Please go ahead.
Jeff Hayden: Hi, guys. A couple of questions on the Fayetteville reserves. First of all is the 1.15 fees you all booked for PUD. Prices came down year end '06 versus year end '05. So I was wondering if you could give us an apples-to-apples number on what would that delta have been assuming the same price deck? And then, I've got another question after that.
Richard Lane: Jeff, this is Richard. I think they would have been slightly higher, maybe 1.2 with the same price. But, no, the real important thing I think is that the -- they were still good adds even at that lower price and that the trend is upward as we get more production history.
Jeff Hayden: Okay. And just a little follow-on to that. You've only got -- it looks like one well with more than a year of production history, so I'm sure they're being pretty conservative. Can you give us any color on what sort of productive history or total productive life and terminal decline rates the engineers are assuming on the wells?
Richard Lane: You're right on the statistics there of the life of the history we have. The vast majority of them have less than six months. Our average reserve life I think is somewhere in about the 40-year range and we're using about a 6% terminal decline rate, and that's mostly from just analogy.
Jeff Hayden: Okay. And then, second question, just trying to think about that as well as what you produced here, or what you've got here in your tight curve. By my math, it's looking like you are getting somewhere between 350 and 400 million cubic feet of production in the first year. If I take that out and then slap a 6% turn on decline and a 40-year life, I'm getting something higher than 1.5. And I know some of your competitors have come out with a number closer to 2 recently with regard to Fayetteville well. How do you reconcile all of that? Am I thinking about something wrong or are you guys just being conservative until you really see more production history?
Richard Lane: Let me try to address that. The numbers that we put out there, the 1.3 to 1.5 numbers are based on our engineers projecting each of our wells and coming to their conclusion about what the numbers are. Ultimate reserves are a factor of many things. Of course, terminal decline rate, the shaping of the curve by the time you get to the terminal decline rate, which is--which could answer the question of why you get higher numbers because if you just take the first year and then straight line it to 6%, it's too simplistic of an approach to it.
So I think that's probably -- that's the answer to why your number, I think, Jeff, would be different than the numbers we're talking about. Secondly, we've warned over and over in our press releases and our statements that you really can't take a composite curve, and that's just--like we've presented here, and all--it's about what else can we show you. We could give you every single well decline curve, but just taking the composite of the average daily rates, it's probably not a good way of getting to reserves completely. You see what I'm saying? Jeff? Are you there?
Operator?
Operator: I'm sorry, sir. I removed him from the queue. I'll open his line one more time.
Richard Lane: Oh, okay.
Jeff Hayden: Hey, guys, thanks a lot.
Richard Lane: Okay.
Operator: We'll go next to Scott Hanold, RBC. Please go ahead.
Scott Hanold: Good morning.
Richard Lane: Good morning, Scott.
Scott Hanold: Can you talk a little bit more about the Fayetteville Shale reserves? Could you kind of in general talk about your thought process as far as how you go about booking PUDs? It looks like you booked about 1.5 PUDs per proved developed location. Ultimately, I guess that looks a bit conservative. Can you kind of give us your feel of what you plan on doing going forward and if that could change?
Richard Lane: Well, I mean, it might seem a bit conservative. There are probably more that we could book. But we're trying to keep track of what we're doing and get more productive history on the wells, which I think is prudent for us to do. We're basically sticking to no more than one immediate offset to a producing well, and we're just early in the life of the thing, so I think it's a prudent way to approach it.
Scott Hanold: Could you see that move a bit higher as we go further ahead in the development, if things go well?
Richard Lane: Yes, I think certainly that's a potential.
Scott Hanold: Okay. And then, my follow-up question is just on general Fayetteville activity. Obviously, you guys are running 19 rigs right now and to say at least at this point in time of that being the plan for the full year of 2007, what's the potential for you guys to do something where you actually increase that towards the back half of the year?
