Devon Energy Corporation Q4 2007 Earnings Call Transcript

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Devon Energy Corporation (NYSE:DVN)

Q4 2007 Earnings Call

February 06, 2008 11:00 am ET


Vince White - VP of Communications and Investor Relations

Larry Nichols - Chairman and CEO

Steve Hadden - SVP of Exploration and Production

John Richels - President

Darryl Smette - SVP of Marketing and Midstream


Dave Kistler - Simmons & Company

Joe Allman - JP Morgan

Brian Singer - Goldman Sachs

Gil Yang - Citi

Mark Gilman - Benchmark

Jason Ganu - McGuire

David Heikkinen -Tudor Pickering


Welcome to Devon Energy's fourth quarter and year end 2007 Earnings Call. (Operator Instructions).

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

Vince White

Good morning, everyone and thank you operator for that promotion. Welcome to Devon's year end 2007 conference call and webcast.

I am going to start the call with the few preliminary items and then our Chairman and CEO, Larry Nichols will give a high level overview of 2007 as well as updates on a couple of strategic initiatives. Following Larry's remarks, our Senior Vice President of Exploration and Production, Steve Hadden will cover our operating highlights. And then finally our President, John Richels will finish up with the review of the year's financial results as well as our outlook for 2008.

We will conclude the call in about an hour. So if you don't get your question answered, please feel free to contact us after the call for follow-up.

A replay of this call will be available later today through a link on our homepage and we will also be distributing a new issue of Devon Direct as well as posting it to the Devon website.

Also today we will follow Form 8-K as we do each time this year which will provide the forecast for the year ahead. This 8-K includes forecast for 2008 production by product and geographic region, expense estimates and our expected differentials to benchmark oil and gas prices for the year.

The forecast in today's 8-K treat our remaining operations in Africa as discontinued operations. However, in addition to the forecast for our continuing operations, we are providing a summary forecast applicable to the divestiture properties. This will enable those of you that maintain models on Devon to include or exclude West Africa as you choose.

As you may remember our decision to sell last year our African operations triggered the accounting rules for discontinued operations. Under those rules the revenue and expenses for the discontinued operations are collapsed into a single-line item near the bottom of our statement of our operations. However, we are providing an additional table in today's new release that includes a detailed statement of operations for the discontinued ops.

As indicated on this table, net earnings from discontinued operations were $212 million in the fourth quarter and $460 million for the full year 2007. However, I will remind you that that does not mean that the discontinued operations would have contributed that level of earnings if we were not selling them. That's because the accounting rules for discontinued operations require us to stop recording depletion expense on the properties that we're selling once they are declared discontinued operations.

Had we continued to depreciate our African properties, we would have had net income associated with the divestiture properties of a $196 million for the fourth quarter and $368 million for the full year 2007. And both the quarterly and the full year figures include the $90 million gain we recognized in the fourth quarter on the sale of Egypt.

Accounting for discontinued operations also complicates the comparability of our earnings estimates. Most of the analysts that report to First Call excluded the impact of discontinued operations for the fourth quarter. The mean estimate of earnings per share from the analysts that excluded discontinued operations was a $1.91 for the fourth quarter, that compares to our non-GAAP earnings from continuing operations of a $1.93.

For those analysts that included discontinued operations in their estimates, the mean was a $1.94 a share and that compares to our non-GAAP diluted earnings including discontinued operations of $2.16 per share for the fourth quarter.

So in either case, we beat the Street expectations.

Before I turn the call over to Larry, we're obligated to remind you that discussions of our expectations, plans, forecast and estimates are 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 many factors that could cause our actual results to differ from those estimates. And for a discussion of the risk factors that could influence our actual results, you could refer to our Form 8-K that we will be filing today.

One final compliance item, we'll make reference today in the call to various non-GAAP performance measures. When we provide these measures we are also required to provide certain related disclosures and those disclosures have been posted on the Devon website.

That concludes my remarks and I'll now turn the call over to Larry Nichols.

Larry Nichols

Thanks, Vince, and good morning, everyone. Now for the fun. The earnings release that we released this morning really shows that Devon had its best year ever in our 20-year history as a public company. 2007 was a great year. We grew oil and gas production 12% over 2006, up to 224 million Boe. We reported record net earnings of $3.6 billion. We reported record earnings per share of $8 per share. Cash flow before balance sheet changes climbed 21%, also reached an all-time high $7.3 billion.

With cash flow from operations we funded $5.4 billion in exploration and development capital. In addition we repurchased $326 million of common stock and we repaid $567 million of maturing debt during the year.

In laying the foundation for the future we drilled over 2400 wells with a 98% success rate growing crude reserves to a record $2.5 billion of equivalent barrels. Our finding and development costs came in lower than our forecast and did not include any reserves from our deepwater Gulf projects.

We began operations on three of our significant projects that we talked about in 2006 and 2007, the deepwater Merganser field in the Gulf of Mexico, the Polvo offshore field in Brazil and the Jackfish oil sands project in Canada.

In the Barnett Shale, we achieved a 33% production growth and drill-bit reserve additions of more than three times the year's production, very good performance in the Barnett Shale.

In Canada, we increased annual oil production from Lloydminster by 40% to 33,500 barrels per day and added 22 million barrels with the drill-bit. Not to be out done our marketing and mid-stream operations also delivered record results, contributing more than $0.5 billion of operating profit for the year.

And we finished the year in a very strong financial position with $1.7 billion of cash and short-term investments on hand and net debt-to-adjusted cap ratio of just 18%, very strong balance sheet.

In this today's release we did provide summary of reserve report data and I have a couple of observations about those results. The drill-bit reserve additions, and by drill-bit, I of course mean discoveries, extensions and performance provisions came in at 390 million Boe, this exceeded by 30 million barrels, the upper end of the estimated range that we provided in December. These drill-bit additions are nearly 1.75 times our 2007 production from continuing operations.

With a total drill-bit capital of $5.8 billion which includes capitalized interest in G&A, and drill-bit revision reserve additions are 390 million Boe. Clearly our organic F&D cost should be among the most competitive, among our entire peer group.

