EXHIBIT 99.1
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| | | 20 North Broadway | | Telephone: (405) 235-3611 |
| | | Oklahoma City, Oklahoma 73102-8260 | | Fax: (405) 552-4667 |
Devon Energy Second-Quarter 2007 Earnings Call August 1, 2007
Vince White:
Thank you, operator, and good morning everyone. Welcome to Devon’s second-quarter 2007 conference call and Webcast. I will begin with a few remarks and then our Chairman and CEO, Larry Nichols, will review the highlights of the quarter and bring you up to date on some recent initiatives. Following Larry’s remarks, Steve Hadden, our Senior Vice President of Exploration and Production, will cover operating highlights, and then Devon’s President, John Richels, will conclude with a financial review followed by questions and answers. We’ll try to hold the call to about an hour, so if we don’t get to your question, please give us a call this afternoon.
A replay of this call will be available later today through a link on devonenergy.com. We will also be posting to our Website a new issue of Devon Direct. Devon Direct is an electronic report that includes highlights from this Webcast and includes links to additional supplementary information.
During the call today, we will be updating some of our estimates based on the actual results that we saw in the first six months of the year and our current outlook for the second half of the year. In addition to the updates provided in today’s call, we plan to file a Form 8-K later today that will document all the details of our updated guidance.
Also, please note that all references in today’s call to our plans, forecasts, and estimates are forward-looking statements under U.S. securities law. We provide you the very best estimates possible, but there are many factors that can cause our actual results to differ from the estimates. Because of these uncertainties, we encourage you to review the discussion of risk factors that is provided with our Form 8-K along with the forecasts.
One other compliance note — we will make reference today to certain Non-GAAP performance measures.When we use these measures, we are required to provide certain related disclosures. We encourage you to review those disclosures, which are available on our website at devonenergy.com.
Finally, I will remind you that our decision to sell our assets in Africa and terminate our operations there triggered the accounting rules for discontinued operations. Under these rules, we exclude oil and gas produced from the divestiture assets from reported production volumes for all periods presented. The related revenues and expenses for the discontinued operations are collapsed into a single line item at the end of the statements of operations. However, we have provided in today’s release an additional table that gives you a detailed statement of operations as well as the production volumes attributable to the properties we are divesting.
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You will note that the reported net earnings from discontinued operations were $80 million in the second quarter; however, that does not mean that the discontinued operations would have actually reported earnings of $80 million had we not decided to sell them. The discrepancy occurs principally because accounting rules require us to stop recording depletion on the sale properties once they are designated for divestiture. Had we not chosen to exit Africa, we would have had net income associated with the divestiture properties of $50 million...or $30 million less than the $80 million of income we reported from discontinued operations. That’s because we would have had $30 million more of after-tax expenses related to the divestiture properties.
Discontinued operations accounting also complicates the process of estimating earnings. We polled the analysts that report estimates to First Call,and determined that some included the African operations, but the majority excluded the impact of the African operations. The mean estimate for the analysts that we contacted that included discontinued operations was $1.57 per share. This compares to our non-GAAP diluted earnings of $1.87 per share for the second quarter. The mean estimate for the analysts that we were able to contact that excluded discontinued operations was $1.45 per share. That compares to our non-GAAP earnings from continuing operations of $1.73 per share. In either case, with and without the contribution of Africa, this was a blow-out quarter.
With those items out of the way, I’ll now turn the call over to Larry Nichols.
Larry Nichols:
Thanks, Vince, and good morning everyone.
Devon reported terrific results this quarter, extending the momentum we have been building for some time. We are especially pleased with the increase in production from continuing operations, which was 16% better than in the second quarter of 2006 and five percent ahead of the first quarter of 2007, demonstrating solid organic growth. The second quarter of 2007 was our fifth consecutive quarter of production growth and about 3 million barrels better than our target for the quarter. There are several reasons for this out-performance, and later in this call John Richels will explain those reasons and provide a production outlook for the remaining two quarters of the year.
Our second-quarter financial results were very strong. As Vince described...
| | • | | Second-quarter net earnings and earnings per share came in better than analysts’ expectations. In fact, second quarter earnings of $2.00 per share were four percent better than last year’s second quarter and the second highest quarterly earnings per share in Devon’s history. |
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| | • | | Cash flow before balance sheet changes was a record $1.8 billion bringing the year to date total to $3.3 billion. |
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| | • | | Importantly, the 56.2 million equivalent barrels we produced in the second quarter puts us well on the way to producing at the upper end of our full-year 2007 production forecast of 219 to 221 million BOE from continuing operations. That would be more than 10% growth from 2006. |
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| | • | | We are very pleased about our performance at the half-way point of the year and remain confident in the continued success of our long-term growth strategy that combines our predictable, near-term development projects with high impact, longer-term growth opportunities. |
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Now, concerning the African divestiture program,I will give you a brief status update...
