Welcome to Devon Energy's Third Quarter 2010 Earnings Conference Call. [Operator Instructions] At this time, I'd like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.
Thank you and good morning, everyone. Welcome to Devon's third quarter 2010 earnings call and webcast. Today's call will follow our usual format. I'll begin with some preliminary housekeeping and compliance items and then our President and CEO, John Richels will provide his perspective. Following John's remarks, Dave Hager, our EVP of Exploration and Production will cover the operating highlights and then finally, following Dave's comments, Jeff Agosta, our Chief Financial Officer, will review our financial results and our outlook. At that point, we'll open the call up to your questions. Our Executive Chairman, Larry Nichols and other senior members of the management team are with us today for the Q&A session. And as a courtesy to the other participants, we ask that each of you limit your questions to one initial inquiry and one follow-up. We'll limit the call to about an hour, and we will be around for the rest of the day to answer questions after the call.
A replay of this call will be available later today through a link on Devon's homepage. During the call today, we will provide some color on some of our forward-looking estimates based on the actual results for the first nine months of the year, and our outlook for the balance of 2011 and 2012. We will not be issuing a revised 8-K today, because our outlook for the remainder of the year falls within the updated ranges we provided in the Form 8-K that we filed last August. To access a comprehensive summary of our current guidance, which includes any refinements we make today, you can go to devonenergy.com and click on the Guidance link found within the Investor Relations section of our website.
Please note that all references today for our plans, forecasts, expectations and estimates, are considered forward-looking statements under U.S. Securities law. And while we always like to provide you with the very best data possible, many factors could cause our actual results to differ from those estimates. You can find a discussion of risk factors related or estimates in the Form 8-K that contains these forecasts. One other compliance note, we'll refer to various non-GAAP performance measures in today's call. When we use these measures, we are required under Securities law to provide certain additional disclosures and those are available for your review on Devon's website.
By now, most of you are aware that our decision to sell our international assets triggered the accounting rules for discontinued operations. We have therefore excluded international production volumes for all periods presented as well as the revenues and expenses associated with those. Those are collapsed into a single line item at the end of the statement of operations. That line item is labeled Discontinued Operations. For those interested in a more detailed view of our international results, you will find an additional table in today's news release that includes a detailed statement of operations and the related production volumes that are attributable to the international properties.
As a reminder, the third quarter is our first reporting period without financial or operating results from the Gulf of Mexico. While the international divestiture properties are considered discontinued operations, the Gulf of Mexico divestiture assets are included in results from continuing operations for previous periods. For that reason, we are providing supplemental information in our press release that isolates the results from Devon's North American Onshore operations or, in other words, the go-forward business.
As far as straight earnings estimates ago, the majority of analysts chose to report estimates to First Call that included only our North American Onshore operations. The mean estimate from those analysts that focused on continuing operations was $1.25 a share for the quarter, that compares to our non-GAAP earnings from continuing operations of $1.31 per share. So our actual results beat the street estimate by $0.06 or about 5%. With those items out of the way, I'll turn the call over to President and CEO John Richels.
Thanks, Vince and good morning, everyone. For the third quarter of 2010, Devon delivered another very solid performance both operationally and financially.
Production from our North American Onshore properties totaled 613,000 barrels of oil equivalent per day in the third quarter, a 4% increase over the third quarter of 2009. This production growth was driven by an 11% increase in oil and natural gas liquids production. In the current environment, oil and NGLs now account for roughly half of Devon's total oil gas and NGL sales revenue. Strong realized prices for our oil production and improved cost efficiencies resulting from the repositioning drove our adjusted earnings from continuing operations up more than 40% over the year-ago quarter to $571 million or $1.31 per diluted share.
Cash flow for balance sheet changes climbed 47% over the third quarter of last year and combined with the divestiture proceeds Devon's total cash inflows for the third quarter approached $4 billion, far exceeding our total capital demands for the quarter. As a result, we exited the month of September with an enviable position of $4 billion of cash on hand and a bulletproof balance sheet.
And on the operations front, we continued successful execution of our focused North American Onshore strategy as evidenced by quarterly production records at our liquids-rich Barnett and Cana shale plays and a multiyear production high from our Permian Basin properties. We also continue to make significant strides during the quarter towards completing the strategic repositioning that we announced just one year ago. In the third quarter, we completed the sales of our interest in the ACG field in Azerbaijan and our remaining assets in China. So to date, we've received aggregate pretax divestiture proceeds of approximately $6.8 billion.
