El Paso Corp. (EP)
Q1 2008 Earnings Call
May 8, 2008 10:00 am ET
Bruce Connery - Investor Relations
Douglas Foshee - President, Chief Executive Officer
Mark Leland - Chief Financial Officer
James Yardley – President Pipeline Group
Brent Smolik - President El Paso Exploration and Production
Carl Kirst - Credit Suisse
Shneur Gershuni – UBS
Rebecca Followill - Pickering Energy Partners
Mark Afrasiabi - PIMCO
Mark Caruso – Millennium
Good morning, my name is Hillary and I will be your conference operator today. At this time I would like to welcome everyone to the El Paso Corporation first quarter 2008 earnings conference call. (Operator instructions) Thank you, Mr. Connery, you may begin your conference.
Good morning and thank you for joining our call. In just a moment, I’ll turn the call over to Douglas Foshee, our President and Chief Executive Officer. Others with us this morning who will be participating in the call are Mark Leland, our CFO, Jim Yardley, who is President of our Pipeline Group and Brent Smolik, President of El Paso Exploration and Production Company.
Throughout this call we will be referring to slides that are available on our website, ElPaso.com. This morning we issued a press release and we filed it with the SEC as an 8-K and it is also on our website. During the call, we will include forward-looking statements and projections made in reliance on the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995.
The company has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable and complete. However, a variety of factors could cause actual results to differ materially from the statements and projections expressed in this call.
Those factors are identified under a cautionary statement regarding forward-looking statements section of the earnings press release, as well as in other of our filings with the SEC and you should refer to them. The company assumes no obligation to publicly update or revise any forward-looking statements made during this conference call or any other forward-looking statements made by the company, whether as a result of new information, future events or otherwise.
Please note that during the call we will use non-GAAP numbers such as EBIT and EBITDA and we have included a reconciliation of all non-GAAP numbers in the appendix of our presentation. I’ll now turn the call over to Doug.
Thank you for joining us this morning. I also want to thank those of you who committed a half-day to our analyst’s meeting last month. What I hope you took away from that meeting is the environment for both of our businesses is terrific, gas prices are high and the need for new natural gas infrastructure continues at an unprecedented pace.
We don’t see these drivers changing soon. Our pipelines have the best backlog of committed growth projects in the industry and are the best positioned to capture new growth opportunities. Our E&P business is dramatically improved, it’s more profitable with higher returns on higher growth rates. It’s also less volatile with much heavier weighting to the onshore regions and we have a much deeper and higher quality inventory of lower risk, repeatable projects in the non-proved reserve category.
We’ve significantly limited our downside exposure in 2008 to natural gas prices while retaining much of the upside and as Mark will show you later, has already begun to replicate that for 2009. Now turning to the first quarter, we’re off to a great start for the year. Adjusted for onetime items, our $0.33 a share is almost double a year ago.
Both the pipes and E&P delivered solid results, something you should expect to see for the rest of the year and our interest expense was down by almost 20% over a year ago due to the fact that we’re carrying about $3 billion less debt on our balance sheet than we were when we entered 2007.
Q1 was also the first quarter for us to deliver free cash flow in two years. This is particularly meaningful now given the level of growth capital we’re committing to both business units. Mark will give you an update on our hedging for 2009 in a few minutes, but the hedging that we’ve done for 2008 has given us the opportunity to participate in most of the run up in natural gas prices.
The guidance of $1.00 to $1.10 a share for earnings that we gave in January for 2008 assumed $7.50 gas and $70 oil. At an industry conference last month, I had a chart that showed that with $9.00 gas we’d earn $1.25 to $1.35 and with $10 gas for the year, we’d earn $1.44 to $1.54 a share.
So given where prices are now, we would earn another $300-$400 million before taxes and while the income statement with tax effect, those incremental earnings, remember that as a result of the NOL that we have, we’ll fully realize this incremental cash flow. So we’re quite bullish on our outlook for the balance of the year and now I’ll turn it over to Mark for a review of our financial results.
Thank you Doug and good morning everybody. I’m on slide 7. Doug mentioned the company performed well this quarter and it shows in our results. We’re reporting earnings this quarter of $219 million or $0.29 per diluted share. Consolidated EBIT was $600 million compared to $216 million last year.
Last year’s quarter included a $201 million charge for debt repurchase costs. On a combined basis, EBIT for our two core businesses was up $80 million or 15% compared to the first quarter last year. Interest expense was $233 million, down from $283 million in the first quarter last year, reflecting the significant debt reduction we’ve experienced over the years.
