Devon Energy Corporation (NYSE:DVN)
Q3 2009 Earnings Call
November 4, 2009 11 am ET
Vince White - SVP of IR
Larry Nichols - Chairman and CEO
John Richels - President
Dave Hager - EVP of Exploration and Production
Doug Leggate - Merrill Lynch
Brian Singer - Goldman Sachs
Joseph Allman - JPMorgan
Bob Maurice - Citigroup
Joe Magner - Macquarie
Mark Gilman - Benchmark Company
Welcome to the Devon Energy’s Third Quarter 2009 Earnings Call. (Operator Instructions).
At this time, I’d like to turn the call over to Mr. Vince White, Senior Vice President of Investor Relations.
Good morning, everyone, and welcome to Devon’s third quarter earnings call. As usual, I will begin with some housekeeping items and then turn the call over to our Chairman and CEO, Larry Nichols, for his overview. Following Larry’s remarks, our President, John Richels will provide a financial review. Finally, after John’s comment, Dave Hager, Executive VP of Exploration and Production, will provide an operations update. We’ll follow that with a Q&A.
We generally try to hold the call to about an hour or so. If we don’t get to your question, we’ll be in later today, give us a call. As always, we ask the Q&A participants to limit their questions to one question and one follow-up. A replay of this call will be available through a link on our homepage later today.
During the call we’re going to provide updates of some of our 2009 forecasts based on actual results for the first nine months of the year and our expectations for fourth quarter. However, we will not be issuing a revised 8-K today. That’s because most of the estimates remain within the updated ranges that we provided in the Form 8-K that we filed on August 5, 2009. That 8-K is posted to the Estimates page of the Investor Relations section of devonenergy.com and the refinements that we provide to those estimates today will also be posted to the Estimates page of our website.
Please note that our references in today’s call to our plans, forecasts, expectations and estimates are all forward-looking statements as described under US securities law. While we always strive to give you the very best information possible, there are many factors beyond our control that could cause our actual results to differ from the estimates we provide. Therefore, we urge you to review the discussion of risk factors and uncertainties provided in the August Form 8-K.
One final compliance item. We will refer today to various non-GAAP performance measures. When we make reference to such measures, we’re required to make certain disclosures under US securities law. Those disclosures are available on the Devon Energy website at devonenergy.com.
Before I turn the call over to Larry, I want to give you a quick update on our Lower Tertiary sell-down. This process has attracted a very broad interest and we’ve had a strong showing in the data room. We’ve said all along that we will not ask for bids until the Kaskida delineation well results are in and we are confident that we will complete those operations on Kaskida this month. That scheduled would put us with bids due by the end of December.
Now, I’ll turn the call over to Devon’s Board Chairman and CEO, Larry Nichols.
The third quarter was another outstanding one for Devon. We continued the trend that we’ve had for several quarters now, quite a few of exceeding expectations for oil and gas production, while at the same time, driving cost lower. Third quarter production for oil, gas and NGLs totaled 61.9 million barrels, exceeding our guidance by about 900,000 Boe. This represents a 6% increase over third quarter of 2008, and this is in spite of voluntary curtailments that we had during the third quarter of about 1 million equivalent barrels.
We drove LOE per equivalent barrel down by 19% from a year ago quarter-to-quarter, fueled by higher than expected production, improving costs and strong oil prices. We generated net earnings of $499 million for the third quarter. After excluding those items that we and analysts generally do not forecast, we earned $491 million or $1.10 per share, far exceeding the First Call mean estimate of $0.90 per share.
We had cash flow from operations of $1.2 billion for the quarter, which more than funded our total capital expenditures for the period and generated free cash of $168 million. We exited September with cash and equivalent credit lines of $2.8 billion and a healthy net debt to cap ratio of just under 31%.
While natural gas prices declined from the second quarter this year, prices for oil and natural gas liquid strengthened, which drive our sequential increases in third quarter sales and earnings. Oil and gas liquids accounted for 60% of Devon’s oil and gas revenues in the third quarter, which underscores again the importance of Devon’s balance portfolio and the balance between oil and gas that we talked about so much in the past really paid off this quarter.
While natural gas prices are still weak today, as we look ahead, we do see improving economics in the North American natural gas business. Costs have come down considerably from the peaks of last year. Based on our own internal forecast as well as the future strip, our key development gas projects all deliver attractive rates of return that are well above our cost to capital.
With the improving outlook for natural gas prices with the impact of the sell-down of our Lower Tertiary and with lower overall industry cost structure, this should allow us to step up activity next year. With superior acreage positions in many of the best shale plays, we have no shortage of opportunities.
We are currently adding drilling rigs in our major shale development plays and will continue to do so in 2010. The step up in activity for the remainder of the year will move us outside the range of our previous 2009 E&P capital guidance. For 2010, we are currently working through the budgeting process and expect to finalize the 2010 budget by yearend.
Based on our better than expected third quarter production and the impact of higher activity levels in the fourth quarter, we are increasing our full year 2009 production forecast by 3 million barrels to a range of 247 million to 249 million Boe. The midpoint of that range, which is 248 million equivalent barrels, represents a 4% increase of 2009 over full year 2008 production.