The only significant divestiture package remaining, that's our Brazilian assets, is under contract for $3.2 billion. This transaction is pending approval by the Brazilian government and all indications are that this transaction will close as expected around year end. Following the closing, we'll have realized total proceeds from our divestiture program exceeding $10 billion or roughly $8 billion after-tax.
As we have always said, our objective in redeploying the divestiture proceeds is to optimize growth on a debt-adjusted per share basis. To accomplish this objective we've taken a balanced approach by directing $1.7 billion of sales proceeds to reduce debt and by allocating $1.2 billion to capture acreage opportunities across our North American Onshore property base principally in oil- and liquids-rich areas.
In addition, we initiated a $3.5 billion share repurchase program last May. At today's stock price, $3.5 billion equates to approximately 12% of our outstanding common shares. Through today, we've purchased over 15 million shares for right around $1 billion. This puts us on pace to complete the buyback within the 12- to 18-month timeframe that we originally announced.
Buying back Devon stock is an especially attractive alternative given our current stock price. Our share is currently priced in the mid-60s, translate into a net enterprise value of $110 per proven barrel. And this analysis attributes no value to the thousands of unproved locations that we have within our 13 million net acre resource base in North America.
Now before I turn the call over to Dave, just want to address a subject that we received a number of questions about, and that is our capital budget and our production profile for 2011. Given the significant divergence of oil and natural gas prices, similar to what we did in 2010, we expect to focus more than 90% of our 2011 capital on oil and liquids-rich opportunities within our existing portfolio. Although we're still in the process of finalizing our 2011 capital budget and have not yet submitted it to our board for approval, directionally, we have a pretty good idea where we want to go.
First, recapping 2010, we previously indicated that we expected full year E&P capital to total roughly $5.4 billion to $5.8 billion for our North American Onshore business. We're still comfortable with that range but taking into account continued upward cost pressures in the sector, we now expect to be in the top half of that range. This level of CapEx, I'll just remind you, includes a total of $1.2 billion of acreage capture that includes the $500 million that we invested to acquire the Pike oil sands acreage and about $700 million of additional leasing primarily in oil- and liquids-rich plays in the Permian and Mid-Continent. We would not expect to repeat this spend rate for leasehold acquisition in 2011. Adjusting for that gets you to a normalized spend for 2010 of roughly $4.5 billion for our go-forward North American Onshore E&P capital budget.
Based on this starting point and assuming a similar level of drilling activity in 2011, with some inflation for service cost, I would expect our 2011 E&P capital budget to fall between $4.5 billion and $4.9 billion. When you take into account Midstream and other capital, our total 2011 capital demands should be somewhere in the neighborhood of $5.5 billion $5.9 billion. And with that level of spending, we would expect overall production growth of 6 to 8% led by a roughly 20% growth in oil and NGL volumes.
I want to make this very clear. Our asset base has the capacity to grow at a much higher rate next year but top line growth is not what we are optimizing. We're focused on optimizing our growth per debt-adjusted share. We simply refuse to get caught up in the growth-at-any cost mentality.
Given the current environment, we can deliver optimum results through investing in our liquids-focused capital program, buying back our stock and taking a disciplined approach to our debt balances.
In 2011, we expect these actions to boost production per debt-adjusted share growth into the mid-teens. And with that, I'll turn the call over to Dave Hager, for a review of our quarterly operating highlights. David?
Thanks, John and good morning, everyone. I will begin with a quick recap of company-wide drilling activity. We exited the third quarter with 67 Devon-operated rigs running and during the quarter, we drilled 407 wells. These include 384 development wells and 23 exploration wells. All but three of the wells were successful.
Capital expenditures for exploration and development from our North American Onshore operations were $1.4 billion for the third quarter, bringing our total through the first nine months to $3.5 billion excluding the Pike acquisition. This level of activity increased third quarter production from retained properties by 4% over the third quarter of 2009, led by an 11% increase in oil and liquids production over the 2009 quarter.
Moving now to our quarterly operating highlights. First, at our Jackfish thermal oil project in Eastern Alberta, our third quarter daily production averaged a little over 21,000 barrels per day net of royalties. As we indicated in our last quarterly call, Jackfish was taken down for three weeks during the third quarter for scheduled maintenance. Following the turnaround, plant operations were restored on September 30. However, it will take a few weeks to fully restore the steam chambers and climb back to plant capacity. Accordingly, fourth quarter production at Jackfish is expected to average about 23,000 barrels per day net of royalties. Construction of Jackfish 2 is roughly 90% complete and continuing to trend under budget. We expect to begin injecting steam in the second quarter of next year delivering first oil in late 2011 with production ramping throughout 2012. Our third Jackfish project, Jackfish 3 has now been sanctioned, and we filed a regulatory application during the third quarter. Pending regulatory approval, we could begin site work by late next year with plant startups target for 2015. Detailed engineering work is already underway and we have locked down prices on roughly 85% of the major equipment orders. Devon operates the Jackfish projects and owns 100% working interest.
