德文能源 (DVN) 2009 Q2 法說會逐字稿

Welcome to Devon Energy's second quarter 2009 earnings conference call. At this time all participants are in a listen-only mode. After the prepared remarks we will conduct a question and answer session. This call is being recorded.

At this time I'd like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.

Good morning, everybody, and welcome to Devon's second quarter call. I've got just a couple of housekeeping items and then I'll turn the call over to our Chairman and CEO, Larry Nichols. He'll give us an overview of the quarter and some thoughts about how Devon is positioned for the future. Following Larry's remarks our President, John Richels, will provide a financial review and then following John's comments Dave Hager, our Executive Vice President of Exploration and Production will discuss operations. This will be followed by a Q&A period and as usual wheel hold the call to about an hour so if we don't get a chance to get to your question today please feel free to follow up later in the day. As always we'll ask participants on the call to keep their questions in the Q&A section to just one question and one follow up.

A replay of this call will be available later today through a link on Devon's home page. During our call we are going to provide updates to some of our 2009 forecast based on our actual results for the first half of the year and our revised outlook for the second half. In addition to those updates that we are going to give on today's call we'll file an 8-K later today and that will provide the details of all of our updated 2009 estimates. These updates will also be posted to the estimates page on DevonEnergy.com.

Please note that all references today to our plans, forecasts, expectations and estimates are forward-looking statements under U.S. securities law. And while we always attempt to be as accurate as possible there are many factors that could cause our actual results to differ from our estimates and we therefore urge you to review the discussion of risk factors and uncertainties that is provided with the Form 8-K that we are going to file today. One other compliance note. We will refer today to various nonGAAP performance measures. When we make reference to these measures we are required to make certain disclosures under U.S. securities law. Those disclosures are available on our website and again that is DevonEnergy.com. With those items out of the way I'll turn the call over to Larry Nichols.

Despite a rather challenging environment Devon had a very positive second quarter. Total production increased 5% over the first quarter this year and 12% over the second quarter last year. It increased to 719,000 BOE per day which sets an all time record for combined production for oil and gas and NGLs for Devon.

Our realized crude prices climbed more than 50% over the first quarter which more than offsets the lower natural gas prices. This of course underscores one of Devon's strength of having a balance between oil and gas. Cost trends were favorable with most categories coming down in the second quarter with better than expected production, lower cost and stronger oil prices we generated net earnings of $314 million for the second quarter. Excluding those items that analysts generally do not forecast Devon earned $379 million or $0.85 per share for the quarter which is $0.26 or 44% above the First Call mean. We generated cash flow of $1.1 billion in the second quarter which more than funds our CapEx for the period. We exited June with cash and unused credit lines of about $2.6 billion a net debt to cap ratio of 35%, actually a little below 35%. With abundant liquidity and a very strong balance sheet we are well-positioned for an upturn in the current cycle.

Our second quarter performance reflects the very high quality of our oil and gas property base. In spite of the dramatic decrease in drilling activity in the first half of this year for Devon our assets significantly outperformed expectations. Furthermore our oil and liquids components supported sufficient cash flow to fully meet the demands of our capital program and dividends during a period of very low natural gas prices. Based on the very strong performance of our asset base for the first half of the year, we are increasing our full year production forecast by $7 million BOE which takes it to a range of between 243 million and 247 million BOE. The midpoint represents a 3% increase over 2008 production from continuing operations. This level of production is net of roughly 3 million BOE of voluntary reductions that we are planning for the second half of 2009. John will cover the details and the (inaudible) impact on third quarter volumes.

As we discussed in May we have reduced CapEx significantly in 2009 in response to the macro environment. Our 2009 exploration and production budget of 3.5 million to $4.1 billion is less than half of 2008 levels. We are now in the very, very early stages of developing our 2010 exploration and production budget which will ultimately reflect our outlook for commodity prices and cost in the future. Long-term we believe that the combination of prices and cost will adjust sufficient to the reward increased investment in the business. But we also know that the low cost producer always has a distinct advantage and this is especially true during periods of strained industry economics. Accordingly, we are always focused on identifying opportunities to improve our efficiency and our effectiveness.

A direct result of this focus was our decision that we announced in May to combine the Gulf and international divisions. These two divisions had evolved to the point that they were focused on very similar types of activities. Combining them into one single offshore division allows us to achieve meaningful improvements in operational effectiveness by pooling technical resources, eliminating redundancies and ensuring consistent product risking and capital allocation across those areas. While the combination resulted in a second quarter spike in G&A expenses due to related severance costs it will have a lasting positive impact in our overall efficiency.

Before I turn the call over to John Richels I want to give you an update on the status of the process we announced in the first quarter to secure a partner for activity in the lower tertiary play. We announced that we intended to bring in a partner for up to half of our entire position in the play. Principal driver was that our capital allocation of long-term projects had grown more than a third of our E&P capital budget. Historically we've only spent between 10 and 15% of our long-term cycle projects on these expenditures. In the near term we expect to be involved in developing four significant deep water discoveries simultaneously. And these multiple development commitments could eventually cause us to allocate an even larger share of our capital to long-term projects. Bringing in a partner will allow us to reduce capital requirements for the long-term projects and still maintain meaningful exposure to this very exciting growth area.

