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Executives

Vincent W. White - Senior Vice President, Investor Relations

J. Larry Nichols - Chairman and Chief Executive Officer

John Richels - President

Stephen J. Hadden - Executive Vice President, Exploration and Production

Darryl G. Smette - Executive Vice President, Marketing and Midstream

Analysts

Rehan Rashid - FBR Capital Markets

David Heikkinen - Tudor Pickering Holt

Ben Dell - Stanford Bernstein

Robert Christensen - Buckingham Research Group

Joseph Allman - J.P. Morgan

Joseph Magner - Tristone Capital

Brian Singer - Goldman Sachs

Devon Energy Corporation (DVN) Q4 2008 Earnings Call February 4, 2009 11:00 AM ET

Operator

Welcome to Devon Energy's Fourth Quarter and Year-End 2008 Earnings Conference Call. At this time all participants are in a listen-only mode. After the prepared remarks, we will conduct a question-and-answer session. This call is being recorded.

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

Vincent W. White

Thank you. Good morning everyone. And welcome to call. I'm going to begin with a few preliminary comments and then turn the call over to our Chairman and CEO, Larry Nichols. He will provide an overview of 2008 and his thoughts on the year ahead. Following Larry's remarks, our President, John Richels will recap our reserves activity and provide a 2008 financial review and 2009 financial outlook. And then Executive Vice President of Exploration and Production, Steve Hadden, will cover fourth quarter operating highlights. We'll conclude the call in about an hour. So if we don't get to your question at the Q&A period, please feel free to follow-up after the call and as always, we'll ask anybody asking a question to limit it to one question and one follow-up.

A replay of today's call will be available later through a link on our home page at devonenergy.com.

Also later today, we will file a Form 8-K as we customarily do, to provide the forecast data for 2009. This 8-K has detailed estimates for 2009 production by product and geographic region, expense estimates and expected realized prices relative to benchmarked oil and gas prices.

The 8-K will also provide details of our 2009 capital plans, and we'll be providing a lot of this information on the call as well.

Before we get to the business of the quarter, we are obligated to remind you that the discussions of our expectations, plans, forecast and estimates are all considered forward-looking statements under U.S. securities law. And while we always make every effort to provide you with the very best estimates possible, there are a lot of factors that could cause our actual results to differ from our estimates. For a discussion of the risk factors that could influence those results, I am referring you to our Form 8-K that I mentioned that we'll be filling later today.

One final compliance item, we will make reference in the call today to various non-GAAP performance measures and when we provide these measures, we're also required to provide certain related disclosures; those have been posted to the Devon website as well.

Before I turn the call over to Larry, I want to comment on the non-cash impairment charge that led to the fourth quarter loss that we reported today. You may already be aware that the SEC requires companies that utilize the full cost method of accounting to implement a stringent impairment test at the end of each quarter.

For those of you that are not familiar with the full cost ceiling test, I want to spend a few minutes on the mechanics. The test consists of comparing the net book value of oil and gas properties less related deferred income taxes to a calculated maximum carrying value or ceiling. The ceiling is the estimated present value of the after-tax future net cash flow from our proved oil and gas properties plus the book value of any unevaluated properties.

The ceiling is calculated using oil and gas prices and costs in effect at December 31st, held flat forever and discounted at a 10% per annum rate. The company then compares the net book value of its oil gas properties less deferred income taxes to the ceiling. Any excess is written off as expense.

It's worth noting that unlike the test for companies using successful efforts accounting, the full cost ceiling test uses discounted feature of cash flows based on end of the quarter prices. This makes the test for full cost companies much more severe than the test for successful effort companies who use undiscounted cash flows based on their expected oil and gas prices rather than the last day of the year prices.

Consequently, the full cost accounting method may result... often result in a more conservative carrying value for oil and gas properties. Based on the fourth quarter 2008 ceiling test calculations we took an after-tax charge of 7.1 billion in the fourth quarter. That's made up of a 10.4 billion reduction in the recorded value or book value of our oil and gas properties offset by a deferred tax benefit of 3.3 billion. The 7.1 billion net of tax write-down comprises 4.2 billion in the U.S., 2.5 billion in Canada and a little under a half billion in the international sector, primarily in Brazil.

After deducting this charge from our fourth quarter results, we reported a net loss for the quarter. Remind you that this charge is completely cash neutral. It has no impact on cash flow or cash balances.

One misconception about the full cost ceiling test adjustment is that it results in writing-off oil and gas reserves. That is not the case. The reserves estimate is independent of the ceiling test. The ceiling test adjustment is purely a financial statement event that has no impact on oil and gas reserves on the ground.

The main criticism of the full cost ceiling test has long been that it's based on oil and gas prices and costs and effective at single point in time. Oil and natural gas price volatility can result in anomalies at the end of an accounting period, leading to a large impairment charge that is not indicative of a fair value. This volatility is illustrated by the fact that when we did the ceiling test at the end of the third quarter of 2008, that is at September 30th, we had a ceiling test cushion of 4 billion after tax. Just three months later, the calculated ceiling has swung down 11 billion to generate the 7.1 billion after-tax adjustment that we took at December 31st, 2008.

These issues have now been recognized by the SEC with the recent change in the rules, moving to using average oil and natural gas prices rather than prices on a singe day of the year. Unfortunately the new rules do not take effect until the end of 2009. Had the new rules been in effect at December 31st, 2008 Devon would not have taken this non-cash charge.

