Questar Corp. Q3 2009 Earnings Call Transcript

Oct.29.09 | About: Questar Corporation (STR)

Questar Corp. (NYSE:STR)

Q3 2009 Earnings Call

October 29, 2009 9:30 am ET

Executives

Richard Doleshek - CFO

Keith Rattie, Chairman, President and CEO

Chuck Stanley - COO and President of Questar Market Resources

Analysts

Brian Singer - Goldman Sachs

Joseph Allman - JPMorgan

Rebecca Followill - Tudor, Pickering, Holt

Kevin Smith - Raymond James

Carl Brown - Royce & Associates

Operator

Good morning. My name is Antonele, and I will be your conference operator today. At this time, I would like to welcome everyone to the third quarter 2009 earnings release for Questar conference call.

All lines have been place on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions). Thank you.

Mr. Doleshek, you may begin your conference.

Richard Doleshek

Thank you. Good morning, everyone, and thank you for joining us today for Questar's third quarter 2009 conference call. This is Richard Doleshek, Questar's Chief Financial Officer and with me today are Keith Rattie, Chairman, President and CEO; Chuck Stanley, Chief Operating Officer of Questar Corporation and President of Questar Market Resources; Alan Bradley, President of Questar Pipeline Company; Ron Jibson, President of Questar Gas Company and Sam Brothwell, Vice President, Investor Relations and Corporate Planning.

It's been a busy week for us. We put a lot of information out there. We also know this is a busy day for you so we're keeping our prepared remarks brief so we can quickly move to Q&A.

On Tuesday, we issued an operations update for Questar Exploration Production Company in which we updated 2009 production guidance to 183 Bcfe to 186 Bcfe, provided initial production guidance for 2010 of 210 Bcfe to 215 Bcfe, updated QEP's 2009 capital spending guidance to just over $1 billion and provided QEP's initial capital budget for 2010 of approximately $900 million. Also, on Tuesday, we announced a 4% increase in our quarterly dividend, which is payable in December.

Yesterday, we issued our third quarter earnings release in which we reported our results for the third quarter and nine months of 2009, updated our 2009 EBITDA guidance, raised our 2009 net income guidance and provided initial EBITDA guidance for 2010. We'll discuss most of these items today and invite your questions at the end of this call.

In today's conference call, we'll use a non-GAAP measure, EBITDA, which is defined in our earnings release. In addition, we'll be making numerous forward-looking statements and we remind everybody that our actual results could differ from our estimates for a variety of reasons.

Our third quarter financial results were for the most part relatively consistent with our results for the second quarter of the year. Our third quarter EBITDA was $374 million compared to $370 million for the second quarter of this year. EBITDA for the first nine months of 2009 was $1.18 billion, down just 9% from the record level from a year ago even though natural gas prices were about $5 per Mcf lower than they were in the first nine months of 2008.

Factors driving Questar's year-to-date 2009 EBITDA were 7% increase in production compared to last year, up 9 Bcfe to 134 Bcfe, a 62% decline in sea level prices on an equivalent basis, down from $8.58 per Mcfe to $3.22 per Mcfe, which was offset by $465 million increase in revenues from our natural gas and oil hedges; and a 17% decline in combined operating maintenance and production tax expense compared to last year.

Consolidated net income for the quarter was $98 million, up from $78 million for the second quarter of year. Factors driving net income higher were lower DD&A expenses at Questar E&P and lower net mark-to-market losses on our basis-only swaps.

Net income was $243 million for the first nine months of the year compared to $563 million for the first nine months of 2008. Factors driving net income lower, aside from significantly lower commodity prices, were largely non-cash including higher DD&A, $173 million of mark-to-market losses before income taxes on our basis-only swaps and $62 million of gains before income tax on asset sales in 2008.

You'll note from the table at the end of our earnings release that we have combined all of our 2010 and 2011 basis-only swaps with NYMEX gas price swaps or collars. These hedges now qualify as cash flow hedges under FAS 133. We forecast 2009 capital spending to be about $1.46 billion, unchanged from our last estimate. We spent just over $1 billion for the first nine months of 2009, and note that for the remainder of the year, we've shifted some capital from Questar Gas Management to Questar E&P.

In the third quarter, both market resources and Questar Pipeline issued notes, both S&P and Moody's affirmed our debt range with stable outlooks. From a liquidity standpoint, Questar is in great shape. We have no long-term debt maturing until 2011. As of the end of the quarter had over $1 billion in unused availability under committed bank lines.

In summary, we got through the first nine months in pretty good shape. We throttled back on capital spending to live within our cash flow. Our balance sheet remains strong. We have plenty of liquidity to execute our capital plan in 2010.

With that, I'll turn it over to Keith.

Keith Rattie

Good morning, everyone. I'll try to add some color to the 2009 year-to-date results and then spend most of my time on our plans for 2010 and beyond. As Richard has mentioned on Tuesday, we issued a detailed update on Questar E&P operations. We want investors to take note. We intend to be a major player in the Haynesville shale play in Northwest Louisiana and our team is executing. We're building a strong acreage position in the core of the play and our last six Questar E&P operated wells are among the strongest reported by any operator in this play to-date.