On announcing our desire to bring in a partner we received numerous expressions of interest from large companies. We opened a data room in late July and we have begun admitting prospective partners. We will not request offers until we learn the results of an appraisal well that is now drilling at Kaskida. This timing should allow to us evaluate bids and close a transaction or transactions around year end. Although we will be flexible as to the type of deal structure that we will consider, an agreement could involve a combination of both cash and a promoted interest in future CapEx. With that I'll turn the call over to John Richels for a financial review and his outlook. John?

Thank you, Larry, and good morning everybody. I'll begin by looking at some of the key events and drivers that shaped our second quarter financial results and review how these factors impact our outlook for the second half of the year. We will document these changes to our outlook in a in a Form 8-K that we expect to file later on today. Let's begin with production.

In the second quarter we produced 65.4 million equivalent barrels or approximately 719,000 barrels per day. This result exceeded the top end of our guidance range by 3.4 million barrels or about 5%. Roughly two-thirds of the 3.4 million-barrel beat was attributable to our North American onshore assets. The remaining third of the out performance was due to lower royalty rates in Canada and, as many of you know, Canadian royalties are calculated on a sliding scale and the lower natural gas prices during the quarter, lowered royalties and increased Devon's share of production.

When you examine our production performance in greater detail you'll find that we experienced strong year over year growth across most of our major operating regions. Overall, Devon's Company-wide production increased by 76,000 barrels per day or nearly 12% when compared to the second quarter of 2008. Once again our U.S. onshore properties contributed significant production growth, up 12% or approximately 46,000 barrels per day over last year's second quarter.

The leading driver of our U.S. onshore performance was strong growth from our Barnett shale assets. In Canada, production increased by 28,000 barrels per day or 17% year over year. In addition to lower royalty rates the continued ramp up of our Jackfish SAGD project drove the strong results from our Canadian segment. Devon's international properties also delivered meaningful growth in the second quarter. Improved results from Brazil and Azerbaijan increased international production by 16,000 barrels per day over the same period a year ago.

Looking ahead as Larry mentioned, in response to low gas prices we are taking steps to reduce our expected output in the second half of the year. In aggregate, we expect to reduce production buy between 15 billion and 21 billion cubic feet or 2.5 million to 3.5 million BOEs over the remainder of 2009. First, we are reducing incremental compression in the Barnett and Arcoma Woodford. This accounts for more than half of the reduction and most of the remaining reduction will result from deferred completions across North America and by shutting in some marginal wells in the Rockies.

Based on our strong year to date results and lower than expected overall decline rates we are increasing Devon's full year production as Larry already mentioned to a range of 243 million to 247 million barrels. This updated guidance is net of the voluntary production cuts in the second half of 2009. Despite these cuts the revised forecast represents a 7 million-barrel increase over our previous guidance. Looking to the third quarter we expect production to be in the neighborhood of 61 million barrels. This estimate indicates a 4.4 million BOE decrease from the second quarter. The voluntary reductions I mentioned account for about 1 million BOE of the third quarter increase, or decrease, excuse me, in addition, scheduled plant maintenance at Jackfish and downtime for pipeline installation at [Panue] are expected to reduce third quarter oil production by 1 million BOEs, and budgeted downtime for hurricanes reduces our expected third quarter volumes buy about 500,000 BOE. Finally, higher expected royalties in Canada reduce our forecasted third quarter production by an additional 900,000 BOEs. The remaining 1 million BOE reduction is a result of natural decline.

Moving on to price realization starting with oil, in the second quarter the WTI benchmark price rose to an average price of $59.83 per barrel. That's a 39% improvement over the first quarter. In addition to the higher benchmark price regional differentials narrowed and realizations in most producing regions were in the top half or above our guidance range. The most notable improvement occurred in Canada as differentials for heavy oil narrowed due to the addition of some new heavy refining capacity and higher seasonal demand. Overall our Company-wide realized price for the quarter averaged $52.44 per barrel or roughly 88% of the WTI benchmark. This result represents a $19 per barrel improvement in our oil price realization compared to the previous quarter.

On the natural gas side the Henry Hub index declined to an average price of $3.51 per MCF during the second quarter. Differentials tightened in all of our producing regions partially offsetting the weakness in benchmark pricing. Overall Company-wide gas price realization before the impact of hedges came in near the mid-point of our guidance range at 83% of Henry Hub or $2.91 per MCF. During the second quarter we had callers covering 265 million cubic feet per day with a weighted average floor of $8.25. Gas settlements from this hedging position increased our Company-wide average realization by $0.45 per MCF o $3.36 per MCF. In the 8-K we are filing later on today we will fine-tune our guidance for both oil and natural gas price differentials.

Due to the lack of visibility for natural gas prices for the second half of 2009 and for 2010 we recently began taking steps to protect the minimum level of cash flow during these uncertain times. For the second half of 2009 we've entered into additional gas hedges for the last four months of the year. For September we now have protected a total of 425 million cubic feet per day at a weighted average price of $6.65 per MCF. For the fourth quarter we protected our price of $5.86 on 865 million cubic feet per day. We are currently weighing the flexibility of our 2010 capital budget, our projected debt levels and our pricing outlook to formulate our plan for 2010 hedging.