Price revisions gave us a net positive boost in 2007, adding another 44 million barrels. Taking these into account, we are looking at all sources including price revisions. We added $437 million Boe at a cost of $6.1 billion. As with our drill-bit only F&D, our all-sources F&D should be very, very competitive within the industry.

And these results were achieved in spite of our investments during 2007 of roughly $600 million in high impact, future growth prospects which did not add and we are not planning to add any reserves during the year.

Foremost to come among these types of expenditures are our deepwater Gulf of Mexico exploration and development projects and particularly the word treasury. We are actively pursuing these long-term projects in offshore China as well as Brazil. Our second thermal project in Canada Jackfish 2 project and a variety of other North American onshore play projects that are included in that $600 million.

Looking at 2008, we are forecasting another year of strong production reserve growth within even larger component focused on long-term growth. We're forecasting 2008 production of 240 million Boe to 247 million Boe with drill-bit reserve additions of 390 million Boe to 410 million Boe.

With drill-bit capital expected to be somewhere in the $6.1 billion to $6.4 billion in 2008, we should again achieve a very respectable, very competitive finding and development costs, while devoting even more capital to our longer-term growth projects.

In 2008 we expect to spin about $1 billion on these longer-term growth projects. The investments we are making in those projects today will help ensure that we have a very robust development pipeline and development projects not just into the next decade but throughout the next decade.

We also recently announced that we've hedged a meaningful port of our expected 2008 production mostly on the natural gas side. Our decision to hedge was based on several factors. As most of you know, the nature of our capital budget has shifted over the last few years toward a longer-cycle time projects with long-term associated capital commitments. Examples include the Jackfish SAGD projects, our Lower Tertiary exploration and development projects.

These are projects that require continued investment independent of short-term commodity price fluctuations. When we initiated this hedging activity, gas storage in early January, gas storage was at near record levels.

Over the past few weeks, natural gas storage levels have moved closer to five-year averages being led by the record withdrawals that we had last week. While this has somewhat lessened our concern regarding gas storage, we still believe the potential for gas price volatility remains. The extent of that volatility will be driven both by weather conditions during the remainder of the winter and by economic conditions and the persisting concerns about a recession affecting U.S.

The hedges we entered into are very attractively priced and reduced the potential impact of gas price volatility. In fact both the swap price of $8.24 and the floor price of $7.30 are natural gas colors that we're able to exclude for 2008 are higher than the average natural gas price for any year in history except for one yea 2005 when we had the hurricanes. Weighing these factors we believed it was prudent to enter into these hedges for 2008.

To give you a quick update on West Africa, we closed the sale of Egypt last year and are soliciting the final government approvals to close the $205 million sale on our Gabon operations.

We received a variety of attractive bids for the other West African properties and are working through the negotiations with the various purchasers and governments on those properties. Although this is proven to be very time consuming we're optimistic we'll complete these by midyear.

With the anticipation of the completion of our African divestitures, the Board has recently reauthorized the 50 million share repurchase program that we suspended in 2006. We could have considerable free cash flow in 2008, especially following the closing of the remaining divestitures. We believe that Devon stock was very attractive versus alternative investments and expect to opportunistically repurchase shares with our excess cash.

Before I turn the call over to Steve, I want to take a few moments of pride and I hope you'll indulge me. In January Devon was named one of Fortune Magazines’ 100 best companies to work for. At number 48 on that list, Devon has the distinction of being the highest ranked oil and gas producer to ever appear on that list.

In addition of all those companies, we had the fourth lowest employee turnover rate. That is really rather a commendable rate. With competition from employees in our industry at very fierce levels, being selected one of the best places to work gives us a distinct advantage in a very competitive market.

Selection for this type of award is mainly based on feedback, independent feedback that is known by the outside agency and talking to our own employees and we want to thank all of those employees for their support and for the culture that we've created here.

With that, I'll turn it over to John. John? I am sorry, Steve Hadden.

Steve Hadden

Thanks, Larry, and good morning to everyone. As Larry mentioned from an operations perspective, 2007 was an outstanding year. We delivered 12% production growth in pushed proved reserves to a record 2.5 billion barrels of oil equivalent. This was the result of highly successful capital program including the drilling of 2440 wells with a 98% overall success rate.

Nearly 94% of those wells were in low-risk development projects which continue to provide a solid reliable platform from which to grow. At the end of December we had a 122 rigs running companywide with 87 rigs drilling Devon operated well. And we are drilling at a similar pace today.

2007 capital expenditures for exploration and development develop projects came in at $5.4 billion including $1.6 billion in the fourth quarter. To reach the $5.8 billion of drill-bit capital that Larry referred to, you would add roughly $400 million of capitalized G&A and interest to the E&P total.

Moving now to our fourth quarter operating highlights starting with the Barnett Shale field in North Texas, we are currently drilling 32 Devon operated rigs including 14 in the core and 18 outside the core. 20 of these operated rigs are the newer high efficiency models.

Production growth for the field continued to exceed our expectations in the fourth quarter. You may recall that last August we increased our 2007 exit rate target for the Barnett to 875 million cubic feet per day about 10% above the 800 million cubic feet per day target we set at the beginning of the year.

During the fourth quarter we blew through that target as well and we are producing around 950 million cubic feet per day on December 31st. In fact, our net Barnett production average doubled 930 million cubic feet of gas equivalent per day for the fourth quarter, up 9% from the third quarter average and up 35% year-over-year.

To remind you that these production numbers are net to Devon's interest, not gross operated volumes by Devon. Reasons for the rate acceleration include improvements in drilling efficiency which resulted in more wells drilled during the year, and we realized better average well results.

We began 2007 expecting to drill about 400 wells but increased the activity during the year to include more infield wells and more wells outside the core area, ultimately drilling 582 wells in the year.

Our average well results also continue to improve. We bought 116 wells online during the fourth quarter at an average rate of 2.1 million cubic feet of gas per day, compared to average rates of 1.9 cubic feet per day in the fourth quarter of 2006.

About a year and a half ago, Devon's stretch goal for the Barnett Shale production was 1 Bcf per day net to Devon interest by the end of 2009. It now looks as though we will reach that target sometime during the second quarter of 2008, about 18 months ahead of the original schedule.