We also provided a summary of recent well results in our Granite Wash, Woodford shale, Pinedale and Bakken oil plays. So, Haynesville Shale, Pinedale, Granite Wash, Woodford Shale and Bakken, these are some of the hottest E&P plays in the U.S. today and we're right in the thick of the action.

As Richard has summarized, we got through the first nine months of 2009 in pretty good shape for three primary reasons. First, we reallocated capital to our higher margin plays, in particular the Haynesville Shale and Pinedale with still enough capital to make significant early progress in these other plays.

Second, our hedging discipline did what we intended it to do. It protected our cash flow and earnings from the downturn in both natural gas and crude oil prices. In the first nine months of 2009, natural gas and oil hedges increased Questar E&P pretax income by $465 million.

Third, the rest of Questar: Wexpro, Gas Management, Questar Pipeline, Questar Gas and Energy Trading remains on track to generate over $240 million of net income and over $630 million of EBITDA in 2009. As we stress, these businesses contribute cash and earnings that are not very sensitive to commodity prices, they pay our dividend, support our investment grade credit ratings and bolster liquidity. That's not a bad foundation in which to grow an E&P Company.

Yesterday, we raised the low end of Questar E&P's 2009 production guidance. Please note that due to low natural gas prices again in the third quarter, we deliberately shut in or choked back production from some existing wells. We also deferred some completions on new wells. Now, natural gas prices should be higher this winter, so we're now bringing shut-in and curtailed wells back on and we're working through our inventory of deferred well completions.

As we explained in our last call, our decision to deliberately defer Questar E&P second and third quarter production was based on simple economics. In effect, we stored some of our unhedged gas in reservoir rather than sell it at depressed summer prices.

Now, Questar E&P net production averaged 476 million cubic feet per day in the third quarter. As we bring curtailed volumes back on, we're getting flush production. Please note that Questar E&P net production recently jumped above 575 million cubic feet a day. We expect Questar E&P net production to average more than 535 million cubic feet per day in the fourth quarter bringing production for the year in at 183 to 186 billion cubic feet equivalent.

As promised, that's between the goal posts. In fact, at the upper end of the guidance we gave at the beginning of the year despite curtailments. As Richard noted, we expect Questar consolidated EBITDA in 2009 to come in at about $1.6 billion and that's more than double what it was five-years ago.

Let me just touch on a couple of highlights in the operations update. You may want to refer to the new slides we posted with this update at our website, www.questar.com. As you know, we've been telling investors for some time that we intend to lease or acquire additional acreage in the Haynesville Shale play. Well, our Haynesville team is executing superbly.

Questar E&P now has about 43,000 net acres in the core of the Haynesville play. That's up 39% from just three months ago. Questar E&P leasehold is shown in yellow on slide three. Most of the new acreage is in Danville Terrace, that's north of and contiguous with the Woodard property that we acquired in 2008. We've already drilled our first two wells on this new acreage. These wells are waiting on completion and we're now drilling ahead on three new wells on this new leasehold.

Another highlight from the release. Since our last call, we drilled in turn four very strong Questar E&P operated wells to sales. That now makes six straight Questar operated wells with peak 24 hour rates above 20 million cubic feet a day. We're denoting these as red dots on slide three in our presentation. Drilling and completion productivity is up and our well costs are coming down. You'll want to ask Chuck Stanley for more color on that when we get to Q&A.

Let's not forget about Pinedale. We've now completed and turned 82 new wells to sales at Pinedale in 2009. We expect to complete more than 95 wells at Pinedale this year, and our Pinedale team continues to drive productivity improvement. Our completed well costs trended below $5 million in the third quarter, please see slide five for details.

On Tuesday, we also gave you an update on our Anadarko Basin Woodford shale or Cana shale play; and our latest Cana wells, well they are keepers. Initial rates are up, well costs are down. We now have an interest in 45 Woodford shale wells. Please see slide six for details.

Note that we've recently completed a Granite Wash horizontal well in Washita County, Western Oklahoma. We're now drilling ahead on our first Questar operated horizontal Granite Wash well in Wheeler County, Texas. This could be a significant play for Questar E&P. See slide seven for details.

Moving to our Bakken oil play in North Dakota, please note that we recently turned our second horizontal Bakken well to sales with a peak 24 hour rate of 840 barrels of oil equivalent per day. As you'll note on slide eight, this is an important well because it's five miles from the nearest Bakken well to the north and it's the first Bakken producer in this township.

These two Questar E&P operated wells plus nearby wells drilled by other operators are confirming that the Bakken play extends on to our 80,000 net acre leasehold. We are drilling ahead, we expect to reach TD in early November on our third Questar E&P operated Bakken well. Please note on this well we're planning a 9,300 foot lateral.

So, the Haynesville shale, Pinedale, Granite Wash, Woodford shale, Bakken oil, these plays are the foundation of this company's plan to turn up its growth and drive shareholder value in the years ahead. So let me turn now to our plans for 2010 and beyond.

First, we estimate that Questar consolidated 2010 EBITDA could range from just under $1.5 billion to just under $1.6 billion. That's flat to down modestly from 2009. Note that we've hedged nearly 80% of our forecast 2010 production, so Questar E&P cash flow should not be all that sensitive to commodity prices.