While the write-down affects our balance sheet, it does not affect liquidity or compliance with our banking agreements. Devon's bank credit agreements have only one significant covenant and that is a maximum debt to capitalization ratio of 65%.

Under the terms of these agreements, non-cash charges are added back to the capitalization reflecting the fact that our banks agreed that these accounting adjustments do not impact the underlying value of our business. Accordingly, for purposes of our credit agreements, our debt to cap was less than 20% at year end.

When you exclude the ceiling test write-down and the other items that analysts do not attempt to forecast we earned 297 million in the fourth quarter and 4.4 billion for the full year. The mean First Call estimate for the fourth quarter earnings per share from continuing operations was $1.05. That compares to our non-GAAP earnings from continuing operations of $0.67 per share.

When examining our guidance versus actual results for the quarter, lower price realizations and a higher DD&A rate... DD&A rate account for most of the earnings miss. And while earnings per share came in well below the mean estimate, actual cash flow significantly exceeded the average of the Street estimates.

At this point I'm going to turn the call over to CEO and Chairman, Larry Nichols.

J. Larry Nichols

Thanks Vince and good morning everyone. Well 2008 (ph) was really the best year in our history from many operational standpoints and these are the important ones that we'll recap going forward.

First, we increased oil and gas production by 6% to 238 million BOE, generating a record oil and gas sales of more than 13 billion. We added 584 million barrels equivalent with the drill-bit, excluding price provisions and that's at the top end of our forecast range. It means we replaced nearly 2.5 times our 2008 production; very good results.

When adjusted for items that analysts do not forecast, earnings were record 4.4 billion in 2008 or $9.91 per diluted share. Cash flow before balance sheet changes increased 31% to an all time high of 9.6 billion.

As you know we substantially completed our African divestiture program during the year, generating pre-tax proceeds of nearly 3 billion. We drilled a record 2,441 wells with a 98% success rate and that includes 659 wells in the Barnett Shale where we increased production by 31% over 2007. That's very good production growth.

We steadily ramped up at Jackfish, our oil sand project in Canada, reaching a record 22,000 barrels per day on a way to 35,000 barrels per day. We added some 800,000 net undeveloped acreage to our lease inventory positioned in us with more than 1.4 million net acreage in four emerging unconventional gas plays.

Marketing and midstream business delivered another year of solid results reaching 668 million in operating profits. And we finished the year in a very strong financial position with net debt to adjusted cap to 24%, cash on hand of $379 million. And very early in January last month, we increased our unused capacity on our credit lines to more than 3 billion. So we're in good financial condition.

Just over three months ago, Devon reported the largest quarterly earnings in our history. In contrast, in the fourth quarter as a result of the ceiling test write-down, we reported our largest ever quarterly loss. We could debate the merits and nuances of full cost accounting, but it's important to remember that Devon's underlining assets have not been diminished one iota. We still own the same high quality properties with the same oil and gas resources in the ground. It's only this accounting valuation that has changed.

In fact, as Vince mentioned, under the new rules, it will take effect later this year, we would not have announced any write-down today at all.

In tough economic times like this, it's tempting to get caught up in the present and to believe that markets will never improve. We know from experience that they will. The long term supply and demand fundamentals for oil and natural gas remain compelling. Oil production growth and modernization will continue to challenge world's industry ability to quench the thirst for energy.

Both developing and developed economies will recover and today's oversupplies will be absorbed. The only constant in this business is volatility. And 2008 presented us with some remarkable reminders.

Our response to the current environment is to dramatically cut our capital expenditures. We are budgeting exploration and development capital of somewhere between 3.5 billion to 4.1 billion for 2009. This is less than half our 2008 investment in exploration and development.

With the addition of marketing and midstream, a non-oil and gas capital, capitalized interest and G&A, we are forecasting the total 2009 capital expenditures will be between 4.6 to 5.4 billion.

Assuming an average of benchmark prices of $45 WTI and 550 for Henry Hub gas, our 2009 capital budget will require a difference in spending of about $1 billion.

Our philosophy has always been dilute roughly within our cash flow, and we clearly will not continue to spend at this rate in future years without some improvement in oil and gas prices.

However, in order to preserve our business and maintain the level of momentum that will allow us to take advantage of stronger prices when markets do recover, we believe it is prudent to use our balance sheet strength to fund this additional $1 billion of spending in 2009. If we do see further price weakness in 2009, we'll make further cuts in the future.

We are dramatically decreasing our activity across most of our near-term developmental projects in North America. We will continue activity at a rate that will keep us in the game, but at a far lower level than 2008. We see no reason at all to accelerate our natural gas production in this weak natural gas market.

However, we are going to continue the momentum of some of our longer-term growth projects that will position us to bring on new production when oil and gas prices do recover and demand does recover. We are continuing to fund Jackfish 2, and the evaluation and development of our Lower Tertiary assets in the Gulf of Mexico.

We will also move forward with evaluation and de-risking of our very sizeable acreage positions in some of the emerging shale plays, including the Haynesville and Horn River.

This decrease in development drilling will impact our oil and gas production. The Form 8-K that we're filing today will forecast that full year 2009 production will be essentially flat with that of 2008.

We are fortunate that Devon is positioned to withstand the downturn in global economy and the resulting weaknesses in oil and gas prices. Strength of our balance sheet, the quality of oil and gas properties position us to emerge from the current position, in the current environment and prosper into the future.

This point I'll turn the call over to John Richels to cover our year-end reserves. John?

John Richels

Thank you, Larry, and good morning everyone. The first area I'm going to cover is our 2008 reserves activity which is summarized in the table in today's new release.

