Executives
Keith O. Rattie – Chairman, President & Chief Executive Officer
Richard J. Doleshek – Executive Vice President & Chief Financial Officer
Charles B. Stanley – Executive Vice President & Chief Operating Officer
Ronald W. Jibson – Senior Vice President
Analysts
Shneur Gershuni – UBS
Joseph Allman – JPMorgan
Brian Singer – Goldman Sachs
Robert Christensen – Buckingham Research
Rebecca Followill – Tudor, Pickering, Holt & Co.
Ray Deacon – Pritchard Capital Partners
Faisal Khan – Citigroup
Joseph Magner – Tristone Capital
Questar Corporation (STR) Q2 2009 Earnings Call July 29, 2009 9:30 AM ET
Operator
Good morning. My name is Jean. And I will be your conference operator today. At this time, I would like to welcome everyone to the second quarter 2009 earnings release conference call for Questar Corporation. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions).
At this time, I’ll turn the conference over to Mr. Keith O. Rattie, the Chairman, President and CEO. Sir, you may begin your conference.
Keith O. Rattie
Good morning, everyone, and welcome to Questar Corporation’s second quarter 2009 conference call. We have a lot of ground to cover this morning. We are going to try to add some color to our earnings release yesterday. We will be commenting on our outlook for the rest of 2009 and then we will discuss our latest well results in our Haynesville Shale play followed by brief updates on our Pinedale Anticline, Anadarko Basin, Woodford Shale or Cana Shale play, the Granite Wash and the Bakken oil play.
We will be referring to five new slides that we posted under the investors tab at our website questar.com. In addition to Chuck Stanley and Ron Jibson, we are pleased to have two new members of the Questar management team here today. After my remarks, Richard Doleshek, our new CFO will make a few comments about the quarter. Also Sam Brothwell, no stranger to many of you, finds himself sitting on this side of the call as our new Vice President of Corporate Planning and Investor Relations.
So let’s cover the quarter. Natural gas prices as everyone knows are down about 75% from the peak in July 2008 and that’s clearly having an impact on our bottom line. But the hedging discipline we’ve had in place for many years in Questar E&P plus the stable cash flow we get from our other businesses have to a large extend protected 2009 cash flow.
Note that we’ve inserted a new table in our earnings release. EBITDA per reporting segment, Questar consolidated EBITDA was $805 million in the first half of 2009 that’s down just 4% from the first half of ’08 despite the steep drop in commodity prices.
Market resources alone generated $642 million EBITDA in the first half and that’s down just 5% from the year ago period. And of that Questar E&P generated $477 million of the EBITDA in the first half of ’09, down just 5% from a year ago. A story here, cash flow hedges added $309 million to Questar E&P revenues in the first half of 2009.
As we discussed in our last call at year-end 2008 and again at the end of the first quarter of 2009, Questar E&P debooked previously booked proved undeveloped reserves due to shortly lower prices. Lower reserves in the denominator combined with increased volumes from our higher cost pools in the Midcontinent to drive Questar E&Ps DD&A rate, higher invest DD&A expense was up $98 million in the first half of this year.
As of successful efforts company, Questar E&P has not taken the ceiling test write-downs that many of our full cost peers have reported in recent quarters. Instead, we carried the burden of our now higher DD&A rate until prices improve and we bring those reserves back on our books. And if there is some confusion about that please ask us in Q&A to clarify.
Questar E&P first half 2009 net income was also reduced by a $102 million from mark-to-market, non-cash charges on basis hedges, which we also discussed in our last call. Note from the table at the end of our release that we’ve reduced our exposure, the low natural gas prices in 2010 and 2011 by hedging additional production in those years. We put these hedges in place by converting basis swaps primarily in the Rockies to FAS 133 qualified cash flow hedges. This should reduce the volatility and Questar E&P reported earnings caused by mark-to-market swings in the end of the quarter value of the basis swaps.
Operations, Questar E&P grew production 13% to $90.3 billion cubic feet equivalent in the first six months of 2009, compared to a year ago. And that’s despite significant voluntary production curtailments. Voluntary curtailments hurt our growth comps, but we improved returns on capital, capital by deferring some of our unhedged production until natural gas prices improve.
Note also that, 46% of Questar E&Ps second quarter production came from the Midcontinent. And some investors still think of Questar is primarily a Rockies producer, but that’s not the case any more. In 2009, we are allocating 40% of Questar E&Ps $860 million CapEx budget to our higher margin Haynesville Shale play and that’s about the same as we are allocating to our Pinedale Anticline play in the Rockies.
Haynesville and Pinedale are of course two of the most economic natural gas plays in the U.S., and we are allocating much of the remaining 20% of Questar E&Ps budget to our promising Woodford Shale play in Western Oklahoma. As I will discuss in a moment, we are going to put a rig back to work in our Bakken oil play. All of these plays earned risk returns, well above our cost-to-capital on the current forward curve. We are also evaluating horizontal drilling in the Granite Wash formation in the Texas Panhandle, where Questar E&P has significant acreage, a little more on that in a moment.
Now, when natural gas prices were higher, investors tended to focus solely on Questar E&P and overlook the contribution from our other businesses. But in a year like 2009, the contribution we get from the rest of Questar becomes a source of competitive advantage.
The net income and cash flows from these businesses are relatively insensitive to commodity prices and combine the rest of Questar is on track to generate about $225 million of net income and nearly $700 million in EBITDA in 2009. Of course supporting our investment grade, credit ratings, bolstering liquidity and thus enhancing our ability to fund growth in our E&P core.
Yesterday, if you saw the release, we have raised the lower end of our 2009 EPS guidance and affirmed our previous production guidance. Note that we now expect Questar 2009 net income to range from $2.35 to $2.45 per diluted share. That’s up from $2.30 on the low end to $2.45 per diluted share as sighted in our last call.