As Richard noted, we estimate that Questar E&P 2010 production could range from 210 billion to 215 billion cubic feet equivalent in 2010. That would be up 15% from 2009. In 2010, we are allocating about $900 million to Questar E&P and roughly two-thirds of that will go to Haynesville and Pinedale. Please note that 90% of Questar E&P 2010 CapEx is for identified low risk drilling locations in our key resource plays.

We're forecasting Questar E&P production growth up 12% to 15% per year over the next five-years from our existing asset base. We have very good visibility on this forecast. Again, it's based on CapEx for identified drilling locations in our core resource plays. We don't assume Wedge Capital for unidentified investment or acquisitions; and please note that we have the ability to accelerate this growth by adding rigs to our Haynesville or Pinedale or to our other plays if they prove as robust as early results suggest.

We're assuming that natural gas and oil prices will remain volatile, but average at or near the current five-year forward curve. We will continue to hedge, consistent with our long standing practice when prices are at or above the levels that allow us to deliver the results reflected in our five-year plan. Please let me stress that we have not changed our investment criteria. We continue to require our E&P asset managers to show Chuck Stanley a minimum 15% risk IRR on the current forward curve to obtain capital for drilling.

I'll turn very quickly to our other businesses starting with our second E&P Company, Wexpro. We also have good visibility on Wexpro's growth over the next five-years. We are allocating $100 million to Wexpro in 2010. We estimate that Wexpro's investment base will grow from about $440 million at the end of this year to about $460 million at the end of next year. That's net of depreciation.

Over the next five-years, we're planning to invest $650 million to $700 million in Wexpro, and about 35% to 40% of that will be at Pinedale. Just a reminder under the 1981 Wexpro agreement, Wexpro earns a 19% after-tax unleveraged return on its net investment base for the life of the defined set of producing properties in the Rockies.

Turning to our midstream gathering and processing business, we also have good visibility on Gas Management's growth. You'll recall that all of the production from Questar E&P and Wexpro operated acreage on the northern third of the Pinedale Anticline, and that includes partner production, is dedicated to Gas Management for the life of the Pinedale field.

Over the next two years, we plan to build a new cryogenic processing plant at Blacks Fork to extract ethane and propane from this dedicated Pinedale production. We plan to start construction on this new plant in 2010 and put it in service in mid-2011.

We're also building a new cryo processing plant next to our existing Stagecoach plant in the Uinta Basin. Now this project is underwritten by fee-based contracts with third-party producers and this plant should be in service in early 2011.

Our new development, Gas Management, has also recently entered Northwest Louisiana to build gathering and treating infrastructure to support Questar E&P's Haynesville growth strategies. Now as long-term investors have watched, we've built a substantial midstream franchise in the Rockies on an initial entry strategy supported by dedicated volumes from Questar E&P. We're hoping to replicate that strategy in Northwest Louisiana.

Finally, our two regulated businesses, we're allocating $160 million to Questar Pipeline in 2010. Our pipeline team is expanding over thrust pipeline, which as you know runs from Opal to Wamsutter through the heart of the Green River Basin. The pipeline team is also expanding our pipeline out of the Uinta Basin. Please see the slide in our recent IR presentations for details.

We're allocating about $130 million to our utility, Questar Gas, in 2010. That's primarily to connect new customers and replace aging feeder lines. Questar Gas, of course, earns state regulated returns on its common equity; and therefore, utility net income growth, tracks growth in common equity, which in turn is driven by new investment.

So in closing, if we execute, Questar consolidated EBITDA and EPS could grow at a compound rate of about 12% to 14% over the next five-years. Questar E&P production could grow at a compound rate of 12% to 15% over that same time period; and we have better visibility on this growth than at any time during my tenure with this company. So for the next five-years and beyond, it's all about execution and we think we have the balance sheet, the assets, and the people to execute.

With that, Operator, we'll be glad now to open it up for your questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

Since you kind of asked for the question, maybe you could talk about the cost trajectory at Haynesville and then also touch on some of the decline rates you are seeing relative to expectations from the earlier Haynesville wells you drilled at the beginning of the year.

Chuck Stanley

Hi, Brian, Chuck Stanley here. We currently carry an AFE cost on our Haynesville wells of $9.5 million and that assumes about 69 days from spud to rig release. We are averaging well under that, about 55 days about $8.9 million for our most recent wells; and the most recent well that we drilled and TD'd in 41 days, so the drill times are coming down.

We have had our biggest challenge is frankly not in the actual drilling but in the downhole equipment and the high temperatures that we encountered in the Haynesville, which tend to limit the service life of NWD and directional equipment downhole. We're finding service providers who are responding to the need for high temperature equipment and it's making a big difference. So we're not having to trip out as often to replace those tools.

Long-term, I've given up trying to predict performance; but the Pinedale team has continued to amaze me in the way they've delivered lower well costs, improvements in drill times. We're identifying new bids that have significantly reduced our well costs at Pinedale. As we mentioned in our ops release, we've trended below $5 million. We've drilled wells in 16 days. Our average time there is down dramatically from what it was even a year ago and that's after over 400 wells. So I'm very optimistic on our team's ability to drive down cycle time and improve performance in the drilling side.

Second part of your question on well performance decline, you saw the results of the wells that we turned to sales. I draw your attention to a couple things. The initial rates, the 24 hour rates are quite strong on these wells. But you need to look at the IPs or the peak rates in conjunction with flowing pressures and with choke sizes. You'll see that all of these wells had flowing pressures in the high 7,000 to over 8,000 pounds per square inch range on relatively small chokes, 24 to 2,864 chokes.

