Apache Corp. (APA)
Q3 2007 Earnings Call
October 25, 2007 2:00 pm ET
Executives
Bob Dye - IR
Steve Farris - CEO
Roger Plank - CFO
Analysts
Ben Dell – Bernstein
Brian Singer - Goldman Sachs
Tom Gardner - Simmons
Jack Hayden – Pritchard Capital
Leo Mariani - RBC Capital Markets
David Hiberon - Wachovia
James Pascelli – TMV
Adam O'Laughlin - BMO Capital Markets
Operator
Good day everyone and welcome to the Apache Corporation third quarter earnings 2007 conference call. Today's presentation will be hosted by Mr. Bob Dye, Vice President of Investor Relations. Mr. Dye, please go ahead.
Bob Dye
Thanks for joining us today. This morning Apache Corporation released third quarter 2007 results which reported earnings per share of $1.83. I think most of you saw the $1.83 number included a $0.34 non-cash charge, primarily related to the impact of foreign currency fluctuations on our deferred tax balances. Without that, our adjusted earnings were $2.17 per share. Cash flow reach an all-time record of $1.6 billion which is a non-GAAP number.
Today’s discussion may contain forward-looking estimates and assumptions and no assurances can be given that those expectations will be realized. A full disclaimer is located on our website at www.apachecorp.com.
In addition, any non-GAAP number that we discuss will be identified as such with the reconciliation also located on our website. Steve Farris, our CEO and Roger Plank, our CFO will now make prepared remarks prior to taking questions.
With that, I will turn the call over to Steve.
Steve Farris
Thank you, Bob. Good afternoon, everyone and thanks for joining us today. Apache’s performance in the third quarter was outstanding. It was driven by our portfolio balance, quality and depth of our growth opportunities. Third quarter production, as I am sure you have read, was 516,000 barrels of oil equivalent a day which was 9% year-on-year growth and just under our all-time record set in the previous quarter.
Henry Hub spot gas prices were down 17% on an average in the third quarter compared to the second quarter. Differentials meant that as an industry, many people saw $3 gas in the Rockies.
On the flip side, the average WTI oil price increase 16% from the second quarter. The average oil price I am quoting is about $75 and hence, doesn’t really reflect the more recent strong rise in oil prices.
In this volatile commodity setting, our average realizations were stable for the quarter and cash flow of $1.6 billion set an all-time quarterly record, which was 25% year-over-year growth and 10% relative to the second quarter of 2007. That is largely on the strength of our commodity balance. Liquids production accounts for 47% of our production by volume, but accounted for 67% of our revenues during the quarter.
As Bob pointed out, net income was again impacted by a weakening U.S. dollar that requires us to mark-to-market our non-cash differed tax balances denominated in foreign currencies. Without this charge, earnings would have been $2.17 per share.
Times like this underline the competitive advantage that Apache’s balanced portfolio represents. We have a one of the largest North American gas portfolios in the industry with over 5 Tcf in proved gas reserves as well as in excess of 20 Tcf of unrisked resource potential. But Apache is really much more than that: a balanced upstream company with almost half of our production being oil.
We are also balanced geographically. Within our gas portfolio we do not rely solely on North America and have very material and profitable growth areas in Australia and Egypt plus an early stage position in Argentina. We remain very well-positioned to achieve the top end of our 9% to 12% production growth target for 2007. During the first three quarters of 2007, production was up 13% over the comparable period in 2006 and so we are well on our way.
If you look out little further, we have guided so far to a 6% to 10% production growth in 2008 with an additional 108,000 barrels of oil equivalent of production coming online in late 2008, 2009 and 2010 from six large projects. We are more confident than ever that our resource base can generate double-digit growth into the next decade.
I would like to begin the regional comments with Australia, which is one of the three core growth areas for Apache. I want to focus primarily on our activities in the very prolific Carnarvon Basin, which is offshore Western Australia. We have an extensive acreage position of 5.4 million acres and control of Varanus Island, which is an important infrastructure hub.
During the quarter, we announced two major gas discoveries offshore Western Australia. First in July, we found 224 feet of net gas pay in the Julimar East prospect with 85 million a day of production flow. The net pay is nearly double what we found in our Julimar discovery in April and we are own 65% of this block.
Second in August we found 121 feet of net pay in Brunello no. 1 with production tests flowing about 72.5 million a day and 1,230 barrels of condensate, we own 65% and operate this also.
With the three discoveries so far this year of Julimar, Julimar East and Brunello we have found a gas resource with ultimate potential in excess of 1.3 Tcf of gas in Australia alone which is close to 1 Tcf net to us, and this is exiting considering this represents about 150% of our production last year and coming from a single country in our portfolio. We will be limited this year on reserve bookings to the wells that we have down but by themselves those wells will make this project commercial.
We drilled two additional prospects during the quarter at Rosella and Maitland, one worth promising results. Maitland is a known gas accumulation. We drilled the first horizontal well there which started producing substantial sand as we increased the flow rate. We need to drill another horizontal well really with the right sand control, but we remain optimistic that the field will be economic.
Rosella was somewhat disappointing as our maximum flow rate was less than 10 million a day. We are currently doing petrophysical analysis to better understand the reservoir. We have two additional appraisal wells left to drill this year at Julimar and one more expiration target called Norville. We hope to drill this wells in the fourth quarter of 2007, however last weekend the rig had an electrical fire in the engines and the early assessment is it will be offline for four to six weeks. We still should get some drilling in for the remainder of the year.
In 2008, we will begin our exploration campaign in the Gippsland basin. We have identified 12 drillable prospects with reserve sizes ranging from 50 million to 100 million barrels.