We expect to close the sale of our Egyptian operations near the end of August. This is the transaction with Dana Petroleum that we announced early in the second quarter. The sale price was $375 million including $67 million of working capital. That works out to about $38.50 per barrel of proved reserves.
The West African divestiture program began a few months later than the Egyptian program. The interest level has been quite high and we have received more than 30 bids on these assets. As we expected, we received bids for various combinations of properties. We are still in the process of determining the most favorable combination of bids, and we will not announce the sales until we have purchase and sale agreements in hand.
One element of our growth strategy is to regularly evaluate our property portfolio and make changes when necessary to realize the greatest value from our broad set of opportunties. . The decision to divest our operations in Africa and redeploy people and capital to other projects is a direct result of that evaluation.
As we said when we announced the divestiture plans, in addition to funding our capital spending program we expect to use the proceeds to repay commercial paper balances and resume the share repurchase program suspended last year when we made the acquisition of Chief’s Barnett Shale properties. This is in addition to the recently announced 10 B 5 share repurchase program that is intended to offset the dilution of option exercises and grants of restricted stock.
And finally, I want to mention the announcement we made on July 18 concerning the creation of a marketing and midstream Master Limited Partnership. Under the SEC’s pre-registration rules, we are not allowed to provide any new information beyond what was provided in the news release. To recap the news release:
| • | | We plan to form a master limited partnership that will initially own a minority interest in Devon’s U.S. onshore marketing and midstream business. |
| • | | The purpose of creating the MLP is to allow the marketplace to establish an independent value for our marketing and midstream business that is currently embedded within Devon’s overall corporate valuation. |
| • | | A Devon subsidiary will serve as the General Partner of the MLP and Devon will own a majority of the partnership units following the initial public offering. |
Because of the SEC’s “gun jumping” rules, we request that you refrain from asking questions about the MLP in today’s Q&A period. The registration statement should provide answers to most of your questions when it becomes available.
At this point, I’ll turn the call over to Steve Hadden who will give you more in-depth review of exploration and production operations.
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Steve Hadden:
Thanks Larry and good morning to everyone.
We had an active second quarter, drilling 434 wells company-wide. 14 of these wells were classified as exploration, of which 79% were successful. The remaining 420 were development wells and about 99% were successful. We had 141 rigs drilling in June, of which 88 were drilling Devon-operated wells.
Capital expenditures for exploration and development on our retained properties ... this excludes operations in Africa ... were $1.2 billion in the quarter. This brought total exploration and development capital for the first six months to $2.5 billion.
Now let’s move to our quarterly operations highlights,beginning with the Barnett Shale field in north Texas, where we continue to enjoy excellent success and production growth ahead of plans. We are currently running 30 Devon-operated rigs, of which 13 are in the core area and 17 are drilling outside the core, including 11 in Johnson County. During the second quarter, we completed a total of 147 Barnett wells, of which 56 were in the core area and 91 outside the core. At the current pace, we would drill about 500 wells in the Barnett Shale this year, compared with the previous forecast of 385 wells. With this additional activity, we expect company-wide exploration and development capital to come in at the upper end of the forecast range of $4.9 to $5.3 billion.
From an execution perspective, the new, more-automated rigs are enabling us to buck the trend and reduce drilling costs in the Barnett. Average drilling costs have decreased in 2007 versus 2006. This is due largely to a 10% decline in average drilling days per well — down from 18.3 days in 2006 to 16.5 days in 2007. This is saving us about $190,000 per well in drilling costs and helping to offset higher completion and fracturing costs.
We continue to see solid results in Johnson County where during the second quarter we put 24 new wells online at an average rate of 3.1 million cubic feet per day. Two particularly strong wells in Johnson County each had 24 hour sustained initial production rates in excess of 5 million cubic feet per day. In addition, we brought 17 new horizontal wells online in portions of southwestern Tarrant and southeastern Parker counties at an average rate of 1.8 million cubic feet per day.
We also continue to see solid economic results from our core area 20-acre infill drilling program. Through the end of the second quarter, we had completed a total of 128 infill wells, 105 of which were horizontals. A total of 124 infill wells have been connected to the production grid, and 101 of those are horizontals that came online at an average 2.1 million cubic feet per day.