In the separate areas, to add more productability to 2010 price realizations and to ensure sufficient cash flow to support the increased level of activity, we have already hedged a significant portion of our oil and gas production for the year. We have entered into swap contracts for the full year 2010, covering about 1.1 Bcf of gas per day at a weighted average NYMEX price of $6.18 per MMBtu.
We have also protected the price of about 68,000 barrels per day of our 2010 oil production with costless collars. The weighted average of the floor for the oil collars is $67.05 per barrel with a weighted average ceiling of $96.07 per barrel. To put this in perspective, the 2010 oil and gas hedges cover volumes equal to about 37% of our current production.
In recent months, we have also added hedge positions for the fourth quarter of 2009. We now have about 1.1 Bcf per day protected at a weighted average gas price of $5.65 per Mcf. This represents about 45% of our estimated fourth quarter natural gas production. So we enter the final months of 2009 with an improving outlook for our core North American business and with an eye to a much more active 2010.
With that, I’ll turn the call over to John Richels for the financial review and further outlook.
I’ll begin by looking at some of the key drivers that shaped our third quarter financial results and review how these factors impact our outlook for the fourth quarter. Let’s begin with production.
In the third quarter, Devon’s production totaled 61.9 million equivalent barrels or approximately 673,000 barrels per day. As Larry said, this exceeded our guidance by approximately 900,000 barrels. The lack of hurricane downtime in the Gulf of Mexico and lower royalty rates on Canadian natural gas production drove most of that outperformance.
When compared to the third quarter of 2008, Devon’s companywide production increased by 36,000 barrels per day or 6%. The US onshore segment continued to deliver growth in spite of voluntarily reducing production by approximately 1 million equivalent barrels during the quarter. Led by growth from our Arkoma-Woodford and Cana shale plays, US onshore production grew by 12,000 barrels per day or 3% over the third quarter of 2008.
In Canada, third quarter volumes climbed by more than 6% year-over-year. Growing production from our Jackfish SAGD oil project and lower crown royalty rates on Canadian gas production were the primary growth drivers. Production from our international properties increased by 36% or 11,000 barrels per day over last year’s third quarter. Greater production from our Polvo field in Brazil and higher output from the ACG field in Azerbaijan accounted for the increase.
As Larry mentioned earlier, based on our strong year-to-date results and our outlook for the fourth quarter, we’re once again increasing our 2009 production outlook. We now expect full year production to be between 247 million and 249 million barrels. This revised forecast implies a fourth quarter production range of 58 million to 60 million barrels, which is up about 2 million barrels from our previous guidance for Q4.
You’ll recall that last quarter we mentioned that we were deferring well completions and reducing incremental compression, resulting in a voluntary reduction in fourth quarter production of about 12 Bcfe or about 2 million equivalent barrels. So, the 58 million to 60 million barrel fourth quarter production forecast is in spite of that reduction.
Moving on to price realizations, starting with oil, in the third quarter, the WTI benchmark price averaged $68.25 per barrel. That’s about 14% improvement over the last quarter. In addition to the higher index prices, oil differentials improved for most of our geographic regions. The most notable regional outperformance occurred in Canada. For the second quarter in a row, heavy oil differentials were tight, resulting in a third quarter realized oil price in Canada of about 81% of WTI. Companywide, our realized oil price in the third quarter averaged $61.12 or 90% of the WTI index, about $9 per barrel higher than last quarter.
Looking to the fourth quarter, we expect differentials to widen somewhat in Canada as we move beyond the summer high demand months. As a result, we anticipate fourth quarter realized prices in Canada to come in around 65% of WTI. Companywide, we expect fourth quarter oil price realizations to average about 80% of WTI.
On the natural gas side, the third quarter Henry Hub Index averaged $3.39 per Mcf. Our companywide gas price realizations before the impact of hedges came in at 84% of Henry Hub or $2.84 per Mcf. In the third quarter, we had hedges totaling 347 MMBtu a day with the weighted average floor of $7.25. Cash settlements from that hedging position increased our companywide realizations by $0.53 per Mcf to an all-in price including hedges of $3.37 per MCF.
Turning now to marketing and midstream, our third quarter marketing and midstream operating profit came right in line with our expectations at $100 million, and for the fourth quarter, we expect a similar level of marketing and midstream profit.
Before we move to expenses, please note the $96 million of other income reported in Q3. Most of this amount, approximately 84 million, is attributable to a favorable legal decision associated with deepwater royalties. With the final ruling having been received, we have now reversed the contingent liability that we had previously recorded.
Moving now to expenses, our third quarter lease operating expenses totaled $505 million. This result marks the fourth consecutive quarter that Devon’s lease operating expenses have declined. On a per unit basis, our third quarter LOE came in at $8.16 per barrel. That’s about $2 a barrel lower than the year ago quarter. The reduction in LOE reflects declines in virtually every expense category across all of Devon’s major producing regions.
Looking ahead, we expect to continue to achieve cost savings on oilfield services and supplies. For the fourth quarter, we’re now forecasting LOE to decline to a range of $485 million to $500 million.
Our third quarter DD&A expense for oil and gas properties came in at $480 million or $7.75 per barrel. That’s near the bottom of the guidance range provided during our conference call last quarter. For the fourth quarter, we’re forecasting our DD&A rate to be between $7.50 and $8 per barrel of production.