I’d like to give you a little update on our development projects in Western Australia. During the third quarter we sanctioned the Pyrenees oil project which together with Van Gogh will give us 40,000 barrels a day net to Apache. Van Gogh is scheduled to come online in early 2009 with Pyrenees coming on at the tail end of that year. This is the equivalent of 15% of our current worldwide oil production.
In August, with our partner Santos, we initiated the engineering design phase of our Reindeer gas project which will monetize between 416 bcf gas with an initial production target of 100 million a day which is expected to come on line in 2010. We own 55% of this project and operate it.
In addition, we’ve begun the preliminary engineering phase to develop Julimar [Permel] that is expected to have initial production of approximately 300 million a day starting at late 2010 of which 65% will be ours and we will operate it.
I would like to talk briefly about the economics of our gas in Western Australia. We built our major acreage and production position in this area during the last ten years, when domestic gas prices have been in $1 to $2 range. Our returns have been very attractive at those levels with rates of return averaging about 25% over the last three years.
We identified the resource potential early and the profitability of applying our operator skills, so we went in early and built the portfolio. We’ve been able to achieve very acceptable returns in a less than better market but the upside is now in front of us. Western Australia’s economy is growing led by large and long-term mining project and needs natural gas. As a result, gas prices are converging with international levels. This summer, a large supply contract was closed at $7.50 per M, and that is 3 to 4 times our historic levels.
We are currently in discussions with a large contract for Reindeer development gas volumes and I’d like to say that the pricing levels we are seeing are consistent with these recent references. Obviously, this is very good news for our share holders.
We’re becoming increasingly encouraged that our bet on international gas prices is paying off for our shareholders not only in Australia but also in Egypt and Argentina. Each area was out of favor when we entered, and were able to generate acceptable returns in the face of depressed or regulated prices. Now we’re beginning to see signs that the gas prices in those countries will converge with international levels also.
Other competitors are trying to build positions, obviously at higher costs, but we also already have a lot of depth in our portfolio. This is true organic value creation by Apache.
I’d like to turn now to Egypt. We took many important steps forward in Egypt in the third quarter across our primary growth drivers of exploration drilling, gas plant expansions and water flood developments. During the quarter, we made two discoveries, drilled one successful appraisal well and 26 development wells. Our successful wells are really too numerous to mention individually but I do want to comment on this morning’s release.
North of Khalda we have made several Jurassic discoveries on our 250,000 acre Matruh concession including a field called Imhotep and also Jade. The Jade 2x appraisal well that we announced this morning was drilled on the Jade Ridge which is on the Western flank of the Matruh concession . It was drilled specifically to test the AB formation.
We found a 148 feet of AEB pay in the wells which flowed 27 million a day and about 1,325 barrels of condensate of test. The Jade 1x discovery well which is currently producing from the Jurassic formation also logged 217 feet of pay in the AEB. The Jade 4X appraisal well, another well we just got down, an AEB test logged 234 feet of pay in the AEB and will completed as soon as the Jade 2x is finished.
The Imhotep Field is 17 miles east of the Jade Ridge on the Eastern flank of the Matruh concession, and we recently recompleted the Imhotep 2 into the AEB and have tested 4,082 barrels a day of condensate and 3.3 million cubic feet of gas.
I might add that AEB formation has produced 40% of the 250 million barrel liquid production in the greater Khalda area, which is directly south of our Matruh concession. We are very encouraged by the results of the Jade Ridge and as many you may know, this is one of our significant expiration targets that we put on the books to beginning of the year.
Our Salam gas plant expansion projects remains on schedule for completion in the fourth quarter of 2008. This project is projected to add an additional 90 million a day and 4,500 barrels of condensate net to Apache.
At the end of the third quarter, Apache had gross production of 33,000 barrels a day coming from its new waterflood projects which is on track with the estimates presented in our June analyst conference.
We drilled 36 wells and six different waterflood projects and increased water injection capacity 45% to 42,000 barrel a day. We will continue our aggressive development for the next several years to realize our associated 200 million barrel low risk reserve potential.
Our position in Egypt is one of the largest of any western companies in the Middle East which is central to the future of energy industry. Moreover our position has grown at double-digit rates for ten years and it has an extraordinary depth of growth opportunities.
I’ll turn now to Canada. Our Canadian portfolio gives us a truly outstanding scale of resource potential in shale gas, coal bed methane and high impact deep exploration drilling. The third quarter performance again underlines the strength of this portfolio, with Apache Canada delivering steady production in spite of a capital spending cut of 30% lower than last year.
The proposed royalty increase in Alberta is currently formulated. It would have a negative impact for 2008 development drilling program in that province. Rates of return of some of our gas drilling program would decline below 10% and will definitely have an impact on our 2008 spending levels in Alberta.
I might point out that this is the type of development which makes Apache’s portfolio depth and balance invaluable. For example, in Northeast BC which is not affected by the proposed fiscal change in Alberta, we have an aggressive appraisal program planned this winter at our shale gas play. Apache now controls, with our partner in Canada, 400,000 gross, 200,000 net acres to us, enough to potentially drill 1,200 net wells at four wells per section.
We plan to drill and complete nine horizontal wells this winter, which should allow us to develop a firm view of the play’s potential, using a variety of fracture stimulation programs along with micro seismic and listening well data. We intend to construct an all-weather road and expand pipeline and compression facilities there. We are optimistic that this play will be a significant contributor to the future growth of not only the region, but also Apache, with 3 to 6 Tcf of resource potential.