Turning to our marking and midstream business, operating profit for the second quarter came in at $125 million, well above the top end of the guidance range. Higher than expected volumes and higher NGL prices were key performance drivers. Based upon our first half results we now expect marketing and midstream full year operating profit to come in between 430 million and $500 million, an increase of $65 million from our previous guidance. Shifting now to expenses second quarter lease operating expenses totaled $510 million or $7.80 per barrel of production. This result is more than $1 per BOE below the midpoint of our guidance.

When compared to the second quarter 2008 Devon's lease operating expenses decreased by $1.38 per barrel or 15%. Lower industry activity levels continued to put downward pressure on service and supply costs across most of our major producing regions. We expect this trend to continue for the remainder of 2009. Based on the cost savings achieved in the first half of the year we now expect our full year lease operating expenses to be in the bottom half of our full year guidance range of 1.9 billion to $2.3 billion. However, due to the lower production volumes in the second half of the year we may not see further declines in LOE per barrel.

DD&A expense for oil and gas properties declined in the second quarter to $494 million or $7.56 per barrel. And looking ahead to the third quarter we expect our depletion expense to be between $7.70 and $8 per barrel produced.

Moving to G&A expense, in the second quarter reported G&A expense came in at $182 million, approximately $33 million of the second quarter total was due to restructuring charges that resulted from the combination of our international Gulf divisions and the one offshore division. We expect this consolidation to achieve operating efficiencies and reduce G&A costs in future periods. Excluding this non-recurring charge G&A expenditures declined by 10% from the last quarter. Looking at the full year 2009 we are now increasing our G&A guidance to a range of 650 million to $680 million. And this updated forecast reflects the severance expenses associated with combining the divisions, reflects the strengthening of the Canadian dollar and an increase in forecasted pension costs.

Shifting to interest expense, interest expense totaled $90 million for the second quarter. This total is essentially flat when compared with the second quarter of 2008. For the remainder of 2009 we anticipate interest expense to remain steady at about that $90 million level. The final expense item that I want to touch on is income taxes. Reported income tax expense for the second quarter came if at $128 million or 30% of pretax income. However, when you back out the impact of items that are excluded from analysts estimates, our second quarter income tax rate was 32% of pretax earnings with 12% being current and 20% deferred. This is right in line with our full year forecast and similar to the rates that we would expect in the second half of the year.

So going to the bottom line, reported net earnings for the second quarter were $314 million or $0.70 per diluted share. After excluding the unusual or one time items adjusted net earnings for the second quarter were $379 million or $0.85 per diluted share outstanding. As Larry mentioned earlier Devon's earnings were significantly better than the First Call mean of $0.59 per share. That beat was driven by much better than expected production, better than expected price realizations and lower than expected overall costs. In today's earnings release we provided a table that reconciles the effects of the item that are typically excluded from analysts estimates. Now before turning the call over to Dave I'll conclude with a quick review of cash flow and liquidity.

Devon's cash flow before balance sheet changes totaled $1.1 billion in the second quarter. That's a 12% increase over the first quarter of 2009. The $1.1 billion was sufficient to fund our total CapEx and dividends for the quarter. CapEx included approximately $850 million for exploration and production activities. As we've mentioned in previous calls we believe that maintaining liquidity and balance sheet strength is a top priority especially in this environment. Based on this conviction we've continued to scale operations to live within cash flow and exited June with nearly $2.6 billion of available cash and unused credit lines, a very healthy liquidity position. In addition to our strong liquidity our balance sheet also remains one of the strongest in the industry. At June 30, Devon's net debt to capitalization ratio was 33% or 22% as calculated under the terms of our bank credit agreements. At this point I'm going to turn the call over to Dave for an update on operations. Dave?

Thanks, John. And good morning to everyone. Operationally the second quarter was a very good one for Devon. As Larry said, we set an all time record for production of oil, gas and natural gas liquids. All of our major assets are performing very well. We have leveraged our shale expertise and established years of drilling inventory not only in the Barnett but also in the Haynesville, Woodford and Horn River. Furthermore our Jackfish SAGD project continues to deliver industry leading performance.

I will begin the operational highlights with a quick recap of Company-wide drilling activity. During the second quarter we continued at reduced activity levels and at the end of June we had just 24 Devon operated rigs running. We drilled 198 wells in the quarter with only one dry whole. Of the 198 wells, nine were classified as exploratory and the remaining 189 wells were classified as development. CapEx for exploration and development were $848 million for the quarter. This brought total exploration and development capital for the first six months to $2.1 billion. In the second half of 2009 we expect E&P CapEx to continue at roughly the second quarter pace putting us squarely within our previously forecasted range of 3.5 billion to $4.1 billion for the full year.

Service and supply costs continue to respond to lower activity levels across most of our operating regions. On average Company-wide we've seen our costs deflate by about 17% since the beginning of the year and we expect to see another 5 to 7% in the second half of 2009. Industry-wide drilling rig costs are down about 40% year to date and tubular costs are down about 30%. We have not yet experienced a full benefit of these improvements because of term rig contracts and the advanced permit of enough tubulars for about 75% of our 2009 wells. So while the cost picture for Devon is much improved it will continue to get better.

