Devon Energy Corporation Q2 2009 Earnings Call Transcript

 |  About: Devon Energy Corporation (DVN)
by: SA Transcripts


Welcome to Devon Energy's second quarter 2009 earnings conference call. At this time all participants are in listen-only mode. After the prepared remarks, we will conduct the question-and-answer session. This call is being recorded. At this time lied like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.

Vince White

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 we will hold the call to about an hour or 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 will ask the participants on the call to keep their questions in the Q&A session 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 in 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 Please note that all references today to our plans, forecast, expectations and estimates are forward-looking statements under US 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 non-GAAP performance measures. When we make reference to these measures, we are required to make certain disclosures under US Securities law. Those disclosures are available on our website and again that is With those items out of the way, I'll turn the call over to Larry Nichols.

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 a combined production of oil, 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 strengths 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 cents per share for the quarter which is $0.26 cents 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 expenditures for the period. We exited June with cash and unused credit lines of about $2.6 billion and 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 Boe 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 were planning for the second half of 2009. John will cover the details and the [antacid] impact on third quarter volumes.

As we discussed in May, we have reduced capital expenditures 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 the 2008 level. 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 sufficiently 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 insuring consistent project 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 activities in the lower tertiary play.

We announced that we intended to do bring in a partner for up to half of our entire position in the play. A 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 deepwater discoveries simultaneously. 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 to us 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 interests 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 Cascade.

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 the combination of both cash and a promoted interest in future capital expenditures. With that, I'll turn the call over to John Richels for a financial review and his outlook. John?

John Richels

Thank you, Larry, and good morning everyone. 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 Form 8-K that we expect to file later on today.

So 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 US 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 US 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 by between 15 billion and 21 billion cubic feet equivalent or 2.5 million to 3.5 million Boes over the remainder of 2009.

First, we are reducing incremental compression in the Barnett and Arkoma-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 decrease.

In addition, scheduled plant maintenance at Jackfish and downtime for pipeline installation at Panyu 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 realizations before the impact of hedges came in near the midpoint 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. Cash settlements from this hedging position increased our company-wide average realization by $0.45 cents per Mcf to $3.36 per Mcf.

In the 8-K we are filing later on today, we will finetune 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 a 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 marketing 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 of 2008, Devon's unit 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 and Gulf divisions into 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 in at $128 million or 30% of pretax income. However, when you back out the impact of items that are excluded from analyst 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.

We will go into the bottomline. Reported net earnings for the second quarter were $314 million or $0.70 cents per diluted share. After excluding the unusual or one-time items adjusted net earnings for the second quarter were $379 million or $0.85 cents per diluted share outstanding.

As Larry mentioned earlier, Devon's earnings were significantly better than the first call mean of $0.59 cents 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 items that are typically excluded from analyst estimates.

Now just before I turn the call over to Dave, I'll conclude with a quick review of our 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 capital expenditures and dividends for the quarter. Capital expenditures 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 continue 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?

Dave Hager

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, Cana-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 our 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 hole. Of the 198 wells, nine were classified as exploratory and the remaining 189 wells were classified as development.

Capital expenditures for exploration and development were $848 million dollars 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 were down about 40% year-to-date and tubular costs are down about 30%.

We have not yet experienced the full benefit of these improvements because of term rig contracts and the advanced purchase of enough tubular 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 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 to 229 Barnett wells planned for 2009. Our net production in Barnett averaged 1.2 Bcf equivalent per day 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 in Eastern Oklahoma's Arkoma basin, we ran three 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 Cana-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 Akcoma-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 Arkoma-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 Cana. In the second quarter, we brought nine operated wells online including the [Ratter 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 standout 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 Bcf and 9 Bcf per well. Our second quarter net production from Cana averaged 34 million cubic feet of gas 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 feet 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 hole A118H located in the Carthage field in Panalo 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 Smith-Bird 20H 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 wellbore 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 Bcf to 6 Bcf range.

Much like the Cana-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 three 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 west in San 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 sands well, horizontal well online in a Nan-Su-Gail field in the second quarter.