Richard Lane: We don't want to get a plan out ahead of what we logically have concluded to do, Scott. So--but I would just address that question maybe this way is that we went from three to 19 rigs last year.
And we hired about 500 people. A tremendous amount of work required operationally to accelerate to that level, build the organization, get it working effectively.
So there's a time for us when -- with as many locations, as many wells as we have to drill here, that we will need to stop and assess all of the input parameters to the process and look at where prices are at that time, look at all the factors, and then conclude what's the next step. And we don't have an exact timeframe for that happening, but it's an obvious thing that we in managing and leading the--this Company have to do.
Scott Hanold: Okay. Thank you. I appreciate your time.
Operator: And we'll go next to Amir Arif, Friedman, Billings, Ramsey. Please go ahead.
Amir Arif: Good morning, guys. Just a question in terms of you guys being comfortable that 45% of your acreage has somewhat been tested with the production you have already. As you drill the next 400, 450 wells this year, do you have a sense of what percentage of your production you would have in essence tested?
Richard Lane: Well, Amir, we--you've seen in our materials, the map that shades in that area, that's roughly the 45% that we're talking about. We're obviously not calling that whole thing proven. It's just where we have established production and certainly de-risked that area greatly. What that number will end up at comparative to the 45% at year-end '07 is not determined yet. We'll have a number of new pilots. I think that the count is about 12, and so it will be based on the outcome of those wells.
Amir Arif: Okay. These pilots you're talking about, these are going to be outside of that shaded area?
Richard Lane: Correct.
Amir Arif: Okay. And just a question in terms of the resources just for your '07 plan. With three completion crews, obviously, you have enough rigs. But do you have enough completion crews to do the 450 wells? Are you comfortable with that number?
Richard Lane: Yes, we are.
Amir Arif: Okay.
Richard Lane: That's--we're in good shape there and we have more resources available as we need them.
Amir Arif: Okay. Sounds great. Thanks.
Operator: And we'll go next to Michael Scialla, A.G. Edwards. Please go ahead.
Michael Scialla: Good morning, everyone. A question on the Ranger Anticline. It looks like you have quite a few extension wells planned there this year. If those work, is there any potential for adding acreage in that play?
Richard Lane: Well, Mike, we've been adding acreage there--.
Harold Korell: --There are too many other companies listening to answer that.
Michael Scialla: Understood. To follow up on that, can you tell me what the average reserves are in that play now on a per well basis?
Richard Lane: Let's see. I think we've got that somewhere here. For 2006, about 1.9 Bcf gross.
Michael Scialla: In the cost per well?
Richard Lane: Well, they vary. We have some shallow drilling there that's just a bit under 1 million, and then they'll go all the way up to 2 million, depending on the depth where we are.
Michael Scialla: Okay. And then, just one other. You said in your release that you expect inflation and service costs to continue. Others have said they're seeing signs of easing in at least day rates and some--even in service costs. Are you seeing something differently in your areas? Or are you being conservative there?
Richard Lane: Well, it's a really good question, Mike. When you talk onshore U.S., I think there's some softening in the rig demand. And there's a lot of new rigs coming, new rigs going to be delivered on top of that, so that's helpful I think. And a little bit of loosening on the pumping side of goods and services. But I think you really kind of have to be specific to the basin you're in. It's not always -- it's not the same, obviously, in all basins. So in the Arkoma Basin where we're operating the Fayetteville Shale, maybe a little different dynamics. I hope we're being conservative there. We'll just have to see how the year unfolds.
Michael Scialla: Okay, thank you.
Operator: We'll go next to Joseph Allman, J.P. Morgan. Please go ahead.
Joseph Allman: Hi. Good morning, everybody.
Richard Lane: Good morning.
Joseph Allman: Hi. On the cost question in the Fayetteville Shale, I guess -- and you're seeing some efficiencies in terms of the number of days it takes to drill a well. Can you talk specifically about the costs that you're seeing increasing there?