Staring with drill-bit reserve additions, and we define drill-bit additions as net discoveries, expansions and performance revisions. These came in at 584 million BOEs. This is above the top of our forecast range and about 2.5 times our 2008 production. When compared with drill bit capital of $9 billion which includes capitalized interest and G&A, our F&D results should be quite competitive with the industry. The most significant reserve growth area was the U.S. onshore where we added 416 million BOEs with the drill bit at a cost of $5.5 billion.

The additions were nearly three times our U.S. onshore production of 146 million BOEs, Barnett Shale was again the most important contributor to reserve additions accounting for about two-thirds of those additions.

The next largest contributor was East Texas where Carthage and Groesbeck areas combined added 45 million BOEs. This was followed closely by reserve additions in Oklahoma of 43 million BOEs which included 21 million BOEs in our new Cana play that Steve will talk about later on in the call.

Drill bit additions of 17 million BOE offshore in the U.S. slightly exceeded production. The cost per barrel analysis of our offshore isn't really very meaningful because we are investing significant capital and appraisal and development operations on our four Lower Tertiary discoveries, but we have not yet booked any proved reserves. We do, however, expect to begin booking Lower Tertiary reserves in 2010 when the Cascade project begins producing.

In Canada, we added 141 million BOEs with the drill bit with 102 million barrels of that at Jackfish, and 19 million BOEs at Lloydminster.

The only blemish to the reserve report was price revisions. Just as the sharp decline in prices triggered a ceiling test write-down, it also resulted in negative reserve revisions. Certain of our properties, notably our oil sands properties in Canada, were no longer considered proved under the assumptions of costs and oil and gas prices in effect at December 31, 2008 held flat.

Some 70% of the price revisions were in our Jackfish project area in Canada. Jackfish is a Steam Assisted Gravity Drainage project as most of you know. And the SAGD economics are sensitive to the interplay of oil, natural gas and diluent prices as well as price differentials between heavy oil and the WTI Index price.

At year end 2008 WTI declined to $44.60 per barrel and the Jackfish heavy oil differential had widened to about 60% compared with a typical differential of 30%. As a result, none of our Jackfish reserves met the economic threshold to be classified as proved at year-end 2008.

However, unlike the ceiling test write-down for accounting purposes, that is irreversible, reserves loss to negative price revisions will be restored in the engineer... reserves engineering report when prices recover.

You may recall that at the end of 2004 heavy oil prices were unusually low and most heavy oil barrels across the industry were written-off. Within a few weeks, prices had normalized and these barrels were back on the books.

The remaining negative price revisions were spread across our North American property base. These were due mostly to a reduction in the economic life of long-lived fields and the elimination of some proved undeveloped locations. Again, as prices recover or costs deflate, we would expect those barrels to once again be classified as proved.

Subtracting negative price revisions of 473 million barrels and adding the 66 million barrels we acquired, we finished the year with proved reserves of 2.4 billion equivalent barrels.

Even though we added 584 million barrels with the drill-bit during 2008, we did not achieve those results by adding lot of PUDs that is proved undeveloped reserves to the books. We ended the year with just 20% of total proved reserves classified as proved undeveloped.

I will now turn to some of the key events and drivers that impacted our 2008 financial results and our outlook for 2009. My comments will be focused on our continuing operations which exclude the results attributable to Africa.

Let's begin with a review of Devon's production. For 2008, we reported full year production of 238 million equivalent barrels or approximately 650,000 barrels per day. That's nearly 14 million barrels higher than our 2007 production and right in line with the guidance we provided last quarter.

Once again, headlining our 2008 production performance was strong growth from our North American onshore assets. A continued success in the Barnett Shale combined with the ramp-up of production from our Canadian oil projects helped boost Devon's North American onshore production by 13% compared with 2007.

This strong growth was partially offset by production declines in our Gulf of Mexico and international segments. In aggregate, hurricanes in the Gulf of Mexico and operational downtime at the ACG field in Azerbaijan curtailed about 3.2 million barrels of production in 2008.

Fourth quarter production came in at 62.5 million equivalent barrels or 680,000 barrels per day, that's 43,000 barrels per day or 7% higher than the third quarter of 2008. When you examine our fourth quarter production performance in detail, you will find that we delivered solid growth in every producing region other than the Gulf of Mexico, where the impact of hurricanes Gustav and Ike resulted in a negative sequential quarterly comparison.

U.S. onshore production climbed approximately 31,000 BOEs per day in the fourth quarter or 8% over third quarter production. As expected, our Barnett Shale and East Texas assets led the way.

In Canada, fourth quarter volumes climbed more than 4% when compared with the third quarter, driven by the continued ramp-up at Jackfish.

Our international production increased by 23% in the fourth quarter over the third, driven mostly by the ramp-up of Polvo in Brazil. As Larry said earlier, we expect 2009 production to be roughly flat with 2008 at about 238 million equivalent barrels. This translates to an average of a little over 650,000 barrels equivalent per day.

We expect our average daily rate during the first half of 2009 to be between 660 and 670,000 barrels equivalent per day, and based on our current capital plan, production would then trail off during the second half of 2009, reflecting the impact of the reduction in capital spending.

Moving onto price realizations, starting with oil. The WTI Index price declined to an average of $58.51 per barrel in the fourth quarter of 2008. Our price realizations relative to WTI also weakened in the fourth quarter, and most producing regions came in at the bottom or below our forecasted guidance ranges.