The 100% owned Hill-Crenshaw 3H 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 based is the ability to shift capital dollars around when prices favor one commodity over another. This is a case at our Wolfberry oil play in West Texas, where Devon has more than 98,000 net acres. The Wolfberry is a repeatable, low-geologic risk play that can generate outstanding rates of return.

Initial production rates from these wells range from 70 barrels 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 average of record 120 million cubic feet of natural gas equivalent per day in the second quarter; up 36% compared with the second quarter of 2008.

Now shifting to the Gulf of Mexico. We continued 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 downthrown side of the fault 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 Sirius 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 Cascade, the largest of our four lower tertiary discoveries, appraisal drilling operations on the Keathley Canyon #1 will continue. We are now drilling below the salt and expect to reach total depth in September.

Devon and co-owner BP are considering drilling an additional appraisal well next year with the potential production test planned for a later date. Devon has a 30% working interest in Cascade.

Moving now to Canada, at our 100% Devon owned Jackfish 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 be again ramping Jackfish back up and expect to reach the facility's 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 non-fuel operating expenses running below $6 per barrel, Jackfish is extremely profitable.

At our Jackfish 2 project, construction continues on schedule. I will remind you like Jackfish, Jackfish 2 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 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 '08-'09 winter program.

Completion operations are underway now and we expect to tie in these wells and have IP rates for you in the 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 [Harkagie] prospects located on BM-BAR-1 in the Barreirinhas basin, off the Northern coast of Brazil. I'll remind you that this is rank wildcat in a basin with no established oil production.

Following the BAR-1 well, the rig will drill one well for another operator before moving to the Campos Basin in the fourth quarter to drill as a pre-salt prospect called [Itaipu] on Block BM-C-32. This prospect is 16 miles north, a recent Wahoo discovery and adjacent to Petrobras' Jubarte and their pre-salt Whale Park 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 Wahoo discovery. Wahoo 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 BM-C-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.

Vince White

Operator, we are ready for the first question.

Question-and-Answer Session


[Operator Instructions]. Your first question comes from the line of Tom Gardner with Simmons & Company. Please proceed.

Thomas Gardner - Simmons & Company

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 not being perspective or being perspective?

Dave Hager

No, we have not ruled out any of the acreage as not being perspective. We are methodically moving our way through the acreage position. 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 moving to the south. We are currently drilling a well in the San Augustine county, the [Cardill] well. After that we will be drilling a well in Shelby county which is in between Carthage and San 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 that I just mentioned.

Thomas Gardner - Simmons & Company

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

Dave Hager

It's about 109,000 acres and, no, we have not ruled any of it out. The Cana-Woodford is working extremely well. The bulk of our drilling to date has been concentrated on what we call the core and the central portion of the position. We are now moving out to the western portion of the acreage position to evaluate it. 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.


Your next question comes from the line of David Heikkinen with Tudor Pickering Holt. Please proceed.

David Heikkinen - Tudor Pickering Holt

Just going through your guidance and I saw the 8-K, but working through numbers I understand you got 3 million barrels of curtailment. It 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 the third?

Or is it just you haven't started curtailing yet?

Vince White

David, this is Vince. We actually just started implementing the curtailments. 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.

David Heikkinen - Tudor Pickering Holt

Looking at kind of run rates, so fourth quarter volumes at 61 million barrels and third quarter is around 57 million barrels of oil equivalent to hit the midpoint of guidance.

Vince White

That's correct.

David Heikkinen - Tudor Pickering Holt

You talked about Jackfish ramping and Polvo, what's your natural decline rate from third quarter to fourth quarter, then if you have the same breakdown that you walk through as far as third quarter, what's in the guidance?

It would be useful to get the same thoughts on fourth quarter.

Dave Hager

If you take our actual Q2 production of 65.4 million barrels, you take the midpoint of Q3 of 61 million barrels that would imply a reduction of 4.4 million barrels. We would break that out basically as about a million barrels due to the voluntary reductions that we've described.