Turning to the U.S. and our Central Region., our Central Region has two growth engines, the Anadarko Basin tight gas and the Permian Basin oil and they both continue to power here. Production reached an all-time record of 304 million cubic feet of gas a day and 39,200 barrels of oil per day during the quarter. Production was up 21% year on year driven largely by our active drilling program there, which continues into the fourth quarter with 16 rigs.
In the Gulf region, we continue to have a steady generation of cash from our Gulf Region from very strong production. Well production reached an all time high of 57,900 barrels a day during the quarter, which was driven by restoration activities and a successful drilling program.
Our gas volumes were below all-time records in second quarter of 2007 due to really to two independent reasons. One was pipeline shut-ins, which was about half of it, and the other one had to do with depletion. I am happy to report that we restored all production from the storms in 2005.
Apache continues to benefit from falling rig rates in the region. Jack-up rates have fallen roughly 50% this year for all sizes, and barge rigs are down 15%. Our onshore Gulf Coast portfolio was bolstered significantly during the quarter with a large farm-in arrangement from [Innervest], which allow us to explore nearly 400,000 acres in Central Texas.
Now turning to our smallest and newest component of our portfolio Argentina. Within a year it’s given us attractive returns and resource upside and surprisingly price upside at this early stage. We have reduced our percentage of gas sold at subsidized prices as of October 1st and this is a slight delay on the original time line of implementation which was supposed have been sometime during the third quarter. The delay was driven by one of the coldest winters on record in the country however. We ran seven rigs during the quarter and drilled 28 wells.
I will turn now lastly to the North Sea. In the North Sea, we completed two excellent producing wells, the Bravo 63 is currently producing 65,000 barrels a day and the Bravo 32 well is producing 34,000 barrels a day. As you reported and as you saw on our numbers in the second quarter conference call, we report that we were going to take the Alpha and Echo platforms down for maintenance turnarounds during the third quarter which ended up costing us about 9,700 barrels a day for the third quarter.
The work accomplished during the turnarounds is really beyond the scope of the call, but I might say we replaced or inspected or installed over 200 vessels during a 30 day period that required 18,000 man hours of labor. As we near the completion of the topside refurbishment program and focus on production drilling we are setting ourselves up for an outstanding fourth quarter with production in the range of 60,000 barrels a day net to Apache. Remember the 40’s contains 450 million barrels of net resource and every additional percentage of reserve recovery gives us 50 million of light oil reserves.
That concludes my operational update. Now I would like to turn it over to Roger Plank, Apache’s CFO and Executive Vice President for a financial update.
Roger Plank
Thank you, Steve. Good afternoon everyone. The merits of Apache's balanced global strategy was evidenced in our strong third quarter results. Rising oil prices had an outsized impact on our bottom-line results given that oil figures so prominently in our production mix. As a result, while many North American gas oriented companies wrestled with nearly $1.50 sequential decline in NYMEX gas prices a $10 per barrel increase and the benchmark price of oil on strong production drilled Apache's oil revenue up $150 million sequentially during the quarter, enabling total revenue to reach the $2.5 billion mark for the first time in our history.
Earnings of $612 million or $1.83 a share where also quite strong, especially when taking into consideration the $114 million non-cash charge related to the impact of the deteriorating U.S. dollar on Canadian and foreign deferred tax balances.
Theoretically, when it comes time to pay our defer taxes in Canada it will take more US dollars to do so. So, we have to reflect that change in our income statement at the end of each quarter and frankly it’s kind of pain rear as it significantly distorts our true performance.
The important thing to note is while this reporting convention reflects the proper accounting treatment for movement in foreign currency, it is just a non-cash change and not a current period economic event. Therefore, setting aside the impact of the changes in foreign currency, Apache earnings did total of $2.17 per share substantially Street expectations. It is also well ahead of both last quarter and third quarter of ’06 earnings which excluding the impact of foreign currency fluctuations and other non-recurring items totaled $2.09 and $1.70 per share. If you are interested the [inaudible] lays out those adjustments so that you can see each of the components.
The strength of our quarter is readily apparent in our cash flow from operations which being unaffected by this foreign exchange fluctuation reached a record $1.6 billion or $4.83 of share, up 25% from last year’s third quarter; 10% higher than the second quarter of this year and well ahead of consensus estimates as well.
Again, the strong results speak to the benefit of a balanced portfolio approach. I can’t tell you how nice it is for our liquid hydrocarbons -- roughly half of our quarter’s production -- to generate just over two-thirds of our total revenue.
Revenues are the beneficiary of higher oil prices of late and while the weaker US dollar generates the deferred tax amount we project that we may pay someday there is little question that this currency weakness is also benefiting Apache in the form of higher oil prices. From that standpoint, Apache has a natural offset which mitigates the income statement impact resulting from the weaker dollar.
As Steve indicated, our third quarter production was up 9% year over year; it was down 2% quarter over quarter while the slight decline in third quarter production may have surprised some of you, it was relatively consistent with our internal expectations due to the anticipation of the scheduled turnaround in the North Sea which is why we do continue to expect year-over-year production growth at the upper end of our 9% to 12% growth range.
If you do the math, to reach the upper end implies significant growth in the fourth quarter which we fully expect will enable us to close out the year with our highest production level ever. We also anticipate continued strong returns driven by robust margins, the impacted strong global demand and limited supplies on oil prices fueled Apache’s highest cash and pre-tax margins year-to-date despite realizing the lowest gas prices of the year and fighting our industry’s ongoing battle with rising costs.
For the quarter, overall cash costs dropped 1% to $13.55 per boe and combined with 3% higher realizations, propelled margins up 5% from last quarter to $34.83 per boe, our highest year-to-date. Even including DD&A, our total pre-tax margin increased to $22.72 per boe from $21.40 sequentially.