You’ll note that we accrued $19 million in preferred dividends this quarter which is double the normal amount as it includes our second quarter accrual. This also impacted common dividend accrual and is merely a timing issue and will true up in the next quarter.
There are several legacy items impacting earnings this quarter which are highlighted on slide 8. The first is the $21 million pretax or $0.02 per share loss from a change in fair value of our production puts and calls in the marketing segment used to hedge E&P cash flows.
The second item is a $41 million pretax or $0.04 per share loss on power contracts which I’ll discuss further in the marketing results slide. The third significant item impacting the quarter’s results is a $43 million or $0.04 per share mark to market loss on a legacy indemnification associated with the sale of an ammonia facility.
Ammonia prices have skyrocketed in the last two quarters with increased natural gas prices and demand for fertilizer which has triggered mark to market losses on this indemnity. The fourth item is the $65 million or $0.04 per share gain associated with our Case Corporation retiree medical indemnification.
In March we received a summary judgment from a trial court on this indemnification dispute. As a result of the judgment against us, we adjusted our existing accrual which was based upon prior actual actuarial assumptions and re-classed the amount accrued as a post retirement benefit obligation which resulted in a reduction to O&M expense of our corporate segment.
A portion of the accrual adjustment was not tax deductible which caused our overall effective tax rate to be a little higher than normal this quarter. The final item is an $18 million or $0.02 per share gain associated with the partial sale and restructuring of our ownership in Alpheus Communications.
Adjusting for these items brings adjusted EPS as Doug mentioned to $0.33 per diluted share. Slide 9 highlights the business unit contribution. On a combined basis our core pipeline and E&P businesses generated $934 million of EBITDA and on an adjusted basis, EBITDA of $996 million.
Adjusted EBITDA is calculated by including our 50% interest in Citrus and our 49% interest in Four Star. For those of you who calculated NAV using these numbers we have a reconciliation in the appendix. We also include the Citrus debt. Note that there’s not any debt on the Four Star interest.
Marketing and trading recorded an EBITDA loss of $60 million which I’ll provide more detail on in a minute. Power EBITDA was a loss of $2 million and corporate EBITDA was $41 million of income.
Now turning to cash flow, slide 10. Cash flow was strong this quarter. Cash flow before working capital changes was $716 million, up $275 million or 62% and cash flow from continuing operations was $634 million, almost double a year ago.
Cap ex for the quarter was $531 million and we spent $295 million on the acquisition of a 50% interest in the Gulf LNG project. In total, cap ex and acquisitions were up $43 million from last year. So far this year we’ve received $598 million of cash proceeds from the sale of non-core E&P assets that closed during the quarter and we expect to close on the sale of the balance of the non-core E&P properties in the second quarter which will bring another $50 million or so.
A key point to note here is that excluding asset sales and dispositions, we’re free cash flow positive for the quarter. Slide 9 details earnings for the marketing segment. We’ve segregated results to highlight the impact of derivatives used to hedge production cash flows which we view as more strategic positions and then other positions were are primarily related to our legacy trading book.
For the quarter, as I mentioned earlier, we realized a loss, $21 million due to a change in fair value of the production related derivatives compared to last year’s loss of $87 million. The losses were primarily driven by mark to market losses on the 2008 oil collars of $6 million and 2009 gas collars of $15 million, both of which were put on to hedge the 2005 Medicine Bow acquisition.
In the other category of marketing positions, the gas book was flat, we realized a $41 million loss in the power book. Of that loss, $6 million was costs associated with hedging the balance of the capacity exposure which I mentioned on our analyst day and $19 million was due to the PGN basis widening. $16 million was due to other or was really due to lower interest costs, or lower interest rates.
In total, marketing segment loss realized a loss of $60 million versus a $135 million loss last year. So you can see from the financial results, our gas book is now relatively flat, power book is becoming more flat with the recent transaction we just completed in the quarter to hedge off the remaining capacity exposure in the PGN pool.
Therefore, other than changes in interest impacting the overall value of the book and the one remaining exposure we have to PGN basis, we’ve largely completed steps to mitigate against future volatility in our marketing book.
Slide 12 summarized our 2008 hedge program for April forward. In short, the balance of our program for 2008 includes 153 TBTU at an average floor of $7.94 with an average ceiling of $10.24. The hedges are weighted April through October with November and December hedged at about 50% anticipated production.