Shifting to G&A expense, Devon’s third quarter G&A expenditures totaled $137 million. That’s about $9 million decrease in G&A costs when compared to the third quarter of 2008. This decline in G&A is due to a companywide focus on reducing costs.
Looking ahead, the fourth quarter of 2009 will include approximately $20 million of non-cash expense due to the issuance of annual equity compensation. When you include this non-cash expense, we expect fourth quarter G&A expenditures to increase to a range of $150 million to $170 million.
The final expense item I want to touch on is income taxes. For the third quarter, we reported income tax expense of $93 million or 16% of pre-tax income. However, this number has some unusual items that require explanation. First, we received a $59 million benefit in the third quarter due to income tax accrual adjustments that were recorded in conjunction with the filing of current and amended prior year returns. Additionally, we recognized about $22 million of current tax benefits associated with international exploration and $40 million of deferred tax benefits due to the fair value changes of derivatives.
When you back out the impact of these items, our adjusted tax rate for the quarter would have been just over 30% or right in line with our guidance. In today’s earnings release, we’ve provided a table that reconciles the income tax effects of items that are typically excluded from analysts’ estimates.
Cutting all the way to the bottom-line, adjusting for items that most analysts don’t include reduces reported earnings slightly to $491 million or $1.10 per diluted share. While well below earnings in the year ago quarter due of course to much lower gas prices, it marks a 29% increase in adjusted earnings per share on a sequential quarterly basis. As Larry mentioned earlier, these results exceeded the First Call consensus by about $0.20 per share.
Now, before I turn the call over to Dave, I want to conclude with a quick review of our financial position. We generated free cash flow of $168 million in Q3. As a result, we ended the quarter with $905 million of cash on hand and $1.9 billion of unused credit facilities. The reduction in net debt during the quarter combined with the net earnings brought our net debt to capitalization ratio down to 31%. That’s about 21% as we calculated under the terms of our bank credit agreements. So, we continue to maintain a very strong balance sheet with plenty of available resources giving us significant financial flexibility.
At this point, I’m going to turn the call over to Dave for an update on operations.
Our oil and gas properties continue to perform very well during the third quarter. Despite much lower activity levels, we delivered some very positive results.
We invested $832 million of exploration and development capital in the third quarter and ended September with 30 Devon operated rigs running. Total exploration and development capital for the first nine months was just under $3 billion. During the third quarter, we drilled 233 wells, including 225 development wells and 8 exploration wells. All but three of the development wells were successful and three of the exploratory wells were successful.
In the Barnett Shale field in North Texas, we moved one rig to the Cana field in the third quarter (inaudible) in the quarter was seven Devon operated rigs in the Barnett. Devon’s net production in the Barnett averaged 1.1 Bcf equivalents per day for the quarter, 7% below the second quarter of this year. This decrease is consistent with our reduced activity in the field and the decision to both reduce incremental compression and push completions back to late in the year. As we reported in August, we expect to exit the year producing about 1 Bcf equivalent per day from the Barnett net to Devon.
By the end of 2009, we expect to have drilled a total of about 210 operated Barnett wells for the year. At September 30, we had 159 Barnett wells awaiting completion. In addition, we plan to drill 48 wells in the fourth quarter. By picking up completion activity late in the fourth quarter, we now expect to work that inventory down to approximately 150 wells awaiting completion by yearend. As Larry mentioned earlier, we are ramping activity up going into 2010 on most of our major gas plays. We expect to have 16 operated rigs running in the Barnett as we enter 2010.
In addition to the rig we moved from the Barnett to the Cana, we also recently moved one of our rigs from the Woodford Shale in the Arkoma Basin to the Cana play. We have continued with a two operated rig program in the Arkoma-Woodford and brought 13 additional wells online in the third quarter. Our net Arkoma-Woodford production averaged 74 million cubic feet of gas equivalent per day for the third quarter, a 55% increase over the third quarter of 2008. Between now and yearend, we will add three additional operated rigs as we prepare for increased activity in 2010.
Moving to the Cana-Woodford Shale in Western Oklahoma, we increased our operated rig count to six during the third quarter following the relocation of the rigs from the Barnett and Arkoma-Woodford that I mentioned. The additional rigs in the Cana enable us to accelerate the process of de-risking and securing the 109,000 net acres we have in the play area. We continue to see outstanding results from Cana and believe that core Cana to be one of the most economic shale plays in North America.
In the third quarter, we brought eight wells online with average 24-hour IP rates of 6.5 million cubic feet equivalent per day. Production history from our 26 long lateral horizontal wells drilled in the core area of the play now support a tight curve approaching 10 Bcf equivalent per well, including 2 Bcf equivalent of NGLs. Third quarter net production from Cana averaged 53 million cubic feet of gas equivalent per day, more than seven times that of the third quarter of 2008 and up 55% on a sequential quarter basis. We plan to add an additional rig in Cana by yearend
Shifting to the Haynesville Shale in East Texas, I’ll remind you that Devon has about 570,000 net acres in the greater Haynesville trend, equally divided between Texas and Louisiana. More than a year ago, we began evaluating our position around Carthage where we have 110,000 prospective net acres and over 1,800 conventional producing wells.