The plan turnaround at Jackfish and Panyu, probably about another million barrels. We have about half 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.

It will just under in the third quarter relative to second quarter. It will probably result in the reduction of about a million barrels or 900,000 barrels there. So that leaves the natural production decline from second to third quarter of about a million barrels.

David Heikkinen - Tudor Pickering Holt

Then I was trying to do the same breakdown of third into fourth on the 61 million barrel midpoint, just at the midpoint of full year 245 would be 57 million barrels, can you do the same breakdown.

Dave Hager

For there, we would have about 2 million barrels of voluntary reductions going from third to fourth quarter. Of course Jackfish and Panyu would come back on. So that add back about a million barrels. We also anticipate though about a million barrels of decrease wafting and that's just a timing of waftings on our international properties which should be about 2 million barrels for production decline.

David Heikkinen - Tudor Pickering Holt

That's mostly US gas on the production decline?

Dave Hager


David Heikkinen - Tudor Pickering Holt

Thinking about capital spend right then, have you thought about what that implies for 2010 production and the correct amount of spend?

John Richels

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.

Vince White

I would add the fact that we have 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.

David Heikkinen - Tudor Pickering Holt

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

Vince White

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 [number] for it.


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

Doug Leggate - Howard Weil

Conceptually, you talked a little bit about hedging and the increases 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 production in the Barnett in particular? I'm just trying to think how your planning comes together on that?

John Richels

First of all, as you know there are different ways to handle risk. Our philosophy in the past has been that if we had a strong balance sheet which we have traditionally had and if we are 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.

We actually went through and 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 many.

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. 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, 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 budget and as we 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.

Doug Leggate - Howard Weil

On the Cana, obviously you are accelerating it a little bit. Is that really more about establishing HBP or are the economics pretty attractive at these prices and maybe you could give us some color as to what the breakeven economics look like they are right now?

John Richels

It's both I'd say. Current $4 economics, there is certainly at least breakeven, probably a little bit better and normalized numbers are substantially better than that. So 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.

So 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.

Doug Leggate - Howard Weil

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

Vince White

Well, what we've said is that we think we have net risk potential out here of about five Tcf. That translates to risk locations of little bit in excess of 1500.

Doug Leggate - Howard Weil

Were there any reserve upward revisions in the quarter that helped your depreciation charges?

John Richels

Actually, Doug, there were. All of our Jackfish barrels came back on. They came off at year end, both the Jackfish 1 and Jackfish 2 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.

Vince White

John said all the reserves on Jackfish 2, that is the ones that we lost at year end, but we are no place close to fully booked at Jackfish 2.

John Richels

We only booked at 80 million barrels at Jackfish 2. I mean the ones that came out off year end. Vince is right.

Doug Leggate - Howard Weil

300 million were back in the second quarter?

Vince White

That's correct.


Your next question comes from the line of Mark Gilman with Benchmark Company. Please proceed.

Mark Gilman - The Benchmark Company

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?

Dave Hager

There's actually on a number of the projects, we are saving the cost of completion. 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. Yes, it's more than just we don't like the price. It's that we can save some dollars as well.

Larry Nichols

There is one field, the Powder River, where the economics are marginal and so we are setting that field in or portions of it for negative cash flow. But the vast majority of their curtailments are clearly 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.

Mark Gilman - The Benchmark Company

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?

John Richels

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 that whole field, 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 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 a terrific project.

Mark Gilman - The Benchmark Company

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 oil rates are you seeing?

Dave Hager

We are drilling a few on 20 acres, the bulk of them we are drilling are on 40-acre and 80-acre spacing. We are drilling a few on 20-acre and we are seeing performance of very similar, but very, very close to what we are seeing on the 40-acre and 80-acre spacing. So, it continues to have very similar economics.


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

Brian Singer - Goldman Sachs

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

Dave Hager

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

Brian Singer - Goldman Sachs

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

Dave Hager

It's an exciting project and certainly we are drilling an appraisal well right 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 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.

Larry Nichols

Plunging forward.