On the oil side was have 2.6 million barrels hedged with an average floor and ceiling at just under $80. The oil positions are a combination of the old collars put on in 2005 to hedge Medicine Bow and just under 2 million barrels that we recently swapped at a little over $88 dollars per barrel.
So the gas collars provide upside to $10.74 for MMBTU for the balance of the year and the un-hedged portion of our gas gives us plenty of upside exposure to the current commodity price environment. And as Doug mentioned at today’s prices, we would expect to generate an additional $300-$400 million of pretax earnings and cash flow compared to our plan which was at $7.50 gas and $70 oil.
We’ve added to our 2009 hedge program which is highlighted on slide 13. 2009 hedges have an average floor of $8.27 on 76 TBTU at an average ceiling of $12.12 on 93 TBTU. Of the total 2009 gas hedges, 24 TBTU are collars for January through March production with floor prices of $9.00 and ceilings of $18.22. So we’ve added a nice floor while leaving significant upside in 2009 which is consistent with our overall hedging strategy we’ve discussed often before.
On the oil side, we recently completed swaps on 3.4 million barrels at an average price of just under $110 a barrel. The oil hedges for 2009 ensure about $105 million of incremental revenue versus 2008.
So, in summary first quarter financial performance is a good start to 2008 and we’re on track for our sixth consecutive year of improved profitability. Our balance sheet is in good shape, our hedge program provides upside to today’s prices and our 2009 hedge program gives us an excellent base for higher revenue in 2009. Next, Jim Yardley will put some more color on the pipeline results.
Thanks Mark. The pipeline group is off to a fine start this year. On slide 15, our EBIT was up 5% from last year’s first quarter and were on plan for the year. Operationally we continue to see significant volume growth on our pipeline system. And we’re making progress in executing on nearly $4 billion of growth projects in our committed backlog.
We’ve not placed in service two projects already this year. Most recently on May 1 we completed on time and on budget our Cyprus phase two expansion that will increase capacity to Northern Florida by just over 100 MMCF per day in time for the summer cooling season.
We’ll also complete four other growth projects later this year. During the quarter we also received FERC approval on both our High Plains pipeline and Totem storage projects in Colorado. High Plains is our largest construction project this year, 160 miles of 24 and 30 inch pipe and we kicked off construction in it in April. It will be complete by late November to serve winter loads.
We also completed the acquisition of a 50% interest in the Gulf LNG re-gas terminal and put in place $870 million of non-recourse financing on that project and have now started construction.
Finally, as you know, we added the $2 billion FGT phase eight expansion to our backlog based on a 400 a day anchor load commitment from FP&L. Last week we placed another 200 a day of that expansion under long term contract, so this expansion is now already 75% subscribed and will go in service in 2011.
So we have our heads down and are executing on our backlog. On the financials, slide 16, our 2008 first quarter EBIT of $381 million was up $17 million year to year and up $26 million before the minority interest attributable to El Paso pipeline partners. Most of this EBIT growth is due to higher revenues and most of that is from expansions across the country but also from higher revenues in our base business, especially on TGP and CIG.
We also had some somewhat offsetting gains and impairments, including a positive bankruptcy settlement with Calpine and the write off of our Essex project that we mentioned at the April analyst meeting. You see that our EBITDA likewise is up from 2007’s first quarter.
We’ve also shown the EBITDA adjusted as Mark mentioned for our 50% interest in Citrus. This adjusted EBITDA has not increased as much year to year, primarily due to the onetime gain in first quarter 2007 from the settlement of the gas supply contract dispute with Duke. Capital expenditures are essentially flat year to year and as Mark said, the $295 million acquisition is for the 50% interest in Gulf.
On slide 17, throughput continues to increase solidly across the country and for several reasons. On the demand side, increases were driven by power gen loads on TGP, a colder winter in the Southeast, it was actually more normal, and greater access to the Florida market via the new Cyprus pipeline. And we saw a minor decrease in the California.
On the supply side, the independents hub volumes and production increases and expansions in the Rockies all contributed. Overall, throughput increase of 7%, so the underlying health of our pipelines continues very strong.
On slide 18, finally, I want to give an update on our proposed Ruby pipeline. First, let me remind you that we have not committed yet to go forward with Ruby. It is not in our committed $4 billion backlog and we’ve assumed nothing for Ruby in our guidance of 6-8% long term EBIT growth.
We have made substantial progress in its development and we’re optimistic but we’re also very focused on project returns. We’re convinced of the macro logic behind Ruby. Northern California and the Northwest today relies on Canadian imports for about 80% of that region’s total demand.