As a reminder, when we give the EPS guidance, we exclude mark-to-market gains and losses on basis hedges and gains and losses on asset sales. We expect Questar E&P 2009 production to range from 180 billion to 186 billion cubic feet equivalent and that’s unchanged from our prior guidance up 5% to 9% from 2008. And again this is despite voluntary curtailments and our decision to defer some well completions due to weak near-term prices and you may want to ask Chuck about that when we get to Q&A. We put a table in the earnings release that summarizes other key assumptions in our guidance.
Let me turn now to operations starting in the Midcontinent with the Haynesville Shale. Note that we currently have six Questar operated rigs in Northwest Louisiana, four currently drilling Haynesville wells, one drilling a horizontal Cotton Valley well and one drilling a vertical Cotton Valley Hosston well.
Year-to-date 2009, we now have a working interest in 12 new Haynesville Shale producing wells, seven of which are Questar operated, five non-operating. We expect to drill or participate in 35 Haynesville Shale horizontal wells in 2009.
Please note that we’ve drilled and turned four Questar E&P operated Haynesville wells to sale since our last call. The new completions are shown on slide three with red outlines around the call out boxes. Please note that our latest Questar operated well are 88% working interest Sustainable Forest 29H well may be the strongest yet. We turned it to sales about three weeks ago at an initial 24-hour average rate of 25 million cubic feet per day. And please note that the rates that we are reporting are actual sales rates not calculated rates as some operators have reported. Also note that we drilled and completed this well at a cost of just over $9 million.
To the west on our Thorn Lake acreage, we turned our 93% working interest Rex Young well to sales in June at an initial 24-hour average rate of over 25 million cubic feet a day. Both of these 24-hour rates were through 28/64-inch chokes with flowing pressures over 7500 pounds. These two wells you will note are among the strongest wells both drilled by any operator in the play to date, further confirming that our acreage is in the sweet spot of the Haynesville play. Please not that due to current low prices, we have choked each of these wells back to rates of around 10 million cubic feet per day after initial flow back and recovery of some of the frac fluid.
The other two Questar operated Haynesville wells, the Hutchinson and Harper wells shown on the slides are also very strong wells both are flowing to sales, but we have a string of coil tubing stuck in the Harper well which we will fish out later after the pressure declines. And on the Hutchinson well, we’ve experimented with a new frac design and that’s negatively affected the initial rate.
Our Haynesville team is working to add to our already strong acreage position in the core of the play. Please note that we’ve recently entered into a multi well farm in option agreement in the acreage shown in blue on slides 2 and 3. In lieu of upfront cash, Questar E&P has the continuing option to drill to earn approximately 3000 net acres. We’re currently drilling ahead on the first earning well. I should note that we are also working other deals to add to our Haynesville acreage position.
Now we get questions from investors about pipeline takeaway capacity out of the Haynesville area. So let me give you an update on that. Questar E&P currently holds about 65 million cubic feet a day of firm capacity with over 300 million cubic feet a day of additional firm capacity under contract to begin deliveries in several tranches beginning in 2010.
We are also investing in new gathering and treating infrastructure to move gas from the wells to the interstate pipes, where we hold the firm capacity. And moving to the Western Midcontinent, as was the case in the first quarter, we’re operating one rig in the promising Anadarko Woodford Cana Shale play. We currently have a working interest in 35 producing wells; four of those are Questar operated. And well performance thus far has been consistent with the EUR assumptions summarized on the slide four.
Now as those who follow our story know, until the downturn we were allocating capital to a multi-rig drilling program, drilling vertical wells in our Granite Wash/Atoka play in the Texas Panhandle. Given the recent success reported by other operators, we are now evaluating horizontal drilling on our 23,000 net acres. And Chuck can give you more color on that, when we get to Q&A.
Now let’s move to Pinedale, we now have five rigs operating at Pinedale that’s too lees than our last call, and four less than a year ago. Recall that when we came out of the winner this year, we came out with 56 wells drilled and cased. We’ve now completed and turned 50 of these wells to sales.
Our Pinedale team continues to drive hard on productivity improvement in 2009 to date we’ve averaged about $5.2 million to drill complete and connect new wells at Pinedale that’s down over 17% from a peak of $6.3 million in 2008 and we expect it to continue to decline. We’ve averaged 23 days from spud to total depth in 2009, and we’ve drilled 100% of our 2009 wells in less than 30 days. In 2009 we’ve drilled one out of every five wells from spud to TD in less than 20 days.
And please keep in mind that Questar operates on the Northern flange of the Anticline, so our wells are roughly 1000 feet deeper than wells drilled by other Pinedale operators to the south. At the pace that we are on even with five Questar operated rigs, we expect to drill and case about 100 wells in 2009, but please note however that due to current market conditions, we have decided to defer completions on about 20 of these wells.
Let me give you a quick update on our Bakken oil play in the Williston Basin North Dakota. Recall that we drilled and turned our first Questar E&P operated Bakken oil well to sales in January at an initial rate of 960 barrels of oil equivalent per day.
Overall, Questar E&P now has a working interest in 23 wells on our 80,000 net acres in the Bakken play. The good news, the Bakken play appears to be converging on our core acres block on the Fort Berthold Indian Reservation. Other operators have reported initial rates as high as 1700 barrels of oil equivalent per day on wells drilled near our core block, shown in yellow on slide five.
By the end of this month, we expect to have three new well permits in the hand with several more in progress and the locations on these are indicated with a blue diamond on the slide. Therefore we plan to spud our second Questar operated well in August and we hope to keep the rig drilling through the rest of this year and on into 2010. Based on the well cost and EUR assumptions summarized on the slide, our plant Bakken oil wells generate solid returns at current oil prices.
I’m going to quickly run through our other businesses. Wexpro our second E&P Company has grown its investment base 19% over the last 12 months to $411 million at the end of the second quarter. We forecast that Wexpro will end the year with an investment base of about $440 million that’s unchanged from our last call. A reminder under the now 28-year-old Wexpro agreement, Wexpro earns a 19% to 20% after-tax unlevered return on that net investment base.
Gas Management, our Rockies midstream business reported a 36% decline in net income in the first half of 2009 compared to the same period a year ago. That’s due primarily to lower processing margin and higher depreciation expense. Second quarter gathering margins for our midstream company were about flat with a year ago.