We continue our Haynesville de-risking efforts in the area during the third quarter and brought our eighth well online. The Jernigan A 4H Panola County achieved a 24-hour IP rate of 8 million cubic feet per day. With numerous cores, 3D seismic, geologic mapping and correlation with our wells drilled to-date, we have now identified about 1,000 risked Haynesville drilling locations and 4 Tcf of net risk resource potential to Devon in the Greater Carthage area. We expect EURs in this part of the play to average roughly 6 Bcf equivalent per well.
After drilling our eighth well in the Greater Carthage area, we shifted our focus to de-risking our 47,000 net acre position south of Carthage. This is primary term acreage located mostly in San Augustine and Sabine counties in Texas and Sabine Parish in Louisiana. Our first Haynesville horizontal test in the area was drilled in San Augustine County and had some impressive results.
The Kardell 1H achieved an average continuous 24-hour flow rate of 30.7 million cubic feet per day. We believe that this is the highest IP rate of any Haynesville Shale well ever drilled. The well was drilled to a vertical depth of 13,850 feet with a horizontal section of 4,500 feet. Devon operates the well with a 48% working interest. Although the Kardell well is our first in the area, it is a strong indicator of the potential of our Southern Haynesville acreage.
In the fourth quarter, we will ramp-up drilling activity in the Haynesville to a five-rig program for most of 2010. This additional activity combined with our non-operated drilling activity will enable us to begin securing our term acreage in the southern portion of the play. We estimate that about 105 wells will need to be drilled over the next two years for us to adequately secure the acreage we are de-risking in the southern portion of the Haynesville.
Having drilled fewer than 10 Haynesville wells to-date, we still have considerable work to do. We will continue to systematically de-risk our position just as we have done in the Barnett Shale and are currently doing in the Cana-Woodford.
Moving to the Permian Basin, it’s worth noting that while our production mix is weighted in natural gas, we also have a deep portfolio of growth opportunities on the oil side. Our Wolfberry oil play in West Texas where Devon has more than 98,000 net acres is one example. The Wolfberry is a repeatable play that generates outstanding rates of return with low geologic risk.
With the current value proposition for oil versus gas, Wolfberry wells can have a positive impact on cash flow. We currently have two rigs running and plan to add a third rig later this month. This will allow us to bring our 2009 drilling program up to 45 wells. We have significant running room in the Wolfberry with as many as 2,500 locations on an unrisked basis or an estimated 1,100 risked locations.
Now shifting to the Gulf of Mexico, we continue appraisal and development work on our deepwater discoveries in the Lower Tertiary trend in the third quarter. Our 50% on Cascade development project is progressing well. We are preparing to move the West Sirius rig to Cascade this month to begin completion operations of the first of two producing wells. This well was drilled earlier in the year and encountered 500 feet of net pay.
Construction of the FPSO is approximately 95% complete and it should arrive in the Gulf of Mexico in January. The project remains on schedule for first production in mid 2010.
At Kaskida we are drilling an appraisal well 5 miles west to the original discovery. This appraisal well would test a second structural feature on the Kaskida prospect and has the potential to increase the size of the resource that we believe is already the largest of Devon’s four Lower Tertiary discoveries. We said in our quarterly conference call in August that we expect to finish operations on the well in September.
While drilling in the Wilcox section, we encountered an encouraging oil column and are now evaluating options to sidetrack the wellbore for further delineation information. Devon has a 30% working interest in Kaskida and BP owns 70%.
Moving now to Canada, at our 100% Devon-owned Jackfish thermal oil project in Eastern Alberta, we completed two weeks of scheduled downtime for plant maintenance in the third quarter. Since then, we have been steadily ramping Jackfish production back up, sustaining a daily rate of 31,000 barrels per day. We remain on track to reach the facility capacity of 35,000 barrels per day before yearend. We continue to see outstanding well and reservoir performance at Jackfish.
Our steam to oil ratios have improved to 2.4 and the cumulative ratio is below 3. This top tier performance validates our frontend geologic work done to identify and delineate the high quality Jackfish reservoir.
Based on the performance of Jackfish, we are excited about Jackfish 2 project. Jackfish 2 construction is advancing on schedule and is now over 50% complete. In July, we began drilling the initial well pairs. Like our Jackfish project, Jackfish 2 is expected to produce 35,000 barrels per day and to recover 300 million barrels. Jackfish 2 remains on schedule first oil in late 2011.
Over the last couple of years, we have been in the process of evaluating the potential for a third phase of Jackfish development. This involves drilling a number of stratigraphic core wells, analyzing the cores and performing a detailed geologic study to determine the location and quality of the reservoir.
We have now completed this evaluation process and will seek approval from the regulatory authorities and our Board of Directors for Jackfish 3. This is a look-alike project to Jackfish 1 and 2 with 300 million barrels recoverable and production capacity of 35,000 barrels per day. Pending regulatory approval and formal sanctioning, we would begin site work by late 2011 with plant start-up targeted for 2014. Devon has 100% working interest in each of the three Jackfish projects.