Focusing on costs, our third quarter lifting costs increased 2% or $0.17 of boe sequentially to $8.21 per boe. Roughly half of this increase was related to expanded workover activity to increase production on the Anadarko acquired properties and the other half relates to the lower North Sea volumes which as you’ve heard, are forecasted to recover in the fourth quarter.
I also note that the quarter included $0.09 related to the foreign exchange movement and absent fee impacts, LOE per boe would have been around $8 which is a level we consider achievable going forward, even with continuing higher work over activity.
G&A costs dropped 13% sequentially to a $1.19 per boe, probably a good rate, achievable rate going forward. Full cost DD&A was up just 2% sequentially to $10.94 per boe as drilling costs continue above historical levels. Severance and other taxes of $2.42 a boe decreased $0.10 quarter over quarter. This is primarily driven by lower North Sea PRT as lower volumes more than offset higher oil prices.
Financing expense decreased $0.05 to a $1.17 per boe on $126 million lower debt. Continued strong oil prices and rising production should result in further debt as well as debt to cap reductions from the 25% rate that we ended third quarter at.
Our effective tax rate was 48% for the third quarter, the lingering effect of exchange rate fluctuations and further currency weakening so far this quarter should cause our fourth quarter effective rate to remain at around the same level and portion that is deferred should move to around 52%.
Fortunately, the costs start over every January 1st, so absent further FX changes next year’s rate should be back below 40%.
Before closing, I’d like to underscore that not only are we gratified with Apache’s third quarter results, but we also look forward to a very strong finish to our year for good reason. First, solid fourth quarter production will contribute to double-digit growth year-over-year and our 28th increase in the last 29 years.
Second, despite concerns over the US economy, Apache is among those multinational companies benefiting from strong global demand for our product. While it is too early to know exactly where prices will shakeout for the quarter, current WTI oil prices are again over $10 higher than the third quarter NYMEX average of $75 per barrel.
With 7,000 barrel per day of old hedges rolling off this month in October, where the prices was capped $39.25 or less than the half the current price, approximately 85% of Apache’s oil production is now unhedged and enjoying the price run up toward $90 per barrel.
In addition, our lowest gas price hedges rolled off in October. Some 90 million cubic feet per day capped at $6.32 per MMBTU leaving only around 15% of our total gas hedged as we head into the winter demand season.
Finally, today’s cover article, some of you may have noticed in the Wall Street Journal mention price controls in Argentina. I would add and as Steve has indicated, Argentina has begun to take steps towards that with respect to natural gas we’re starting to see the benefit of that. Thus far into fourth quarter Apache’s averaging just over $1.40 per MCF on 200 million cubic feet of gas per day and that’s 40% or so higher than what we actually received in the third quarter.
So in a nutshell, the combination of rising production and prospects for strong product prices should enable continued attractive -- or even improving -- margins resulting in a very strong finish to 2007.
Steve Farris
Thank you, Roger. I might just close with a few comments. The third quarter was outstanding for Apache both financially and operationally. Cash flow set records, we had outstanding earnings. Operationally, our evolving high impact exploration portfolio in our core growth areas, resulted in two natural gas discoveries in Australia and a gas condensate discovery in Egypt. In Canada we added about 104,000 gross 52,000 net acres to our British Columbian shale gas resource play, and now control over 400,000 gross, 200,000 net. We look forward to testing the viability of this play with the drill bit during the winter campaign.
Our portfolio balance has shown through in our commodity mix as Roger pointed out, liquids which account for half of our production generated two-thirds of our revenues, and that should continue into the fourth quarter.
We should exit the year with a rising production profile and should end the year on the high end of our range and with development projects underway scheduled to add 108,000 barrels of oil equivalent per day over the next three years fueling our growth. Our resource base is capable of delivering strong growth through the end of the decade.
With that we would love to take your questions.
Question-and-Answer Session
Operator
Your first question comes from Ben Dell - Bernstein.
Ben Dell - Bernstein
My first question is really around reserve bookings. You outlined a number of your discoveries, there are obviously timing issues in terms of when you book those. Last year your F&D in the US was a particular drag. Do you see that coming down this year or your overall F&D declining this year versus last year?
Steve Farris
Finding cost? Well, we still got a quarter to go and our reservoir engineers haven’t told me what the numbers are yet. I will tell you this; the thing that is going to affect our finding cost in the U.S. this year is same that’s affected them in last year, that is we still have an awful lot of the hurricane damage that we put in this year which was really as we pointed out last year, was really the impactful thing in the United States.
Ben Dell - Bernstein
Maybe turning over to Argentina, can you give some color, and you obviously mentioned the collar on the gas market there. With the elections coming up, do you have a feel for what sort of escalation in gas prices you could see over the next two, three years as the market tightens?
Steve Farris
Well, everything I am going to tell you is obviously what -- as I always mention we go into new country we are their guest, and they are the host. There is a lot of anticipation that the new administration is going to at least relook at that issue. I will give you some anecdotal comments about that though. We recently entered into a three-year contract with a major gas user there that’s in other parts of the world. In the three years they are at 15 million a day and they go from $3 to $3.50 to $3.90 over the next three years. So we are seeing, already we’re seeing actually more than I anticipated when we got in there at this point of time.
I don’t think that’s going to change as you I am sure you are aware. They need indigenous gas terribly. They import 250 million a day from Bolivia at over $6 now. I am hopeful that everybody is reasonable about the way you attract foreign investment and part of that is that you have to make a return and in order to do that, you have to have acceptable prices.