Richard Lane: Well, we have -- what we're trying to do is increase the efficiency, Joe. I think we averaged 18 days re-entry to re-entry in 2006. We're kind of challenging our team to drive that down to more like 16 during 2007. But also impacting the full year stuff is -- we're going to be trying some new things. We're going to be trying some longer laterals. We'll be doing some of that drilling in the Moorefield Shale. We'll be having some new pilots where we have extensive testing and all those things, so -- and then, where the completion costs come in, as we experiment with those things, we could have some higher costs if doing those new things we see the benefit of that in the performance.
And then, we had--late in the year, we had a lot of issues with weather that caused our location costs and road costs which are very expensive to be a little higher, so we need to try to get a hold--ahead of that in some of the dryer months.
Joseph Allman: Got you. And then, are there some areas in the Fayetteville Shale play where the Moorefield Shale actually looks better than the Fayetteville Shale?
Richard Lane: Well, I wouldn't say better yet because the proof is in the--in how it produces and all of those things. So it's an attractive secondary reservoir, like Harold said, and we just need to get more data on it.
Joseph Allman: All right. Thank you.
Operator: And we'll go next to Marshall Carver, Pickering Energy. Please go ahead.
Marshall Carver: Yes. A quick question on equity and debt. You talked about your bank line increasing, but I know previously when you released your 2007 plan in December, you talked about either using equity or debt to fund the difference between CapEx and cash flow this year. What are your thoughts about the use of equity, and any potential timing for that? Or how are you thinking about that this year?
Greg Kerley: Well, our--Marshall, this is Greg Kerley. Our new credit facility does give us a lot of flexibility over the long-term and provides us a low-cost financing alternative. And it's great to get that in place right now. Our capital plans, the $1.3 billion investment, we do expect to exceed our cash flow by around 700 million. We can fund that shortfall through borrowings under our credit facility or debt offerings in the public market or equity. At this point, there's a lot of unknowns and a lot of what we do will depend on market conditions during the year.
Obviously, we are very early in the year--what gas prices are going to do this year, and what costs are going to do. And then, as we move into the year, a big part of what our decision process is going to go through will depend on how we think 2008 also is going to shape up. So, I guess it is--there's a lot of unknowns. It gives us a lot of flexibility and you can rest assured that we'll be a prudent use of--user of capital.
Marshall Carver: Right. Thank you. And one other question. You talked about a 6% terminal decline rate. Would you be willing to give us your assumptions on second, third, fourth year, those types of numbers?
Richard Lane: No, I don't think right now, Marshall. Let's get some more production history and we'll try to give you all the visibility of that that we can at that time.
Marshall Carver: Okay. Thank you.
Operator: And we'll go next to Richard Moorman, Capital One Southcoast. Please go ahead.
Richard Moorman: Thank you. Good morning. Congratulations on the great year-over-year growth. Just wanted to ask you a couple of questions around, first, your backlog. You have, I assume, with the ramp up in rigs and number of wells drilled but waiting on tie-in and completion even. Could you comment on how many wells you have in that state now and your thoughts on the year forward as you enter new pilots?
Richard Lane: Yes, Richard. This is Richard. I think our inventory of wells waiting to be completed is in the low 20s right now. And not much less than that is probably kind of the optimal inventory level. So right now, we see that static. If we get the efficiencies in the drilling side we talked about, then that obviously changes.
And then, we have wells in various stages. We have wells that we've used the sputter rig on and moved off, waiting on the bigger rigs. We have wells that have been drilled with the horizontal drilled with the larger rigs, and waiting for work-over rigs to come in and prepare them for the completion phase. And then, another group that those rigs, work-over rigs come back and [tube] those up for production. So a variety of wells in different stages, but the completion of one is--I think it's about 24 wells right now.
Richard Moorman: Super. Thank you. And then, the second question, not that you don't have enough new techniques you're trying right now. But a lot of the chatter in the Barnett calls this quarter has been about the simultaneous frac'ing off-pads and so on. And it seems like a number of operators are maybe even doing almost half their wells that way. How do you feel about the application of this or do you have plans in the Fayetteville right now?