Looking into 2008, we planned level of activity in the Barnett Shale that's similar to what we experienced in 2007. We will also continue execution of our 80-surface acre infill drilling program as well as drilling a few trial horizontal infill wells on 40 surface acres and on 20-surface acre locations.

We expect our Barnett Shale program to deliver another year of strong production growth in 2008.

From a reserve performance perspective, the Barnett Shale was the leading growth area for the company again in 2007. Extensions, discoveries, and performance revisions in the Barnett accounted for 158 million barrels of oil equivalent of additions. This was well over three times our production of 50 million Boe for the year.

Associated capital was $1.6 billion. At year end we had 724 million Boe booked in the Barnett and 87% of those reserves are developed compared with 78% developed at year end 2006. So PUD bookings in the Barnett are only 13% of the year end improved reserves.

In the Woodford Shale in eastern Oklahoma we currently have five operated rigs running. We bought a total of 12 new operated wells online during the fourth quarter and now operate about 60 wells in the play with gross operated production running about 47 million cubic feet a day. Until now our Woodford activity was focused on drilling the hold acreage principally, but in 2008 we will shift to developing that acreage. We plan to invest about a $160 million of capital in the Woodford and double our operated well count by drilling about 60 wells during the year.

Moving to the Rockies and the Washakie Basin in Wyoming, we had four rigs running throughout the fourth quarter. During the quarter, we drilled 16 wells in Washakie bring full year total to 49 wells on Devon operated acreage. We also participated in a 112 outside operated wells during 2007.

Devon's net production at Washakie averaged about 103 million cubic feet per day in the fourth quarter, up 4% from the third quarter average and up 14% year-over-year. In 2008 we plan to invest about $125 million of capital in the Washakie drilling approximately a 130 wells.

Two high efficiency rigs are expected to be delivered later this year to increase our drilling time per well. With over 300 undrilled locations we have plenty of running here in Washakie.

Shifting to east Texas at Carthage we wrapped our 2007 93 well vertical Cotton Valley drilling program during the fourth quarter. We had 6 rigs running throughout the quarter and drilled 32 vertical wells. In 2008 we expect to spend about $200 million on low risk repeatable vertical program drilling 100 wells. Also at Carthage, our horizontal drilling program continues to deliver solid results.

During the fourth quarter we drilled and completed three new Cotton Valley horizontal wells including the 100% working interest at Langford 6H well that Iped for 4.6 million cubic feet a day.

In 2008 we plan to spend a $160 million as we step up our Carthage horizontal program. We expect to run 4 rigs and drill 23 horizontal wells for the year. Today we have about a hundred horizontal locations identified at Carthage.

In total our Carthage net production averaged a record 277 million cubic feet of gas equivalent per day for the fourth quarter, up 7% from the third quarter average and up 19% from the year ago.

From a reserves perspective Carthage delivered an impressive growth again in 2007. We added 46 million barrels of oil equivalent of reserves, 3 times our 2007 production, with drill-bit capital of $426 million delivering strong reserve growth at low F&D.

With the combination of our horizontal and vertical drilling programs, we believe we can continue to grow Carthage production and reserves well into the future. Southwest of Carthage at Groesbeck, we're still in the early phases of evaluating our acreage position and optimizing our site selection, drilling and completion techniques. We've made some good strides in improving our consistency and reservoir performance from the wells we have drilled in some areas is very good.

We brought online two strong horizontal wells at Groesbeck in the fourth quarter. In the Nan-Su-Gail field, the Nail-B 12H Iped at 24 million cubic field a day and in the Oaks field the Thompson 12H Iped at 12 million a day. As we did in the non-core Barnett we will move very deliberately until we mature our understanding and are prepared to maximize the return from our position.

And while we still have more to learn we believe we have an attractive horizontal play in the Groesbeck area with a sizable number of potential horizontal drilling locations.

Now moving to Canada, at the Devon operated Jackfish thermal heavy oil project in Eastern Alberta, we began injecting steam last year and are now selling oil. We are seeing some minor startup issues as we monitor and adjust the systems but only reservoir responses good and we’ve not detected any design problems with the above ground facilities.

Production will ramp up gradually heading towards an expected sustainable production rate of 35 barrels of oil a day. At Jackfish 2 we awarded primary engineering contracts in the fourth quarter of 2007 and in mid-2008, we hope to receive regulatory approval and formally sanction the project. If all goes well, we could begin site work in the fall. Jackfish 2 is planned to have the same design as Jackfish with production capacity of 35,000 barrels a day and 300 million barrels of recoverable resources.

At our Lloydminster Oil plant, Alberta this exceptional asset is demonstrating the breadth of Canadian portfolio. We are increasing production dramatically at Lloyd with low F&D costs and very high rates of return. We ran a four rig program in the fourth quarter and drilled 145 new wells. This brought the full year total to 429 wells, Lloydminster production averaged 38,000 thousand barrels per day in the fourth quarter, up 9% from the third quarter and up 46% year-over-year.

2007 drill-bit reserve additions at Llyodminister totaled 22 million barrels of oil equivalent just about doubled the year's production. Drill-bit capital was $241 million. In 2008 we plan to spend 280 million and drill another 475 wells in the Lloydminister area.

Now shifting to the Gulf of Mexico in our Lower Tertiary exploration program, we are preparing to drill the objective section on a Chuck prospect located in Walker Ridge 278. The objective is a large subsold structure, but we won't have any results to report until the well has been logged and evaluated. Devon is the operator of Chuck with a 39.5% working interest.

Also drilling is the Lower Tertiary Green Bay prospect, Green Bay's and Walker Ridge 372 in approximately 6,300 feet of water, the prospect was spot in the fourth quarter and is currently drilling below 20,000 feet. Green Bay is about 20 miles north of the Saint Malo discovery and about 18 miles east of the Chuck prospect. Devon has a 23.4% interest in Green Bay.

We are conducing appraisal and development activities on each of the four Lower Tertiary prospects where we made discoveries. At Saint Malo also located in the Walker Ridge area, we reached the planned depth with our second delineation well, the Saint Malo Number 3 and have completed coring in the Wilcox. We'll now plan to drill another 200 feet to 300 feet when we finished here the rig will mobilize and move on to the Saint Malo Number 4 appraisal well.