So I can’t forecast. I can tell you what we’ve been able to do lately, but in terms of our expectations I think our expectations are pretty optimistic, frankly.
Roger Plank
The other thing I would add to that is, the article in the paper implies everything is regulated and priced and gas is too, but it is really the residential market and some of the small usage markets that are regulated, and it is certainly low price, but they also recognize that they are running out of gas. They have to import it, like Steve says, at $6 so they have let incremental gas sell for whatever the market will bear.
So once we have delivered into the lower priced, regulated markets then we can go after these markets that Steve just indicated where we are seeing prices at $3 or triple what we got last quarter.
So they have the right ingredients in place and they have the right mindset; people who bring on new gas will get rewarded with higher price.
Ben Dell - Bernstein
Just one last quick one. On Enesco’s call today they suggested the demand for jackups in the Gulf of Mexico is picking up and highlighted yourselves as one of the key players coming back to the market. Can you give us an indication on what your rig demand in the Gulf will be next year versus this year?
Steve Farris
I think they are hopeful. I will leave it at that.
Operator
Your next question comes from Brian Singer - Goldman Sachs.
Brian Singer - Goldman Sachs
When you look at your Australia gas exploration program can you talk to where you stand on prospect inventory and how aggressively should we expect gas exploration to be in ‘08, given what’s going on?
Steve Farris
We will have a very active program. We have a number of other prospects on the block 356; we have a block that is north of our old East Bar which is a field that made about 750 Bcf of gas, it is west of Varanus Island that we are going to drill. We have Norbo which we are going to drill. We have a number of additional prospects in the Carnarvon Basin to drill next year.
I guess you are asking the potential of the market or the potential of our gas resource base?
Brian Singer - Goldman Sachs
Really just the potential of the gas resource base and how aggressively you plan to drill that in ’08 versus your program in ’07?
Steve Farris
Well I actually I think we have two rigs running next year. I will tell you it is difficult to get a rig into the Carnarvon Basin and I will give you the fire we just had. It will be December before we get another rig into the Carnarvon Basin because they have safety cases that a new rig has to go through.
We think there is about 2.2 billion barrels of resource potential that we have in front of us of exploration stuff. The beauty of where we are right now is if you look at Julamar Brunello which we believe is commercial as it sits; and our Reindeer, our only downside is not getting that done and executed. Because as you know once you get infrastructure and you can look for lesser and lesser sized reserves or add-ons to the infrastructure. So we will have a very aggressive program in the Carnarvon Basin on the gas side next year as we will and in the [Gypsum] Basin starting about February with one jackup coming in there.
Brian Singer - Goldman Sachs
In the U.S. were there any intricacies of oil production being up relative to the second quarter with the gas production being down a bit? Anything you need to share there?
Steve Farris
You mean in the gas production in the Gulf of Mexico?
Brian Singer - Goldman Sachs
Yes.
Steve Farris
We were down about 40 million a day and about 20 million of that was strictly facility related or pipeline related; 20 million a day of it. A little bit of it was weather and the part was natural declines. Quite frankly we’re expecting a little uptick on our gas production for the fourth quarter and our oil production should be about flat to up a little bit.
Operator
We’ll go next to Tom Gardner - Simmons.
Tom Gardner - Simmons
Good afternoon, guys. Given the continued success you are having in Egypt, particularly in the Khalda concession, at what point does it make sense to take another look at your gross gas processing plants and perhaps revising those upward?
Steve Farris
Well we have two plants that are going to come on starting in the fourth quarter of 2008 which is about 200 million a day of processing capacity. I will say that we had a bigger appetite than that. We go through the operating companies, each company in Egypt has an operating company that is owned 50% by the foreign contractor and 50% by the EGPC which is the government arm of the oil industry. It would not surprise me at all for us to be starting discussions in earnest on drilling, at least filling one more 100 Mcf train sometime in the next year. They are going to need the gas, and we have to take away capacity.
Roger Plank
The other thing we have an arrangement where we move gas through another operator’s plant that supplied basically by one field that has been depleting. To the extent that, that gas isn’t replaced that frees up room for more Apache gas into the future.
Steve Farris
To be a little more specific, we take about a 150 million a day of our gas out of Cosor, North to a field called Obiat that has a 380 million a day gas plant. Obiat has been online for a number of years and continues to decline so to the extent they decline our gas rates will go up through there also.
Tom Gardner - Simmons
To be clear, this 100 million a day that you speak of , is that incremental to these 700 million gross?
Steve Farris
That would be, yes sir.
Tom Gardner - Simmons
Jump over to the North Sea, you continue to have success there as you mentioned in the Bravo well, I guess appropriately named. Some people are pulling out of the North Sea, I just want to get your thoughts on the UK natural gas market perhaps consolidation opportunities in your capital spending plans there going forward?
Steve Farris
We continue to put together exploration projects but our main concern frankly right now is to get 40’s up and running because if you look at the fields in the North Sea I think the 40’s field is either the second or third largest field still in the UK North Sea and if you consider that and we are seriously believe there is another 450 million barrel resource potential there it would rival any field that has been found. Our immediate goal is to make sure we make that run everyday and I think we are later than what I anticipated but I think we are pretty close to be in there.
With respect to the gas markets, I mean with the United States Bank, they had a psychedelic ride, I mean they have gone through one of the most aggregated volatile markets. It went from sometimes over $20 to $4 to $3. Frankly I think that gas market will continue to be tremendously volatile in the UK for the very reason that I think it’s going to be somewhat volatile in United States and that is they have to import their commodity and that has to do, as gas becomes more and more worldwide the gas is going to find the place that is going to pay a nice price because once they get on the water in the LNG they are going to the highest priced gas market.