Shifting to the Horn River Basin in British Columbia, Devon has 153,000 net acres under lease. During the third quarter, we completed and tied-in three horizontal wells from our 2008, 2009 winter drilling program. Initial production rates from these wells are averaging about 900,000 cubic feet of gas per day for each frac stage. This is consistent with the better wells drilled to-date in the Horn River play.
Production history is limited, but early indications suggest first year decline rates could be as low as 50%. With only three producing wells in the play, it is still in early stages, but we are very encouraged with these result. Going forward, we will continue to fine-tune our completion techniques in order to achieve the best economics at Horn River.
Over time, we expect to achieve drilling and completion costs of about $8 million per well with average recoveries between 7 and 8 Bcf per well. We will continue to de-risk and secure our acreage with eight horizontal wells planned for 2010.
Finally, in Brazil, in the third quarter we wrapped up exploratory drilling on the Petrobras operated (inaudible) prospect located in the Block BM-BAR-1 in the Barreirinhas Basin. That well was unsuccessful and has been plugged and abandoned. The rig is now on location and just spud are pre-salt in Itaipu prospect located on Block BM-C-32 in the Campos Basin. This prospect is 16 miles north of our Wahoo discovery and adjacent to Petrobras Jubarte and a pre-salt well park discoveries. Devon will operate the well with a 40% interest. We are also currently drilling an appraisal well to the Wahoo discovery on Block BM-C-30. Wahoo is operated by Anadarko and Devon has a 25% interest.
So, in summary, the quarter brought very encouraging results from all of our major shale plays and exciting news about the outlook for a third Jackfish project. We are now in the process of ramping up activity for a more robust drilling program in 2010.
At this point, I’m going to turn the call back over to Vince to open it up for Q&A.
Operator, we’re ready for the first question.
(Operator Instructions). Your first question comes from the line of (inaudible) of Bernstein, LLC.
Obviously, your debt to cap has come down significantly. It sounded from your commentary as if you are considering or looking at acquisitions. Did I get that impression correctly or is that incorrect?
I have no idea how you got the notion we were looking at acquisitions. The debt is coming down because the cash is building up with our oil revenues coming in. There is no change on our attitude toward acquisitions that we’ve had over the last five or six years. It’s difficult to see any change certainly in a major transaction. We continue to look for small add-ons here and there that are consistent with our leasing position. If you look at the acreage portfolio that we have around the company, we are awash in opportunities and don’t see any holes that we need to fill with any acquisitions, which is what we said for a long time.
On the cost deflation side, obviously there’s been a huge amount of cost deflation in the industry from service costs, drilling costs, particularly fracking costs. Now that the service industries earnings that are operating margin, doesn’t appear – so we ought to take those any lower, where do you see the real opportunity to continue to drive down costs?
I think the major opportunities we have, I think we’re very effective when we have repeatable play types like we have in the shale plays that we can continue to drive down the drilling cost by just continued improvement opportunities, and we certainly done an outstanding job of that in the Barnett, decreasing the drilling time from 30 days to 15 days, in some cases even less than 10 days on these wells.
We’re continuing that type activity also in the other shale plays, the Haynesville, the Cana, the Woodford where we haven’t drilled as many wells, we’re continuing to drive down those costs and use the experience we had in the Barnett and import that to the other shale plays. So I see that’s probably the biggest opportunity we have.
I just add one point as well, if you recall that in 2009 we were essentially drilling with committed rigs that were not at the spot price, and we also had -- we talked earlier about the fact that we had acquired and contracted for a lot of tubulars at the end of 2008, when tubulars were in short supply. With our reduced program this year, we are still working that off. So we ought to see a reduction in cost going forward just on that basis as well in addition to what Dave has said.
Just to clarify, can you confirm, what percentage of your capital costs on a well are actually day rate drilling costs on say Haynesville well?
He asked for a percentage.
A percentage of the total, oh.
I think it’s about 20%.
Your next question comes from the line of Doug Leggate of Merrill Lynch. Please proceed.
Doug Leggate - Merrill Lynch
A couple of questions. John Richels, I guess the hedging policy, are we going to see this get a little more aggressive as we move forward into 2010, because I guess you still only have only about 30 your total production hedged. Just kind of outline how you’re thinking about that right now?
Doug we talked before in the past we tended to take the view that there are lot of ways to manage risk, and we managed that risk by keeping very strong balance sheet and remaining a low-cost operator. However, as we get into more plays that have a lot of momentum that you can’t turn on and off regularly or easily, having a little larger hedge position is a good thing.
I think you see we’re already a little more active than we have been in the past. So as we go forward, we’re going to monitor our view of prices, our view of capital costs and our view of the industry direction carefully and make that call, but I think you could see us do it in on a bit more regular basis.
Doug Leggate - Merrill Lynch
Maybe I’m reading too much into it John, but you covered about a Bcf a day for next year, and you are producing about a Bcf a day from the Barnett, which is probably arguably one of your biggest decline issues in the company. Is there any relationship between those two as the implication that we’re going to stabilize and start to grow again in the Barnett?
No, not at all, Doug, as a matter of fact we still notwithstanding discussion around the Barnett. The Barnett is still a terrific play. We have almost 7,500 locations in the Barnett, and while we have seen a rollover in our production as a result of reduced activity levels.
As we ramp up our activity levels, we’re going to increase that production again, and we think there’s a lot of running room for us there. So there’s absolutely no correlation.