Consequently, Devon's fourth quarter company-wide realized oil price before the impact of hedges averaged 41.86 per barrel or roughly 72% of the WTI Index. However our oil collars mitigated the fourth quarter effect somewhat as cash settlements increased our oil realizations by $2.2 per barrel to a realized price, including hedges of $43.88 per barrel.

On the natural gas side, the fourth quarter Henry Hub price declined to an average of $6.95 per Mcf, the lowest... actually the lowest quarterly average in 2008. Natural gas price differentials also widened significantly during the quarter for most producing regions, as we forecasted in our third quarter conference call. Consequently, fourth quarter company-wide price realization before the impact of hedges were 76% of Henry Hub or $5.30 per Mcf.

We had about 60% of our natural gas position hedged for the quarter and that boosted our realizations by $0.52 per Mcf, bringing the fourth quarter realized price up to $5.82 per Mcf.

Looking ahead to 2009, we currently have approximately 265 million a day of our natural gas production hedge with a weighted average floor of $8.25 and a ceiling of 12.05. In today's 8-K we provide detailed guidance for expected 2009 oil and natural gas price differentials.

Moving now to marketing and midstream results for the fourth quarter. Marketing and midstream operating profit was 122 million, bringing the full year up to $668 million. Looking into 2009, we expect the lower commodity price environment to reduce full year marketing and midstream operating profit to a range of between 375 and $425 million.

Moving to expenses, 2008 lease operating expenses were right in the middle of our guidance range at $2.2 billion. For the full year, Devon's unit operating costs increased by 14% when compared to 2007.

Fourth quarter LOE came in at $9.32 per BOE, about 8% below the third quarter as costs declined in most of our producing regions and the U.S. dollar strengthened relative to the Canadian dollar.

Looking ahead to 2009, we anticipate the decrease in E&P activity across the industry to cut downward pressure on oil field service and supply costs. For the full year 2009 we are forecasting lease operating costs to range between $8.10 and $9.55 per BOE. Unit LOE will likely start the year at the top of that range and decline throughout the year as costs come down.

For 2008, Devon reported DD&A expense for oil and gas... Devon's reported DD&A expense for oil and gas properties came in at $13.68 per barrel. This was $0.43 above the high end of our full guidance range.

The higher than expected depletion rate is entirely due to the negative price revisions through proved reserves at the end of the year. However, we now expect our future DD&A rates to decrease significantly due to the non-cash reduction in the carrying value of oil and gas properties. For 2009 we are forecasting unit DD&A in the range of $10.25 to $10.75 per BOE of production.

Moving on to G&A expense, Devon reported full year G&A of $653 million. Looking ahead to 2009 we expect to reduce G&A expense by roughly 10% to a range of 565 to $605 million.

Shifting to interest expense; interest expense for 2008 was $329 million or 23% less than 2007. The year-over-year improvement resulted from lower overall debt balances. As we look forward to 2009 we expect interest expense to range between 330 to $340 million.

The next item I want to touch on is income taxes. After backing out the impact of items that are generally excluded from analysts' estimates, our adjusted full year 2008 income tax rate was 32% of pre-tax earnings, 5% current and 27% deferred.

For the fourth quarter, the adjusted tax rate was 38% of pre-tax earnings, about 6 percentage points higher than our full year average rate. The higher fourth quarter rate resulted from a $28 million deferred income tax charge based on a change in our estimate of future deferred tax benefits. This was driven by a reduction in our expectations for future oil and gas prices.

Looking to 2009, we expect to combine income tax rate similar to that in 2008 with roughly one half current and one half deferred.

The final item that I want to cover is a quick recap of 2008 balance sheet activities. Our operating cash flow before balance sheet changes climbed to a record high of $9.6 billion, a 31% increase compared with the 2007 total.

In addition, in 2008 we received another 1.9 of the $2.2 billion of total after-tax divestiture proceeds from Africa, and another $280 million as part of an asset swap agreement with Chevron that we told you about earlier in the year.

In addition to funding a robust capital program including $2.5 billion of property acquisitions and $490 million of investments in our midstream infrastructure, we reduced capital balances by $2.1 billion. As of today, Devon has cash on hand and unused credit facilities in excess of $3 billion and a debt to capitalization ratio of less than 25%.

Looking to 2009 the business environment presents challenges we have not seen for many years within our industry. However, we believe our conservative approach to the business has prepared us well for these conditions.

At this point, I'll turn the call over to Steve to review our 2008 capital program and operational highlights.

Stephen J. Hadden

Thanks John and good morning to everyone. Our operated rig activity peaked in 2008 with 112 rigs running company wide. But in response to falling product prices, we began tapering back activity in the second half of the year and by year-end had just 96 operated rigs running company wide. We are currently operating 68 rigs and expect to be down to 32 operated rigs by the end of the first quarter.

Full year 2008 exploration and development capital came in at $9.3 billion, including $3.8 billion in the fourth quarter. Keep in mind that our fourth quarter capital included about $900 million in undeveloped acreage capture bringing expenditures for new acreage up to almost $2 billion for the full year.

In our third quarter conference call, we indicated that we are in the process of making significant investments in undeveloped acreage, notably in four new unconventional gas plays. We previously talked about two of these areas, the Haynesville and Horn River, But I'll discuss the other two plays.

First is an emerging Mid-continent shale play called Cana. Named for Canadian county in Oklahoma, the Cana play targets the deep Woodford Shale down in the Anadarko Basin. Devon is the largest leaseholder in the play with 112,000 net acres located in Canadian Blaine and Kettle (ph) Counties in West Central Oklahoma.