So when you're comparing apples and apples, you really need to look at that because the flowing pressure and long-term performance of these wells is directly related as well as initial rate. We can't speak to many operated Questar wells to look at the decline curves because, frankly, we've constrained flow on the wells. As we announced in our last call, we've deliberately been choking back on these wells. After we cleaned them up, we tend to put them on a smaller choke and produce them at around 10 million cubic feet a day for two reasons.

One, in response to prices this summer; two, as a result of building out gas treatment infrastructure, we'll be commissioning a new 300 gallon per minute aiming treatment unit in the Woodardville area on the east side of the river in a few days, and we'll commence construction on a 1,000 gallon per minute aiming treatment unit early next year that will be online this summer. The combined capacity of those two facilities will be close to 500 million cubic feet a day of raw gas processing capacity. So as we build out the infrastructure, we can flow the wells at higher rates.

We are still studying the impact of opening these wells up and flowing them at high rates and the long-term profit stability, et cetera, of the wells. So I wouldn't read a lot into what you see in the production data from our wells, I think they're very strong wells. The wells that we have participated in that have been flowed without constraint are performing on our tight curve or better than our tight curve of 6.5 Bcf to 7 Bcf per well EURs.

Brian Singer - Goldman Sachs

Secondly, switching to the Pinedale, how are you thinking about Pinedale strategically? If gas prices do move higher than expected, where does the Pinedale stand in the pecking order of incremental capital relative to your non-Rockies plays? Maybe just touch on how you're thinking about the extent of five acre down spacing throughout your Pinedale acreage?

Chuck Stanley

Well, first of all, Pinedale I would argue is one of the best, lowest cost unconventional gas plays in the U.S. It ranks right up there with another sort of story, unconventional plays including the Haynesville. As we continue to improve our performance, drilling completion performance and drive down well costs, obviously, Pinedale becomes even more attractive. In addition to low finding and development cost, very low operating cost, it's the lowest operating cost asset in our portfolio and we are the low cost operator at Pinedale.

So, we will continue to allocate capital to Pinedale. I think you saw us slowdown this past year in response to broadly low prices, NYMEX prices, and concern over potential for basis blowout. As other operators have slowed down, we've seen capacity increase on the Rockies pipes that drain the region. So our concern over a wide basis differential has gone away. We currently forecast utilizing six rigs at Pinedale. We'll allocate in round numbers about $250 million to Pinedale next year.

We had the ability to bring more rigs in and then move faster if prices remain at the current levels or improve; but interestingly, Pinedale is a great asset. It's one of our most attractive, but we have another plays in the Midcontinent region that exhibit similar returns and have the added benefit in cases like the Granite Wash of having significant liquids volumes which further enhance the economics.

Before I leave Pinedale, just two other points, of course, Wexpro, our other E&P Company is a participant at Pinedale and there is other opportunities to invest alongside QEP in the drilling and completion of new wells. We also, of course, have the entire northern third of the Anticline dedicated to our midstream field services business, Gas Management, so we capture value downstream of the wellhead.

The follow-on question on well density, everything that we see today, Brian, would support the development of the flanks of the Pinedale Anticline. So if you look at the map in our slides that we put out on our website, slide number five on Pinedale. If you could imagine a central core that will likely not need anything less than 10 acre density development because we think we drain a larger area, I would point out that roughly two-thirds of the Anticline from our initial development on five acre density would very strongly indicate that five acre density is appropriate.

The SEIS or Supplemental Environmental Impact Statement requires that we develop the field on whatever density we deem appropriate. Then after we complete the wells, we move on and reclaim the disturbance down to a minimum and that's our plan to develop the field. We think, not only is it required under the SEIS, but from an economics perspective, these wells when they're first put on show no signs of interference.

So the highest present value for extracting the gas on increased density is to drill them now and complete them and simultaneously deplete the entire block of rock with the ultimate density rather than coming back and trying to infill. From a safety and drilling difficulty standpoint, coming back and trying to infill will be extremely difficult because then you'll encounter partially depleted reservoirs that we think will be a real challenge for drilling and completion activities.

Sorry for the long winded response.

Keith Rattie

Brian, it's hard to add color to that, but I want to make just one added comment on that. As I described in my prepared remarks, I am looking at Pinedale in the Haynesville as our fly wheel for accelerating growth, and I would ask you if there are any other E&P companies in your coverage universe that have a fly wheel for acceleration like Pinedale.

Brian Singer - Goldman Sachs

I appreciate it. Pinedale and Haynesville definitely a good combination.

Operator

Your next question comes to the line of Joe Allman with JPMorgan.

Joseph Allman - JPMorgan

Regarding 2010 spending, just curious given the premium price that oil is trading relative to gas; why would you not ramp up the Bakken more? Is it some kind of like an HPB issue, you've got to hold a bunch of acreage over in Haynesville, so you just need to spend the money over there?

Chuck Stanley

Joe, Chuck again. Right now we forecast one rig active in the Bakken, one operated rig. There is a couple of issues. One, we want to sample our acreage over its aerial extent and make sure that we understand the geology; not only in the middle Bakken but also in the underlying Three Forks before we go into an orderly development program.