Ethane and propane prices in these processing margins have improved in the last three months, but remained well below the record levels we saw in the second and third quarter of 2008. I should note this morning that our midstream team has secured a long-term contract with a major producer to build a 150 million cubic foot per day, deep cut cryogenic processing plant adjacent to our existing Stagecoach plant in the Uintah Basin. We expect to put this new plant in service in late 2010.
Turning quickly to our regulated businesses Questar pipeline remains on track with two important expansion projects on our Overthrust Pipeline system. This year, we’re installing 32,000 horsepower of new and compression to increase firm capacity on Overthrust from Opal to Wamsutter, Wyoming, by 300 million cubic feet a day. Next year, we will construct a 42-mile, 36-inch bidirectional loop of Overthrust to deliver gas into El Paso’s Ruby pipeline. Both of these projects are underwritten by long-term contracts.
Finally, our utility Questar gas is on track to earn its allowed return in 2009. Our utilities closing in on 900,000 homes and businesses served and it’s also doing its part to demonstrate that lower carbon American produced natural gas as a clean low cost alternative to gasoline refine from foreign oil in America’s cars and trucks.
With gasoline prices trending backup towards $3 per gallon CNG demand is once again surging and to meet this demand. We’re expanding several of our 19 CNG filling stations in Utah.
Now before we go to Q&A, I’m pleased to invite Richard Doleshek, our CFO to make a few comments.
Richard J. Doleshek
Great. Thank you, Keith. First of all, I would like to say how delighted I am to be at Questar. This is a great company with wonderful assets and people and really it’s a terrific opportunity for me. As Keith mentioned, given the dramatic fall and commodity prices over the last 12 months, the company’s results for the second quarter and first half of the year are pretty impressive. EBITD as we define it was $370 million for the quarter, $805 million for the first six months, down only 11% and 4% respectively from the record levels in the previous year’s corresponding periods.
Factors driving the six months EBITD figure where a 13% increase in production compared to last year. A 63% decline in field level prices that were offset by $309 million of revenues from our hedges and that’s about $3.42 per Mcfe and 11% decline in combined operating maintenance production tax expense.
Our reported capital spending for the first half of the year was $703 million compared with full year current CapEx number of $1.3 billion. When you take into consideration of $139 million of carry over from 2008, our capital spending is on track for the year.
In terms of liquidity at the corporate level, we renewed $275 million of the CP back-up lines that matured on 630 and added an additional $15 million commitment. So on July 1, our committed lines to the corporate level were $405 million. I think the commercial banking sector has gotten healthier through 2009. And we really appreciate the support of our existing and new banks.
At the end of the quarter, there were no outstandings under those CP back-up lines and we had $36 million of commercial paper issued at an average rate of less than a 0.5% interest. On the Q&R level at June 30, we had $500 million outstanding under the $800 million revolver on July 15, we paid down $25 million of that revolver. And so during the second quarter, there was virtually no change in our indebtedness reflecting us living us inside the internal cash flow for the period.
In summary, from an EBITD perspective the quarter, the first six months were pretty good from an net income perspective inside from lower commodity prices a non-cash charges primarily increased DD&A in the mark-to-market losses on the non-133 hedges drove our quarter and six months numbers down from a year ago. Our balance sheet remains strong. Our aggregate liquidity from committed lines is approximately $700 million, and projected cash flows supported by robust hedging program for the rest of the year support our capital spending program for the rest of the year.
With that I will turn it back to Keith for closing comments.
Keith O. Rattie
Okay great. Thanks Richard. Let me just summarize, we all know these are tough times for the natural gas industry and obviously for Questar. But we continue to weather the storm. Questar E&P earnings are down significantly from the boom times of 2008, but as Richard has just summarized cash flow and thus our balance sheet remain strong. We are on track to grow production 5% to 9% this year despite sharp cuts in capital spending and despite significant voluntary curtailments.
As I summarize, we are allocating most of our E&P capital to two of the most economic plays in the country, the Haynesville shale and Pinedale Anticline, and we hope to confirm with the drill bit that we’re also in the heart of the Bakken oil play in the Williston Basin. We’re satisfied with our results to date in the Cana shale play, and we’re evaluating horizontal drilling on our Granite Wash acreage in the Texas Panhandle. No one knows when the U.S. natural gas markets going to turn up, but it will. And when it does, we intend to capitalize on this company’s high quality assets both physical and human.
And with that operator, please open up the lines for questions.
Question-and-Answer Session
Operator
(Operator Instructions). Our first question comes from Shneur Gershuni from UBS. Go ahead please.
Shneur Gershuni – UBS
Hi, good morning guys.
Keith O. Rattie
Good morning, Shneur.
Shneur Gershuni – UBS
A lot of great info in the prepared remarks. Just want to kind of touch off on a couple things. I was wondering if you can kind of talk about cash flow versus CapEx with respect to 2010. If you feel comfortable with the amount of capacity you have on your credit lines available to keep up this type of a drilling pace, if gas prices remain sub six bucks into 2010?
Keith O. Rattie
That’s a great question, Shneur. The answer is we don’t have a firm budget yet set for 2010, but we, as you will note have hedged a significant amount of our production next year. And we are looking at a level of capital spending next year that shouldn’t be too far from the level that we’ve had this year. I will invite either Chuck or Richard to add to that if they want to.
Charles B. Stanley
I think based on what we are seeing in terms of commodity prices our hedge portfolio. We expect a slightly down capital budget, we haven’t put all that planning stuff together yet.
Richard J. Doleshek
Our cash flow will be down modestly at a nominal $6 NYMEX price next year from this year, but not a lot.
Shneur Gershuni – UBS
Okay. You mentioned actually the hedges for next year, it seems that you move the basis swaps up into fixed price swaps and so forth. Can you give us a sense as to where you kind of hedged next years production throughout the quarter, was it around the $5.80 to $6 level when you added everything together or?
Keith O. Rattie
That’s pretty close Shneur. The NYMEX was $5.80 to $6.