And with imports from Canada declining, accessing Rockies production is a natural for supply diversity. And clearly Rockies producers will need additional export capacity. So we’ve always thought of Ruby as both a demand pull and supply push pipeline to the benefit of shippers at both ends of the pipe.
We’ve made substantial marketing progress on Ruby. On the demand side, PGE is committed to more than 25% of the total likely capacity to the pipeline. Incidentally, PGE has clarified that its announcement Tuesday was that the PGE parent is withdrawing from participating in the equity ownership of Ruby, but PGE utility remains committed to its transportation contract on Ruby and is seeking PEC approval of the contract in California.
We’re in front of the producing community now, have been in April and now May and are negotiating actively with several producers concerning commitments under remaining capacity. So we’re continuing to make progress on the marketing front. We’re also very conscious of the inflationary cost environment for steel, pipe and contractors and we’re in continual discussion with contractors and pipe suppliers around the world for Ruby as well as for other projects.
Clearly, costs have increased since we started the Ruby marketing effort more than a year ago, and just in the last month or two, underlying steel costs have escalated yet again driven by sharp increases in raw material costs for iron ore, coking coal and steel scrap.
So, we’re looking hard at the risk return proposition of Ruby. We’re considering especially how to manage the capital cost risk between suppliers, customers and ourselves. We want Ruby to happen and we think the California and Northwest customers and Rockies producers also have a vested interest in seeing it succeed, but we’ll go forward obviously only if we see an acceptable return on the project.
In summary for the pipeline group, we’re off to a very good start for the year, financially and operationally. We’re focused on executing on the $4 billion of growth projects we have in hand and we have several other growth opportunities in front of us. And with that I’ll turn it over to Brent.
Good morning everyone. I’ll begin on slide 20 this morning. We covered a lot of ground a few weeks ago at our analyst meeting so most of my comments today are going to be geared toward the first quarter. The most significant achievement of the quarter was successfully closing on our domestic asset sales.
Remember our strategy is to add assets in areas where we can establish repeatable programs in areas with running room and the properties that we sold were the late life higher cost assets with limited future development opportunities. As you know, the assets we divested are essentially the same size for production reserves as the Peoples acquisition which came with significant new inventory adds in the Arklatex and the South Texas areas.
Our first quarter volumes increased 8% over last year’s first quarter and this growth is really a combination of our 2007 acquisitions and organic growth from the capital program. On a same store basis which excludes the volumes that we divested in 2008 but includes a full year of the Peoples volumes, we grew volumes by about 4% and I’ll discuss production in more detail in a moment.
And in 2007 we were a top tier performer in our direct lifting costs and I’m pleased to report that we continue to make progress in this area. On the cost front, we improved our per unit direct lifting costs, realizing about a 14% reduction versus the same period last year. So bottom line for the quarter, we’re off to a good start and we’re on track to meet our full year 2008 guidance.
Moving now to slide 21, the E&P segment reported about $242 million of EBIT for the quarter which is a 35% increase over our 2007 results and the increase was primarily due to higher production, higher commodity prices and our continued focus on our cost structure. Included in the Q1 08 results was a $35 million mark to market loss we incurred on our derivatives that are not designated for hedges versus about a $3 million mark to market gain that we had in Q1 2007.
So if we adjust for those results, we would have reported more than a 50% increase in EBIT. Our adjusted EBITDA of $486 million and that’s adjusted to include our proportionate share of our Four Star EBITDA was up almost 30% over Q1 of last year. And similarly if we adjust for the mark to market gains in losses, EBITDA would be up about 40% over Q1 of last year.
Cap ex for the quarter, excluding acquisitions was about $302 million which is about $50 million lower than we were prior year and we plan to grow quarterly cap ex spend for the rest of this year as we increased our activity levels and we feel the impacts of some of the higher steel and higher energy prices on our own cap ex programs.
In the first quarter of last year we spent $254 million for our South Texas acquisition and our Gulf Coast team has since doubled the production from those properties from about 20 million a day in January of last year to around 40 million a day today. And as Mark said, we received almost $600 million in net proceeds from the portion of our domestic asset sales that we closed in the first quarter.
And we expect to receive about $50 million more in additional proceeds in the second quarter as we finalize some of the outstanding pref rights and some of the consent and we close out the remaining sales.