So, first thing is sampling. Second, is permits and the permit situation has improved dramatically over the past few months. It's not the rate limiting step now. The primary focus will be on making sure that we understand the geology. In our slide deck that we put out on questar.com, on slide eight, you can see there have been a lot of very good initial results from other operators immediately adjacent to our acreage that have significantly de-risked at least a portion of our over 80,000 net acres.

So I have a lot more comfort in moving forward with the drilling program out there and after we see some additional results on some of our acreage, we may very well pick up another rig and accelerate that program. In addition to that, we are going to continue one rig program down in the Uinta Basin focused on Green River oil accumulations, horizontal drilling to target horizons that have not been drained in now over 60-year, almost 70-year development history out there. There is still a lot of oil in the ground and we're continuing to focus on that, so we'll have an oil directed program in the Uinta Basin.

Then as I mentioned earlier, we are targeting liquids risk reach our high yield gas and free liquid production both in the Granite Wash but also in the Woodford shale over in Central Oklahoma.

Joseph Allman - JPMorgan

Then how about your ability to sell the oil at the Bakken, what kind of outlet do you have to sell the oil and also the associated gas as well?

Chuck Stanley

Well, we have multiple outlets for the oil. Right now we're trucking and railing. One of the other operators has a rail facility in place with a significant tank volume that allows for staging produced oil and then sending out unit trains of oil. There is also several projects both Enbridge and Kinder have expansion projects underway. One will be in place in February of 2011 and another one a couple years later.

Obviously, we're suffering the same differential that other producers are out there at $12 or so a barrel. We think that additional pipe will help ameliorate that problem and we're working with other producers to make sure that happens.

On the gas side, the infrastructure is being built down toward this sort of hole that has existed between the Bailey Field of the south and the Parshall and Sanish Field to the north. There are a number of midstream opportunities out there to collect the gas, relatively low volumes of gas; but obviously very rich in liquids. So that infrastructure is being built and will continue to be built out as the oil volumes increase in the middle part of the fairway.

Joseph Allman - JPMorgan

Just lastly on the Bakken, how much of your acreage do you think is perspective for the Three Forks/Sanish?

Chuck Stanley

There have been some results on the western part, immediately west and north of our acreage that are encouraging for the Sanish/Three Forks. We'll have to drill some additional vertical wells, pilot holes, and core the Sanish/Three Forks and evaluate it; but subjectively without a lot of control probably two-thirds of our acreage.

Operator

Your next question comes from the line of Rebecca Followill with Tudor, Pickering, Holt.

Rebecca Followill - Tudor, Pickering, Holt

Can you kind of bucket the 12% to 15% growth that you're looking at per year over the next five-years? Can you bucket how much is Haynesville versus Pinedale, or is it just 90% Haynesville? That's my first question.

Then the second question, regarding Keith's comments that you could accelerate production, what would cause you to accelerate rig count in the area? How do you balance that without spending cash flow? Thanks.

Chuck Stanley

Okay, well Rebecca, I think Keith's description of Pinedale and Haynesville as fly wheel is pretty good. If we just look at next year, we can drive 20% to 25% growth at Pinedale and 25% to 30% growth in Northwest Louisiana with our capital investment programs there. We'll allocate roughly two-thirds of our capital to those two core areas and they will drive growth.

In addition to that, we've got other very interesting opportunities, and we've talked about them in our release so I won't reiterate, but the Granite Wash, the Woodford, the Bakken are all elements of potential growth beyond next year that have significant running room. As we de-risk them with more and more drilling, a lot of visibility, but you can focus primarily on Pinedale and Haynesville for the next several years and easily achieve the mid-teens growth targets that we're putting forth.

We've gone through a fairly detailed, well not fairly, a very detailed five-year plan, which we just finished reviewing with the Board on Tuesday. All of this growth that we're projecting and we feel very comfortable with projecting is based on our inventory of identified development locations and scheduling them out.

Our capital spending, we forecast averaging about $1 billion a year, less next year but $1 billion a year over the five-years to deliver that kind of growth. I'd hasten to say that we make that projection using today's performance, so we're not assuming a rapid improvement in drill times and well delivery in the Haynesville, I think it will happen. We've got a track record of making it happen, but we can make that promise with existing pace of development in our existing plays.

That's pretty unheard for a company that a few years ago, basically had one growth driver and that was Pinedale. Today, we have multiple growth drivers.

Keith Rattie

Becca, you've asked the question that frankly was one of the most discussed issues as we put this plan together. Next year, market resource is going to modestly outspend cash flow from operations maybe by a couple hundred million dollars. Over the five-year period, the plan that we have just summarized, we actually generate significant free cash flow in the out years. So we have the ability to turn up the growth even beyond what we have just described. That will be a function of how we feel about commodity prices going forward, the results we're getting in some of these plays and some other factors.

Chuck Stanley

Most of the outspend next year, by the way, is related to lumpy projects, investment midstream, infrastructure; which is basically a one-time investment. As Keith mentioned in his prepared remarks, we'll be building a gas processing plant which will be adequate to handle growing volumes and peak production from Pinedale. So we're building infrastructure that will be long lived, that will serve the growing production volumes that we forecast out of these assets.