At Jack, also in Walker Ridge we plan to drill the Jack 3 appraisal well with the Ocean Endeavor rig after complete its work on a Chuck exploratory well. The result of these appraisal wells at Jack and Saint Malo will help the partners to determine the optimum development approach for these projects. Devon has a 25% working interest in Jack and 22.5% working interest in Saint Malo. The partners in the Cascada discovery are planning the next round of appraisal operations to be performed in the second quarter of 2008. Devon has a 20% working interest in Cascada, which is in the deepwater Kirkley Canyon lease area, west of Walker Ridge.

At Cascade, the first of Devon's Lower Tertiary discoveries slated for development, we awarded the remaining contracts for facility supply, construction, and installation in the fourth quarter. Later this year we plan to drill the first of the two initial Cascade producing wells.

We anticipate first production at Cascade in the first half of 2010. Devon and Petrobrass have equaled 50% working interests in Cascade. In our deepwater Miocene exploration program we expect to begin drilling on the Sturges north prospect located at Water Valley block 138 in the next few days. A previous discovery at Sturges encountered over 100 feet of net oil pay. The Sturges north is adjacent to the original discovery but we'll test the separate structure. Devon has 25% working interest in the Chevron-operated prospect.

Now moving to Brazil, we continued development drilling on the Devon-operated Polvo oil project on block BMC8 during the fourth quarter. Due to some mechanical issues production at Polvo has not ramped up as quickly as we expected. However, we're pleased by what we have learned about the reservoir from the drilling the first few wells.

We believe our resource estimates at Polvo were solid but it could take a little bit longer to reach peak production than we initially planned. We continue to move forward with our exploration program in Brazil where we're building an inventory of high potential prospects. We currently have ownership in 9 blocks in Brazil comprising 1.3 million gross acres and 700,000 net acres and 3 offshore basins.

We have 17 prospects identified to-date with gross un-risk potential ranging from a 100 to 460 million barrels per prospect. Seven of the blocks are located in the prolific Campos Basin where hydrocarbon discoveries and production have been established in place from the Cretaceous presold to the Miocene.

We are partnered with Petrobrass in four of these blocks in Campos Basin. In addition to the presence in the Campos we have acquired two frontier deepwater blocks, one in the Barinas basin and one in the [Cameleon] basin. In 2008 we'll drill our first presold exploratory well on block BMC30 in the Campos basin. Then in January 2009 the Devon-operated deepwater discovery drillship is expected to arrive in Brazil to commence drilling seven planned wells over a two-year period.

That concludes the operations update. I’ll now turn it over to John Richels to review our financial results and the 2008 outlook. John?

John Richels

Thank you, Steve and good morning, everyone. This morning I will take you through a brief review of the key events and drivers that shaped our 2007 financial results and our outlook for 2008. As Vince mentioned, we have reclassified the assets, liabilities and results of operations in Africa as discontinued operations for all accounting periods presented. So I’ll focus my comments only on our continuing operations, which exclude the results attributable to West Africa.

Let's begin with our production. For 2007 our full year production was 224 million barrels of oil equivalent or approximately 614,000 Boe's per day. Compared to last year you'll find that company-wide production increased by 65,000 Boe per day or nearly 12%.

Our US onshore and international operating segments drove this year-over-year growth. We grew production from US onshore by nearly 40,000 barrels per day or 13%.

Increased drilling activity in the Barnett Shale coupled with overall reservoir outperformance in the Barnett were the biggest drivers of our US onshore growth. We also nearly doubled production in the international sector to 54,000 barrels per day in 2007 driven by the performance of the ACG field in Azerbaijan and initial production from our Polvo field in Brazil.

For the fourth quarter of 2007 production came in at 58.1 million equivalent barrels or 632,000 barrels per day. This represented a 10% increase in fourth quarter production over last year and marks the seventh consecutive quarter of production growth.

In addition, we exceeded the fourth quarter guidance provided in our third quarter conference call, by just over a million barrels. This was driven by several of our core properties in North America, delivering better than expected results, and the lack of any significant hurricane downtime in the Gulf of Mexico.

Looking ahead to 2008, we anticipate continued, strong production growth. The mid point of our 2008 forecast range implies a 9% increase over 2007, driven by growth from our established onshore properties in both the US and Canada, the ramp-up of production from our Jackfish steam-assisted gravity drainage project in Alberta. A full year of production from Merganser in the Gulf of Mexico and the continued ramp-up of production from our Polvo project in Brazil.

We expect production for the first quarter of 2008 to be up slightly at about 640,000 Boe’s per day with growth expected each quarter for the reminder of the year.

Moving to price realization starting with oil, the WTI benchmark rose steadily throughout 2007 and ended the year with the fourth quarter average of $90.92 per barrel. Ultimately the full year WTI index averaged $72.39, a 9% gain over 2006.

In addition to the strength and benchmark oil prices, most regional differentials narrowed, when compared to last year, and most important to Devon was the robust internationally oil market, reflected in premium pricing for our light sweet oil in Azerbaijan.

Overall companywide price realization rose to 88% of WTI or $63.98 per barrel for 2007. As the result of the improvement in differential, 2007 realizations actually outpaced the rise in WTI by a couple of percentage points.

On the natural gas side, the benchmark Henry Hub index averaged $6.86 per MCF for the year, a 5% drop off from 2006. However, in the fourth quarter the Henry Hub index rebounded by 13% from third quarter lows to $6.97 per MCF.

For the year Devon gas price realizations came in at the top end of our guidance range at approximately 87% of Henry Hub, a 3% improvement over 2006. Price realizations were especially strong in Canada and in the Gulf of Mexico. However, this regional strength was partially offset by widening price differentials in the Rockies prior to startup of the Rockies Express Pipeline.

In today's 8-K we provide detailed guidance for expected oil and natural gas price differentials for the upcoming year, as well as details of the hedges that Larry mentioned. The hedge volumes in the 8-K include another 25,000 MMBtu of gas hedges entered into, after we issued Monday's press release.

In additional to strong upstream performance, Devon’s marketing and midstream operations also produce outstanding results. Driven by strong gas processing margins, fourth quarter operation profit totaled $148 million and brought full year marketing and midstream profit to $509 million. This the highest level in company history and $73 million more than the 2006 total. Looking forward to 2008, we expect marketing and midstream operating profit to increase once again, to some more in the $510 million to $550 million range.