Richard Lane: Well, we're--we have started to work at the pad drilling. That's another factor in '07 that I didn't mention in the costs. So we've started into that type of a strategy to test it. Obviously, the reason to do that is that the greater efficiencies you might have, both on the drilling side and on the completion side. And early into that, there'll be more cost than less as we try to sort that out.
But really more to your question of the simultaneous fracs, if you have a centralized location with multiple wells and you get all the tankage out there and the equipment you need to do to frac it, I think you can go ahead and do as many of them as you can right then. Operationally it's efficient, and then you have the simultaneous thing going on I think with that. I think it's a very interesting part of the unconventional horizontal wells. From a theoretical standpoint, myself personally, I think it has some very interesting merit in terms of maybe improving well performance. We're not really there yet, but we will be working at that.
Richard Moorman: Great. Well, thank you very much, and I look forward to next quarter. Thanks.
Operator: And we'll go next to Jason Gammel, Prudential. Please go ahead.
Jason Gammel: Thank you. I was hoping that you could contrast and compare the 3,000-foot lateral with what you are doing currently in--with the 2,200-foot lateral in terms of the cost versus expected recovery parameters and what you maybe have modeled in for the 3,000-foot laterals? And then, maybe also discuss the number of frac stages in each type of well.
Richard Lane: Yes, Jason, this is Richard. What we've--we've experimented with different amount of stages during '06, and those ranged I think from about five stages to maybe 10 stages in our--most of our wells. So I can't give you a specific amount of stages that we would do if we had 3,000 feet of horizontal well and zone. But certainly, the direction there is to open up more reservoir with the greater lateral, and at least keep the same density of stages.
I don't think it makes a lot of sense to go backwards there, so notionally you would be increasing the number of stages. I don't have a number for you that would ratchet up some kind of well recovery to go with that. But common sense and common science on the issue tells you that if you open up more rock and fracture stimulate more rock, it ought to be better.
Harold Korell: I think, just to open that subject up a little bit more, the obvious right thing to be doing here in completions -- we've said it since we started talking about this, is to be in contact with the most rock you can, the most of the shale that--the most shale you can per dollar invested. And so, we are continuing to -- we'll be continuing to try to do that. And longer laterals, of course, would say that's going to put you in contact with more of the rock and you can do more stages.
But another factor that's probably not as obvious to you guys, but it's a real world thing is you want to be sure that the additional footage that you drill is within the zone, and that it's placed optimally within the vertical section of the shale also such that the fracture is effective as possible. So -- and how do you accomplish that? You either -- you have to have a good map of the geology of where the shale is, of course. You don't want to cross structural features like faults and other things. When you're in an unknown area drilling a new pilot with very little control and not well control and very little seismic or no seismic, there is a certain amount of guessing goes into that. That, of course, affects the ultimate well result, too.
So as we drill more wells, therefore have more data points in which to put the geometry of the geology together, and as we shoot more seismic and we're shooting lots--we've got continuing seismic programs going on this year, one would hope and think that it would allow us to place our horizontal wells both within the vertical section, to stay in the zone, and also to then figure out how many stages to do to get the best result per dollar we put into it.
So a lot of things and you don't just -- you can't just push out and drill 4,000-foot laterals, if you don't know where the shale is. You may have some of the well bore outside the zone. And so, I wanted to bring up that discussion because it's important to understanding how--a seriotum of pushing to longer laterals. And then, making sure you have the results you want.
Jason Gammel: Okay. Thank you very much, guys.
Operator: And we'll go next to Ken Carroll, Johnson Rice. Please go ahead.
Ken Carroll: Hey, guys. Good morning.
Richard Lane: Good morning.
Ken Carroll: Just a quick kind of detail question in terms of the credit facility, $750 million, you had zero drawn at year-end. You clearly outspent your cash flow in Q4. What's the current outstanding balance under that facility and how much is available?