Although the shale and the clean-up play is the same shale formation found in the Oklahoma basin and Eastern Oklahoma, there are some important differences. The shale in the Cana play is found at greater depths ranging from 11,500 feet to 14,500 feet or an average about 5000 feet deeper than the shale found in Eastern Oklahoma.

The higher pressures at these depths result in greater storage capacity in the reservoir. Initial gas in place estimates for the Cana Woodford indicate upwards of 200 Bcf per square mile, with recovery factors expected to be similar to those found in the best shale plays in the country.

This gives us net risk potential on our existing acreage position in Cana of 4 trillion cubic feet equivalents. We drilled our first horizontal well in the Cana play about 18 months ago and now have completed 10 operated wells in the play including seven long lateral horizontals.

Initial well results indicate average ultimate recoveries in excess of 6 Bcf per well. In fact, four of the long lateral wells where we have significant production history have estimated ultimate recoveries in excess of 8 Bcf per well. We have been de-risking our Cana acreage and perfecting our completions and have achieved repeatable commercial results.

As we move into full scale development, drilling and completion costs should average less than $9 million per well based on the current cost environment. As we continue to optimize drilling and completion techniques and apply practices as we perfected through the thousands of successful wells in the Barnett Shale, we believe we can reduce well costs and further enhance per well recoveries.

Adding to the appeal of Cana play is the liquids rich gas with up to 1300 MMBtu per Mcf. Each development plans will likely include building up processing facility to capture additional value, just as we have done in the Barnett and the Oklahoma Woodford.

In 2009, we plan to drill approximately 27 operated horizontal Cana wells with a four rig program. We also have acquired 3D seismic over most of the play area, and we'll require acquire seismic over the remaining acreage during 2009 to further evaluate and de-risk the play.

The fourth of our emerging plays is the Cody (ph) play, located in South Central Montana where we have assembled 575,000 net acres. Of the four emerging unconventional plays in which we are involved, our understanding of the Cody is in the early stage of evaluation.

So far we have drilled 7 wells and completed just three to date with some encouraging early results. However, we will need to do some considerable additional work to understand this play and de-risk our large acreage position. We will keep you updated as this play continues to mature.

Moving now to our fourth quarter operating highlights, starting with the Barnett Shale field in North Texas, we are continuing running 23 Devon operated rigs compared with a peak of 39 rigs in the fourth quarter. This curtailment in activity is reflected in our average fourth quarter net production of 1.17 Bcf equivalent per day. This was up 4% over the third quarter and up 25% over the fourth quarter of 2007.

Looking forward in 2009, we plan to invest about 750 million of capital in the Barnett and drill over 200 operated wells. We plan to decrease the number of operated rigs to 8 and we'll focus primarily on the continuing success of our 1000 foot and 500 foot offset infill programs.

Moving to the Woodford Shale in Eastern Oklahoma's Arkoma Basin, net production climbed to an average of 64 million cubic feet of gas equivalent per day in the fourth quarter, that's up 35% from the third quarter average and 165% compared with the fourth quarter of 2007. We've reduced our operated rigs from 6 to 5 and expect to further decrease activity and average 3 rigs throughout the year.

Devon's per well recoveries improved dramatically during 2008. This has been driven by improvements in completions, characterization of the reservoir, and longer laterals. Our current model for our wells in this field is 4.5 Bcf at a cost of $6 million per well. We plan to invest $112 million of capital in the Woodford and drill 26 operated wells in 2009.

Moving to the Rockies, our net production in the Powder River Basin in Wyoming averaged a record 100 million cubic feet of natural gas per day in the fourth quarter, up 6% from the third quarter average and up 40% compared with the fourth quarter of 2007.

In the Washakie Basin in Wyoming, we had two rigs running throughout the fourth quarter while drilling 17 operated wells. Our net Washakie production averaged about 150 million cubic feet per day in the fourth quarter, up 12% year-over-year. We plan to invest about $90 million of capital at Washakie in 2009 and plan to drill approximately 40 operated wells with two high efficiency rigs.

In the Haynesville Shale, we had 40,000 net acres in the fourth quarter bringing our total to 570,000 net acres in the play. Progress has been slowed due to mechanical issues in our first two horizontal wells. However, we have incorporated what we have learned into our third horizontal well which is currently completing. We are encouraged that our initial wells confirmed the presence of a sixth organic Haynesville Shale under our leasehold with high reservoir pressures. In 2009, we expect to maintain a two rig program and drill 11 Haynesville Shale wells in the year.

At Carthage, we wrapped up our 102 wells vertical Cotton Valley drilling program during the fourth quarter. We had three rigs running throughout the quarter and drilled 220 vertical wells. In 2009 we expect to spend about $49 million drilling 24 wells.

We also wanted to provide an update on our Haynesville fractured line play. As you may recall last quarter we reported on two wells completed in Haynesville line that IPed at 22 million and 26 million cubic feet a day. Those wells are currently producing 10 and 17 million cubic feet a day respectively with ultimate recoveries of 5 billion and almost 9 million cubic feet of gas. In 2009, we expect to complete 10 additional wells.

Northwest of Carthage at Groesbeck, we bought two high rate Bossier sand horizontal wells on line with the Nan-Su-Gail field in the fourth quarter. The Crenshaw 21H IPed at 19 million cubic feet of gas a day and the new B (ph) 15H IPed at 16 million a day. These wells helped drive our net fourth quarter Groesbeck production to a record 104 million cubic feet of gas per day, up 41% from the fourth quarter of 2007.