Shneur Gershuni – UBS
Right.
Keith O. Rattie
And the reported numbers that show up in the table at the end of our earnings release, Shneur are obviously reflect not only the basis hedges, but also gathering and processing the quality adjustments. So embedded in those numbers was a conversion around $6 of MMBTU.
Shneur Gershuni – UBS
Okay, great. And just one last question, you’ve provided a lot of great information with respect to the Haynesville flow rates and so forth and what not. It seems that do you feel that you are becoming increasingly more comfortable with it being an economic play. Do you have any plans to update kind of your 2P and 3P reserve numbers to further incorporate all the new information that have available?
Charles B. Stanley
Shneur, this is Chuck again. It’s a great question. Right now, we’re waiting to see the final rules come out of the SEC, because as you know, there are likely to be significant changes at year end with respect to reporting of non-proved reserves, as well as new rules with respect to reporting of proved reserves, especially in unconventional reservoirs like the Haynesville. So rather than doing interim update using the old rules, which by the way is a lot of work. We would prefer to wait until we see the final rules report reserves and both proved reserves and non-proved reserves using the new final rules after they are promulgated. And I don’t know when the final rules are going to come out from the FASB. It could be in the fourth quarter.
Shneur Gershuni – UBS
Hey great. Thank you very much.
Keith O. Rattie
Thanks, Shneur.
Operator
Our next question is from Joe Allman from JPMorgan. Go ahead, please.
Joseph Allman – JPMorgan
Thank you. And good morning everybody.
Keith O. Rattie
Good morning, Joe.
Joseph Allman – JPMorgan
Keith, could you talk about the E&P production curtailments and do you have incremental curtailments to what you spoke about three months ago?
Charles B. Stanley
Joe, it’s Chuck. There seems to be quite bit of consternation or concern about our sequential decline quarter-over-quarter. And I for one have been a reluctant disclosure of the details of what we have curtailed. First of all, because it’s an estimate. It dependent on when we could have completed the wells and turn them to sales, there are deferrals and completions that are going on our places like Pinedale as Keith mentioned. And then we have production that is pinched back or not flowing at maximum rates. At Pinedale and also as Keith mentioned in the Haynesville and in other areas around the company. I will give you some general directional information that may help you, put your head around this, because it’s important to understand since we report volume weighted LOE and volume weighted DD&A and each one of these components is impacted by the production that we actually sell in each of these different areas and cost pools.
If we had, just looking at our first quarter to second quarter production decline, had we not deferred completions and if we had produced the wells at normal rates, we should have seen or would have seen a 2% to 3% increase quarter-over-quarter in production. Okay. So that gives you some sense of I think people were calculating a 6.5% or 7% quarter-over-quarter sequential decline and production from the first quarter to second quarter. And expressing some concern about that in the flash notes that came out last night. So that gives you a sense for the impact of our deliberate management of volumes in order to basically defer production into higher price environments.
We are looking at nearly a doubling of price next year into the extent that we hedge those volumes and bring them on next year in a higher price environment we double our cash flow from the volume. So there is some of that going on, but importantly in addition to the curtailments, because we’ve deliberately slowed down production in low cost pools like Pinedale. We have negatively impacted our reported LOE. If you think about it, Pinedale is the ultimate in low cost production on a cash basis and by slowing down completions and differ and doing some actual curtailments of production.
We’ve negatively impacted our weighted average LOE. We’ve also done that in some of our other lower cost areas. But again if we were managing just those metrics, what we would do is, we would actually shut in all of our Haynesville production, maximize production from Pinedale, but in the case of doing so make our reported metrics look better on a unit of production basis, but actually generate far less cash flow than we’re producing today with the production mix that we have in a curtailments that we are doing.
On an incremental basis going forward, you tell me what third quarter prices are going to be. And I will tell you how much gas we are going to curtail third and fourth quarter prices. But I think that given our sort of pessimistic view with the shoulder months going into the heating season, I could see us continue to maintain the current curtailments and maybe even pinch back a little more on some of air producing pools.
Keith O. Rattie
But, let me just to be clear that we intend to be bring production into the goal posts of the guidance this year.
Joseph Allman – JPMorgan
Okay, that’s helpful. And then so the bulk of the curtailments that you mentioned the Pinedale Anticline, any other area that was exposed to the curtailments more than other places?
Charles B. Stanley
Well, we are deliberately curtailing sales in the Haynesville these wells are capable of substantially more than 10 million a day, and so by flowing them back to cleaning them up and immediately pinching them back to about 10 million a day, we are negatively impacting Haynesville volumes. We’ve got, I think I talked about it on the last call. We have multiple options, we can delay completions, which we are doing. Well, first of all, we cannot drill wells and we are doing that in the higher cost pools. We can drill wells and not complete them and we are doing that at Pinedale. We are doing that in the shallow gas reservoirs in the Northwest Louisiana, i.e., in the Cotton Valley/Hosston reservoirs, because we had a rig commitment there and the rig is not capable of drilling deep Haynesville wells. We are continuing to drill and case shallow Cotton Valley/Hosston wells, but we are not turning them into the sales right now.
We also have the option and as Keith mentioned in his prepared remarks, drilling and casing but not completing at least 20 wells at Pinedale this year. So there is that component of deferral of production and then the final component is deliberately pinching back on producing rates. We are doing that in wells after flow back and cleanup in the Haynesville. We have a substantial amount of gas curtailed at Pinedale and also in our Legacy division in the Rockies. So there are components of each of those that are impacting our production volumes today and they will continue to do so in the third and fourth quarter.
Joseph Allman – JPMorgan
That’s very helpful. And then it’s interesting to see the basis differentials across the country narrow here. Any comments on that and I would also to love to hear comment on your kind of your storage situation in the Rockies?
Charles B. Stanley
Basis as you point out Joe, for the remainder of the calendar year 2009, in the Rockies is down to $0.72. I think it was north of three bucks a year ago, a dramatic change. Obviously the key impact here is the continued move eastward of the Rockies Express pipeline. REX is now making deliveries into the Western Ohio markets at Lebanon and is on track to be in service from what we understand from the operators by the end of this year. So REX is having the impact that we all expected.