At Pike, this is our SAGD oil sands joint venture with BP that we formerly called Kirby. We have begun the appraisal drilling required to determine the optimum development configuration. We expect to complete appraisal drilling this winter with the goal of launching the regulatory process for the first phase of development around the end of 2011. Between Jackfish and Pike, we expect to grow our SAGD oil production to between 150,000 to 175,000 barrels per day by 2020.
In our Lloydminster oil play in Alberta, we drilled 53 new wells in the third quarter holding production steady at roughly 40,000 barrels equivalent per day in the quarter.
Moving to the Permian Basin. Our net production averaged just over 44,000 barrels of oil equivalent per day in the third quarter, up 18% over the third quarter of 2009 and 6% over the second quarter of 2010. Our third quarter oil and NGL production in the Permian was up 23% over 2009 and accounted for roughly 70% of our total Permian volumes.
The growth in liquids speaks to the quality and flexibly of our Property portfolio. As we mentioned last quarter, we are adding to the depth of this portfolio with approximately 200,000 additional acres in several oil- and liquids-rich plays to lease year. We have ramped up activity in several of our key oil plays and now have 17 rigs running in the Permian.
One of these projects is our Wolfberry light oil play where we recently added a fifth rig. We drilled 27 wells during the third quarter including one of our best wells to date in the play, which had a 30-day IP of 500 barrels per day. Our net Wolfberry production has increased nearly 150% since the beginning of the year to approximately 9,000 barrels of oil equivalent per day. Our focus over the coming months will be to continue the evaluation of our 200,000 net acre Wolfberry position.
Also in the Permian Basin. We have four rigs running in the Avalon Shale play. Devon has assembled over 200,000 prospective net acres in this condensate- and liquids-rich gas play. So far this year, we have participated in 18 Avalon wells and have a production data on a total of 30 wells covering a wide geographic area. While we are still in the early stages of evaluation of this play, the data support EURs of 400,000 to 600,000 barrels of oil equivalent per day depending on location within the broader play area, lateral length, et cetera. We expect to participate in 14 additional Avalon wells this year. We're encouraged with the results we have seen and we'll keep you updated as we gain additional information.
Another focus area in the Permian is the Bone Spring oil play, where Devon has 170,000 net acres. The Bone Spring is an oil play historically developed by vertical drilling. However, with the application of today's horizontal techniques, we have recently seeing some outstanding wells. In the third quarter, we drilled and completed the strawberry 7 federal 4H [ph] that we brought online at more than 700 barrels of oil per day. Early results from the six horizontal wells we have drilled to date in this play indicate EURs could have average around 300,000 barrels of equivalent, the cost of $3.8 million per well. We currently have three rigs running in the Bone Spring and expect to drill approximately 20 wells in the play this year. We are also running five additional rigs in the Permian targeting various conventional formations primarily with horizontal wells.
Moving north to the Texas Panhandle, where Devon has approximately 58,000 net acres in the Granite Wash play, we stepped up drilling activity during the quarter with the addition of a third rig that was relocated from the Barnett Shale. In the third quarter, we brought three Devon-operated wells online with average IP rates of 4,290 barrels of oil equivalent per day, including 605 barrels of oil or condensate and 1,450 barrels of NGLs. With the attractive rate of returns generated by these wells, it's likely that we'll add additional rigs in the Granite Wash as we head into 2011.
Moving to the Cana-Woodford Shale in Western Oklahoma, we continue to add to our acreage position during the quarter and now have approximately 240,000 net acres, focused in the best parts of the play. This has increased our risk resource potential at Cana to more than 10 trillion cubic feet equivalent. In order to continue to derisk our position and secure term acreage that we acquired this year, we have significantly ramped up our drilling activity over the past few months. We currently have 19 operated rigs running and expect to add two additional rigs by year end. We continue to see outstanding results from Cana. In the third quarter, we brought 11 operated wells online with average 24-hour IP rates of 5.3 million cubic feet equivalent per day, including an average of 175 barrels of NGLs and condensate.
Third quarter net production from Cana averaged a record 117 million cubic feet of gas equivalent per day, including 1,300 barrels of condensate per day and 4,000 barrels of NGLs. This is a 12% increase on a sequential quarter basis. By year end 2011, we expect to drive our net Cana production up more than 100% to 250 million cubic feet equivalent per day, including 14,000 barrels per day of condensate and NGLs. In addition to enhancing upstream economics, the liquids-rich portion of the Cana field also create opportunities from a midstream perspective.