Ditto in the Haynesville. We mentioned the gas treatment facilities. That will be an incremental, for instance the 1,000 GPM or 1,000 gallon per minute aiming plan is a $30 million type investment that we'll be making next year that will handle 300 million to 350 million a day of raw gas coming out of the Haynesville shale.

Rebecca Followill - Tudor, Pickering, Holt

That's all for yourselves?

Chuck Stanley

Well, Becca, we will no doubt gather and process or gather and treat the working interest partners gas in our wells. As you've seen us do in other plays in which Gas Management is active, we'll probably try to pick up some third-party gas to help amortize the cost over a larger volume.

Rebecca Followill - Tudor, Pickering, Holt

Then just one more question if I may. The acreage that you added to the North of Woodardville in Bienville Parish, I see lots of triangles there. So you're drilling there, are you expecting the same results in that acreage, do you still think that that is in the same core area as the rest of Haynesville?

Chuck Stanley

We sure hope so, yes, Becca. In addition to the well control, we've got two wells down waiting on completion, three wells drilling on the newly acquired acreage. There are some old vertical wells that penetrated the Haynesville Shale. They give us wireline log data and in a couple of instances actually some core data that give us comfort that the characteristics of the Haynesville that we think are important to be part of the core, thickness, porosity, and pressure are all present in that block of acreage to the north.

Rebecca Followill - Tudor, Pickering, Holt

Just one more. In looking at your costs. I know that you guys don't want to talk about what you paid for acre on this acreage; but just looking at your increasing CapEx budget versus that acreage that you picked up, it's got to be well below the market rates that we've seen; is that fair?

Chuck Stanley

I think it would be a very reasonable calculation for you to make; and you are right, I'd prefer not to get into the details of exactly what we paid because it's our intention to continue to add to this acreage. I think one of the things that we've pointed out to you in previous calls is we think these resource plays require chunky contiguous acreage blocks so that we can build the infrastructure and enjoy the economies of scale that you don't get if you have a diffuse acreage position where you have to build a lot of infrastructure and don't get to use it repeatedly, as we will in the case of this acreage play.

Keith Rattie

Becca, just to give you a little more help on that. I've noted in my comments that we've already drilled our first two wells on this new acreage and we're drilling ahead on three more. So it would be, I think, inappropriate to assume that all the incremental CapEx went for leasehold acquisitions.

Chuck Stanley

One final point and we'll get off of this. The other thing that I'm proud of in this particular deal, we got over 79% net revenue interest in our newly acquired leasehold, which is significantly better than the average that has been acquired in the play by other operators.

Operator

(Operator Instructions). Your next question comes from the line of Kevin Smith with Raymond James.

Kevin Smith - Raymond James

You mentioned delayed completions. How many wells have you drilled, but not completed? Once you kind of decide to start completing them, do you expect any bottlenecks in service providers or any sort of service as you bring those wells online?

Chuck Stanley

Well, we've got about 20 wells at Pinedale that we deliberately deferred completion on. We're actively completing those wells now. Whether the air temperature will drive how many of those wells we complete and turn to sales by year end. We may carry some over into next spring. It's just not cost-effective to try to fight minus 30, minus 40 degree Fahrenheit temperatures with frac crews, but we don't anticipate any bottlenecks at Pinedale.

In the Eastern Midcontinent and Northwest Louisiana, we have an inventory of a similar number, about 20 vertical Cotton Valley Hosston wells. Fortunately, we don't have to fight minus 40 degree weather and we're working through that inventory. We haven't seen any issues. One of the key points there is that it's a totally different frac crew that we mobilize to frac those shallower lower pressure vertical Cotton Valley Hosston wells. So we're not competing for services with the Haynesville operators.

Kevin Smith - Raymond James

I know it's a little bit early; but as you look at Pinedale reserve bookings at the end of the year, do you sense that anything material is going to change in your kind of reserve booking methodology with the new rules?

Chuck Stanley

Yes, that's an interesting question. We're still waiting for the pronouncements from the FASB and the final SEC rules to really get a handle on what we can book, and then we'll have to look at judicious reserve booking going forward. I think that one of the other operators has already coined the phrase "near proved". I think the street should have a pretty good sense for the quality of the unproved locations at Pinedale.

The reserve booking, other than the posting a number, doesn't have a material impact on our book cost metrics because we have virtually no cost in our leasehold pool and the only way that adding additional reserves moves the book performance is if you have a very large leasehold pool cost. So it wouldn't make a material impact on DD&A. It would only change, and I would argue slightly change a perspective or perception of the street on the quality of Pinedale reserves.

We view Pinedale as being a very predictable reserve adding machine as far as well results. As we drill the well and complete it we know before we drill a well and complete it within a few tenths of a Bcf what that well will recover and within a few tenths of a million cubic feet a day, what the initial rate will be. So, not a lot of surprises expected as far as the results go.

Keith Rattie

Kevin, just to give you a little bit more color. The last time we did an update on our estimates of probable reserves at Pinedale that number was north of 2 trillion cubic feet equivalent, and that was before we did a bunch of delineation drilling on the northern end of the Anticline. Those, as you know, the quality of the probable estimates at Pinedale are very high. Those were net numbers, by the way.

Operator

Your next question comes from the line of [Stewart Weinman] with Catapult.