The other factor, of course is that, the rig count in the Rockies is down by two-thirds compared to where it was last September. So the historic growth rates that we were seeing out of the Rockies in close to high-single digit type year-on-year growth rates in production that has come to an end. And Rockies production has been flat to slightly downward trending over the last several months. So that’s taken the pressure off the pipes out of the Rockies and market is expecting with Rockies volumes hitting the northeast with growing volumes out of the Marcellus with Haynesville volumes growing and putting potentially pressure on Perryville and Henry Hub that we may see a flattening relationship between the Opal and NYMEX for the next several years, and that was a consideration in our decision to take our lumps and get rid of a substantial portion of the Rockies basis hedges. As far as storage is concerned, Clay Basin is at…
Keith O. Rattie
Slightly under 80%…
Charles B. Stanley
Just under 80% full today and that’s well above historic norms for this time of year and we obviously will anticipate that when Clay Basin is full, of course, Questar pipeline owns and operates Clay Basin. And when Clay Basin is full you are going to see gas on gas competition impact near month prices probably in September.
Joseph Allman – JPMorgan
Just lastly, and then I will get back in the queue. So Clay Basin at this time of the year would typically be how much full?
Ronald W. Jibson
We are running about average.
Keith O. Rattie
Well, it’s a little bit less than this. The pace of storage refill has slowed down a lot in the lost few weeks. Questar gas is the primary entity that still has some capacity to use under its firm storage contracts, our utility.
Joseph Allman – JPMorgan
And typically it gets full November 1. Is that right or?
Keith O. Rattie
It gets typically full sometime around October.
Ronald W. Jibson
Mid October.
Keith O. Rattie
Late October, early November.
Joseph Allman – JPMorgan
Okay. But you would expect it to be full when at this point?
Ronald W. Jibson
On average. I mean, we are actually tracking very close to similar.
Keith O. Rattie
Speak up Ron.
Ronald W. Jibson
This is Ron. Joe, we are actually running very close to what we would on a typical year. We’ve been able to manage that throughout the year and although storage is ahead of pace in most of the country, we’re running pretty much with where we typically would be at this time. So we would anticipate again late fall being full.
Joseph Allman – JPMorgan
Okay.
Keith O. Rattie
That’s the correction of what I told earlier.
Joseph Allman – JPMorgan
Okay. So it’s okay. So nothing out of the ordinary at this point?
Keith O. Rattie
In the Rockies.
Ronald W. Jibson
Not in the Rockies.
Joseph Allman – JPMorgan
Okay.
Keith O. Rattie
It had been until a few weeks ago.
Joseph Allman – JPMorgan
Okay. All right. That’s very helpful. Thank you.
Operator
Our next question is from Brian Singer from Goldman Sachs. Go ahead please.
Brian Singer – Goldman Sachs
Thanks. Good morning.
Keith O. Rattie
Hi, Brain.
Brian Singer – Goldman Sachs
I want to see if you could provide a little more color on how you are thinking about the granite wash as you evaluate whether or not to go horizontally and your expectations for potential results versus some of the other wells that we’ve seen.
Charles B. Stanley
Brian, Chuck, great question. We have acreage in and around the recently reported high rate wells that were reported last week by another operator. We have the same geology and in particular the Atoka Sands appear to be the most perspective for drilling horizontal wells. Having seen the results of the new fill wells that are reported as well as our own experience in the Cotton Valley over in Northwest Louisiana. We are encouraged by the prospectivity. We will likely commence a horizontal drilling program to evaluate some of our acreage later on this year. We are in the process of choosing optimum locations and getting permits on those locations doing the title work before we go out and commence testing our play. But it’s in the right zip code.
Brian Singer – Goldman Sachs
Great. That’s helpful. And then you highlighted or you mentioned in your earlier remarks on one of the Haynesville wells, you tried a new frac technique that led to a lower production rate. And I guess I was wondering does that mean whatever you tried isn't working or still waiting on it? What is it that you tried?
Charles B. Stanley
We pumped smaller individual frac jobs and put away a smaller total volume of profit, individual stages. And the general view that we’ve developed and I think you seen it in the last three wells the Sustainable Forest, the Harpar well, which is curtailed for another problem unrelated to the frac design. And the Rex Young well, all three of those wells have potential rates in the 25 plus million a day range. In fact, they’ve touched 30 million a day, and basically the 25 million a day rate is sort of the maximum that we can produce these wells at through our existing high pressure flow back equipment. Anything more than 25 million a day and we start having just basic plumping problems at the surface and we are not convinced it’s worth dragging out and entirely at a second set of flow back equipment just to report a higher rate.
Although we could do that. It might be interesting to do on one well just to see what we can report. But anyway, the key relationship that we are starting to observe is more frac stages better. More sand or more profit better. So that the more property you put in the ground and the more stages you put in the ground, the better the initial rate and time will tell how it will impact long-term production performance. So we are trying to find a sweet spot as we have done at Pinedale between the amount of sand, the number of stages an ultimate well EUR. And we are moving toward more as better.
Brian Singer – Goldman Sachs
Thanks. And I can just ask one follow-up. I don't know whether you have any of your Haynesville wells drilled earlier in the year that’s not being choked back, I was wondering if you have any commentary on decline rates you are seeing versus the type curves that are out there of call it an 80% or so first data decline?
Charles B. Stanley
I think directionally that initial decline rate is probably about right. The longest lived horizontal production from the Haynesville is a little over year old now. So that the first year decline seems to match that in 70% to 80% initial decline rate. The real question is what’s the terminal decline rate? Whether it’s 4% or 6% or 8%. We are still looking at EURs based on the initial well performance from the wells that we have drilled and wells we participated in the area of six to eight bcfe. And that's probably conservative, but I think you have seen from our previous performance and our previous view on booking reserves we tend to error on the side of being conservative and then add reserves as performance dictates.