So in terms of our future on the gas side, I think that depends on how other people look at it, because at $86 a barrel the things that we have seen that have come through have been pretty high priced.
We certainly didn’t get into the North Sea just on 40’s however. So we are very high on the potential of the North Sea and things that we know how to do very well.
Tom Gardner - Simmons
one last question with respect to Australia. I just want to get an idea of to what degree you are able to manage those higher spot prices? How much of your gas is termed out and when does that come open for free negotiation? Then the growth component on top of that, what does that look like relative to what you are producing today?
Steve Farris
We have about 40% of our gas that is going to come off, 40% to 50% of our gas is going to start coming off 2009 and 2010; our existing gas.
Tom Gardner - Simmons
Meaning come out of contract?
Steve Farris
Yes, come out of contracts. The real demand for gas today in Australia besides the rollover contracts that we will obviously try to renew are the hard metals that you are seeing in the rest of the world, if you look at the copper prices or anything, steel prices. There are a number of new mining plants going in on the western side of Australia to capture that price for minerals. If you looked at a demand curved in Australia over the next five to six years, it is not unlike the demand curve you see in Egypt which is about 12% per year.
Our honest Achilles Heel is we have to get these projects done, and it is not an Achilles Heel, but our future is in front of us if we can take advantage of it. We have the closest, we have the gas that can get to market in the near term. We had a tender, we had 23 expressions of interest for gas, so there is definitely a demand for gas, and there will be an advance for gas. I don’t know if you read some of the information that comes out of the Western Australian government, they are concerned about natural gas starting in 2009, 2010.
Tom Gardner - Simmons
Is Apache being aggressive in going after that market then going forward?
Steve Farris
Yes sir. I might add to that again I want to make sure I made my point as I made it. Our Reindeer gas we are into the engineering design and it should come on in 2010. We just ended a tender process where we were asking for interested parties to submit indications of interest by last week Friday. We got 23 indications of interest; now obviously we are going to pick two or three and deal with them, but their appetite was overwhelming.
Operator
Your next question comes from Jack Hayden – Pritchard Capital.
Jack Hayden – Pritchard Capital
A couple of quick questions. First on the tax rate issue you talked about Q4 tax rate being about the same as Q3 assuming you report it the same way, stripping out the forex impact, where would you expect the tax rate to shake out?
Can you give some additional detail on what you have going on in the Canadian shale play? If possible, some results from these couple of wells drilled and a little color on the depths, targeted well costs, anything like that?
Roger Plank
Regarding the tax rate, I think I got the gist of what you are asking. There has been further deterioration in the fourth quarter. So the number that I gave before or the comment I made before that the fourth quarter rate, although it would be comparable to the third quarter rate of 48% is taking into consideration that deterioration in the U.S. dollar that we’ve seen so far in this quarter. So if there is no further deterioration from here we still ought to have a rate of about 48%. Does that answer your question?
Jack Hayden – Pritchard Capital
No. You had 48% but you stripped out components as unusual due to the forex change, which got the tax rate down to about 38% ex that. So assuming you considered the forex impact in Q4 again to be kind of unusual, should we expect a recurring tax rate of about 38% again?
Roger Plank
Our natural un-foreign currency changes, tax rate of 38%, 39% something like that. Now, but to get there we have to go through year end because of the changes that have taken place so far that the impact is blended throughout all the quarters ahead of you. So you won’t see that until next year. If you know what I am saying. We have a carryforward of that impact from the change in the foreign currency year to date.
Steve Farris
The clock starts over January 1st and so it would take another currency move like the one we have seen to drive rates next year up to that mid to high 40% range.
Roger Plank
So far, I mean it’s been a $0.15 move from start of the year to the current timeframe so that would be another huge move. Well we’ll just see, but hopefully with the clock starting over we will be back below 40% next year.
Steve Farris
The question on the shale, you're exactly correct. Actually, we have four wells in the shale, two vertical wells and two horizontal wells. One of the horizontal wells I would describe as actually legitimately testing in a play the way we will this winter. We put three fracs on a well; obviously the next well we'll probably put seven or eight fracs on it.
We're very encouraged by the results of that well. The rate was about commensurate with a three frac well. The decline curve has not been nearly as steep as we anticipated. It has been actually tremendous; it has declined but it's been a tremendously shallow decline. We're designing fracs. We'll probably do two or three different kind of fracs in the wells that we're going to drill this year. But between us and EnCana, our partner, we'll end up drilling nine wells this year.
We have 400,000 acres under lease of which we own 50% across-the-board and EnCana owns 50%.
Operator
We'll go next to John Herrlin with Merrill Lynch.
John Herrlin - Merrill Lynch
In Australia, Steve, you talked about Julimar and the associated discovery being commercial. How are you going to produce that, or where?
Steve Farris
John, in terms of the development plans, we have about three different scenarios that we're working on because we have obviously a lot of pipe to lay. One version is to take it close to Varanus Island without taking it on Varanus Island so that we can move gas. We have a 450 million a day pipeline that goes to shore right now at Varanus Island. Reindeer will have a pipeline to it because we're going directly to shore at Reindeer to the north.
So the design plans would have either going over, through Reindeer, or coming down and making sure that we can get Julimar gas, Brunello gas, Maitland gas, whatever else gas we find not coming through Varanus, but coming close to Varanus so we can continue to be able to take gas in from that pipeline also. Actually, we haven't settled on a design currently, John.