Moving now to our quarterly operations highlights starting with the Barnett shale field in north Texas where we are currently running eight Devon operated rigs, during the second quarter we brought 98 operated Barnett wells online with an average IP rate of 2 million cubic feet per day. We are continuing to improve drilling efficiency in the Barnett and recently set a record by drilling a well, drilling and completing a well in nine days from spud to rig release. Given the improved efficiencies in September we plan to relocate one rig from the Barnett to Cana Woodford in Oklahoma. We believe that we can still comfortably drill the 229 Barnett wells planned for 2009. Our net production in Barnett averaged 1.2 BCF equivalent per in the second quarter, a 12% increase over the second quarter of 2008 and essentially flat with the first quarter of 2009. Stronger than expected performance from our base production in the Barnett helped to drive Company-wide reported production to an all time record high.

We did however see Barnett production begin to fall in July as a result of our lower activity levels. Given the reduction in drilling and lower levels of compression in the Barnett, we expect to exit 2009 producing about 1 billion cubic feet of natural gas equivalent per day here. In the Woodford shale and eastern Oklahoma's Arcoma basin we ran through operated rigs throughout the second quarter. However, since the majority of our acreage in the play is now held by production we elected last month to move one of these three rigs to the Canaan Woodford. The remaining two rigs will continue to focus on drilling long lateral horizontal wells in the Northridge area. However we will defer completion of these wells until 2010. In the second quarter we brought ten operated Woodford wells online. Our net Arcoma Woodford production averaged 79 million cubic feet of gas equivalent per day in the second quarter up 110% from the rate in the second quarter of 2008.

Shifting to the Cana Woodford shale in Western Oklahoma we ran four operated rigs during the second quarter and with a relocation of a rig from the Arcoma Woodford in July we have five operated rigs running today. As I mentioned next month we will, a rig will be relocated from the Barnett bringing our total operated rig count in Cana to six. These additional rigs will help us secure our lease position as we continue to evaluate and derisk our 109,000 net acres. We continue to see outstanding results from Canaan.

In the second quarter we brought nine operated wells online including the [Rotter] 1-24 that had a 24 hour IP of 8.2 million cubic feet per day. The well has an estimated recovery of over 14 billion cubic feet and costs about $8 million to drill and complete. This is obviously a stand out well but it illustrates the improvements we are seeing with higher EURs and lower drill and complete costs in the primary area of the play. Production history from our 25 long lateral horizontals drilled to date indicate ultimate recoveries of between 6.5 and 9 bcf per well. Our second quarter net production from Canaan averaged 34 million cubic feet per day up nearly tenfold over the second quarter of 2008 and up 43% when compared to the first quarter of 2009.

Moving to the Granite Wash located in the eastern sections of the Texas Panhandle this play where Devon has more than 46,000 net acres has received a bit of attention recently. Devon drilled ten successful horizontal wells here in 2008. Horizontal drilling in recent years has focused on the sands located at depths of 11,000 to 16,500 feet. Typical drill and completed costs for these horizontal wells are between 5 million and $11 million with recoveries up to 7 bcf per well. Initial production rates can range from 3 million to 15 million cubic feet per day. While these results can be attractive under normalized conditions our acreage is held by existing production so we have the luxury to defer drilling. We have no drilling plans here for 2009 but we will keep you posted on future developments.

Shifting to the Haynesville shale in East Texas last quarter we told you about our 110,000 net acres in our greater Carthage area. With numerous cores, 3-D seismic, geologic mapping and correlation with our wells drilled to date we have now substantially derisked 74,000 of the 110,000 net acres. In the second quarter we completed our sixth operated well in the play. The whole A-118 H located in the Carthage field in Panola county had a 24 hour IP rate of 5 million cubic feet per day. In July we brought our seventh well online also located in the Carthage field. The Smithbird 20 H achieved a 24 hour IP rate of over 6 million cubic feet per day. While we have seen instantaneous rates as high as 9 million per day we continue to bring Haynesville wells on cautiously.

Recent industry experience suggests that in addition to preserving well bore integrity choking Haynesville wells back during completion can prevent reservoir channeling and actually increase per well recoveries. Our second quarter results further indicate that the derisk portion of our Haynesville acreage in the greater Carthage area can deliver average per well recoveries in the 5 to 6 bcf range. Much like the Canaan Woodford we have achieved significant improvements on the cost side with our most recent Haynesville wells costing between 7 million and $9 million to drill and complete. Since the first well we drilled in the Haynesville we have seen a 60% improvement in drilling efficiency. We expect these improvements to continue as we apply the practices we have perfected through drilling thousands of successful unconventional shale wells. To date we have identified roughly 800 risked Haynesville drillings locations over our derisked acreage in the greater Carthage area alone. These locations represent more than 3 TCF of risk resource potential net to Devon.

In July after drilling an eighth well in the greater Carthage area we moved the rig south to drill our first well in Saint Augustine county. This will be the first of several Haynesville horizontal wells drilled to test our 47,000 net acre position south of Carthage. We hope to report results in our third quarter call. Southwest of the Haynesville at Groesbeck we brought yet another high rate Bossier sand well horizontal well online in a Nan-Su-Gail field in the second quarter. The 100% owned Hill Crenshaw 3 H had a 24 hour IP of approximately 18 million cubic feet of gas per day. Second quarter net production at Groesbeck reached a record 115 million cubic feet of gas equivalent per day, up 7% from the first quarter and 26% compared to the second quarter of 2008.