Brian Singer – Goldman Sachs
Thank you.
Operator
Our next question comes from Carl Kirst from BMO Capital. Go ahead, please.
Carl Kirst – BMO Capital
Hey, good morning everybody. And Chuck, appreciate all your color on everything. Most of my questions actually have been asked. One thing, perhaps on the cost and just noticing, Chuck, on an aggregate basis, we had G&A sort of creep up a little bit this quarter sequentially to first quarter exploration expense was up. I know there can be timing issues and the like, but my understanding is, is that in the guidance that you guys give, there really isn't any assumption of the deflationary oil service environment. And I was wondering if perhaps you could give any color on what you are currently seeing on the ground with respect to those costs. If we wanted to assume second quarter for instance, is the new benchmark given this little bit of lower production?
Charles B. Stanley
Okay, Carl. Couple of questions. One on cash costs, G&A and other components, keep in mind their volume weighted average G&A cost to the extent that we have deliberately reduced or curtailed production or delayed production against a relatively constant fixed cost. Our G&A rates on a unit basis are going to be higher. So some of that is we are distorting the reported metrics and you are seeing flat or increasing numbers as a result of deliberate deferral of production volumes. On the well cost data and on the DD&A rate, let me just see if I can help think through this because it’s created a quite a bit of confusion. Yes, well costs are coming down. But the real driver that the biggest variable that impacts our DD&A rate is whether or not reserves come on and off of the books. So to the extent that we have price related reserve provisions like we had at the end of the first quarter and the Northwest Louisiana pool as a good example.
We saw a big chunk of reserves that we had booked at the time we made the acquisition come off the books as a result of almost 50% decline in prices. As a result, we saw a near doubling of the DD&A rate. So as reported on a volume weighted average with growing production from Northwest Louisiana and a DD&A rate that has nearly doubled as a result of price related reserve provisions, even significant 10%, 15% and 20% reductions in individual well costs don't move the needle as much as rebooking those reserves we lost at the end of the first quarter. So in our guidance assumption, I think you’ve heard sort of a view that we think that prices were continue to be soft in the third quarter and probably end of the fourth quarter of 2009.
As a result, we are not optimistic that we are going to see a big chunk of those reserves jump back on the books. That being said, our DD&A rate will continue to remain quite high and may even go up some if we lose more reserves in the third quarter, which I think is possible given softness in commodity prices and sort of the broad macro environment with respect to national storage levels. So there are real cost savings. Keith mentioned what's going on at Pinedale.
We’ve seen our Haynesville well cost start to come down and I'm optimistic our team will continue to drive those costs down, but the DD&A rate reflects the full pool of reserves and the full costs associated with those reserves. And the only thing that changes that. There is two things to change that. One, putting those reserves back on the books. And two, if we see severe enough price depression and we can take an impairment and basically write-off a big chunk of the investment, which most full [costers] have already done, then we’d see that DD&A rate reset as a result.
Richard J. Doleshek
Carl, this is Richard. If I could give you a little bit color on the G&A on a quarter-to-quarter basis. Some of that G&A increase you are seeing on an absolute dollar basis is driven by share-based compensation. And so when you look at the stock price at the end of the quarter when that goes up, we’re going to report, higher G&A even though it’s a non-cash. Also we took a $750,000 charge in the second quarter for what we believe is our share of some remediation expense at the gas company. So a couple of things that are kind of moving around in the quarter make the G&A number look like it’s kind of growing. But it’s some of that’s non-cash and some is just one-time related stuff.
And just to followup on Chuck’s point. If you look at our historical impairment, really in the commodity price environment that we have been in the last nine months, you haven’t seen a lots of impairment coming out of Questar’s E&P business and so Chuck’s point about the full cost guys taking the ceiling test write-downs we haven’t had that, still to the success that we think we are going to recover all of our investment based on the commodity price environment we are in today. And so I think actually not having a large impairment at the expense of having a high DD&A rates is actually a good thing.
Carl Kirst – BMO Capital
And I appreciate all that color, I know the DD&A can be confusing; I should have prefaced it with just sort of specifically looking at cash costs. I think I’m all clear on what’s going on with the depreciation component. Mainly just kind of making sure that with the creep up we saw on the G&A in the second quarter that for instance if we just look at LOE, unit LOE and unit G&A for the second half of the year relative to what you might call second quarter as the new benchmark with the current production volumes that presumably with the deflationary environment we are seeing in the oil service. I would think worst case scenario those costs are going to be flat possibly perhaps getting better. I mean is that still a fair review?
Keith O. Rattie
I am looking at Richard. We will both answer the questions I’ll try first. Keep in mind G&A is basically our overhead costs our salaries and wages, insurance, et cetera, et cetera so. It is relatively fixed and as Richard pointed out you get all these weird timing issues that come and go depending on timing of booking stock based compensation et cetera, et cetera. So not really impacted by declining oil service costs, it’s a pretty fixed cost and to the extent that our volumes are down or being deliberately curtailed. G&A on a unit basis will stay flat or go up. Normally we are for instance in Northwest Louisiana, we got volumes that are coming up, we are adding headcount there, and we are not producing that maximum rates deliberately. So we’re distorting that headcount increase by not amortizing that additional cost over the full unconstrained production volume.
Richard J. Doleshek
And Carl, I will give you a little more color. Questar with flowing gas flows has a pretty low cash LOE component. We don’t move a lot of fluids in the Rockies. As we move more, more production in the Midcontinent. You are going to see us creep toward a more traditional multi-basin cost producer. The biggest component of our cost as Chuck mentioned is labor, we are not laying people off we are actually adding people and we are moving more fluids to Haynesville so on a per unit basis I don’t think it’s flat to last year even though you think oil field service cost are coming down. We’re not laying people off, we are having more production that’s coming on that’s generally at a higher cost in our traditional stuff. So that’s just some color for you.
Carl Kirst – BMO Capital
I appreciate that very much. And then just one final question very small one. I believed Keith mentioned the midstream opportunity next year the deep cut $150 million a day. Is there investment dollar you could share for that?