John Herrlin - Merrill Lynch
In Egypt, you spent a fair amount of time talking about your gas discoveries and the AEB and the condensate to the south. Do you think they're connected? How big do you think the condensate field is?
Steve Farris
The reason I bring up the two independently is -- and I'm sure you caught the gist of it – they are 17 miles apart and one is on a ridge that goes up on the eastern side of the Matruh Ridge. We currently have two more exploration wells drilling in the Matruh Concession. One is called Amber which is along the Jade Ridge to the north, and the other one is a big Jurassic structure which is more than a step out but it's east of Obiat Field. That's a Jurassic test. We have six exploration wells that we're going to drill either between now and the end of the first quarter of next year up there.
The potential of the Ridge on the Jade side, I think we talked about that in order to be one of our significant discovery or potential prospects it has to have the potential of 50 million barrels of oil or 500 bcf of gas.
John Herrlin - Merrill Lynch
Gulf of Mexico, you mentioned that rig rates are coming down. It's a good free cash flow generator for you, even though it's not always a growth province. Would you consider more consolidations there since some of the small fries have had operational issues?
Steve Farris
I would point out that we've never indicated that we are going to organically grow the Gulf of Mexico. Our position has always been that it is doing and has done a tremendous job for a number of years and in generating a lot of cash. It has a good size to it right now. I can't see us getting significantly larger.
From a smaller standpoint, there are still a lot of players in the Gulf of Mexico. If the right opportunity came by, that would be something we would be interested in. But we are a portfolio player so in terms of its size, it fits very nicely in with longer life gas in Canada and the U.S. and Central Region.
Operator
Your next question comes from Leo Mariani - RBC.
Leo Mariani - RBC Capital Markets
I just wanted to clarify the growth in your Egyptian gas volume. Correct me if I'm wrong, but do you feel that you expect some plant capacity expansions in the first quarter of '08 as well as in the fourth quarter of '08? If that's the case, could you give us a sense of the magnitude of those?
Steve Farris
Well, if I said the first quarter, I misspoke. I meant to say the third quarter. We have two trains that are coming on, one will be right behind the other. Actually, it should be on a little bit before the end of the third quarter, and they're both 100 million day trains. Both of those will come on first or the fourth quarter. So we have 200 million a day gross, which has the capacity of about 16,000 barrels of liquids or a little less, of which we have between 45% and 50% depending on what the prices do, because price has something to do with the cost recovery oil that we get.
Leo Mariani - RBC Capital Markets
A question on Argentina. One of the things you referred to in your prepared comments was the fact that your price realizations weren't as strong third quarter but you would pick up in the fourth quarter. I was just trying to get a better handle of the dynamics. I noticed your volumes were down around 9% sequentially on the GAAP side. I'm just trying to understand that a little better. I guess you guys were talking about a cold winter down there in Argentina and I was a little surprised to see your volumes down if that's the case.
Steve Farris
Well, the volumes are down specifically because the take is out of Tierra del Fuego. That's not a performance issue. That has to do with a Methanex contract that's going to Chile that Argentina does not want us to export gas to Chile right now. So, the volume, we can produce what we produced every quarter before that, and hopefully, we'll continue to raise that.
Our production from when we got in there, we're up about 19% on the gas side, and we can find gas. We can find hydrocarbons down there. This is going to be an issue of economics and what they allow us to do in the future.
Roger Plank
It's a little bit upside down like a number of things down there. They say you can't export because we need the gas in this country but in Tierra Del Fuego, basically that time of the year the pipelines to the north where the population is are full. So the net result is we've got to shut in the production rather than selling it to Methanex. So that's about 16 million to 20 million a day that was curtailed.
Leo Mariani - RBC Capital Markets
Can you give us a sense of how oil drilling is going down there in Argentina, what your plans are for the near future?
Steve Farris
We have basically two different areas as you might know. We have Tierra Del Fuego which is down at the south and then we have our Neuquen drilling and most of the Neuquen stuff that we're doing is extensional type work around fields that we acquired from Pioneer.
In the Tierra Del Fuego area, we are shooting a 2,000 square kilometer 3D seismic shoot there that should be done by the second quarter of next year, across not only the existing fields but also as part of a shoot across 680,000 acres down there. This is a very, very under-drilled province in terms of exploration potential.
San Sebastian field is a 65 million barrel oil field, so there is a lot of potential down there to find additional oil. One is an exploration play and the other one is an exploitation play.
Floyd Price
A couple of specifics, we drilled an oil well.
Steve Farris
I'm sorry -- for those of you who don't know, this is Floyd Price who runs our international Argentina and Australia.
Floyd Price
Just to give you a feel about Tierra Del Fuego, like Steve was talking about, we just fracced a well down there that came on for 165 barrels of oil a day. We drilled another exploration well that came in on Don Piadra and it came on for 5 million a day but it was about 50 barrels a million when you took into account the gasoline as well as the condensate we were making with it. So very rich, and we think we can do pretty well with our liquids.
Steve Farris
Sometimes the gas gets clogged up down there because of limited pipeline capacity. They are expanding and looping that line to the north, aren't they, Floyd?
Floyd Price
That will happen towards the end of 2008.
Leo Mariani - RBC Capital Markets
Moving over to Australia I know it's a little early in the game and you had three very nice discoveries this year, you talked about potential around 1.3 Tcf and you're still working on development plans. Do you have any estimate of the kind of potential development cost there on a per Tcf basis or anything like that?
Steve Farris
I mentioned to John Herrlin that we have three different design schemes. It really depends on which one of those we pick. When we get closer to a final design that we are going to go with, it's probably more appropriate to talk about where we think the cost will be. I'd be estimating right now, and it could be significantly off one way or the other.