Doug Leggate - Merrill Lynch
Okay. I’m going to guess that wasn’t my follow-up, so if I could risk my follow-up. In the Cana, I don’t think Dave mentioned anything by way of how much running room you might have there, obviously with the economics and the NGO portion and so on. I imagine that’s screening pretty well. What kind of activity levels can we expect, and what kind of location backlog do you have there? If you could widen the discussion a little bit on the Cana that will be great. Thanks.
We currently have 109,000 net acres in the play. The play is essentially leased up. It’s essentially held by two companies, ourselves and Cimarex. When you look at it, we think that we have up to about 1,600 risk locations there, and we give it a total potential on the order of 5 to 6 Tcf. So you can see it’s essentially a billion-barrel oil-field net to Devons. So it’s a very substantial opportunity with very strong economics particularly because of the liquids content.
Doug Leggate - Merrill Lynch
What are those well costing to drill it?
On average, the most recent wells we’ve been drilling on the order of around $8 million.
Doug Leggate - Merrill Lynch
You think it’s only [done say to that] or is that pretty much as good as it gets?
We’re always improving. So we have drilled a number of wells out there, but we’re continuing to drive those costs down. So I wouldn’t say there’s a huge amount of improvement, but I think we’ll continue to improve on that number.
Your next question comes from the line of Brian Singer of Goldman Sachs. Please proceed.
Brian Singer - Goldman Sachs
When we look at your comment on Kaskida, I know you highlighted that this has the potential to be resource additive, but because it was an appraisal well, could you perhaps add a little bit more color on what was encouraging about the oil column versus what might have been expected and what might you need to see to deem the result commercial?
Brian, obviously, BP is the operator here, and they’ve indicated that they don’t want to do a release on this well until the operations are through. They have approved us to say what we’ve said, but when you consider that this well is something like 5 miles away from the discovery well at Kaskida and it has a separate geographical feature or a second high, just the fact that it’s oil-charged is a very positive indicator to us.
When you ask why that is encouraging is that there were a couple of possibilities. One was that it was also well charged and the other was that it was not. So the fact it is full of oil we view it as encouraging.
Brian Singer - Goldman Sachs
Secondly, on Cana-Woodford, I think we may have discussed this in the past, but the 6.5 million cubic feet a day IP compared to an EUR of 10 Bcf a day. The IPs tend to be a little bit less relative to the EUR versus other plays, and wonder given that it seems like some of the well results that you’ve drilled in the past as well as the IPs coming in are better than expected. If you can talk about the decline profile that you expect and what you’re seeing?
We have found that really we feel to maximize the EUR on these wells that are out here, that it’s better from a completion standpoint to bring them on a little bit slower than we do some of our other plays, minimize the migration of finds and things like that.
So we’re just doing that from a prudency standpoint to maximize the EUR. You’ve made a good observation on that, I agree, that the IPs are a little bit lower in relation to other plays. We’re very confident that what we’re having is somewhat lower declines than the first year, because we’re bringing them on at lower rates and will achieve those type EURs that I described.
Brian Singer - Goldman Sachs
It seems like choking back the wells, what do you think they could be producing, or I guess the other side of the question is, how long can that 6.5 million a day rate be sustained before you do see a decline?
Well Brian, it is hard to say exactly what, they will obviously be a little higher. The other thing is with these wells they have that other component that Dave was talking about of having that high liquids content. So, that influences to some extent the way we bring them on as well. So I’m not sure that we have a good answer for what a kind of hypothetical IP would be, if we open up that choke a little faster.
Brian Singer - Goldman Sachs
Great. If I could ask one last one, and I know you haven’t put out official guidance for 2010, but how are you thinking about just overall growth when we think about the inventory that’s scheduled to come on. Do you expect overall production both oil and gas to be up next year?
Brian you’re asking us to get out in front of our forecast for next year, and we’re in the process of finalizing our budget. We’re not going to answer that specifically, but we do think Devon has the opportunity and the resources to be a long-term grower.
Your next question comes from the line of Joe Allman with JPMorgan. Please proceed.
Joseph Allman - JPMorgan
In terms of the ramp-up and the shale plays, I know in that release you put out the other day, you said that in Haynesville you’re going to have a five-rig program in that Southern part of East Texas.
What’s your intention elsewhere in East Texas or Louisiana and Haynesville? In the Barnett, you have got seven rigs running now, what’s the plan for 2010? Any kind of estimate about what kind of production you might be seeing in the Barnett shale as you exit 2010 or go out to 2011 or any period in the future?
We do have the five-rig program in Haynesville. This is directed towards the primary term acreage in the Southern part of the play. We also have a lot of opportunities in the greater Carthage area. We are in the order of 952,000 identified locations. Those are essentially held by production. So we don’t have an urgency to move on those. So we’re really finalizing our capital plans right now to decide how much, if any rig activity we want to put on that versus focusing on the primary term acreage and securing that acreage.
In the Barnett, we do have seven rigs. We’re going to be ramping up to 16 by year end and we’re having probably around 17 rigs working for most of next year. That’s our current plan in the Barnett. We think that with that level of activity that as John mentioned earlier, that we will not be declining the Barnett. It will be flat to starting to grow again in the Barnett with that level of activity.