Charles B. Stanley
Carl this is Chuck. I’d rather not give you an exact investment dollar on it for competitive reasons.
Richard J. Doleshek
It’s in the capital is included, this years capital is included in the $134 million allocated to Questar gas management for 2009.
Carl Kirst – BMO Capital
Great. Thanks for the clarification.
Operator
Our next question comes from Robert Christensen from Buckingham Research. Go ahead please.
Robert Christensen – Buckingham Research
Good morning. Of the $860 million I think you cited for 2009 CapEx. How much would be for rig commitments? How much would be for holding of leases or earning of leases. I’m trying to get at a number that you might reduce the capital budget by where those obligations not there?
Charles B. Stanley
Rob its Chuck. I don’t have an exact number. I can tell you that we have very few long-term rig commitments. And so in our total rig count, we probably only have, I’m trying to think on the fly here three or four three rigs that go past 12 months. And they’ve got staggered contract expiries. So that is one component that drives such whatever called non-discretionary drilling capital, so that’s a relatively small component. The next component all of the activity that we have a Pinedale is not the lease driven there. There are no expiries at Pinedale that’s all held by production. We have very limited lease expiries in the Bakken play in North Dakota that we will be addressing when we pick up a rig as Keith mentioned later on this quarter to drill wells in the Bakken.
So that leaves Northwest Louisiana really as the primary area where we are addressing lease expiries in the Haynesville in particular and we’re also performing under the farm out that we mentioned in the prepared remarks. But to that end, it’s not that many wells, maybe 10 wells or so that we have to drill in the Haynesville in order to maintain all of our leasehold and preform under the farm out. So I can’t give you an absolute number, but I would think that we could reduce by more than half. I’d say half to three quarters of our CapEx is fully discretionary in that we could shut it down and not incur either loss of leasehold or penalties under drilling contracts.
Robert Christensen – Buckingham Research
I can follow that. Great, thanks. The next question, if I might would be related to the DD&A rate, and I guess the successful efforts of treatment of reserves. You guys to my recollection have never revealed how many reserves where deducted from the books because of prices? Am I right?
Charles B. Stanley
I think we actually gave those numbers in the first quarter call.
Robert Christensen – Buckingham Research
Okay. My bad hard luck for that?
Charles B. Stanley
And we may not have given area-by-area adjustment. But we did give you a sense for the total quantum that was taken off at the end of the first quarter.
Robert Christensen – Buckingham Research
One macro call bit industry picture maybe Keith, here we sit with the CFTC attacking speculators and potentially putting some limits on these index contracts. Should more regulation come and less liquidity come with this industry, the E&P industry have less ability to hedge in the future and with the detriment of less drilling and more volatility coming in actual prices? I mean is this floating around the executive ranks of E&P industry worries about the inability to hedge? Or worse, this Wall Street Journal opinion page today that we end up traveling down the path of regulating prices again The Natural Gas Policy Act of 1978 revisited.
Keith O. Rattie
Let’s hope we don’t revisit that nightmare. Yes we are concerned about this. I’m going to wait and see what the actual reports says, but I find it hard to believe that so-called speculators had the kind of impact that The Wall Street Journal front page article apparently understood from some unidentified source. We will as an industry the market always response to this type of regulation, I could see some of the trading activity would be shifted to potentially overseas exchanges. We may see different types of commercial arrangements for Questar. You might see us discontinue the practice of hedging into, doing fixed price swaps into the regional pipeline, where we actually deliver the gas. It might impact, for example, whether we continue to structure most of our hedges as cash flow hedges under FAS 133. We may end up going into more fixed sales contracts, which will undermine the attempts to make price discovery more transparent. This is wrong-headed thinking on the part of the CFTC. I’m interested in seeing the full report before we comment much further on how it might impact our business.
Robert Christensen – Buckingham Research
Just FYI, the opinion piece in the Wall Street Journal, today, the Politics of Speculation is a great read. Thanks, guys.
Keith O. Rattie
Thanks, Bob.
Operator
Our next question is from Becca Followill from Tudor Pickering.
Rebecca Followill – Tudor, Pickering, Holt & Co.
Hey, guys. Couple more questions for you. Have you taken a look what ’09 production would have been without the curtailments and shut-ins and delayed completions?
Keith O. Rattie
Yes, we have.
Charles B. Stanley
Becca, I think, answer to your previous question, I talked about sequentially quarter-over-quarter, our production would have been up 2% to 3%. So, you can kind of back into a number. I think…
Rebecca Followill – Tudor, Pickering, Holt & Co.
Okay, I was just trying to…
Charles B. Stanley
Our overall volumes would have been potentially as much as 6% higher.
Rebecca Followill – Tudor, Pickering, Holt & Co.
Okay, great.
Charles B. Stanley
For the fist half of the year.
Rebecca Followill – Tudor, Pickering, Holt & Co.
Thanks. And then on hedging, it seems like an awful high percent hedged, if I just assume production is flat in 2010, which I doubt that it will be, it would imply 87% of production hedged, which seems much higher than your normal policy. So can you tell us your thoughts around that, why such a big chunk hedged and does that imply much greater productions for 2010?
Keith O. Rattie
Think about the answer to my previous question. We have a lot of volumes that we can literally turn on tomorrow and as a result we feel normally, when we are at this point in the hedging cycle we would be looking at high 60s, mid 70s as the maximum percentage. But a lot of that is driven by concerns over operational risk and to the extent that we have a larger percent of our volumes basically PDP and salable tomorrow our comfort in increasing our hedge percentages goes up. Also we are protecting against a follow through into 2010 of the negative trend that we’ve seen in gas prices over the last 12 months or so.
Richard J. Doleshek
Just a couple of other things, we have not changed our basic policy Becca, which is to hedge up to 100% of production from proved developed reserves. The other thing that we have done in converting the basis swaps is to protect our development program in Pinedale. We are looking at, and this could obviously change, but we are looking right now at 2010 our only likely activity on the gas side will be a continued development of Pinedale at roughly the current pace that we are on. And Pinedale being the lowest cost play in the Rockies can earn acceptable returns on the realized prices that we effectively locked in with the conversion of those swaps.