Operator
Your next question comes from David Hiberon - Wachovia.
David Hiberon – Wachovia
You mentioned in Alberta worst case scenario, if the tax package goes through or the interest goes through as planned, if you look at a CapEx budget call it $700 million to $800 million, you reduce that, where does that CapEx go?
Steve Farris
In Canada?
David Hiberon – Wachovia
Yes, if you were to take it out of Alberta, where would you deploy it elsewhere in the program in your portfolio?
Steve Farris
Well, our winter drilling program in our shale gas in B.C. is about $100 million this year. We have the opportunity to spend it. What I'd hope and as many of you might know this evening they're supposed to detail the outline of their new royalty scheme. I don't know who listened to the Premier yesterday, but it was a little more steady than at least what the rhetoric has been around it.
There's some hope that they will phase in any royalty adjustments they may have, which would go a long way in trying to look at capital budgets in Alberta next year. There's some talk that their deep drilling royalties may not be part of a deep gas drilling. It would probably cut at least a couple hundred million dollars out of our budget in Alberta next year, but that's a supposition, honestly.
David Hiberon – Wachovia
I know that's a supposition, though it sounds like you would allocate a little more to B.C., and then just elsewhere throughout the program.
Steve Farris
Unless it just gets really chaotic up there in Alberta, I can't imagine us spending -- our budget will probably be somewhere around what it is this year and honestly it could be higher.
David Hiberon – Wachovia
One more big picture question. There's been a lot of speculation and I think the general consensus was Canada would come off a little quicker, not for you but for industry as a whole once the rig count plummeted last year. I think maybe some people were surprised about the level of exports into the U.S., that it didn't fall off more. Do you have any feel for why that was? Was it a function of CBM production or was it a function of the marginal wells got knocked off first?
Steve Farris
I don't know. The only thing I would say is if they use the proposal that they're talking about or the one that the panel came up with, and it may take six months to fall off but you are going to see a real reduction in Alberta drilling. That can't do anything but reduce the amount of gas that's going to come this way. Two or three months are really hard to forecast.
David Hiberon – Wachovia
Yes.
Steve Farris
A year is much longer but that's even pretty short. Some of these things have a long term effect.
David Hiberon – Wachovia
We'll wait and see what happens tonight. Thanks.
Operator
Your next question comes from James Pascelli – TMV.
James Pascelli – TMV
This is a follow-up on the last question. I know the trends don't look good for Canada but with Alberta gas recently around 5.95 or so, not terribly low, it's been lower, are you thinking that the industry is looking for something closer to $7 an Mcf to really get things going again or do you just think that the latest announcement about the royalties et cetera is going to put a big damper on any more interest in Canada? I'd like to add to that, that when everybody is getting discouraged with Canada, perhaps it's time to take a second look or we're getting close to a time to taking a second look.
Steve Farris
I think the biggest concern, frankly, is the uncertainty around what is going on. I heard the Premier last night say that they want to put some certainty in this and if they don't, it will put a damper on it because in the world today, people have a lot of different places to put capital and I think that the most important thing they could do would be to come up with something and stick to it.
I think it has more to do with the places a lot of people are drilling than it does necessarily on price. Certainly costs have been high in Canada. They are coming down as they're coming down in the U.S. We're not totally oblivious to the large service companies earnings and where they're getting their earnings, but I think there is an awful lot more capacity out there.
I happen to have a gentleman from one of the very large service companies in this morning, and if rig rates just stay the same there's probably 20% more capacity than there was a year ago and there's going to be 20% more the following year. So I think that's going to have an impact on the competition and what the cost side is going to do.
James Pascelli – TMV
Well, I think the negativity is extreme. The question is how much worse does it get? Obviously I've heard a lot of the calls on the service companies. The tax proposal is somewhat self-defeating. I'm just wondering where the turning point is.
Steve Farris
We'll find out. It's going to be interesting, let me put it that way. We're supposing about something we know nothing about yet because we haven't seen the final proposal.
Operator
Your next question comes from Adam O'Laughlin - BMO Capital Markets.
Adam O’Laughlin - BMO Capital Markets
Can you revisit quickly again what you're expecting in production in the North Sea again for the next quarter?
Steve Farris
We're looking at about 60,000 barrels a day.
Adam O’Laughlin - BMO Capital Markets
Next year, where is the growth in production really going to come from? I assume it's really in Australia and the oil. Can you elaborate a little bit? I know it's exploration success, but just a little bit of segmented growth?
Steve Farris
Well, I think certainly you're going to see some growth in the United States, you're going to see growth in the Central Region. I think given where we are in the North Sea, I think you could see some growth in the North Sea. We've had a bunch of ups and downs in the North Sea this year. Certainly, we're going to see some growth in Egypt as we have in the past and with two trains coming on that are going to come on at the end of the third quarter, you're going to see some significant growth in the fourth quarter of next year coming out of Egypt. But we have an active drilling program there.
Unless we get some surprises out of Argentina, you're going to see some growth in Argentina. I think the only area that we don't advertise growth in is the Gulf of Mexico, because that is a different part of our engine than the rest of our regions, and it is wide open with respect to Canada. I mean, that's a function of how much capital and what kind of returns you can get in Canada, because many of you probably have heard me say, there's more gas in the Western Sedimentary Basin of Canada than any other place in North America. So it's just a question of economics.
Operator
Thank you. It appears we have no further questions. At this time, I'd like to turn the conference back over to our presenters for any additional or closing remarks.
Bob Dye
Thanks for joining us. If any of you have further questions I'll be in my office. Thanks again.
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