Our net Barnett Shale production averaged a record 797 million cubic feet of gas equivalent per day in the second quarter. The second quarter average was up 9% from the first quarter and up 37% compared with the second quarter of 2006. We previously announced a target rate of 800 million a day by year-end 2007. Having essentially reached that target already, we have revised our year-end expectation to 875 million cubic feet equivalent per day. We had also set a longer-term target of 1 Bcf per day by the end of 2009. Given our progress to date, we would expect to set a more aggressive target when we update our long-term projections later this year.
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Because the Barnett Shale is so dominant, we seldom highlight our conventional gas operations in the Ft. Worth basin. However, in the second quarter, we also increased conventional Ft. Worth basin production — it was up about 7% from the second quarter of 2006 — to 70 million cubic feet per day.
Moving on...in the Woodford shale in eastern Oklahoma, we currently have five operated rigs drilling in the play. We brought a total of 7 new operated wells online during the second quarter with individual well production rates as high as 4 million cubic feet of gas per day, bringing our total operated well count to 38. Devon’s gross operated production was about 35 MMCFD. Our total net Woodford shale production averaged over 16 million cubic feet of gas equivalent per day in the second quarter, and we plan to grow that volume to 25 to 30 million cubic feet per day by year end. We believe that Devon’s net resource potential in the Woodford could be as much as 1 TCF.
To accommodate our growth and that of others in the area, we are constructing a $30 million dollar gas processing plant located about 20 miles west of McAlester, Oklahoma. The plant will have the capacity to process up to 200 million cubic feet of natural gas per day and produce about 18,000 barrels per day of natural gas liquids. The plant is scheduled to be operational in May of 2008.
Shifting to East Texas, we continued with a seven rig vertical Cotton Valley drilling program in the Carthage area. In the second quarter we drilled 22 vertical wells and continued an active re-completion program. At the end of the quarter we were drilling the 44th well in the 88-well vertical program planned for this year.
We also continue to have success with our horizontal drilling program in the Carthage area. We added a 3rd horizontal rig during the second quarter and drilled 2 new wells, including our first Cotton Valley horizontal in the Central Carthage field. The 98% working interest Hancock 15H well averaged 6.7 million cubic feet of gas per day for the first 30 days of production. Two additional Cotton Valley Sand wells were drilled during the quarter and are awaiting completion. In total, we expect to drill 15 horizontal wells in the Carthage area this year.
Our net Carthage production averaged 249 million cubic feet of gas equivalent per day for the second quarter, up 7% from the first quarter average and up 6% from a year ago.
Also in East Texas...we continue to pursue the horizontal drilling program in the Groesbeck area. However, we have scaled back this year’s drilling plans from 22 wells to 17 wells. The reservoir performance we have seen from the wells in this area is very encouraging, but drilling and completion options are very complex and we are working toward refining our approach before moving into full development. This is similar to our initial approach in the non-core Barnett Shale where we thoroughly evaluated our position before moving into wide-scale development. We still believe we have as many as 200 potential horizontal drilling locations in the Groesbeck area.
Moving to the Rockies... In the Powder River Basin in Wyoming we have 8 rigs currently running, including 4 Devon-operated rigs drilling the Big George formation in the West Pine Tree and Juniper Draw areas. We expect to drill more than 200 new wells by year-end. Our net Powder River production averaged 61 million cubic feet of gas per day in the second quarter, up 9% from the first quarter average and up 11% compared with the second quarter of 2006. We expect to exit 2007 producing over 70 million per day and ultimately expect to bring Powder River production to more than 100 million cubic feet per day in late 2008.
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Now shifting to the Gulf of Mexico, we are pleased with our continued progress in the quarter in the deepwater Lower Tertiary trend.
First, at our 2006 discovery, called Kaskida,the MMS approved expansion of the Kaskida unit to the west with the addition of Keathley Canyon blocks 244 and 245 in June. As a result, the Keathley Canyon 244 #1 well, previously known as the Cortez Bank prospect, was included in the unit as an appraisal of the Kaskida discovery. The well, some 12 miles from the discovery well, sits in 5,500 feet of water and is currently drilling below 30,000 feet. Kaskida is operated by BP and Devon has a 20% working interest.
The second Lower Tertiary well we are drilling is on our Chuck prospect located in Walker Ridge 278. This exploratory well targets a large sub-salt structure in about 6,500 feet of water. The well is currently drilling below 8,000 feet with the Ocean Endeavor deepwater rig that we have under long-term contract. Devon is the operator of Chuck with a 39.5% working interest.