Unidentified Analyst

Wanted to ask a quick question to make sure I got the numbers right. Chuck, I thought you mentioned that in your current plans it's about $250 million spend in the Pinedale for 2010, and then later you said which could drive 20% to 25% growth; is that correct?

Chuck Stanley

Yes, 243 is the exact number, I've got my numbers guide, I'm point to the number here, $243 million. This year we'll produce 62, 63 Bcf at Pinedale and next year, we'll be in the mid to upper 70's; and that gets you into the mid 20s sort of growth range. The assumption is that our well delivery pace mimics the average from this year and if every other year proves to be indicative, that's probably conservative. So you can drive 25% growth at Pinedale with six rigs in our portfolio, which is a pretty astounding result compared to where we were a few years ago when we were thinking we needed a dozen rigs to do the same thing.

Unidentified Analyst

That's excellent growth. My next question is, inside the 2010 guidance for the Haynesville wells, does the guidance show wells choked back at these 10 million a day levels or how should we think about just your Haynesville production coming online next year?

Chuck Stanley

The way we forecast production from our operated Haynesville wells is we assume that they come on, you clean them up so you'll see relatively high rates, 20-plus million a day clean up rates. Then after we get the water off the purse, we do choke them back to 10 million a day. We hold them there until the well approaches the natural decline. So if you think about it, there will be a plateau period of 10 million a day production. That's gross production and at some point in the future, the well will intersect the normal hyperbolic decline profile that we model in the type curve.

So there is some anticipated constraint on the flowback. Why are we doing that? We just don't know yet whether pulling these wells hard might cause embedment of the profit into the surrounding rock. We want to collect more data on that as we continue to experiment with flowbacks on these wells. The last thing we want to do is inflict permanent damage on the formation as a result of being too aggressive on the initial flowback.

Unidentified Analyst

Then lastly, with such a large hedge position, in 2010, should we expect or anticipate if we see gas prices weaken, how should we think about deferments next year in the summer again? Is it the same type program we've seen in '07 and '08 and '09 or should we expect you guys to just drill through at this time since you're so hedged?

Chuck Stanley

Well, we drilled through with the exception of a fairly dramatic decrease in rig count this year as compared to last year. We've continued to drill in our core plays, and we have made monthly decisions on whether to flow gas or not based on spot prices. Remember that the hedge position delivers the financial results, it delivers the cash flows whether or not the physical gas flows or not. The election to sell gas into the spot market is independent of the hedge position. We have some physical sales in place that will protect the actual physical sale of gas, as well as the hedge position. But I think in short, you can expect us to continue to act rationally with respect to selling our gas.

Keith Rattie

When we give production guidance, we try to give ourselves some leeway for things that go bump in the night. They always do in this business. So if you look back over many years at our guidance and our actual delivered results, you'll see that we've got a pretty good track record of bringing production in at or above our guidance.

Operator

Your next question comes from the line of Carl Brown and Royce & Associates.

Carl Brown - Royce & Associates

I was wondering if you could give a little more color on the Colony wash and Granite Wash acreage, the 24,000 net acres. Can you break it out a little between Colony wash and Granite Wash? Then maybe some sense of what's the gross acreage, your average working interest and who the operators are on the acreage?

Chuck Stanley

Carl, it's Chuck again. The well that we reported in the ops release, the Roxanne Well is actually over in Oklahoma. It's in Washita County, which is if you go to the east and then you skip a county, go due east of Wheeler County you'd end up in Beckham County or southern Roger Mills County; and then the next county to the east of that, about 100 miles away from our core Granite Wash position is the location of the Roxanne Well.

Our acreage position there is relatively modest. We've participated in some outside operated wells. It has allowed us to practice drilling horizontal Granite Wash wells, and I think the results there are pretty good. They are pretty indicative of the remaining potential out there. We've got an interest in about 44 sections out in the Colony Wash area. That's a couple of thousand acres, 2,300 acres net. But we've got a fairly small working interest, about an 8% working interest in that play. So we're really not driving the pace there.

We have a couple of high working interest sections, but I would have take you back over to the slide seven in our slide deck and talk to you about the position we have in the Texas Panhandle, primarily centered in Wheeler County. In that play, we've got over 20,000 net acres, and the gross acreage position there is about 50,000 acres. So we've got a little bit over about a 45% average working interest. In some areas, we have 100%.

In that area, we're targeting multiple Granite Wash sands starting up in the shallow section in the Cherokee and Caldwell sands, which are fairly continuous. We see them in a lot of vertical wells. They are liquids rich. They tend to be the oilier horizons, so they generate significant free liquids in the form of condensate anywhere from 30 barrels per million cubic feet of gas to a 100 barrels per million of condensate.

Deeper down in the section we've got the Granite Wash A through E sands and then a couple of washes in the Atokan section, and Atokan Granite Wash and then and Atokan carbonate wash, all of which are perspective for horizontal drilling.

Next year, we'll drill 10 wells at least out here, with two rigs, one rig focused on drilling vertical control. If you look over in the southwestern part of our acreage, you'll see just two or three red dots. We need to drill some more vertical wells in that area so that we can map the continuity of the sands, and really set up our horizontal development program targeting these multiple sands.