Greg Kerley: We have right now about $90 million to $95 million drawn on that facility.
Ken Carroll: Okay, great. Thank you, guys.
Operator: And we'll go next to Travis Anderson, Gilder, Gagnon, Howe. Please go ahead.
Travis Anderson: Good morning.
Richard Lane: Good morning.
Travis Anderson: Just a comment, first. I can't help thinking that looking at the same data, some of your competitors, maybe those guys up in Oklahoma would have somehow come up with an extra 100 B's of reserves in the Fayetteville. But I like that you're conservative. My question is on looking out towards next year, have you identified or thought about where you might find or would you even need more rigs past '07?
Richard Lane: Well, yes, we've certainly--we're looking forward more than the year in front of us, Travis. And we have looked at where the additional resources would come from and we've talked to vendors and suppliers of those things. So we're just not at the point where we want to detail out what that might be.
Travis Anderson: Okay. And the sale leaseback, you didn't mention booking any gain on there, but I did notice that you talked about $94 million worth of sale leasebacks. But it looked to me like you generated 130 million? I wasn't quite sure of the accounting for that--.
Greg Kerley: --We had--.
Travis Anderson: --[Inaudible] gain on sale.
Greg Kerley: Right. We had a 7--a little over -- close to a $7.5 million gain on the sale that will be amortized, Travis, over the term of the lease.
Travis Anderson: Okay.
Greg Kerley: The 130 million or so was the 94 million this year we invested plus, if you might recall, while we hadn't received rigs, we had payments that we made in late 2005 towards the construction of those rigs. So that's why the amount was greater than the current year expenditure.
Travis Anderson: Okay, great.
Greg Kerley: And then we also--there were a couple of rigs that we would have written checks for at the end of the year delivered to us -- taking it from 13 to the 15 that we actually are operating that on the sale leaseback deal. They ended up purchasing the rigs and so that didn't go through our investment for the year.
Travis Anderson: Okay. Thanks.
Operator: (Operator Instructions.) We'll take a follow-up from Bob Christensen, Buckingham Research. Please go ahead.
Bob Christensen: Thank you. The success in West Texas, I noticed the word "success" on those two wells. Why do you deem them successes? West Texas Woodford, I'm referring to.
Richard Lane: Are you talking about our--.
Bob Christensen: --Culberson. Yes, the two wells there.
Richard Lane: Culberson County?
Bob Christensen: The words in the press release were successful--two successful wells.
Richard Lane: Yes, well, we've produced gas from both of them. I think the--I would categorize them as certainly one is non-commercial--tested gas out of both of them. One is certainly non-commercial at the rates that we saw and the other one is--we're encouraged, but we'll have to see more data there before we go forward.
Bob Christensen: How much in the finding and development costs here in the year in the Fayetteville--they were obviously higher the year before--simple arithmetic. But how much of the costs would you characterize as real front-end costs like roads, if you will, that will be used over 20 and 30 years and probably cost you a lot of money. Can you characterize sort of the one-off big-ticket items and the amount? You may not have it at your fingertips, but help us think about just a very large resource play and the early years of--are high-cost front-ended?
Richard Lane: Yes. Well, it absolutely is and to the extent it keeps growing and be successful, that we have the--we have some optimization that will go on there and will affect finding costs. Another big factor, I mean, your roads, as an example, Bob. Yes, if you put in a couple hundred thousand dollars worth of road, and then you end up adding well pads at the end of it, there's certainly some economy from that. A big issue is the--is what we book is proved compared to what ultimately we hope to get out of these. That's certainly a huge driver on the finding costs.
Harold Korell: Well, all costs are front-end loaded because all the acreage, whatever acreage we have bought is--we don't have to buy it again. Whatever roads we've built, our communication systems and things that we're--towers that we're putting up to be able to gather all the data, monitor that, the ponds we're building to catch water to be used in the frac jobs. There are a lot of costs that are front-end loaded. And to kind of--to take a snapshot picture of a single year, of course, is it doesn't give you any indication of what the ultimate costs will be.