Brian Singer - Goldman Sachs

On the Cana play, you highlighted the 8.4 million a day IP rate and expectations for a 14 Bcfe work and I think implied in that a much shallower decline rate relative maybe what we are typically used to in some of these plays. Can you just talk a little bit about that and what you are seeing from some of the wells that have been in production for a little bit longer?

Dave Hager

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 on the order of 5 million to 6.5 million cubic feet a day. Our EURs out there are ranging from around 6.5 Bcf to 9 Bcf per well. At those kind of numbers, it's a highly economic project.

Brian Singer - Goldman Sachs

Is there anything in a decline versus a normal 50% to 70% decline? It would seem like there seems to be a much shallower decline coming from the Cana-Woodford wells and I just wonder if that's right and if you are seeing that in the wells [30, 0:43]inaudible] that have been in production so far?

John Richels

These are always ranges, Brian. 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 on a regular basis. That was kind of an anomaly, that 14 million Bcf EUR well. What kind of interesting about the Cana as compared to the Woodford in Eastern Oklahoma, it's over pressured more, so it's a little bit different, some different production characteristics as well.

Vince White

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.

Brian Singer - Goldman Sachs

And if I could 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. Could you give us some sense on what the percent breakout is between what would be drilled to completed, but shut in versus drilled and not completed?

Vince White

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

Brian Singer - Goldman Sachs

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


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

Rashid Rehan - FBR Capital Markets

Any update on the data room for the lower tertiary sales?

Larry Nichols

The data room has opened, but we are not pushing that because we want to wait until the next Cascade 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.

Rashid Rehan - FBR Capital Markets

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 think about what CapEx could look like?

Darryl Smette

As it relates to the rigs, currently it's about a 40% decrease for the rigs we have under contract to 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 was 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.

Rashid Rehan - FBR Capital Markets

If there any dollar number besides these two savings and what would it add up to?

Darryl Smette

40% on a average rig cost. It's running right now about $16,000 or $17,000. 40% above that, about $23,000, $24,000 a day.

Rashid Rehan - FBR Capital Markets

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

Darryl Smette

Yes, we actually have seen a decrease in the basis differential in virtually all of the major producing areas over the last couple of months. The biggest change in basis differential just in the last month or so has been in the Rocky mountains which have been trading between dollar and a dime and $1.50, and going into this month it's actually trading between $0.30 and $0.45 cents.

We've actually seen a decrease in basis, in East Texas Gulf Crossing is now on and operating about 95% capacity and that basis differential has moved from about $0.50 cents down to about $0.20 cents this morning.

Rashid Rehan - FBR Capital Markets

And your [Transfer] 85 capacity is helping in all this, right.

Darryl Smette

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 that we are dropping off at places in between but certainly helping.

Vince White

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


Your last question comes from the line of Biju Perincheril with Jefferies & Company. Please proceed.

Biju Perincheril - Jefferies & Company

The completed well costs that you highlighted for in Cana, $8 million, is that a good number to use going forward?

Then you sort of alluded to the returns in Cana. Can you give us some rate of return metrics in Cana and compare to it what you are seeing in the Barnett? And also maybe some guesstimate of what you expect from Haynesville, the Carthage area?

Dave Hager

Yes, first to your question on Cana for the drilling costs, yes, we are seeing on the order of $ 8 million to $9 million per well. 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 Cana relative to Barnett, we are seeing as good if not slightly better economics for what we are currently drilling out in Cana as compared to the Barnett. Not to say the Barnett is not good. Obviously it hasn't changed to the negative at all.

Cana looks like it's as good or even a little better which means basically at a $4 Henry Hub, you are probably more like a 10% or so breakeven rate of return on those more normalized price at $5.50 or so. You are certainly looking at 20% to 25% rate of return at least on these type projects.

We are still in the early stages of Haynesville and we are still derisking the acreage. So I think we are going to see 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 550, we are getting between 20% to 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 to drive drilling costs down and the kind of recoveries we are anticipating of five to six Bcf per well.

Larry Nichols

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


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.

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