Moving to expenses, as we indicated in our third quarter conference call, our reported 2007 our lease operating expenses came in at the high end of our guidance range. Full year LOE was 1.8 billion or $8.16 per barrel produced.

The increase in the 2007 LOE rate reflects higher oil transportation costs, largely related to production growth in Azerbaijan, increased workover activity in the Gulf of Mexico and upward pressure relating to the strengthening of the Canadian dollar. In 2007 the average Canadian exchange rate increased about 6% over the 2006 average. Unit LOE for our US onshore segment grew at a much more moderate pace of 5%. For 2008 we anticipate continued but more moderate pressure on costs. Our forecast indicates 2008 lease operating and transportation expenses to range somewhere between $8.90 and $9.25 per equivalent barrel.

For 2007 Devon’s full year DD&A expense for oil and natural gas properties came in at $11.85 per barrel, about a nickel above the high end of our full year guidance range. Overtime of course you would expect our unit DD&A rates to gravitate towards the average unit finding and development costs. As a result we expect our DD&A rate to come in between $12.75 and $13.25 per Boe in 2008.

Moving on to G&A expense, full year G&A expense for 2007 was $513 million. Higher employee-related costs drove G&A just above the high end of our guidance range. Looking to 2008 we anticipate a continuation of the current tight employment market, resulting in additional upward pressure on personnel expenses. Consequently we're forecasting our 2008 G&A costs to be in the range of $590 million to $610 million, including approximately $90 million of non-cash equity based compensation expense.

Turning to the interest expense, interest expense for 2007 was $430 million at the low end of our guidance range.

Commercial paper and credit facility balances accounted for just over 20% of total interest expense for the year. Looking at 2008, we expect our interest obligations to decline, as we continue to pay down commercial paper and credit facility borrowings.

Our forecast assumes a mid year close on the remaining West African asset divestitures and a simultaneous payoff of our commercial paper balances. Based on these assumptions and our expectation for lower interest rates in 2008, we expect 2008 interest expense to decrease by about 20%, to a range of $340 to $350 million.

The final expense item I would like to touch on is income taxes. Devon's reported income tax expense for 2007 came in at 26% of pretax income. When you back out the impact of items that are generally excluded from analysts estimates, you get an adjusted current tax rate of 12% and a deferred tax rate of 20% for a total income tax rate of 32%.

The main contributor to the lower than expected current tax rate, was increased intangible growing cost deduction, due to higher E&P activity levels. Looking to 2008 we expect a similar combined tax rate with about one third being current and two thirds deferred.

In today's earnings release, we provided a table that reconciles the income tax effects of items that are usually excluded from analyst estimates. So moving to the bottom line fourth quarter reported earnings from continued operations were an impressive $1.1 billion or $2.45 per diluted share. That’s a 120% increase in earnings from continued operations over the same period a year ago.

After backing out the impact of items that are generally excluded from analyst estimates, we had net earnings from continued operations of $868 million or $1.93 per diluted share.

For the full year our adjusted net earnings from continued operations increased by 13% to $2.9 billion or $6.38 per diluted share an all-time record.

To sum it up from almost every perspective in 2007 was a great year for Devon.

And with that, I will turn the call back over Vince to open it up for Q&A.

Vince White

Thank you John. Our operator, we're ready to take the first question.

Question-and-Answer Session


(Operator Instructions). Our first question will come from the line of Dave Kistler with Simmons & Company. Please proceed.

Dave Kistler - Simmons & Company

Good morning.

Larry Nichols

Good morning.

Dave Kistler - Simmons & Company

With respect to the Barnett, both you and the industry are having very prolific production growth there. It seems like kind of across the board people have a very deep inventory there, obliviously you guys have one of the deepest. Do you foresee any potential if the structure constraints in the near future, whether it would be transportation gathering, processing, and, if so, can we talk a little bit about your development plans for handling that?

Darryl Smette

Yeah, Dave, this is Darryl Smette. Obliviously you are correct that Devon and number of the other participants in the Barnett Shale are having success and that has put some strain on infrastructure not only gathering systems but export systems in processing plants.

Devon has in place, from transportation enough processing capacities assisting plants and our own gathering systems so we can handle all of the production that Devon for seasoning produce into the future. So while we do see something constraints in the area, we think that we have positioned ourselves not only to produce the volumes but they will have a gathered, processed and transported the variety markets throughout the United States.

Dave Kistler - Simmons & Company

Great. Kind of building off that a little bit. Kind of blocking in all of those plans. Do you guys or have you projected what you estimate to be kind of peak Barnett production for you guys or a goal for peak production?

Steve Hadden

Yeah, this is Steve Hadden, Dave. You saw that we talked earlier that we set a target or a stopping off point of a Bcf a day by the end of 2009, not too long ago, maybe a year or so ago and we belong to that pretty quickly.

Our goal is to continue to drive the efficiency with the drilling and completions that we are seeing across the business and continue to work to have those volumes grow. We are seeing better well performance as I mentioned in the earlier comments, better well performance year-over-year as we've been progressing.

We've also had success with our infill drilling program that continues to add to our inventory, and this inventory of drilling is very, very deep for us and will go on for a very long time. So as we look out for the foreseeable future for the Barnett Shale for Devon, we expect growth continue to occur and these efficiencies to continue to deliver good growth.

So, our goal for say is not any one stopping off point because we'll continue to grow well beyond the Bcf a day of net once we hit that in the second quarter and that will continue for years.

Dave Kistler - Simmons & Company

Great. Thank you for that clarification. If I can just ask one more question. When you kind of look at the deepwater, what do you see is the chief technological challenges as you progress with getting those prospects and projects commercialized. And I guess as a part of that discussion if you could talk about where you are with respect to securing FPSO for Cascade and realizing you are not the operator but would love to get the color on that?

Steve Hadden

Yeah. Relative to the Cascade we're continuing to move forward with that development and specifically to the FPSO for Cascade, it's already been secured. The contract has been left. The vessel is actually in Singapore being retrofitted as we speak. And so we're well on our way and right on our path for first production in 2010. And we'll drill the two wells, the two producing wells, last half of this year and then into 2009 to get the FPSO out there, have the subset work done in 2009 and in the early 2010 and then be ready for the first production there.