It's like looking at single year versus full costs, full cycle economics of a well, and then the reserves affect it. Another big cost is everything we're doing of an experimental nature on the completions, which includes the various kinds of completions we've tested and it also includes every new well we drill in a new pilot, which is basically a step-out exploration test. And so, there are a lot of the costs, of course, yes, that the costs are high in the front-end of it.
Bob Christensen: Sure, sure. So, that explains it. Thank you.
Operator: And we'll take a follow-up from Gil Yang, Citigroup. Please go ahead.
Gil Yang: No question. Thank you.
Operator: And we'll go next to Joseph Allman with a follow-up. Please go ahead.
Joseph Allman: Hi, again, everybody. Could you say some more about the CBM play in North Louisiana? And how did you get in there and what are the opportunities for expanding further there?
Richard Lane: Well, it's lower Wilcox coals that are very interesting, decent thicknesses. We put our block together there. That's part of the dollars you'll see detailed in our information in the Acquisition category. I think we have a little over $9 million that we put together there, which includes, for the most part, it's capturing the opportunity and there's a few wells in there, a little bit of production. But it's lower tertiary coals, and then what we're going to be doing is some--what we've started on is a pilot program to kind of check how that coal is going to dewater and how fast the gas is going to come and those things that you need to look at for that kind of play.
Joseph Allman: Okay. And you've got some production there already?
Richard Lane: A little bit.
Joseph Allman: All right. Thank you.
Operator: And we'll take our next question from Richard Moorman, Capital One Southcoast. Please go ahead.
Richard Moorman: Thank you. Just a quick follow-up on your Texas operations, particularly, Angelina. You're having some success there. Do you have any projections or feel right now whether this will be capable of going down to an 80-acre spacing or beyond, like Overton?
Richard Lane: It's pretty early, Richard. I think right now we see it as a little greater than that. It's a totally different reservoir situation. We're talking about the Travis Peak and widely dispersed [pay] zones over a real thick interval, so a harder thing to hone in on because of that, but we'll just have to see. Right now we see it as more than that on the spacing, but a lot of acreage there still to develop, if we can get some traction in it.
Richard Moorman: Super. And then, just a quick thought on other zones in the vicinity. Some operators to the east of you are doing some James Lime work and I believe there's a Deep Bossier in the area as well, so just kind of wondering what other possibilities you see for your operations there.
Richard Lane: Yes, there's Deep Bossier players in the area. We're not really after that. I wish they weren't in the area because it's making the leasing tougher. But on our block, our new block that we call Jebel, I discussed, there's actually I believe a new pedate horizontal well that's producing within the block on some sub-acreage we don't have, which is very interesting to us. So those would be the things that we're kind of watching.
Richard Moorman: Great. Well, good luck. Thank you.
Operator: And with no further questions left in the queue, I would like to turn the conference back to your presenters for any additional or closing remarks.
Harold Korell: Sure. Well, a number of you have asked questions about this. I feel sort of compelled to wrap up with this. And that is that we're still in the early stages of realizing the full impact of the Fayetteville Shale play in our numbers. When I say in our numbers, I mean on our production numbers and our reserves. Our reserve bookings are impacted by the average results of all the wells we've drilled as we've assessed new areas and developed the technology to complete these wells.
And the job of the reserve engineers is not to look forward with rose-colored glasses, but rather to assess the reserves based on the past performance and to diligently analyze existing data. And we must report by those numbers. Now, does the past dictate the future? To me, not necessarily. Will the future get better? I mean, the answer to that is performance and technology plays usually improves. And so just all in closing, I would say we look forward to continuing our work throughout 2007, and then reporting those results to you. And thanks for being on our call today.
Operator: This does conclude today's conference. We thank you for your participation. You may disconnect your lines at any time. Have a wonderful day.