Moving to the Permian Basin, one of our advantages of our diverse asset base is the ability to shift capital dollars around when prices favor one commodity over another. This is a case at our Wolfbury oil play in West Texas where Devon has more than 98,000 net acres. The Wolfbury is a repeatable low geologic risk play that can generate outstanding rates of return. Initial production rates from these wells range from 70 to 140 barrels per day. A typical well costs 1.5 million to drill and complete and can produce as much as 150,000 barrels over its life. We currently have two rigs running. While we have drilled just 15 wells in the play to date we have significant running room with as much as 2,500 additional locations.

Moving to the Rockies and the Powder River Basin of Wyoming we continue to see the effects of our aggressive 2008 Big George drilling program as net production averaged a record 120 million cubic feet of natural gas equivalent per day in the second quarter; up 36% compared with the second quarter of 2008. d Now shifting to the Gulf of Mexico, we continue appraisal and development work on our four deepwater discoveries in the lower tertiary trend in the second quarter. At Cascade our 50% owned development with Petrobras, the project is progressing well. In the second quarter we drilled a Cascade number four well on the down throne side of the default and encountered approximately 500 feet of net pay. The number four well is the first of two planned producers and we will begin completing the well later this year with the West Cirrous rig. Facilities construction and installation remain on schedule for first production in mid 2010.

At Jack and St. Malo, Chevron, as operator has a letter of intent with a third party to build, own and operate a 100-mile pipeline to transport the natural gas that will be produced in conjunction with the oil. Front end engineering and design work continues in anticipation of a sanctioning decision next year. Devon has 25% working interest in both Jack and St. Malo. At Kaskida, the largest of our four lower tertiary discoveries appraisal drilling operations on the Keathley Canyon 291 number 1 well continue. We are now drilling below the salt and expect to reach total depth in September. Devon and co-owner BP are considering drilling in an additional well next year with potential production test planned for a later date of the Devon has a 30% working interest in Kaskida.

Moving now to Canada, at our 100% Devon owned Jack base thermal oil project in eastern Alberta well and reservoir performance continues to lead the industry. Jackfish production continues to climb with production averaging 28,000 barrels per day in June and reaching a peak daily rate of 33,000 barrels. Following two weeks of scheduled downtime for plant maintenance in September we will begin ramping Jackfish back up and expect to reach facilities capacity of 35,000 barrels per day in the fourth quarter. It is worth pointing out that with current oil and gas prices, favorable differentials and nonfuel operating expenses running below $6 per barrel Jackfish is extremely profitable.

At our Jackfish two project construction continues on schedule. I will remind you that like Jackfish, Jackfish two is expected to produce 35,000 barrels per day and to ultimately recover 300 million barrels over the project life. During the second quarter the plant, the first plant module arrived on-site and in July we began drilling the first of 28 planned well pairs. In the Horn River basin of northern British Columbia during the second quarter we drilled a third horizontal well in the '08 '09 winter program. Completion operations are underway now and we expect to tie in these wells and have IP rates for you in our third quarter call. You will recall that Devon has 153,000 net acres in the Horn River play.

Finally, in Brazil at our Polvo development project we brought one development well on during the second quarter, driving gross production to 20,000 barrels per day. Devon has a 60% working interest in Polvo. On the exploration side drilling continues on the Petrobras operated (Haricaugie] prospects located on block B in bar one in the Barreirinhas basin off the northern coast of Brazil. I'll remind you that this is a rank wildcat in a basin with no established oil production.

Following the Bar one well the rig will drill one well for another operator before moving to the Campos basin in the fourth quarter to drill a presalt prospect called [Ataiku] on block BMC 32. This prospect is 16 miles north of a recent Wahu discovery and adjacent to Petrobras Gibartie field and the presalt discoveries. Devon will operate the well with a 40% interest. In the second half of this year we also expect to participate in an appraisal to our Wahu discovery. Wahu is operated by Anadarko and Devon has a 25% interest. Finally, Devon will participate with a 35% working interest in a Petrobras operated exploratory well on BMC 35, expected to spud in the fourth quarter. All in all a very exciting exploration lineup for Brazil in the second half of this year. At this point I'm going to turn the call back over to Vince to open it up for Q&A.

Operator, we are ready for the first question.

(Operator Instructions) Your first question come from the line of Tom Gardner with Simmons and Company, please proceed.

Good morning, everyone. I had a question regarding Devon's progress in derisking acreage in some of your key emerging plays specifically in the Haynesville. I understand you have about 580,000 gross acres that may have changed but have you ruled out any of this other than what you indicated in this morning's release as being -- not being prospective or being prospective?

I'll take a stab at this. This is Dave Hager. No, we have not ruled out any as not being prospective. We are methodically moving our way through the acreage position. As I said at this point we drilled most of the wells in the Carthage area and we are very confident that we have derisked that area. We are now moved to the south. We are currently drilling a well in the St. Augustine county, a Cardell well. After that we are going to be drilling a well in Shelbey county which is in between Carthage and St. Augustine county. That will help to derisk an additional 47,000 acres. A great deal of the remaining acreage is actually minerals and held by production so there's not as much of an urgency to derisk most of the other areas outside of the acreage I just mentioned.

I have a similar question on the Canaan Woodford. I understand about 112,000 acres. Have you ruled any of that out?