You've seen some of the well results posted by other operators in the play near our acreage, over 20 million a day of initial gas production rates. In the shallower horizons in the Caldwell, in the Cherokee, significant liquids production. One well that IP'd at nearly 2,000 barrels a day of liquids in addition to 25 million cubic feet a day of gas. So very strong initial rates and those wells are hanging in there and we've got plans. We're already drilling ahead on our first horizontal well in the Texas Panhandle Granite Wash play.

Keith Rattie

Another potential growth accelerator for us, Carl.

Carl Brown - Royce & Associates

Sure. The areas that you're not the operator, who is the operator; and to what extent do you feel like you've got good visibility on what their pace will be; and how did you do that in 2010 guidance?

Chuck Stanley

Well, in the Texas Panhandle the other two main players out here, the operator who broke the story on the horizontal development of the Granite Wash is Newfield, and we are participating in wells with them and we jointly own acres with them. Forest is also an active player in the Texas Panhandle. Over in the Oklahoma portion of the play, probably Chesapeake is the dominant player there. In fact, I think of all of the wells we've participated in other than operated wells, Chesapeake was the operator. So they are the main player there and they're still quite active in the play.

Carl Brown - Royce & Associates

You've used Newfield's and Forest's guidance in terms of your non-op participated capital that you'll put to work in 2010?

Chuck Stanley

We try to, Carl. Most operators don't give enough granularity to be able to specifically predict CapEx, so what we rely on in part are a pattern of AFEs coming in from other operators to get a feel for outside operated activity; but it's one of the variables in our plan. We make assumptions based on historic activity in the various plays where we are participating, but not operating. Maybe we've been conservative because, obviously, this year has been enormously slow year in a lot of these plays. But with the uptick in gas prices and in oil prices, we've seen activity increase in some of these plays, and we're trying to do the best we can to forecast it but it's not a simple exercise.

Carl Brown - Royce & Associates

A quick question on Louisiana, I think you guys talked about an eight rig program, seven doing Haynesville. Should I assume the other rig is doing horizontal Cotton Valley? Could you give us an update on horizontal Cotton Valley, I've kind of lost track as to where that stands. Depending on how the economics compare to Haynesville, what the strategy would be in terms of pace of development and timing of development for that play?

Chuck Stanley

We are very encouraged by the initial results. I think we've drilled three horizontal Cotton Valley wells. The initial rates on those wells have been in the 5 million to 10 million cubic foot a day range. The wells tend to be shallower, they're cheaper to drill and complete. They generate acceptable economics that meet our investment criteria. We will continue to allocate capital to it.

We've got a significant acreage position in the horizontal Cotton Valley play out here. It is our intention to drill some wells, most of the wells we've drilled have been on the west side of the river in the Thorn Lake area, and up in our Elm Grove area. This coming year we'll delineate the horizontal Cotton Valley in the area east of the river, the Woodardville area and in our newly acquired acreage, because we need to understand the aerial extent of the play before we go in for full development.

We may want to drill horizontal wells in the Cotton Valley and in the Haynesville from the same pad using the same infrastructure and same rig, and therefore, reduce the number of rig moves and drive down cost.

Carl Brown - Royce & Associates

So even if the economics are not superior to Haynesville you might still develop it alongside rather than waiting for it to get at the end of the line and going back?

Chuck Stanley

I think there is clearly economies of scale and economies of avoidance of repetitive motion, if you go in and develop them simultaneously. Right now, we're focused on drilling wells to preserve leasehold in the Haynesville. So you'll see us focus on that primarily next year. But we will do some delineation on the horizontal Cotton Valley.

Keep in mind, when we establish production from the Haynesville, we earn all rights from the Haynesville and shallower so there is not a pressing need to develop it from a leasehold perspective. Although, from an economic perspective, it may very well work in conjunction with Haynesville development.

The other thing I'll point out just because I think it's interesting to get a sense for the difference between a horizontal and vertical well. We've seen vertical wells in the Cotton Valley with EURs, estimated ultimate recoveries, gross recoveries of less than a 0.5 million a day vertical wells and we drill horizontal wells adjacent to them and we've seen rates as high as 9 million a day and we are forecasting three to five Bcf from those horizontal wells.

So you take a reservoir in a play, which is uneconomic at, say, $5 gas; and by drilling a horizontal well in it, increasing the deliverability and increasing the recovery from the horizontal versus the vertical development you make that play economic. We touched on that when we made the acquisition of Thorn Lake and Woodardville back in 2008 as an upside. It, frankly, probably is the right way to develop the Cotton Valley on this acreage going forward.

Carl Brown - Royce & Associates

What do you think those horizontal wells will cost?

Chuck Stanley

They're $5 million to $6 million drilled and completed.

Operator

At this time, there are no more questions. I'll turn it back over to Mr. Doleshek.

Keith Rattie

This is Keith Rattie. I'm going to go ahead and close. We want to thank everybody for listening in today. Just a quickly recap, we've talked about our growth strategy, built on our core E&P plays, the Haynesville Shale, Pinedale, Granite Wash, Woodford Shale, Bakken oil, Chuck just talked about horizontal development in the Cotton Valley, there are some other plays on our legacy acreage that look very promising that we're not ready to talk to you about.

I think the message in our call today is simply this: we have the assets and the identified opportunities to drive growth and shareholder value over the next several years and that's what we're going to get after. Thank you for listening into the Questar call today.

Operator

Thank you for your participation. Ladies and gentlemen, this does conclude today's conference call. You may now disconnect.

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