Joseph Allman - JPMorgan
If you just step back, industry wide, I mean, do you think that Barnett has basically flattened out here, or do you think it can grow based on your activity and the activity of others.
I think it’s hard for us to judge other people’s position very well. I know that the bulk of our acreage is really located right in the core of the play, and Denton, Tarrant, Johnson, Wise, Eastern part of Parker County, and so the vast majority of our acreage is located there.
That’s where the best wells have been drilled, and we still see that we have a lot of running room on that acreage, and we’ve looked at maps comparing our position relative to other companies in that area.
We can see that our well density is not nearly as great as others have. So I can’t comment overall about other companies, but I do know that it’s best part of the play, we have a lot of running room to go.
Your next question comes from the line of [Scott Rumas] of Simmons & Company. Please proceed.
Regarding your recent Haynesville well and San Augustine County, can you give us a little color on the completion design of that well? I also noticed that the choke size was about 3764, and that looks to be a little wider than other chokes. So if you could give some other detail as well?
It’s about 2,000 feet deeper, so I think much of the Haynesville has been up in the Carthage area. So we’re dealing with a little bit higher pressures, which, of course, helps out on the deliverability side. It gives you higher rates as well.
I know there have been some questions about this higher choke size. I think anybody with some engineering knowledge understands that what you’re really trying to do here is to monitor, you’re looking at the flowing casing pressure. That’s the most important thing.
I can tell you every time we increase the choke size, our production rate increased significantly, and our flowing casing pressure remained very high. The only reason we kept increasing the choke size, is we’re trying to get back some of the frac fluid. We still only recovered about 12% of the frac fluid as we speak.
So, we’re just trying to get the well unload and we got a very high production rate. So I can tell you this is an extremely strong well. I wouldn’t focus on the choke side. The more important thing is what kind of pressure are you flowing the well at with this high larger choke size. I think you can see that our pressure of over 6800 PSI is a very high pressure that we’re flowing this well at.
How many frac stages did you guys complete this well with?
I think it was a 12-stage frac.
That’s right, it was 12.
Okay, and then how has the production held up?
Well, we just increased it, and we had actually shut the well in here briefly, because when we go south, had a shut-in, we had a little bit higher than pipeline spec on CO2. So we shut that in to I guess some equipment modifications, and then we’ll be opening the well back up very soon.
Then moving to Horn River, can you guys mention the completion designs there and the activity level for 2010?
Our idea in the Horn River was that what we were really focusing on is what kind of productivity we could get per frac stage. So we recognize that if we wanted to go out there and put 10 or 12 stage frac, we could do that but we just didn’t feel it was necessary at this point of the play to do that.
We recognized there was essentially a linear relationship, we believe, of about 0.9 million cubic feet per day per frac stage, and we proved that. So, we put on the order of 4 to 6 frac stages on these wells, and we verify that ratio and so we’re comfortable once we move into a full development of the field we can increase the number of fracs and get much higher rates and then we’ll the trade-off between the cost of additional frac stages and the additional production you get from that.
So that’s all we were trying to prove with this year’s activity, that ratio held up, and it did. Regarding future activity, we do have plans to use two rigs, going to drill about eight wells. Actually after the breakup, next summer we’ll be drawing eight wells to just continue to evaluate our acreage, to hold the acreage we have out there.
Although those are very long-term leases and just increase our understanding. So this is a resource that, again, we talk about the company being very opportunity rich, and you can see, when you put together something like this. So we’re not really pushing too hard at this point, but these results are certainly as good as anybody else is having out in the industry. We think we have a lot of future growth opportunity here.
Your next question comes from the line of Bob Maurice of Citigroup. Please proceed.
Bob Maurice - Citigroup
Larry, a question on your spending here. I noticed what you spent in the third quarter, and with all of the rigs you plan to add by year end. Can you tell us what sort of run rate that is on CapEx? In other words once you ramp up to that activity level that you’re going to get to with all the rigs you’re adding by year end, what sort of annualized CapEx rate is that?
I’m going to jump in here, Bob. This is Vince. We miss spoke and we do not expect this ramp-up of activity in the fourth quarter to push us outside our previous guidance range. So we’ll probably be near the top of our previous guidance, which is a little over 4 billion of EMP expenditures. The top end of the range was 4.1 and we still expect to be there for the full year.
Bob Maurice - Citigroup
Okay. Let me ask you, then, I know obviously your cash flow depends on commodity prices next year, but do you plan to spend within cash flow, or do you anticipate or you willing to supplement that with the proceeds from your lower tertiary sale when you look at your capital budget for 2010?
Well, one of the reasons that we are doing the sale of the lower tertiary is to bring balances spending back in line, as we said in past calls, so that we’re not spending as large a percentage in the gulf that are spending more of it on our core onshore properties. So we certainly do intend as long as oil and gas prices continue the way we think they will to ramp up our spending in 2010.
We haven’t put out an official amount for that yet because we haven’t finalized the budget, because we want to get all the data before we get there, but we certainly do intend to spend cash in any of cash flow from lower tertiary is cash flow. I imagine it is more likely we will use that for drilling activity based on the assumption that we see the economy recovering and oil prices continuing to be strong and gas prices continuing to improve.