As far as the overall challenges to getting to a sanctioning decision in commercialization, obviously these things are technically challenging and relatively complex as you go through both the size and the magnitude of what these things could be. And we're working through those things with integrated project teams, with our partners. The challenges include everything from working through all the options for drilling and completing the wells most efficiently and effectively for the reservoir to working on the configuration for the producing facilities that will deliver the best economics and long-term performance for that reservoir as we continue to characterize it with the appraisal drilling that we're doing.

So we're right in the midst of working through those things with the integrated project teams and with Jack in St. Malo we're probably looking at some sanctioning decision in 2009.

Dave Kistler - Simmons & Company

Great thanks so much for these clarifications.

Larry Nichols

Yeah. Dave, let me just add one thing. This is Larry. And that goes back to the use of the word peak on the Barnett Shale production what we really and that sort of implies this is going to ramp up quickly and then ramp down equally quickly.

The model that we really see for Devon's portfolio and we do have by far the largest and most in-depth portfolio with it concentrated in the near core or the best rock that is and always will be. But what we see is that after many years of growth the rate of growth will gradually flatten out and there will be a flat plateau for an extended period of time and then a fairly gradual decline.

So it is not like a, the word peak sort of implies its going to shoot up and shoot down and that is not at all what we see with the portfolio that we have there.

Dave Kistler - Simmons & Company

Great. Well thank you for that clarification.


And our next question will come from the line of Joe Allman with JP Morgan. Please proceed.

Joe Allman - JP Morgan

Yes good morning everybody, could you tell us where the price- related reserve revisions were and just confirm, it sounds as if most of the performance related revisions were in the Barnett Shale.

Steve Hadden

Yeah, I will tell you that Joe the majority of the performance revisions were in the Barnett Shale and Carthage. We had good performance revisions in Carthage as I mentioned in the call. When you look at the price effects, I think the pricing revisions we saw were principally positive revisions in the thermal projects in Canada, based on the year end pricing and then there was some impact in the Barnett Shale and a few other things across, really smaller things just across the portfolio as we look at that.

From an international standpoint there was a negative price revision that was a result of simply higher prices and the impact on the production sharing contract at Azerbaijan.

If you look at the performance revisions, the performance revisions came principally again from the Barnett Shale and Carthage and the reason that’s occurring is the fact that we are drilling horizontal wells in those areas and for instance one of the largest contributions to the performance revision that came from the Barnett Shale, came from wells that were a vintage of about 2003.

So what we are doing is going and we are drilling these horizontal wells, we are booking them very judiciously, initially and then we looking for performance and as we get more and more well performance and see those curves flatten out, then we are having additional performance revisions.

In addition to that, we work very closely together on our both our mid-stream and marketing facilities, along with the producing facilities to do things like lower line pressures, optimize flow rates, add additional compression, those type of things. And those are continuing to have an effect on the performance especially in the Barnett Shale but. These horizontal wells, for instance we are drilling them in Carthage also, we book them, we want to see how they go hyperbolic and then once we get confidence on their performance basis then you see these positive revisions come in.

Joe Allman - JP Morgan

Okay, it's helpful. And then where are the reserve addition, I aside from the revisions whether reserve additions as much as you expected early in 2007 and just a add on there, the finding cost in ‘07 were higher the finding cost in ‘06, and what was the big driver there and what would you be expecting in terms 2008, I just don’t need a specific number but kind of a similar finding cost in ’08 versus ’07?

Steve Hadden

Relative to the additions and extensions that we saw, they were basically on target to where we would have expected to be. When you look at the, some of the issues about the finding and development cost, that may appear to be bit higher some areas. That's principally driven by what Larry talked about earlier in the call. We spend $600 million on projects that we think are going deliver great value and long-term growth for the company. But, they are not delivering any reserve in the given budget here. So I think that's going to be the principal reason of that variation that you saw there.

Joe Allman - JP Morgan

Okay. And around 2008 would you expect, I mean, are they similar large expenditures that aren’t necessarily going result in reserves, such that the finding cost can be about maybe roughly the same?

John Richels

Yeah. I think, we are going to see similar numbers in 2008.

Joe Allman - JP Morgan

Got it. And then really quickly cost, in the overall are you seeing cost, doing a completion cost coming down here still plateauing, could you just give us comments on that?

Steve Hadden

Yeah. For a cost standpoint, overall we certainly see the rate of increase coming down on average across the business when you look this on average. I think you can roughly say that as a company the drilling and completion cost that we see are probably, escalation might average around in a 5% range or something like.

But, when you look across the portfolio for instance in Canada, we've seen significant reductions in drilling and completion cost in that market, which we had anticipated and we continue to anticipate because that market was pretty over heated. On the other extreme when you see the deepwater side of our business, those costs still remain relatively high because demand for rigs etcetera is still pretty tight.

Joe Allman - JP Morgan

Okay, that’s very helpful. Thank you.

Vince White

Joe this is Vince, I might add to what Steve said that our drill-bits reserve additions for the year and the resulting, finding and development cost were really right in the sweet spots of what we had forecasted at the beginning of the year. So, it very much came in line with our expectations and those did not change throughout the year.

Joe Allman - JP Morgan

Okay, thanks Vince.


And our next question will come from the line of Brian Singer with Goldman Sachs. Please proceed

Brian Singer - Goldman Sachs

Thank you. Good morning.

Unidentified Company Representative

Good morning, Brian

Brian Singer - Goldman Sachs

On Jackfish, what should we expect in terms of quarterly progression of bitumen sales, and do you have any initial thoughts based on what you've seen so far regarding steam/oil ratios?

Larry Nichols

Yeah. I think what we will see is a pretty steady rise over the next year in a little bit to the peak of 35,000 barrels a day. We've always estimated that on average, once we started steam injection and got up and running, that ramp-up could take as long as about 18 months. And we're very pleased with the reservoir performance so far.

As I think we've mentioned before in some of our calls, we think the Jackfish reservoir is in the top quartile of the oil sands reservoirs. And the results that we've seen so far from the reservoir indicate that that's true. From a facility standpoint, the design looks very good. As you probably know when we begin to produce the oil and the water together here, the specific gravities of the two are very close. And we have to work through some issues on both chemicals and operations of the plant to simply line it out.