Now moving to Canada. Based on our first year of production reservoir performance at Jackfish is a resounding success. Steam ore ratio is as good as we have hoped it would be. And as a result Jackfish is one of the top performing SAGD projects in Canada.

Jackfish wells are producing more than 1600 barrels of oil a day per well, which is among the highest rate of any SAGD project. Production continues to ramp up and in the fourth quarter we reached 22,000 barrels per day.

We remain on track to hit a sustained rate of 35,000 barrels per day later this year. At Jackfish 2 side work is moving ahead in spite of a very cold winter in Alberta. All long lead time drilling and completion items were ordered during the fourth quarter.

The current business climate is allowing us to renegotiate some of our costs. We expect capital expenditures for Jackfish 2 project to total 1 billion U.S. of which approximately $350 million will be acquired in 2009.

Jackfish 2 will have the same basic design as Jackfish with production capacity of 35,000 barrels a day and 300 million barrels of recoverable resources net to Devon's 100% interest. Jackfish 2 is expected to be fully operational in 2011.

Now shifting to the Gulf of Mexico. As I mentioned earlier in 2009 we plan to continue forward momentum in our deepwater projects, including our four Lower Tertiary discoveries.

At Jack and St. Malo the partners are focused upon a joint development concept for the two fields. Efforts in 2009 will be directed towards the final concept selection front end engineering and preparation of tendering package in anticipation of the sanctioning decision. Devon has 25% of both Jack and St. Malo.

At Cascade, drilling operations continued at the Cascade number 3 which will one of two initial producing wells at Cascade. Construction of the production facilities is on schedule. Installation of the risers FPSO mooring, flow-lines and the gas export line are all planned for 2009. We anticipate first production at Cascade by the middle of next year. Devon and Petrobras each have 50% working interest in Cascade.

At Cascada, the largest of our four Lower Tertiary discoveries, we are currently drilling an appraisal well. The co-owners are considering a wide seismic shoot in late 2009 or early 2010 and drilling of an additional appraisal well for a possible well test in 2010. Devon has a 30% working interest in Cascada.

In our Lower Tertiary exploration program, the test on the Bass Prospect located on Keathley Canyon 596 as well as our Damascus prospect located on Walker Ridge 581 have both been plugged and abandoned.

Now moving to Brazil. On the Devon operated Polvo oil project on block BMC-8, I am pleased to report that we've solved the mechanical delays we faced earlier in 2008 and gross production from Polvo is now up to 17,000 barrels a day. We expect productions to continue decline throughout 2009. We operate Polvo with a 60% working interest.

Also in Brazil in December, we took possession of the deepwater discovery drill shift that Devon has under long-term contract. The rig is currently positioned off the Northern Coast of Brazil, drilling the current Gaisler (ph) prospect in Block BM BAR-3. This is in the Parnaíba Basin in 7600 feet of water and is the first deepwater well in this Frontier basin. Devon is the operator with 45% working interest.

The rig will test as many as seven additional deepwater exploratory prospects in Brazil over the next two years.

We also plan to drill and test a well to follow-up for 2008 Oahu discovery.

That concludes the operations update and at this point I am going to turn the call back over to Vince and open it up for Q&A.

Vincent W. White

Thanks Steve. Operator we are ready to take the first question. I'll remind everybody that we ask you to limit it to one question and one follow-up per caller.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). Your first question comes from the line of Rehan Rashid with FBR Capital Markets. Please proceed.

Rehan Rashid - FBR Capital Markets

Just a quick question on the Haynesville front. Should we go a little bit faster there at based on what everybody else is announcing or maybe just how do you think about progressing from here?

Stephen Hadden

Yeah, based on what we see relative to Devon's position, we are very encouraged with reservoir results we saw. We did have some mechanical problems on the first two wells. We have another well that's completing and flowing back... today starting to flow back as we speak. And we're very pleased with those early results we're bringing on relatively slowly.

We also have couple of wells that are drilling, horizontal wells that are drilling and coming down. So we think we're moving through our acreage in a pace that we think in this environment is very appropriate to identify the potential derisk the areas of the play and move forward into a full commercial development.

So we're pretty pleased with where we are considering the environment that we're in. And again, the reservoir information that we have on our Haynesville position is very positive from our perspective.

Rehan Rashid - FBR Capital Markets

Okay. Thank you.

Operator

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

David Heikkinen - Tudor Pickering Holt

Good morning. As I think about your capital budget and targets outspending cash flow by $1 billion this year. As you look at 2009 and 2010, can you keep up that pace or are you betting on a 2010 rebound? Would you continue to outspend as you look forward to next year? If there is a recovery in gas and oil, just wanted to get your perspective on how is this a V bottom, U bottom recovery or how you plan a multiyear program?

Vincent White

David, this is Vince. As we said in the call we would not continue on a multiyear basis to outspend cash flow. We're adamant about protecting our balance sheet, and frankly we think there is a real lack of visibility on the link of the economic downturn. And we'll have to see how the industry responds, see how quickly natural gas process will recover. The main thing that we're going into this year with a... for you to stay flexible and adjust our spending in response to the market environment.

David Heikkinen - Tudor Pickering Holt

Just a follow up there, how much of capital this year is tied to longer term project or kind of larger projects that are more fixed?

Vincent White

David it's about when you take in into account all the pieces of it. So that is, we're doing Jackfish 2 and as Steve described what we're doing in the Lower Tertiary and in Brazil, it accounts for about 1.6 billion of our total CapEx for the year.