To capture this value, just as we have in the Barnett and Arkoma, we are building a gas processing facility. Construction of the Cana plant is essentially complete and we expect to begin processing next month. The facility will have an initial processing capacity of 200 million cubic feet per day and will be capable of extracting up to 15,000 barrels of NGLs per day. The plant's processing capacity is expandable to 600 million a day as our volumes from the field grow.
Shifting to the Barnett Shale field in North Texas. In the third quarter, our net production reached the previous all-time high of 1.2 Bcf equivalent per day, including over 40,000 barrels of NGLs and condensate per day. This illustrates the depth of our inventory in contrast to that of many of our peers. With virtually no lease expiration issues and thousands of remaining high-quality locations, we have considerable capital flexibility in the Barnett. It is likely that we will choose to run a 12-rig program in 2011 with a focus on the liquids-rich portion of the play. This level of activity should allow us to maintain our current production level. With most of our activity in the Barnett now focused on drilling multiple wells from a single pad, we are finding that we are able to achieve even greater levels of efficiency. We have also continued to improve drilling efficiency and recently set a new record of eight days from spud to rig release for three recent Barnett wells. We are currently running 16 operated rigs in the Barnett, but we'll relocate four of these late next month.
Moving to the Haynesville Shale. After derisking much of our held-by production acreage in the Carthage area during 2009, our 2010 activity has focused on our term acreage in the southern area. However, given the rising service cost environment in the Haynesville, and a deep inventory of other attractive opportunities in our portfolio, our term acreage in the Haynesville does not directly attract capital within our portfolio. Therefore, we are continuing to bring in industry partners that are interested in developing this acreage. Keep in mind, the Haynesville drilling we did in 2009 in the Carthage area confirmed that we have a repeatable, economically attractive play under a more normalized gas price environment. Since this acreage is held by production, we have the luxury of pursuing this resource when the gas price and the cost environment is most favorable.
And finally, in the Horn River Basin of Northern British Columbia, we have now drilled all seven horizontal wells that we planned for this year. Four of these wells have been completed and we expect to have them tied in and producing by year end. Our producing wells at Horn River continue to perform better than expected, supporting an average EUR of 7 to 8 Bcf equivalent per well. Given that the Horn River is dry gas, we plan to spend minimal capital there in 2011. With that, I will turn the call over to Jeff Agosta for the financial review and outlook. Jeff?
Thanks, Dave, and good morning, everyone. Today, I will 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 upcoming quarter and 2011. As Vince mentioned earlier, we have reclassified the assets, liabilities and results of operations from our international assets into discontinued operations for all accounting periods presented. Since we completed our exit from the Gulf of Mexico during the second quarter, our third quarter results from continuing ops represent just our North American Onshore operations. Or in other words, the result of the repositioned Devon.
Looking first to production. In the third quarter, we produced 56.4 million oil equivalent barrels or approximately 613,000 barrels per day. This was in line with the production forecast range we've provided during last quarter's call and about 1% less than last quarter's production for our North American Onshore assets. You may recall that during last quarter's call, we told you that production from the second quarter had benefited from a 9,000 barrel per day royalty adjustment related to prior periods.
Also, due to a scheduled plant turnaround, Jackfish was off-line for three weeks during the third quarter. As a result, average daily production from Jackfish was 8,000 barrels per day lower on a sequential quarter basis. Removing the out-of-period royalty adjustment, and the impact of Jackfish maintenance, sequential quarter production was up almost 2%. On a year-over-year basis, third quarter production for our North American Onshore assets increased 22,000 barrels per day or 4%. As mentioned before, an 11% increase in oil and NGL production drove the favorable comparison.
Looking ahead, our high-quality North American Onshore assets remain on track to deliver full year production of 223 million to 224 million equivalent barrels. This implies fourth quarter production of 625,000 to 635,000 Boe per day, or roughly 10% over fourth quarter 2009 production.
Moving to price realizations, starting with oil. In the third quarter, the WTI Index averaged $76.08 per barrel an 11% increase over to third quarter of 2009. Company-wide oil price realizations were near the top end of our guidance range at 82% of WTI. The most notable regional performance was the narrowing of heavy oil differentials in Canada. On the natural gas side, the third quarter benchmark Henry Hub gas price averaged $4.38 per Mcf. But out of third quarter realized gas price before the impact of hedges was 84% of Henry Hub, or $3.67. Cash settlements from our hedging position and regional basis swaps increased our overall price realizations by $1, bringing our all-in price including hedges to $4.67.