Also in our Lower Tertiary exploration program...during the second quarter we completed an agreement to acquire a 23% interest in the Green Bay prospect located on Walker Ridge 372, approximately 20 miles north of the St. Malo discovery and 18 miles east of our Chuck prospect. This area has seen many of the lower tertiary discoveries to date. We expect to begin drilling an exploratory well on the Green Bay prospect in the fourth quarter.
The Gulf team continues to work with our partners toward commercial development decisions on each of our Lower Tertiary discoveries.
At Cascade, our 50% working interest project with Petrobras in the Walker Ridge area, we expect to sanction the project and award FPSO and development contracts later this year.
At Jack,also in the Walker Ridge deepwater lease area, Devon and our co-owners are preparing to initiate drilling on a second delineation well, the Jack #3, late this year, with results expected in 2008. The well will be operated by Devon and drilled with the Ocean Endeavor rig when drilling is completed on the Chuck exploratory well. The co-owners are also evaluating various development options for Jack, in which Devon has a 25% working interest.
And at St. Malo, also in the Walker Ridge deepwater area, we expect to drill another delineation well during the fourth quarter. We have a 22.5% working interest in St. Malo.
In the eastern Gulf of Mexico, the Merganser field was readied for production to the Independence Hub in the second quarter. Devon has a 50% interest in the two Merganser wells, which should commence production later this month. We expect our share of production to be about 50 million cubic feet of natural gas per day.
Shifting to the Gulf of Mexico shelf ... again this quarter we had success in both exploration and development projects. We made a discovery at our Lime prospect, on Eugene Island 354. The well was drilled to about 10,600 feet and penetrated the Lentic sands where we found approximately 140 feet of net pay. We expect to bring the Lime discovery online in the third quarter at an expected rate of about 8 million cubic feet equivalent per day. Devon has a 50% working interest in the discovery.
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On the development side, we drilled a 3rd offset to our very successful 2005 Chopin discovery. The B-12 development well located on Eugene Island 333 was completed in June and came online at 25 million cubic feet of natural gas per day. All four wells are currently producing at a combined rate of 75 million cubic feet of natural gas equivalent per day. Devon has 100% working interests in the four Chopin wells.
Our Gulf team has now largely completed the 2007 shelf capital program with a 100% success rate, a job well done.
Moving to Canada...we drilled just 63 wells in Canada in the second quarter due in part to an extremely rainy spring. The wet and muddy conditions delayed drilling in the first two months of the quarter at our Lloydminster oil play in eastern Alberta. However, in June we ramped activity back up to 5 rigs and were able to drill 36 wells at Lloydminster. We plan to maintain a 5 rig program for the remainder of 2007. Our net production from the Lloydminster area averaged 33,000 barrels per day in the second quarter, up 48% compared with the second quarter of 2006. We have also begun preparing for our next expansion of the Manatokan plant. An additional 10,000 barrels a day of processing capacity will be added to bring our total processing capacity at the facility to 27,500 barrels per day in anticipation of our growing oil volumes.
At our 100% Devon-owned Jackfish thermal heavy oil project in eastern Alberta, pre-commissioning activities were completed in June and first steam was achieved on July 16th. As we have indicated before, we expect production from Jackfish to begin around the end of this year. Production will then ramp up toward an expected sustainable rate of 35,000 barrels a day by the end of 2008.
At our Jackfish 2 project, engineering and budgeting work continue and we expect to receive regulatory approval around mid-2008. At that point we expect to make a formal decision about the project. Jackfish 2 would essentially double the size of the Jackfish project, adding another 35,000 barrels a day of oil production.
Moving to the international arena ... development drilling on the Devon operated Polvo oil project on block BM-C-8 in Brazil continued during the second quarter. As we announced on Monday, we have now begun producing oil to the FPSO from the first of 10 development wells. The additional wells will be drilled and tied in throughout the remainder of this year and into 2008 as we ramp up our production to 26,000 barrels per day, net to our 60% working interest.
In Azerbaijan,where Devon has a 5.6% interest in the ACG oil field, gross oil production exceeded 750 thousand barrels of oil a day in early May. Devon’s share of ACG production averaged more than 40 thousand barrels a day in the second quarter. This was above forecast because of favorable timing of liftings. We do not expect that situation to repeat in the third quarter. In fact, we expect two to three weeks of planned down time at ACG in September to tie in new facilities.