It's about 109,000 acres and, no, we have not ruled any of it out. The Canaan Woodford is working extremely well. The bulk of our drilling to date has been concentrated on what we call the core and central portion of the (inaudible). We are now moving out to the western portion of the acreage position to evaluate it. But so far everything has worked outstanding and as I mentioned we are adding two additional rigs up there. So we are obviously pleased with the results we are seeing.

Thank you. I'll let me someone else hop on.

Next question, David Heikkinen, with Tudor Pickering Holt.

Going through your guidance, I saw the 8(K), working through numbers I understand you have 3 million barrels of curtailment, looks like two of that is really in the fourth quarter, does that imply that you expect fourth quarter gas prices to be much lower than a third? Or is it just you haven't started curtailing yet?

David, this is Vince. We actually just started implementing the curtailment. And so the impact will be disproportional to the fourth quarter. It really doesn't reflect that we think fourth quarter is any worse than third.

That just started. Looking at kind of run rates, fourth quarter volumes at 61 for third quarter, just want to make sure that my math is right, is around 57 barrels of oil equivalent to hit the mid-point of guidance?

That's correct.

Whenever you talked about Jackfish ramping and Polvo, I guess the question is is what's your natural decline rate from third quarter to fourth quarter then? Do you have the same breakdown that you walk through as third quarter, what's in the guidance? It would be useful to get to the same thoughts on fourth quarter.

Hi, Dave, this is Dave Hager, let me take a stab at that. If you take our actual Q2 production of 65.4 million barrels and you take the mid-point of Q3 of 61 million barrels that would imply a reduction of 4.4 million barrels, we break that out basically 1 million barrels due to the voluntary reductions that we've described. The plant turn around at Jackfish and Panue probably about another million barrels. We have about 0.5 million barrels built in there for hurricanes and probably a change in the Canadian royalty structure where we will not get quite as favorable results. Be just under, in the third quarter relative to second quarter. We will probably result in a reduction of about 1 million barrels or 900,000 barrels there. So that leaves the natural production decline from second to third quarter of about 1 million barrels.

Right. Then I was trying to do the same breakdown of third into fourth on the 61 million-barrel mid-point to just hit the mid-point of full year 245 would be 57 million barrels can you do the same breakdown.

Sure can, David. For there, we have about 2 million barrels of voluntary reductions for the going from third to fourth quarter. Of course Jackfish and Panue would come back on. So that would add back about 1 million barrels. We also anticipate though about a 1 million barrels of decrease liftings and that's just a timing of liftings on our international properties which would leave about 2 million barrels for production decline.

Okay. And that's mostly U.S. gas on the production decline?

Yes.

Thinking about capital spend rate then have you thought about what that implies for 2010 production?

David, we are really just getting into very early stages of developing our 2010 capital budgets and so we really haven't forecast that out through 2010 at this point.

I would add, this is Vince, I would add the fact that we deferred a lot of completions if in fact we are in an environment that encourages us to bring that production on in 2010 it bodes well for our 2010 production profile.

Just thinking about that plus other major projects, I put a 3% kind of quarter over quarter base decline in and then you do major projects and more completions, is that a fair way to bracket things? Just thinking 2 million barrels on a 60 million-barrel base.

We can't point out any flaw in your logic although obviously our activity levels have a tremendous impact on our production profile. And so until we establish what that will be for 2010 we don't really have a--.

Okay. I asked more than two questions. Thanks.

It's okay, David.

Your next question comes from the line of Doug Leggate with Howard Weil.

Thank you, good morning everybody. Conceptually you told us a little bit about hedging and the increases I guess which is kind of new, over the balance of the year but conceptually what would stop you taking a more significant hedging position on making a little bit more of an effort to maintain product in the Barnett in particular? I'm just trying to think how your plotting planning comes together on that?

It's John. Let me take a crack at it here at that question. First of all as you know there are different ways to handle risk. Our philosophy in the past has been that if we were-- if we had a strong balance sheet which we have traditionally had and if we were a low cost operator which we have traditionally been then that's a way to minimize risk or to manage risk and we have traditionally not hedged a lot except when we did for specific reasons like when we did acquisitions and that kind of thing.

What we are doing is, and we actually went through and I think we may have discussed this before, we've taken a look at whether a more systematic or a formulaic approach makes sense where you just continually hedge a certain amount of production, we really don't think that that responds well to the markets and makes a lot of sense, we just haven't seen the evidence of that being the right thing to do. What we are doing, though, is continually monitoring our expected cash flow. Our capital programs which we have a bigger piece of our capital programs these days that is dedicated to longer term projects that you don't want to slow down too much on. And our view of prices and making a call on that basis. So it's something we are continually monitoring. When we develop our 2010 capital budgets and as we develop a, continue to develop a view on pricing for 2010 we may well put some more hedges in place. But we haven't at this time.

Got it. If I could ask a couple of quick follow-ups, on the Canaan obviously you are accelerating it through a little bit. Is that really more about establishing HBP or are the economics pretty attractive at these prices and maybe you can give color as to what the break even economics look like there right now?

It's both I'd say. The current the a $4 economics there is certainly at least break even probably a little bit better. Normalized numbers are substantially better than that. It's just a play that's working as well as any play that we have out there in the Company I would say at this point. We do want to establish our acreage position. Make sure we are holding our acreage position but it's also an extremely economic play overall for us.