Bob Maurice - Citigroup
Second question, on the Willcox section you saw in the Kaskida appraisal well, did you expect that to be part of the continuous reservoir from the discovery well, it was something that you anticipated might have been fault separated? I know BP you’re operating, you can’t say a whole lot, but in drilling that well, was it anticipated, or is it something now that you’re drilling a side tract, how did that differ from what you mapped out prior to drilling that appraisal?
I think you just said the key phrase. BP is the operator of this. So we have an agreement on what we will say here and what we won’t say. So I don’t know if I can add a whole lot more color to it than what we’ve already said. We have found an encouraging column and again it is five mills away and it’s essentially on a separate culmination from the original discovery well.
Your next question comes from the line of Joe Magner of Macquarie. Please proceed.
Joe Magner - Macquarie
I know there has been some question around Kaskida. Just to clarify the timing, it sounds like you have the information in hand to move ahead with the bid process, but there is a column in release that side track is being considered. Is that something that will be pursued once the sell-down has closed, or how does that factor into your…?
No. We’re actually [obtaining] the side track right now. It’s at 30,000 feet, so you never know for sure, but we anticipate that this could probably take on the order of a couple of weeks or so to finish the side track.
After that we will finish the operations at Kaskida. We’ll take the West Sirius rig over to cascade to begin the completion operations there. So we think that ones all of that information is given, then all of the data will be completed and available.
The final data will be completed and available in the data room including the side track. Everybody has seen everything except the side track already. Then we will be able to complete the sale process, which we said will be done by the end of December.
Joe Magner - Macquarie
I know you haven’t completed the 2010 planning process yet, but at one point, up until the middle of 2008 Devon was talking about a five year growth potential that it was in the 7% or 9% range. Is that a range that we can expect to see again, now that you are more confident about the outlook and planning to ramp up development of some of your onshore plays? If so, what sort of capital do you think would be required to drive that sort of annual growth going forward?
There were some price assumptions for oil and gas behind those forecasts, and our resource base has the potential to deliver that kind of growth and actually higher growth rates than 7%, and long-term, we live within cash flow. We have not been willing to shovel better equity out the door to support growth.
So it’s highly dependent on the future of commodity prices. Everybody has got a view on that; but assuming kind of strip pricing, I think you can expect Devon to move back into the high single digit growth rate over time.
Joe Magner - Macquarie
Last quick one on the Haynesville, what is your EUR expectations in that Southern area, and then with the deeper debts, what sort of completed well cost are you expecting, or did you have on the first well?
It’s a little bit hard to say what the EUR expectations are. We think up in the Carthage area, we’re probably on the 5 to 6 Bcf per well range, probably 5.5 to 6 realistically. We obviously think and maybe somewhat better down here, but again we just brought this well online, and we does have such very limited production data that it is a little bit hard to say.
So I would expect it to be a little higher than we’re seeing to north, but we just need to get more data to say for sure. As far as the well costs go, we anticipate that future well costs in this order will probably be on the order of around $10 million or so.
We spent a little bit more on this well because it was the first well we drilled down there. We did some extra work on this well, but we anticipate around $10 million going forward. Again a little bit deeper, little bit higher pressure requires different casing design, et. cetera and that’s why it’s a little higher well cost.
Operator we have time for one more question.
Your final question comes from the line of Mark Gilman of the Benchmark Company. Please proceed.
Mark Gilman - Benchmark Company
Just a couple of quick things, if I could. Do you have a cost estimate yet Jackfish 2?
We have said Mark Jackfish 2 is going to come in the neighborhood of a billion US. So it continues to – with the 300 million barrels that continues to have a obviously a very-very low F&D costs but and that’s up a bit from where we were in Jackfish 1, just with cost inflation but frankly with the reduction in activity in the oil patch and particularly in heavy oil sector in Canada, we are getting better services, and being able to bring it in faster and within budget and within schedule.
Mark Gilman - Benchmark Company
Could you talk just for a second about what kind of facility sharing agreement regarding Cascade Chinook you have and what that would mean in terms of your share of the facility production?
Mark, I don’t have all those details in front of me. We do have obviously arrangement of share the facilities, I believe it’s over 50/50 sharing arrangement that we have with the Chinook development. We basically have our half of about, if I’m not mistaking around, our half of around 85,000 Boe per day and facility.
Mark Gilman - Benchmark Company
Just one more quick one if I could. As per your stats, there were I guess four unproductive wells drilled in the international arena, exploratory wells in the quarter. Dave, you talked about one of them, what were the other three?
There were some very minor interest wells outside of our core areas that we’re actually countered in those stats, I think actually couple of wells that we never even talk about over in Russia, that were included in those stats and the other area is the Angola wells. We also have some dry holes in the Angola wells in the Angola block that we have.
I might also mention we’re currently drilling an appraisal well to our previous discovery in Angola. They are just [drilling] well over there, don’t have results on that yet.
Just to remind you, we’ve got a 15% working interest in those well, so that’s why Dave said there are really no low interest wells therefore we have the dry holes.
That ends today’s call. Thanks everybody for joining us.
Thank you for joining today’s conference. This concludes the presentation. You may now disconnect. Good day.
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