And finally in China, we will be replacing a production riser at Panyu during the third quarter. Accordingly, we anticipate up to two weeks of down time at the Panyu field. This work was originally scheduled for the second quarter but was delayed awaiting delivery of the replacement equipment.
In summary, the second quarter delivered strong operational results, demonstrating good organic growth and advancing our high impact projects, adding both near-term and long-term value. Now, I’ll turn the call over to John Richels to review our financial results for the second quarter.
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John Richels
Thanks, Steve. This morning I want to take you through a brief review of the key drivers that impacted our second-quarter financial results. In addition, I will review with you how these factors are likely to affect our outlook for the remainder of the year. As Vince mentioned, we are issuing an 8-K today that will provide further details of our updated 2007 forecasts.
As a reminder, we have reclassified the assets, liabilities and results of operations in Africa as discontinued operations for all accounting periods presented.I will focus my comments on our continuing operations which exclude results attributable to Africa.
Let’s begin with production....
In the second quarter, we produced 56.2 million equivalent barrels, or approximately 618,000 barrels per day. These results exceeded our guidance by over 3 million barrels, or 6%. Approximately half of the 3 million barrel out-performance is attributable to better than expected performance from core North America properties. The other half of the out-performance is attributable to favorable royalty adjustments in Canada; timing of oil sales from the ACG field in Azerbaijan and rescheduling of expected downtime at our Panyu project in China.
When you compare our second quarter results to the same quarter a year ago, you will find that company-wide production increased by 84,000 barrels per day, or 16%. This strong year-over-year growth was driven primarily by our U.S. Onshore and International segments. Production from the U.S. Onshore grew by over 40,000 barrels per day, or 15%, when compared to the second quarter last year. Once again the leading contributor to our U.S. Onshore performance was growth in Barnett Shale production. In addition, we also experienced significant growth from our international sector — up nearly 45,000 barrels per day over the same quarter last year. This was primarily attributable to the ACG field in Azerbaijan. In Canada, despite significantly scaling back conventional gas drilling activity, second quarter production remained relatively flat year-over-year and actually increased by 4% over the first quarter of 2007. Strong performance from our Lloydminster area oil projects was also aided by reduced royalties.
Based on first half results, we expect production to come in at the top end of our full-year 2007 forecast range of 219 to 221 million oil-equivalent barrels. Looking to the second half, we expect our production to total approximately 55 million equivalent barrels in the third quarter and 57 million barrels in the fourth. The third quarter estimate reflects a slight decrease in production from the second quarter. This is driven by the timing of oil sales and scheduled field downtime in Azerbaijan; scheduled downtime for equipment replacement in China; and an anticipated drop in production from Canada. The fourth quarter growth will be fueled by our U.S. Onshore properties and the ramp-up of production from the Merganser field in the deepwater gulf and the Polvo field offshore Brazil.
Moving on to price realizations...
Starting with oil... In the second quarter, the benchmark WTI oil price averaged $65.08 — that was 8% below the second quarter of 2006, but a 12% increase from the first quarter of 2007. In addition to the strong oil price environment this year, regional differentials narrowed and price realizations in virtually all of our producing regions were in or above the top half of our guidance range. The leading driver of our higher oil price realizations was the robust international oil market, and this is reflected in the premium pricing we received for our light, sweet oil in Azerbaijan. As a result, our company-wide price realizations rose to 92% of WTI, or $60.01 per barrel for the quarter. That is a 15% improvement in realized pricing when compared to the first quarter of 2007. We will be updating our full-year oil differential guidance in today’s 8-K to reflect the improvements in pricing.
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On the natural gas side,the benchmark Henry Hub index averaged $7.55 per Mcf in the second quarter. This was 11% higher than in the second quarter of 2006 and 12% higher than the first quarter of 2007. Our company-wide gas price realizations came in near the midpoint of our guidance at approximately 86% of Henry Hub. Price realizations remained strong in Canada and the Gulf of Mexico, however, this regional strength was offset by weak gas price realizations in the Rocky Mountains. As many of you know, price differentials in the Rockies have widened significantly over the past few months due to increased production and constrained take-away capacity. As the result of this short-term issue, we continue to expect soft pricing to persist in the Rockies for the remainder of 2007. Looking ahead to the 3rd quarter, we now expect natural gas price realizations to approximate 100% of NYMEX for the Gulf, 80% of NYMEX for the US Onshore and 90% of NYMEX for Canada. Updates to our full-year differential guidance will be provided in today’s 8-K.
Turning now to our marketing and midstream business...