Are you able to give any risk locations at this point or is it too early?

Well, what we've September is that we think we have net risk potential out here of about 5 TCF. If that helps you out.

That translates to risk locations of a little bit in excess of 1500.

Got it. Thanks, Vince. Final one for me is, were there any reserve revisions, upward revisions in the quarter that help with depreciation charges?

Actually, Doug, there were. All of our Jackfish barrels came back on. You remember they came off at year end both Jackfish one and Jackfish two and they are all back on and that's somewhere in the neighborhood of 300 million barrels that came on just as a result of the economics. With the large variance between oil and gas on energy equivalent basis and with the narrowing of the differentials that we talked about earlier, those projects have become extremely profitable. And they are all back on.

I would, just to clarify, John, said all the reserves on Jackfish two that is the ones that we lost at year end but we are no place close to fully booked at Jackfish two.

We have only booked about 80 million barrels at Jackfish two. I'm sorry, I meant the ones that came off at year end. Vince is absolutely right.

300 million were back in second quarter.

That's correct.

Thanks, appreciate it.

Your next question comes from the line of [Mark Jimlan] with Benchmark Company.

Hi, guys, good morning. With respect to the voluntary curtailments is there any portion of it that is dictated by expected cash loss as opposed to just you don't like the price?

Yes, Mark, this is Dave Hager again. Yes, there is, there's actually on a number of the projects we are saving the cost of completion. And so that is actually we are saving capital by deferring these completions particularly in the Woodford and the Washakie, is allowing us to actually save costs. We are also saving some money on the compression as well. So yes it's more than just we don't like the price. It's that we can save some dollars as well.

To answer it in a different way, this is Larry, there is one field, the Powder River, where the economics are marginal and so we are shutting that field in or portions of it for negative cash flow. But the vast majority of the curtailments are purely voluntary, very profitable operations that we just elect not to sell the gas into a very weak gas market. Rather keep that gas in the ground and sell it next year at a higher price.

Vis-a-vis the Jackfish, Dave, can you talk a little bit about the progression in terms of steam oil ratios and where it stands currently?

I think John's going to take that one.

When we first scoped out Jackfish, Mark, we were assuming that we would see a steam to oil ratio that was less than 3 and in fact it's been, that whole field to be honest with you has just performed, the reservoir and the wells have performed better than we have expected. So we are actually on many parts of that project now at below a 2.6 steam oil ratio which if you look at the other way it's one MCF per barrel and the wells continue to produce at levels which are really industry leading results. So it's been just a terrific lease for us and terrific project.

One final one for me if I could. In an environment of the reduced activity in the Barnett, what are you doing with respect to the 20-acre program? And if there's activity in that regard, Dave, what kind of well rates are you seeing?

We are drilling a few on 20 acres, the bulk of them we are drilling are on 40 and 80-acre spacing. We are drilling a few on 20-acre and we are seeing performance of very similar, just slightly not quite as good but very, very close to what we are seeing on the 40 and 80-acre spacing. So it continues to have very similar economics.

Great, guys, thanks very much.

Next question come from the line of Brian Singer with Goldman Sachs.

Thank you, good morning. Shifting to the Gulf of Mexico, you highlighted the development well at Cascade. I was wondering what your expectations were for in that pay relative to the 500 feet I think you mentioned and any implications on resource potential and confidence in Cascades production rates?

Well, the net pay was as anticipated. We had no surprises in the well. If anything we actually saw a little bit more pay than we had prognosed predrill. There's no change in our resource estimates as a result of this well. Very happy with the results.

Great. Also on the Gulf of Mexico. Anything we should read into the potential decision for an additional Kaskida appraisal well?

No. Other than it's a very exciting project and certainly we are drilling an appraisal right well now that if successful could double the size of the field. I think BP has said if successful it could be one of the largest if not the largest field in the Gulf of Mexico. The fact that we are maybe considering an additional appraisal well just means that we like the project and we are going to keep evaluating it. That's all you can read into it.

Plunging forward.

Yes.

Great. On the Canaan play you highlighted the 8.4 million a day IP rate and expectations for 14 BCF EUR and I think implied in that a much shallower decline rate than we are what typically used to in some of these plays. Can you talk a little bit about that and what you are seeing from some of the e wells that have been in production for a little bit longer?

Well, overall I think we can say that our IPs out there and we typically don't bring these on quite as hard as we do in some of the other areas but we typically see IPs of around, on the order 5 million to 6.5 million cubic feet a day or so, our EURs out there are ranging from around 6.5 to 9 BCF per well. At those kind of numbers it's a highly economic project.

I guess is there anything in decline versus the normal 50 to 70% decline, I guess it would seem like there's, correct me if I'm wrong, that there seems to be a much shallower decline coming from the Canaan Woodford wells and I just wonder if that's right and if you are seeing that in the wells that have been in production so far?

I think the decline -- these are always ranges, Brian, as you know. I think maybe they are on the lower ends of the range. We take your point there that the EURs as compared to the IPs are a little bit different. You have to remember that one well as we said was no what we expect to see an a regular basis. That was an anomaly the 14 million a day well that came on. Or the 14 million BCF EUR well. I'm sorry. But these are, would what's kind of interesting about the Canaan as compared to the say the Woodford in eastern Oklahoma, it's over pressured more so it's a little bit different, a little bit different, some different production characteristics as well.