Also remember that in addition to the $650 million in proceeds we’ll realize from the divestitures, we also eliminated approximately $110 million of discounted abandonment liabilities. Slide 22 shows our cash cost components for the quarter compared to full year and end of first quarter 2007. Again our direct lifting cost declined about 14% from a year ago to about $0.82 per unit.
While our high grading efforts have started to help on our cost structure, we also had lower work over and maintenance activities in our Gulf of Mexico and our South Louisiana region in Q1. For the remainder of the year, we expect further improvement in our direct lifting cost as we realize the full benefits of our divestitures.
As you would expect, production taxes were higher than the first quarter last year and the full year due to higher commodity prices and based on the current NYMEX strip, this trend will likely continue for the remainder of the year and the good news is with the higher commodity prices, we more than offset the increased production taxes with overall improvement in our EBITDA margins.
Our unit G&A was about $0.64 which is 7% lower than the prior year quarter and flat versus the full year 2007. We expect G&A costs to increase slightly in the second quarter due to the affects of losing the divestiture volumes and then they’ll decline again in the second half of the year as new production volumes come online.
So in aggregate we’re on track with our full year guidance of $1.75 to $1.90 per unit cash cost at least for those that are price related controllable costs. Slide 23 shows our drilling results by risk category and by division. In the first quarter of 2008 we drilled 93 gross wells with a 96% success rate which again reflects the low risk nature of our portfolio.
And our onshore central program we drilled 66 wells and we had a 100% success rate. Included in that performance are 23 wells in the Arklatex, that’s an area that we plan to steadily increase activity throughout the year and we should get to somewhere north of 110 gross wells for the full year.
These totals only include 2 wells in our onshore Western region which were both successful but not included in this performance are 96 Raton wells that we’ve drilled in the quarter but not yet completed. And remember in these stats we count completed wells and we batch complete the Raton CBM wells in order to improve the cap ex efficiency.
All of these Raton wells will be completed in tied in this year and we expect to have close to 1,000 Raton CBM wells online when we complete our 2008 program. We’re successfully ramping up activity in the Texas Gulf Coast division. We drilled 23 gross wells there with an 87% success rate and included in that performance are 10 wells in our South Texas Vicksburg program with 100% success.
This program is our second largest base volume in our portfolio and our technical team in South Texas continues to add successful exploration and exploitation projects to the program. In our Gulf of Mexico program, we drilled one successful well out of just a couple of attempts. The successful well was from our Highland 351 platform which we installed in 2007.
The 351 number 3 well which is currently producing about 20 million a day and we have 100% interest in the project is the first of six wells that we plan to drill in our Plio-Pleistocene program throughout 2008. So the Q1 activity including those Raton CMB wells puts us on track to complete our 2008 program of around 500-525 wells.
Slide 24 breaks down production by division for the first quarter and we’re showing our quarterly results here on a reported and a pro forma basis so you can better understand the results. Remember that our 8-12% three year growth rate is from a pro forma 2007 base of about 800 million cubic feet a day.
For the quarter, including Four Star we grew volumes 8% from about 820-886 on a reported basis and 4% from 770 to about 800 on a pro forma basis. The Peoples acquisition was a significant driver of the reported quarter to quarter increase so I’m going to focus my comments on the pro forma changes this morning and that’s the bars on the right side of the slide.
Our Central division which represents about 35% of our total volumes grew about 4% on a pro forma basis. We’ve had steady organic growth from that region and you should expect us to continue that and even to accelerate that growth through the year.
We’re actively developing the Peoples properties, especially in the Arklatex area. We’ve moved to a ten rig program which essentially doubles our 2007 levels. And two of those rigs are capable of drilling continentally horizontal wells and or Haynesville shale wells, depending on how we allocate that equipment.
In our Western division, production declined slightly on a pro forma basis but we expect production levels there to increase as we come out of the winter and we increased our drilling and recompletion activities in the Altamont field in Utah. In 2007 we also completed 160 wells in Raton and we’ll add over 100 wells this year and the production from those wells, remember will steadily decline as they continue to dewater, sorry, incline, as they continue to dewater.
As I indicated at our analyst meeting, we see significant growth from the Texas Gulf Coast division this year and we’re off to a good start with about a 10% increase in our pro forma basis and as I mentioned on our January call, TGC is down from the fourth quarter due to the decline that we’ve got in some flush production from some particularly high rate wells that we brought on late last year and from a slower ramp up in the Peoples assets.
So, however, we expect to gain those volumes back and we’ll growth further as we ramp up our drilling program and I’ll show you our reactivity chart in a couple slides. Our Gulf of Mexico South Louisiana division grew 7% on a pro forma basis and this growth is really driven by the installations in our [Highland] and West Cameron blocks in mid to late 2007.