In addition to terrific upstream performance in the second quarter, Devon’s marketing and midstream operations once again delivered impressive results. Marketing and midstream operating profit for the second quarter totaled $119 million — that was $14 million greater than the second quarter of 2006 and a $10 million sequential quarter increase. This solid performance was driven by increased gas processing revenues combined with higher gas pipeline throughput. Based on our strong showing in the first half of the year, we now expect our Marketing and Midstream full-year operating profit to come in between $420 and $460 million. This represents an increase of $30 million from our previous guidance.
Moving to expenses...
Second-quarter lease operating expenses were near the midpoint of our guidance, coming in at $439 million, or $7.81 per barrel produced. Unit LOE costs were 4% lower than the $8.13 per barrel we reported in the first quarter of 2007. However, we still anticipate a rise in LOE during the second half of the year. This increase will be driven by scheduled maintenance in our International and Canadian operating regions along with higher unit costs incurred while our new development projects ramp-up production. We now expect our full year lease operating expense to be in the range of $8.00 to $8.30 per equivalent barrel.
Our second quarter DD&A expense for oil and gas properties came in within our guidance range at $11.48 per barrel. Looking forward, we expect our third and fourth quarter DD&A rates to rise to between $11.50 and $12.25 per equivalent barrel. Based on this, we are now forecasting our full year 2007 DD&A rate to come in between $11.40 and $11.80 per equivalent barrel.
Moving on to G&A expense...
G&A expense for the second quarter was $113 million, right in line with our guidance and $6 million less than the previous quarter of this year. At this time we are not making any changes to our full year G&A guidance range of $460 to $480 million.
Second quarter interest expense came in at $107 million, right in line with our expectations. Of total interest expense for the quarter, $20 million was related to commercial paper balances, which we expect to pay down following the close of the African divestitures. As Larry mentioned earlier, we expect to close the sale of Egypt during the third quarter and are expecting to close on the West Africa sales near year-end. Based on these expectations and the related timing of commercial paper balances, we now expect full year 2007 interest expense to be in the range of $430 to $440 million.
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The final expense item I want to touch on is income taxes...
Income tax expense for the second quarter came in at 29% of pre-tax income. When you back out the impact of items that are generally excluded from analysts’ estimates, you get an adjusted current tax rate of 15% and a deferred rate of 16%, for a total income tax rate of 31%. We remain comfortable with our full-year guidance ranges for income taxes. In today’s earnings release we have provided a table that reconciles the tax effects of items that are usually excluded from analysts’ estimates.
Moving to the bottom line...
Reported earnings from continuing operations were an impressive $824 million or $1.82 per diluted share in the second quarter of 2007. That’s a 43% increase in earnings from continuing operations over the first quarter of this year. Earnings from discontinued operations came in at $80 million or 18 cents per diluted share. In aggregate, after backing out items that are typically excluded from analysts’ estimates, our total net earnings for the second quarter were $845 million, or $1.87 per diluted share. As we said earlier, the results far exceeded our expectations as well as those of the street.
Cash flow before balance sheet changes reached a record $1.8 billion, up 24% from last quarter and up 18% from the second quarter of 2006. Year-to-date, our operating cash flow before balance sheet changes totaled $3.3 billion ... comfortably funding $3.0 billion of capital investments ... and leaving us with nearly $300 million of free cash flow. In addition to our strong cash flow, we exited the month of June with a healthy cash balance of $1.4 billion while our net debt to capitalization ratio reached a twelve month low of 20 percent.
Looking to the remainder of 2007...we expect cash flow from operations to generally cover our total capital demands. That will leave us with the after-tax proceeds from the African divestitures available to reduce debt and resume repurchasing shares.
To summarize, Devon’s second quarter performance was a strong one in almost every way.
With that, I am going to turn the call back over to Vince to open it up for Q&A.
Vince:
Operator, we’re ready to take the first question.
Larry Nichols:
To summarize:
| | • | | Devon reported very strong financial results this quarter, with the second-highest earnings per share in our history. |
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| | • | | Production growth throughout the company drove the financial performance, and we are solidly in position to reach the upper end of our full-year production target of 221 million Boe through organic growth |
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| | • | | Outstanding performance from the Barnett Shale and other low-risk core producing properties will be supplemented by our new production at Merganser and Polvo in the second half of this year and in 2008. |
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| | • | | We continued to advance projects in our high impact portfolio including the Lower Tertiary trend. |
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| | • | | We are very pleased with first half results and are looking forward to a great second half. |
We will talk to you again in November.
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