David Heikkinen - Tudor Pickering Holt

Thank you guys.

J. Larry Nichols

David I might add. We're really balancing two things as we go through this year. On the one hand, we have one of the stronger balance sheets in the industry and we want to protect it. On the other hand, we want to position ourselves so that when the recession does end which it will and when gas prices do increase, which they will, as production in the country declines. The Devon is in the best position possible to have fully evaluated the Haynesville as well as all of our other plays and to have both the employees of the companies as well as the assets well positioned to really take off so that we can be selling gas into the rebounding market, rather than trying to maximize gas production now when gas prizes are week. That makes no sense at all. That's not a good way to create shareholder value.

So, we are trying to keep the company in good financial condition to evaluate the assets and to position ourselves where we can achieve maximum production growth at the right time. When that happens? Hard to say. We'll evaluate that continuously as we go forward.

David Heikkinen - Tudor Pickering Holt

Thanks Larry.

Operator

Your next question comes from the line of Ben Dell with Stanford Bernstein. Please proceed

Ben Dell - Stanford Bernstein

Hi guys,

J. Larry Nichols

Good morning.

Ben Dell - Stanford Bernstein

I had two quick questions. The first was on the $27 million pretax charge that you took due to the change in the vesting policy. It seems like a big number. Can you give us some outlines of what the change in the policy was?

Vincent White

Ben this is Vince. I'll attempt to address it. First, this was a change made early in the year and it was to bring our vesting policy for Senior Executives and to align with our peer companies. And what it does is allow for retiring executives, allow them to continue to vest upon retirement. And one of the ideas behind this is to prevent an incentive to hastily sell the company as someone moves towards retirement, we've seen that happen a couple of times in our industry. The main shift is that it accelerates the expense, it's not a significantly increase in expense, but it changes the period during which it's recognized. So, I hope that helps you add some color.

Ben Dell - Stanford Bernstein

Yeah. That's great. And then just on production question. Given your new outlook for 2009 can you give us some indication of what that would mean specifically to your Barnett volumes?

Stephen Hadden

Yeah, Ben, this is Steve. The Barnett volumes will rise slightly from the average production that we mentioned in the press release. So, we'll have... we'll continue to benefit from over 600 wells that we drilled this past year. We'll drill another 200 plus wells on an operated basis, and of course we'll have some non-operated wells.

So the average production year-over-year for the Barnett will go up. Rate wise we may see a little bit of tailing off as we get into the late third and the fourth quarter, depending on what we do as we look at things in the middle of this year.

Ben Dell - Stanford Bernstein

Okay. Great. Thank you.

Operator

Your next question comes from the line of Robert Christensen with Buckingham Research Group. Please proceed.

Robert Christensen - Buckingham Research Group

Yeah. Any other Lower Tertiary well cutting expected for 2009?

Stephen Hadden

Well, no, not in 2009. We're... what we are focusing on right now is the development of Cascade and driving that to first production. So we'll finish drilling the first producing well which we're on right now and then we will move to drilling the second producing well and then go through completing those two wells, and that will carry into early 2010.

We also are working on the drilling of the appraisal well on Cascada and that's really in its early phases and will continue through the middle of this year or so. And then, we are moving forward with some additional work that we are dong on Jack and St. Malo, but there is no additional Lower Tertiary well cuts that are planned at this point in our portfolio for 2009.

Robert Christensen - Buckingham Research Group

Thank you.

Operator

Your next question comes from the line of Joe Allman with JP Morgan. Pease proceed.

Joseph Allman - J.P. Morgan

Yes, thank you. Good morning everybody. Steve, what are your thoughts on the production at Cascade and what kind of ramp up do you expect and what kind of capacity you expect out there and also any updated thoughts on the complexity of the reservoir?

Stephen Hadden

Well first, we are in the process of drilling our third Cascade 3 which is going to be both producing well and we'll side track that well to just further confirm any issues that relate to any compartmentalization. We haven't seen that as a major barrier at all. Right now, we think as far as the interplay between the reservoir quality and the fluid quality, that's going to be fine. And with the completions that we are running we could probably see in the range of 10,000 barrels a day or better on a per well basis.

And this will be the first long term flow test of these Lower Tertiary wells. And we are really looking forward to that. So not really overly concerned about the complexity issues, very interested to get these wells on, get that long term production test and move forward there.

Joseph Allman - J.P. Morgan

Okay. And how is like capacity there at the facility there?

Stephen Hadden

The capacity of facility is about 80,000 barrels a day in total. And remember that facility is shared between the Sinop development and our Cascade development. Cascade has about 40,000 barrels a day of capacity allocated to it right now. So we're well positioned there. And then we can expand that capacity in the future as we go through the stage development of the project.

Joseph Allman - J.P. Morgan

Great. How about the Cana program, what kind of infrastructure should (ph) it have besides having to build the processing facility?

Darryl Smette

Joe, this is Darryl. We are moving down building processing plant right now. It looks like there will be about 200 million a day plant to start with. We are also putting in the number of gathering systems in the main export line to center delivery compressions point. We are currently in the process of negotiating with the two or three different companies for a long haul pipeline out of this area. Those negotiations are ongoing but right now we feel very comfortable that we'll be able to have the plant up and running by mid 2010 with all the facilities and we'll be able to keep up with the E&P production.

Joseph Allman - J.P. Morgan

Okay. Thanks Darryl, thanks Steve.

Operator

Next question comes from the line of Joe Magner with Tristone. Please proceed.