And going forward we expect the division to range somewhere in the 120-140 million a day as new projects come on to offset our base declines. We shrunk our Gulf of Mexico business through our high grading program but the assets remaining there have deep inventory and they’re providing great cash flows and returns at current prices.
These results combined with our planned ramp up in activity levels gives us confidence that we’ll be within the range of our bottom guidance and above 860 million a day for the full year. Slide 25 shows our total average operated and non-operated monthly drilling rig activity. This slide excludes Four Star and begins in January 2007.
As the chart shows, our rig activity bottomed in the third and fourth quarters of last year and then we steadily increased the activities as we continued to adjust following our divestitures and the integration of our Peoples assets. So increases have come primarily in the activity levels in the onshore Central and the TGC divisions.
The lower Q3 and Q4 rig count naturally has an impact on our Q1 production but going forward we expect volume growth through the remainder of the year as we continue to increase our activity levels. And then turning to slide 26, for those of you that might have missed our analyst meeting, we spent the bulk of the E&P portion of the meeting discussing the depth and the quality of our proved and our non-proved resources.
Since then we’ve continued to get a few questions on our future opportunities so this morning I just want to briefly recap on our future inventory potential. The base of 2.8 T’s of proved reserves adjusted for divestitures is predominately lower risk US onshore opportunities and following our high grading efforts, more than 85% of our reserves are now onshore US.
And we’re very focused on drilling programs were we have competencies and where we have repeatability which will allow us to deliver consistent predictable results and further lower our finding and development cost. The next layer of our resource potential is the 2.8 TCF of non-proved risk resources and about 2 of that 2.8 TCF is comprised of unconventional opportunities like our coal seam programs in Raton and the Black Warrior Basin and tight gas plays in the Arklatex and Texas Gulf Coast region.
We consistently delivered north of 95% aggregate success rates in this part of the portfolio and we believe that we have the ability to turn those resources and to proved reserves and future production with a very high level of confidence. Additionally we think the total 5.6 TCF in proved and non-proved reserves is a conservative estimate.
We’ve got a significant amount of upside potential for further infill drilling and applying new techniques in our existing programs and from a couple of the emerging shale gas plays. And we’ve not included anything for the Haynesville shale in our legacy areas or on the Peoples assets in the Arklatex or for the Pierre shale in the Raton basin.
As I mentioned at our analyst meeting, we’re in the process of testing both of these plays in 2008 to understand the impact and the economics and the impact on the size of our inventory. We’re drilling and we expect to test our first Haynesville well in the second quarter this year and if successful we’ll continue with several more during the remainder of 2008.
And in the Pierre shale or Niobrara we expect to drill three wells this year to expand our current knowledge of the play. Also our unproved inventory doesn’t include the upside potential of our Cotton Valley horizontal drilling and we recently completed our first well in that pilot program and that well is producing over 5 million a day at de Sales and the well is still in the clean up phase post-frac. We’re still making frac water, so we’re pleased with the early performance of that well.
And of course we’re continuing to catalog the upside potential on our Brazil and our Egypt operations. So in summary you should feel confident that we have a solid inventory for the near term and the upside potential that’s going to drive our long term growth.
So in closing we’re off to a solid start for the E&P program for the year, we’re moving past the Peoples acquisition and our divestiture adjustment period, prices are strong, activity and production are increasing and we’re holding the line on controllable cash costs. With that I’ll hand it back to Doug for closing comments.
Thanks Brent. We’re on track for a very good year this year and given the combination of our committed backlog in the pipes, existing inventory in E&P and the continuation of our hedging program into 2009, we’re actually on track for several good years to come. The fundamentals for both our businesses are very good which is great, but they’re good for everyone.
The way we’re going to distinguish ourselves is through execution and we remain very focused on the cost and timing of our pipeline projects and on how we bid new projects. On the E&P front, we’re ramping up our drilling program which will translate into growth that we’ve articulated. We’re doing very well on the cost front so far and you’ll see continued progress as the year goes on.
Finally, we’ve retained much of the leverage to higher gas prices so we’ll do much better than our original guidance for 2008 and with that we’re happy to open it up to your questions this morning.
(Operator instructions) Your first question comes from Carl Kirst - Credit Suisse.