For the fourth quarter of this year, we remain well hedged with approximately 60% of our natural gas production locked in at a weighted average price of $5.87 per Mcf. We also have roughly 70% of our fourth quarter oil production collared with an average floor of $67.47 per barrel and an average ceiling of $96.48. Looking to 2011, we recently added 300 million per day to our gas hedge position, bringing our total up to 525 million cubic feet per day for the year swapped at a weighted average price of $5.56. As part of these recent additions, we sold call options on 12,000 barrels of oil per day for 2011 and '12 at $95 per barrel, and call options on 300 million cubic feet per day of gas for 2012 at $6 per Mcf. Also for 2011, we have collars in place on 33,000 barrels of oil per day where the floor is $75 per barrel and an average ceiling of $109.
We will be posting a schedule on our website after the call with all the details of our hedge position. Looking briefly at NGLs. Our price per barrel in the third quarter averaged $29.01 or about 38% of the WTI Index price. This compares to average realizations of about 40% of WTI in the previous quarter. We expect seasonal factors to provide a modest boost to NGL prices in the fourth quarter.
Turning now to our Marketing and Midstream division. They continue to deliver impressive results. For the third quarter, our operating profit totaled $125 million, a 20% increase over third quarter 2009. Increased throughput and higher commodity prices drove the improvement. For the fourth quarter, we expect our Marketing and Midstream operating profit to be in the range of $110 million to $130 million. This will bring our full year operating profit to roughly $500 million.
Looking now at the main expense items for the quarter. As we move forward with a strategic repositioning, we are seeing the efficiency gains flow through to our reported results. On a sequential quarter basis, most expenses decreased during the third quarter on both an absolute and a unit of production basis. Lease operating expenses totaled $415 million in the third quarter or $7.35 per Boe. This represents a 3% decrease from last quarter. This rate is indicative of what we would expect for the fourth quarter.
Shifting to G&A. G&A expenses continue to be well contained in the third quarter, totaling $131 million. For the first nine months of the year, our G&A costs have declined by $73 million, or 15%, when compared to the same period of 2009. Based on the actual performance for the first three quarters, we now expect our full year 2010 G&A expense to be near the bottom end of our previous forecast range of $580 million to $600 million.
Turning to interest expense. For the third quarter, it came in at $83 million, right in line with our expectations. When compared to the third quarter of 2009, interest expense decreased by 8% due to lower debt balances. Looking to the fourth quarter, we expect interest expense to approximate $80 million. DD&A expense for oil and gas properties declined by 7% from last quarter to $397 million. The improvement in DD&A resulted from the sale of Gulf of Mexico assets. For the fourth quarter, we expect DD&A expense to range between $7 and $7.25 per barrel.
The final expense item I will touch on is income taxes. After backing out the impact of items that are typically excluded from analyst forecasts, our adjusted third quarter tax rate on earnings from continuing operations came in at 33% of adjusted pretax income. This tax rate consisted of deferred taxes equal to 40% of pretax income and current taxes of a negative 7% for the quarter. This atypical distribution of current and deferred taxes was due to an adjustment related to the filing of our 2009 tax return. Essentially, our 2009 tax return indicated more carryover benefits available for 2010 than we had previously estimated.
The cumulative impact for the first nine months of the year was recorded in the third quarter. In spite of the unusual third quarter tax rate, our adjusted tax rate for the first nine months of 2010 was similar to what we now expect for the full year, with a total rate of 33% of pretax earnings, composed of a 6% current tax rate, and a 27% deferred tax rate. In today's news release, we have provided a table that reconciles the effects of items that are typically excluded from analyst estimates.
Moving now to the bottom line. Non-GAAP earnings from continuing operations totaled $571 million or $1.31 per diluted share. Higher oil and gas revenues along with strong cost controls increased our adjusted earnings from continuing operations by over 40% when compared to the third quarter of 2009. As Vince mentioned earlier, this result also exceeded the comparable First Call mean number by $0.06. Before we open the call to Q&A, I would like to conclude with a quick review of our financial position.
During the third quarter, Devon generated cash flow before balance sheet changes of $1.8 billion, a 47% increase over the year-ago quarter. Additionally, we received $2 billion of cash from the sale of assets in Azerbaijan and China. After funding our total capital demands for the quarter of $1.8 billion and repurchasing $499 million of common stock, our cash balances increased by over $1 billion during the quarter, reaching a total of $4 billion. With that level of cash, and total debt of roughly $5.6 billion, we clearly maintained a great deal of financial strength and flexibility.
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