Joseph Magner - Tristone Capital

Good morning, thank you. Perhaps you touched on a little bit earlier. I just wanted to talk about the liquidity position and the capital availability you'll have, even if you have been cash flow issued $2 billion. You will be sitting on north of 2 billion in cash and available capacity on your revolvers. Can you just walk us through the priorities for your use of that capital if we do see recovery within the bad timing but upon recovery how you would prioritize that?

Vincent White

Joe, that's a little hard to determine it at this time. I mean your summary is pretty close. Obviously without I think about $2.1 billion of available credit at the end of the year assuming we overspent by $1 billion. And Larry made the point and it's a great point, the real art here for us is to take advantage of our considerable financial strength and good asset bases that we have and hit the accelerator at the right time when we see a light at the end of the tunnel.

Certainly a lot of what we're doing this year is as Larry has indicated already is that we're not spending a lot. We're not trying to accelerate gas production into a very weak commodity price market. We're focusing on these longer term projects. However, we have so much in our inventory in these gas projects that we can very quickly start to ramp up production if we see the picture turning around and commodity prices improving. But we haven't really developed our detailed thinking on how that 2010, for example, capital program might look. But we have such a great inventory that we'll be able to move that up pretty quickly.

J. Larry Nichols

Yes, there is no doubt that at a point time we will go back to maximizing production growth... the 31% production growth we got at the Barnett this past year. So we will go back to maximizing the Barnett as well as Haynesville, as well as Cana as we continue to derisk those. So as the gas markets improve which they will, recognizing in the U.S. we have... the whole nation has an average decline of about 31%. Supply and demand will get back in line and in due course we'll go back to full throttle on all of our gas plays.

Joseph Magner - Tristone Capital

Okay. There's specific concerns about possible acquisitions but it sounds like to summarize your focus initially would be on organic opportunity. And just one quick follow-up, any plans to alter or update your hedging strategy at this point in time?

Darryl Smette

Yes, this is Darryl. First, let me just tell you where we are... reemphasize where we are in our hedging program. Currently we only have 265 million hedged for 2009, no oil hedge for 2009, no gas hedges or oil hedges hedged in 2010. Historically Devon has not been a big user of the financial hedging market.

However as we're getting into more long-term projects, we are currently evaluating whether we want to put a consistent hedging policy in place. So we do not have one at the present time. It's something we are looking at and we'll move that forward as we look at the long-term projects we have in front of us.

Joseph Magner - Tristone Capital

Thank you.

Vincent White

We've got time for one more question.

Operator

Your final question comes from the line of Bryan Singer with Goldman Sachs. Please proceed.

Brian Singer - Goldman Sachs

Thank you. What gas price would you need to see to ramp-up the rig counts? And if you look at where you are decreasing your capital on rigs now, what's the area that maybe would be the last one to be laid down but then be the first that would be brought back?

Vincent White

Brian, this is Vince. Just a couple of observations. The calculus of where to cut back is a lot more complex and it might appear at first wash. We need to keep our workforce engaged. We need to keep the service and supply industries engaged. And so really our cutbacks are across the board in North America in all short cycle time projects.

And consequently depending on the degree of recovery of prices, our ramp-up would also be across the board. We're prepared to do that. Clearly, one of our most intense areas of activity over the last couple of years and in the future is the Barnett Shale. And we've got a lot of running room there. So it's clear that we would, under current market conditions would dramatically accelerate there if we had additional cash flow available to us. But really, I think it would be across the North American landscape.

Brian Singer - Goldman Sachs

And that would... what price would you need to see to ramp things back?

Vincent White

While our limiting factor being not the economics on the play so much as our cash flow. Each incremental improvement in our view of prices will give us more cash flow to invest.

Brian Singer - Goldman Sachs

Great. And lastly, could you talk about your backlog? What levels of oil and gas production onshore U.S. in general terms is waiting completion or completed the waiting time?

Stephen Hadden

Brian, I'll tell you that it's an interesting number to get at, but we generally can probably run about a couple... take the Barnett Shale for instance, we drilled operated, non-operated, we drilled 680 wells last year. We probably came into this year with an inventory of a couple of 100 wells yet to be completed. And so, that's probably a pretty good indicator in the bulk of those.

The other plays are relatively early. Some of the plays like Cana and obviously the Haynesville plays are really ramping up and so they don't have nearly an inventory or a hangover like that. But the Barnett is probably reflective of what inventory we came into this year with.

J. Larry Nichols

Brian, I might add one more point on that on your question on the price. The price can't be answered in average strike (ph) without reflection on the costs. Our industry has in the fourth quarter of last year, we had 2008 cost structure with prices were back in the 2001, 2002 level. Rig costs and all the service supply costs are going to come down. They are coming down dramatically and they will continue to come down. And we will get back in balance.

It's kind of hard to say where that balance will happen, but they will get back in balance. They have in every other cycle and there is no logical reason why this won't happen. And so declining costs during the rest of this year make it feasible to be more active in some area at a better price, at a price realization that we're not at this moment. So those two, you got to balance those two.

Brian Singer - Goldman Sachs

Great. Thank you.

Operator

We're couple minutes past the hours.

Vincent White

So, as I said we'll go ahead and respect your time and cut off the call at this point. As usual, we'll be around for the rest of day, if you'd like to contact us with any questions that we didn't get to. Thank you for your participation.

Operator

Thank you for you participation in today's conference. This concludes our presentation. You may now disconnect. Have a good day.

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Source: Devon Energy Q4 2008 Earnings Call Transcript
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