Carl Kirst - Credit Suisse
Mark with respect to how we should be thinking about the uplift of the cash flows this year, clearly with commodity price assumptions or the commodity strip, add to that at some point we’re likely to see I would think another drop down to the MLT, is this something where we should kind of continue to see perhaps a rise in the cap ex for the rest of the year as we take advantage of more opportunities or should we kind of look at that as kind of more of a windfall to the strengthening of the balance sheet?
Well I think that it’s early to say, you know we haven’t changed our guidance for cap ex. We have, of course, we have additional capital projects that the pipeline part is working on and but its early days to say whether that, where that additional cash will go. It’s a good problem to have.
I’d just add to that, we obviously aren’t going to spend it until we have it, meaning we’re very encouraged and we’re actually pretty bullish on gas prices but we want to see that in our actual received cash versus the forward curve. Having said that, planning on receiving that, we’ve got some great alternatives.
We’ve got a significant amount of growth capital already in the pipeline business and we’re not done yet, we still continue to chase not only the projects that, the rather large green field projects that we’ve alluded to but of course our typical bread and butter kind of pipeline projects.
We also have some really exciting things going on in the E&P side if we’re successful in proving up Cotton Valley horizontals, if we’re successful in our Haynesville tests, if we’re successful in our Pierre tests. We’ve got the ability then to ramp up some spending there.
And then of course depending on where our shares are trading at that moment, we have the ability to give our shareholders some of their money back which is also a consideration. And so those are in kind of priority, without a particularly priority, that’s where our heads are right now.
Carl Kirst - Credit Suisse
Jim, one specific question on Ruby, I guess I was just trying to, can you refresh my memory, the PG&E tariff, is that a fixed tariff or will that be readjusted depending on inflation and where the total project may go and ultimately I’m trying to get a sense of typically pipelines, 9% after tax on levered return on capital, what’s sort of the minimum threshold that you would need to go forward with a project of this size?
First of all in answer to the first question of the PGE terms of that contract, we haven’t, those are confidential, we haven’t divulged terms on any of the contracts with PG&E or with others. On return expectations, I think you saw Carl at our analyst conference that over the course of the last two or three years the projects we’ve put in service have typically been in the seven times cap ex to EBITDA range.
We also showed our information with respect to our committed backlog at around the same level. And so that’s a marker for what we’re looking for here with also trying to mitigate some of the risk.
Your next question comes from Shneur Gershuni – UBS.
Shneur Gershuni – UBS
On the E&P side [inaudible] with respect to E&P program Brent, if you can give us some color with respect to your expectations with respect to drilling costs, days to drill and so forth in the areas like Arklatex, the Raton, Black Warrior and so forth, do you expect them to trend down over the next year or so, are there things that you’re working on to try and drive them down and obviously improve returns?
Yes, let me step back a second Shneur, we’ve been able to do that a couple years in a row where we’ve, Raton is a good example, Arklatex is a good example where we’ve been able to hold the line on cost. Total cap ex for the projects, even though we’ve experienced some inflationary pressures in the services, for the first half of this year, I think we stand a good chance of doing the same because we were able to use our contracting strategies to secure up some of those prices.
As we look out to the second half of the year and we look at primarily steel prices and energy prices, they’ll have some net impact on us in the second half. So I think we’re okay near term, longer term we got to see how the energy prices and steel prices shake out.
Shneur Gershuni – UBS
With respect to drilling times though is there an opportunity, do you see opportunities to drill faster and potentially exceed your targets for wells to be drilled for this year?
We are seeing that in a couple of rig lines this year. We saw that last year, if you go back where we finished up the Black Warrior Basin program and the Arkoma program and part of the Arklatex program early. And so we are seeing a couple of the, because of efficiency gains and time gains, we’re seeing a couple of our rig lines this year that we could finish up early.
That’s a good problem to have. We’re continuing to make that kind of progress. The other way we get there is we may add time in the case of the Cotton Valley Horizontal wells, they take a little longer to drill, but we gain it in terms of the uplift efficiencies.
So we get more production and reserves per capital dollar that we spend but we actually add time. So we’ve got some of both, we’re able to keep improving in some of the areas where we’ve traditionally made gains on time and then we’re looking at other ways to gain on efficiencies.
Shneur Gershuni – UBS
At the analyst day you sort of talked about infill drilling potential in a lot of these projects, have you made any progress with respect to either filing to get it done or actually doing test wells and so forth?
We have a deep enough inventory now where we haven’t infilled anymore of the Arklatex area since the analyst day. So we’ll continue to work through our current inventory and we’ll continue to size it on how much potential we think we have in the infill. And so it may show up in our inventory cataloguing before it actually shows up in pilot test.