Brian, I guess to add I think the issue there really is that we choose not to bring these wells on at such a high rate and so that's why you are just seeing a lower overall IP to the EUR. We could bring these on more of them at a higher rate. It's a little bit like I described in my prepared remarks on the Haynesville that we have seen some evidence that it can perhaps degrade the overall EUR if you try to bring these wells on too hard initially. So that's going to change your overall decline rate I think you are looking at.

That's helpful. If I can just ask one last one of the two MMBOE you are expecting to be deferred in the fourth quarter which I think translates to about 130 million cubic feet a day, do you have some sense on what the percent break out is between what would be drilled, completed but shut in versus drilled and not completed?

The shut in overall is probably on the order of about 0.5 million barrels or so and more about 1.5 million barrels or so on the ones we are not completing .

Thank you.

Your next question--.

A follow up, not to beat a dead horse here but you ask about decline rates in the Canaan. Our early indications, what we are looking for 50 to 70% in the Canaan shale, as opposed to say the Haynesville where decline rates are 75% first year or greater is 50 to 75 is a big difference in terms of IP to EUR. I think it is fair to say that the early view of the Canaan is lower decline rates than the Haynesville.

Your next question come from the line of Rashid, Rehan with FBR Capital Markets. Please proceed.

Two quick questions, the first one I actually joined a little bit late so I apologize, any update on data room for the lower tertiary sales?

Yes, we covered that, the data room has opened but we are not pushing that because we want to wait until the next Kaskida well is down. And that's when we will really start asking for business when that data is in. So that process is ongoing. Satisfactorily.

Okay. Thank you. And on the cost front we do talk about having locked up tubulars and stuff at much higher prices and somewhat the same for rigs. If we were to reprice those two contracts, any thoughts on to what kind of savings we could net from that so I can thinking about what CapEx could look like?

Yes, this is Darryl Smette. As it relates to the rigs, currently it's about a 40% decrease for the rigs we have under contract and what the current market is. The number of rigs we have under contract will change as we go out obviously some of those will move down. We currently have 30 rigs under contract. That moves out or down as we go in the out years. In terms of our tubulars, we would see about a 30% improvement in the 75% of the need that we have if we were buying on the open market today. Most of that surplus material will go away as we move through the rest of this year and most of it will be gone by the time we enter 2010.

Any dollar number besides these two savings and what would it add up to?

Well, the dollar, I would have to calculate it out but 40% on a average rig cost that's running right now about 16,000 or $17,000, 40% above that, what does it get you, 23,000, $24,000 a day.

And basis differential across the board, are we seeing some benefits as time progresses and your new take away capacity?

Yes, we actually have seen a decrease in the basis differential in virtually all of the major producing areas over the last couple months. The biggest change in basis differential just in the last month or so has been in the Rocky Mountains which had been trading between $1.10 and $1.50, and going into this month is actually trading between $0.30 and $0.45. We've actually seen a decrease in basis, it looks East Texas as Gulf Crossing is now on and operating about 95% capacity and that basis differential has moved from about $0.50 down to about $0.20 this morning.

And your Transfer 85 capacity is helping in all this, right?

Absolutely. We are moving about 655 million a day on Gulf Crossing now, a majority of that right now at this moment is going to station 85. Some of it we are dropping off places in between but, yes, certainly helping.

Perfect. Thank you.

Operator, I'm showing the top of the hour. Let's make this our last question.

Your last question come from the line of Bijou Perincheril with Jefferies and Company. Please proceed.

Thank you. A couple of quick questions. While the completed well costs that you highlighted for in Canaan 8 million, if, is that a good number to use going forward? And then you sort of alluded to do the returns in Canaan. Can you give rate of return metrics in Canaan and compare it to what you are seeing in the Barnett? And also maybe some guesstimate of what you expect from Haynesville, the Carthage area?

Yes, first to your question on Canaan for the drilling costs, yes, we are seeing on the order of 8 million to $9 million per well. So I think that's, and the costs are continuing to come down with each well that we drill out there. I think around 8 million longer term is a very good number to use.

In regard to the economics of Canaan relative to Barnett we are seeing as good if not slightly better economics for what we are currently drilling out in Canaan as compared to the Barnett. Not to say the Barnett is not good. Obviously it hasn't changed to the negative at all. But it's, Canaan looks like it's as good or even a little better which is basically at a $4 Henry Hub you are probably at more like a 10% or so break even rate of return on those more normalized price at $5.50 or so. You are certainly looking at 20, 25% rate of return at least on these type projects.

Haynesville is, we are still in the early stages of Haynesville and we are still derisking the acreage. So I think we are going to see a variable and we need to understand it better before we can give you a comprehensive answer to that but we are certainly confident in the Carthage area where we say we derisked 74,000 of our 110,000 net acres at price environments around 500, 550, we are getting between, 20, 25% rate of return in that area as well at the kind of costs that we are now achieving in the play where we've been able drive drilling costs down and the kind of recoveries we are anticipating of 5 to 6 BCF per well.

I think it's important to most that the economics that Dave' talking about are full cycle rates of return, fully loaded with our acreage costs and not go forward drilling economics.

That's helpful. Thanks.

This concludes our question and answer session and ends the presentation. Thank you for your participation in today's conference. You may now disconnect and have a great day.