And that's something that we had expected. We're working through those things right now. So we think over the year you'll just see a steady ramp-up in the volumes as we go forward.

Brian Singer - Goldman Sachs

We should not expect full production for the second quarter of 2009?

Larry Nichols

No. We'll probably get the full production yearend this year or sometime in that timeframe.

Brian Singer - Goldman Sachs


John Richels

Brian, its John. I think what's important to realize is the point that Steve was making here that as you bring these facilities on, there are stops and starts and things that we anticipate. What we're really pleased about, as Steve said, is the reservoir performance, and we haven't seen any of the very significant facilities related issues that you have in some other projects in the industry overtime. So, all of those things are positive.

Brian Singer - Goldman Sachs

It sounds like you're well on your way to Jackfish too. Were those some of the data points that you've now seen and give you greater confidence to precede. It sounds like things are well on their way there.

Larry Nichols

Well, I think we are very eagerly waiting getting to a sanctioning decision and the regulatory approval. Obviously, with Jackfish 1 under our belt and what we are able to do there in constructing both the plant and seeing that the reservoir performances at least early on is really consistent with our thinking. That certainly does continue to encourage us from a technical standpoint on Jackfish. And we'll look at the numbers once we have the early engineering and the economics together and make that sanctioning decision sometime this year.

Brian Singer - Goldman Sachs

Great. Similar type of question on, although you mentioned, I think it's taking a bit longer to head towards peak production, can you provide a little color and when you expect to get to that peak level now?

Larry Nichols

Yeah. What actually happened, Brian, is that we had delays and hookup in completion of the facilities initially and some of the construction issues around the drilling rate. That was one of the bigger things that slowed us down before we even began drilling the well.

And then we drilled three wells, actually drilled a fourth, but it was a long reach well that was probably 4,000 meters long trying to reach out to another part of a reservoir. And we and had a drilling problem there and a float shoe failed, and essentially we've had to redrill that well. So that slowed us down a little bit and we're in the process of redrilling that well. As a matter of fact, it's nearing its PD right now.

We think we'll continue to have the production growth from this point forward. Again, we've drilled 3 of about 12 to 15 wells that we'll drill in the development phase of the program. That ramp-up, we thought we'd reach the peak of about 26,000 barrels a day net this year. That will probably get to some peak in early '09.

Brian Singer - Goldman Sachs

Great. Thank you.


(Operator Instructions)

Our next question will come from the line of Gil Yang with Citi. Please proceed.

Gil Yang - Citi

Hi. Did you comment, Steve, on what you think the reservoir quality is for Jackfish 2 versus in comparison to Jackfish 1?

Steve Hadden

I think its top quartile. We think it's the same. It's right in the same area and in and amongst the same leasehold that we have up there. So, it's going to be of similar quality.

Gil Yang - Citi

Okay. Going to the Barnett you commented that it sounds like the wells are leveling off earlier than you thought. And I guess the big effect was on the 2003 vintage of wells. Are you now booking all the new wells since subsequent to 2003 with that assumption or do you potential revise up all the booking in between, for 2004 and '05, '06, 07 as they flatten out as well.

Steve Hadden

Yeah. It's more the latter than the former here. We booked them with an initial factor, an end factor that they use to try and guess estimate what that hyperbolic decline will be and where they will flatten out. Once we have the performance, obviously, if they were 2003 wells, we've got a few years of performance under our belt, our confidence and certainty goes up in increasing those reserves on those wells.

And then, we try and factor in technically that understanding into future wells. But we'll lean more heavily on performance in making these additions, these performance revisions. And therefore, we won't go back through and take all the wells up to the 2003 performance level. We'll just want to see the performance of each subsequent year and make those bookings.

Now over time, we may adjust our initial bookings a bit higher but we probably won't take the whole bite at one time.

Gil Yang - Citi

Well, given that you are seeing the improved performance in 2003. So you are saying that in 2007 you didn't book assuming that improved performance, you sort of still booking assuming the original performance?

Steve Hadden

Yeah, that's kind of a, generalities are little bit tough, but when essentially we had enough performance on the '03 wells to make that adjustment, we didn't go back through to the '04 through '07 wells and make a similar, make the same adjustments. So as we get more performance and our confidence rises there, you'll see more of these performance revisions from this incremental reservoir.

Gil Yang - Citi

Okay. So will the '08 wells be booked on the new knowledge of the '03 wells?

Steve Hadden

That will be booked that based on our knowledge of the area, you know that it's an accumulation of knowledge and understanding and it just depends on where the wells will drill and what our engineers think is reasonable certainty for those initial bookings.

Gil Yang - Citi

Okay. Last question is, maybe either Steve or Larry, could you just comment on the -- you comment that there is a long-term billion dollar spending on long-term projects. Can you just comment on roughly what the distribution of the different kinds of projects Gulf versus Brazil versus onshore resource place that kind of thing?

Larry Nichols

Well, I don't have a percentage firmly but the bulk of it is in the deepwater followed by the Jackfish 2 project for this year to pay on how much we get done, that's going to be the largest two components.

Gil Yang - Citi

Is there much spending our new resource play exploration?

Larry Nichols

Oh, yes. There is a good deal of that in the east Texas, variety of areas, some of which we talked about, some of which we haven't where we're looking to out there into the future not just. I mean our goal for a long time has been not just to have the good solid short-term growth that you get out of resource plays like the Barnett Shale where we're our U.S. onshore bread and butter growth were 13% this year just from the blocking and tackling that we do on the U.S. onshore but to looking at longer-term plays that will allow us to achieve that kind of growth for a long time into the future.

Gil Yang - Citi

Okay. Thank you very much.


And our next question will come from the line of Mark Gilman with Benchmark. Please proceed.

Mark Gilman - Benchmark

Guys good morning. Just one Steve on the Barnett resource base in light of the favorable performance, could you perhaps update us on where you might stand vis-à-vis the prior risked estimate of overall Barnett resources and whether you're inclined to adjust recovery factor any higher?