Your next question comes from Rebecca Followill - Pickering Energy Partners.
Rebecca Followill - Pickering Energy Partners
Follow up question in Pierre, on the Haynesville and Cotton Valley, how many Haynesville tests do you plan this year and how many horizontal Cotton Valley tests this year?
Right now two of the rigs are capable of drilling both and so our plans are right now to keep two rig lines working through the rest of the year and we’re still juggling back and forth between the two. Likely one of them will drill Cotton Valley horizontals for the rest of the year and then the second rig line will be part Haynesville, part Cotton Valley, the way it looks today. So two active rigs into Arklatex.
Rebecca Followill - Pickering Energy Partners
On the pipeline side, just a question on these steel cost increases are pretty amazing, when you go in to structure your contracts with shippers, at what point do you lock in those steel costs, is it after you get FERC approval, is it when you get the firm commitment from the shipper? Give us a feel for that.
As we’re marketing the project we’re getting a good sense for what we can do on the revenue side. At the same time during that process and as you know it can go on for months, we’re testing the market for what we think is appropriate to cost out the project, both with respect to steel as well as contractors.
And then what we’d like to do and to minimize our risk is in or around the time that we’re committing to go forward on the revenue side with our shipper contracts, we’re trying at a point very close to that to be ready and positioned to contract for the pipe as well as go forward with contractors.
That’s the aim but invariably either on the revenue side or on the cost side you’re hung out for a little bit. A good example is what we did on FGT phase eight. As you know we committed to the project a couple of months ago and we’re probably, we will be ordering pipe this month so, and we built into that estimate a couple of months ago adequate contingencies so that we feel good about the estimate that we had at that time. So we try to match up the revenue and cost as best we can timing wise and that’s that.
Rebecca Followill - Pickering Energy Partners
But on the case with Ruby, because you didn’t have enough commitment at that point you had not ordered pipe, is that correct?
Well right, I mean Ruby is still to come. We haven’t committed on either the revenue side or cost side. We haven’t committed to go forward with the project, so right now we’re in front of the producers in a big way trying to get a better sense for volume, rate, risk and so as soon as we get a better handle on that, we’re going to try to be read y to do something on the pipe order side.
Your next question comes from Mark Afrasiabi – PIMCO.
Mark Afrasiabi - PIMCO
On the operation and maintenance lines, I just wanted to clarify, make sure I understand the drop year over year, sort of, can you maybe explain that number for me and I guess the negative $39 million corporate O&M, what the non recurring component is there.
The operations expense is down year over year primarily as a result of a lot of things. But primarily as a result of the Case indemnity obligation that I mentioned early in the walk through, it’s really an adjustment of an accrual that was a benefit. On the corporate side, that is an unallocated cost as well as the charge associated with the indemnity in the ammonia line indemnity.
Mark Afrasiabi - PIMCO
So the $271 million number, if you ignore this non-recurring component, what’s that dollar amount that’s in that number just so that I can get to more of a run rate on the O&M line from Q1.
Rather than reconcile O&M right now I’d be more willing to do that for you offline Mark. I mean I think that O&M generally is pretty flat year over year, there’s nothing significantly changing our core operating expenses quarter over quarter.
Your last question comes from Mark Caruso – Millennium.
Mark Caruso – Millennium
Doug and Mark you had mentioned in your prepared remarks that you expect guidance to be sharply higher, I guess what’s the holdback considering with the new hedges, not officially raising it, because I know you guys since Howard Wheel have kind of given indication of sensitivities but not, I’m just curious, why not official raise it?
I think what we’ve tried to do is we’ve tried to say if you strip out commodity pricing, we’re reaffirming guidance. And then we’ve given you a gas price grid and you can do your own forecast of what you think gas prices are and you can get to a range of what our earnings should be. And then secondarily what we’ve said is to the extent your forecast is above $7.50 Henry Hub, while that revenue will get tax effected in our income statement, because of the NOL it’s actually going to be real cash to the company.
Mark Caruso – Millennium
So it’s more of just, you’re letting people make their own assumptions because I know at Howard Wheel the curve at $9.00 gas and gas is at $11.00, you guys are saying $1.25-$1.35 so I thought using that would have been still conservative in light of the current market.
That is conservative in light of the current market.
At this time we have no further questions in queue.
Thank you for joining the call, if you have any further questions please call investor relations. Thank you.
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