Steve Hadden

Well, we're going to update that in the very near future. We were at I think roughly 14 Bcf on that risk basis, I think which you're referring to Mark. And I think you've heard us talk about the 80-acre, the 40-acre and 20-acre wells that we'll be drilling. So this is just an incredible reservoir, that's about 11% to 13% recovery of the gas in place and we think it may go higher, but we'll update that here in the very, very near future.

Mark Gilman - Benchmark

Okay if I could, is it correct you did not book any Cascade reserves despite sanction?

Steve Hadden

No, we did not book any Lower Tertiary reserves and we did not book any Cascade reserves specifically.

Vince White

This is Vince, hi. I want to add for all of you that we're planning no doing an update on Barnett and some, as well as resource potential throughout our portfolio sometime in the spring and we'll be announcing a ate in the near future.

Mark Gilman - Benchmark

Thanks guys.


And our next question will come from the line of [Jason Ganu with McGuire]. Please proceed.

Jason Ganu - McGuire

Good morning gentlemen you had a very successful high grading of the international portfolio over the course of 2007. I just wanted to see if you are reasonably happy now with the composition of that portfolio with the focus on drilling in Brazil and China or are there are areas that you are actually looking to supplement the international portfolio with. Then I guess on the other side of that is there anything within the portfolio that you would consider non-core, think it maybe ACG in particular.

Larry Nichols

We will be happy with the portfolio once we have successfully exited out of West Africa and we are hopeful that we'll get that done some time here fairly soon, which I say is the middle of the year. At that point of time we will be happy with the portfolio and we'll see how it revolves. Brazil in particular is an area where significant reserves have been discovered.

We've got, as Steve described, a large portfolio there and we very much want to see how that plays out. Azerbaijan still has some growth, they are still doing some expanding that field and it's not a core area for us in the sense that in areas where we were going to grow or expand but it is a quality resource for us to keep in the portfolio. We have made and we are making lot of money out of that and China also is an area where we've got an interesting portfolio where we are using a lot of the same technology and expertise, we have in the US deepwater in offshore China and offshore of Brazil. So, we'll be fairly happy with that portfolio.

Jason Ganu - McGuire

Thanks for an insight Larry. If I can just follow up with one quick one, my recollection is that the debentures or the convertible in the Chevron shares mature this year. Is there any accounting treatment that we should be looking for moving forward and I think you actually have quite a bit more value in the Chevron shares and what the debentures are reliable for?

Larry Nichols

Yeah you are referring to the exchangeable debentures that are exchangeable into the Chevrons shares that we own and you are correct that they mature the share and we have several options available to us and we will consider those options and those would most senses from a business perspective and really aren’t prepared to say what that is at this point Jason, by the way welcome back.

Jason Ganu - McGuire

Thanks then.

Larry Nichols

Jason I will remind you that to the extent that we had some of those exchangeable debentures [10 or 2] are in the last while we paid them off using our strong balance sheet to do that.

Jason Ganu - McGuire

Absolutely, thanks a lot guys.

Larry Nichols

Operator we will take one more question.


And our last question will come from the line of David Heikkinen, with Tudor Pickering. Please proceed.

David Heikkinen -Tudor Pickering

Good morning just I want to talk a little bit about the strategic decision to start hedging in ’08 and then thoughts going in to ’09, given a pretty clean balance sheet and generating free cash flow. Could you just talk through the decision making process and start,. Locking your -- some hedges?

Larry Nichols

Yes, what’s the concern in particularly earlier this share, early in January with the large amount of gas in storage and with the twin concerns of both U.S. hiding in some kind of recession, as well as the overhang of gas that existed at that time we had some concerns about the natural gas markets very short-term it might be that they not be volatile. As I said in my comments the concerning about gas storage has dissipated somewhat with the record withdrawals that we had so that gas storage now, inline with five year average. But we are still, we still have two more months to go before the winter is out, who know when that’s going to be. We just started would be prudent, when we looked at the fairly remarkable swabs and color is that we get off, we thought getting a little insurance by giving up a little upside above numbers that that we thought were fairly high to get a little downtime protection seemed prudent to give us a little insurance against short-term volatility.

David Heikkinen -Tudor Pickering

So, from early January to now, would it be a surprise for you to do more hedges? Are you seeing a change now and where you think the commodity price will be?

Larry Nichols

Well, we've got about pushing two thirds of our expected gas production hedged, which is a rather large percentage. The concern is not that much on oil because there are so many places around the world that can drive oil little prices higher. I think there is more upside pressure on oil than downside in general, and worldwide economies, they are not just the US economy, which has more impact on natural gas prices. So I think we're fairly comfortable with where we are now.

David Heikkinen -Tudor Pickering

Thanks Larry.

John Richels

And David, just to reiterate a point here, we were able to put some of these hedges in place in the last short while at what we think are very, very good prices because of the cold weather that we are having. Nothing has changed other than we recognize there's potential for a lot of volatilities. There's still two months of winter left and you know how that's going to look.

Then there is a bit more uncertainty around prices in the short-term. The point I want to make is we're really looking at a short-term perspective here. We still remain or the belief that we're going to see relatively strong prices through the end of 2008 and in 2009 on the natural gas side. So, it is really just to address the concerns or the uncertainties that Larry mentioned in the shorter term.

David Heikkinen -Tudor Pickering

Thanks, John.

Larry Nichols

And as you correctly alluded when you started off your question, we have very little debt, very strong balance sheet, very strong cash flow and cash flow margins. Budget for the year is well within our expected cash flow. So it's really no change in any of those drivers that we've talked about in the past is driving. It's seeing some remarkably attractive collars and swaps that you can get of in the phase of some concern over volatility.

Since that was our last question, let me just say in summary that we're very pleased with 2007, not only for what we accomplished in that year alone with production growth of 12%, taking reserves to an all-time high, good strong earnings, record earnings, record earnings cash flow, but more importantly with what it portends for the future. As we look at the success rate we had with the drill-bit, bringing in very attractive F&D from across our portfolio, very attractive for reserve growth, and seeing that the asset quality we had and the strength we have will continue that into 2008 and beyond. So we're very excited about 2008 coming off of a very strong 2007.

With that, we thank you for your attention and appreciate your interest in Devon. Take care.


Thank you for your participation in today's conference. This concludes your presentation. You may now disconnect. Good day.

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