Rebecca Followill – Tudor, Pickering, Holt & Co.
Thanks. And then the last question is on Haynesville well cost at $9 million a well. Where does that put you as far as reduction from the last few wells and where do you think you are headed on well cost?
Keith O. Rattie
The early wells were over $10 million Becca. And they were that the increase or the higher costs were related to longer times to drill and higher frac costs. We are seeing improved drilling efficiency. The days of drilling are coming down. We’re getting better picking the right bits. We’re getting better efficiency out of the rigs. We are having a less trouble from failure of measurement while drilling tools et cetera. The other thing is we are getting much better tracking on the last well that we just turned to sales is sustainable forest well. We averaged four frac stages per day. And that included a little bit of trouble time in those four, the average of four frac stages per day and we pump 16 frac stages on that well. So we’re getting better and better.
We are getting the right people from our shop focused on the key issues that are driving costs. We are getting the right service company assets on the ground and all of those things are starting to come together. Where can we go on costs? It’s hard to say. I think there is still lot of room for improvement on the drilling side. And I think we also have some opportunities to increase efficiency on the completion side. Can we get to $8 million if I say $8 million that’s probably too high? I should probably put the bar at $6 million and see how close we can get to it. But I mean at this point, we drilled just a handful of wells when you think about it in terms of efficiency gains. I am pleased with the progress that we are making. And you think about the number of wells it took us to get the where we are today at Pinedale. We’re seeing a much deeper improvement a much little more rapid improvement in the learning curves than we had at Pinedale.
Rebecca Followill – Tudor, Pickering, Holt & Co.
Great, thank you.
Keith O. Rattie
Thanks, Becca.
Operator
Our next question from Ray Deacon from Pritchard Capital. Go ahead, please.
Ray Deacon – Pritchard Capital Partners
Hey, just a quick question. Chuck, the 31,000 net acres in the Haynesville that looks like the same as last quarter and so with the earn in agreement that could go up to kind of around 35. Is that about right and I guess…
Charles B. Stanley
Starts at about 3000 net acres available to us under the farm in.
Ray Deacon – Pritchard Capital Partners
Okay. Got it. To see the opportunity to do to other farm-ins like this?
Charles B. Stanley
Yes. We’re working on several other transactions that I would rather not talk about detail that we think will have an opportunity to increase our acreage position. There are farm outs out there. There are other opportunities up that we’re looking at.
Ray Deacon – Pritchard Capital Partners
Okay.
Keith O. Rattie
It is our intent to build a bigger acreage position in the core areas we currently define it.
Ray Deacon – Pritchard Capital Partners
Got it. And I guess just one more. It looked like your well cost was coming down in that Cane play. Is that primarily completions or drilling or kind of across the board?
Charles B. Stanley
It’s both Ray. It’s a combination of drilling faster and then frac cost have come down as we’ve gotten more efficient at pumping more than one stage a today.
Ray Deacon – Pritchard Capital Partners
Okay. Got it. And I guess just lastly, can you go over again what your cost structure is currently in the Pinedale in terms of cash flow breakeven and where you get it an acceptable rate of return I guess?
Charles B. Stanley
I don’t have those costs.
Keith O. Rattie
We try to get those costs before the end of the call.
Ray Deacon – Pritchard Capital Partners
That’s fine. Hey, thank you very much.
Operator
Our next question comes from Faisal Khan from Citigroup. Go ahead, please.
Faisal Khan – Citigroup
Good morning guys. It’s Faisel from Citi.
Keith O. Rattie
Hi, Faisel.
Faisal Khan – Citigroup
Quick question I'm just going back to the Granite Wash area, Chuck I think you have said you are in the zip code where some of your peers had been experiencing some pretty robust production. Can you just remind us how much, I may have missed this, but how much acreage you have there, and what’s your plan are to maybe to test this concept?
Charles B. Stanley
We got about 22,000; 23,000 acres in the Granite Wash play there in that core area.
Faisal Khan – Citigroup
Okay. And then what are your plan to maybe test that concept in terms of what they are doing our there?
Charles B. Stanley
We are actually meeting with our technical team here in a couple of weeks who have been working on a couple of initial test for our acreage, and we will probably do that in the third or fourth quarter this year.
Faisal Khan – Citigroup
Okay, great. Thanks guys.
Operator
Our next question comes from Joe Magner from Tristone Capital. Go ahead please.
Joseph Magner – Tristone Capital
Good morning. Thanks. Just not to beat this too much but go back to the sort of production expectations for the full year. You reiterated your guidance, the annualized the first half of ’09, and you get to the low end of the range. Expectations for prices to be soft Q3, Q4, seems like curtailment, deferral decisions will continue production could be flat to down second half. I guess, what are you thinking in terms of maintaining that full year? Is it that you have enough locks or enough flexibility to get volumes back up in the fourth quarter in orders to still hit that range? I’m just looking for a little more rationale and the maintenance rather than bringing the full year expectations down now and addressing it later?
Charles B. Stanley
Joe, just from an operational perspective as we bring new wells on and clean them up. We will pretty much be able to maintain flat volumes, it doesn’t take many 25 million a day Haynesville wells at high working interest to basically fill in the decline hole. And as we bring those to sale, we have to clean them up at fairly high rates for few weeks. So given the drilling schedule we have and given the completion schedule we have not only in the Haynesville, but also in Pinedale. We’ve got a fairly high visibility on the volumes coming out of our key plays are driving production volumes.
Joseph Magner – Tristone Capital
Okay. And then I guess along those lines if half to three quarters of your budget is fully discretionary and the economic or the price of outlook, looks to be challenging here in the near term, what else is, if it not term contract related or acreage related, what else is sort of driving your decision to maintain that program if the economics are challenging, and you still have a decent amount of volumes that are unhedged in the second half of the year, that are exposed to the current environment?
Charles B. Stanley
I’m sorry, Joe, you have to repeat question?
Keith O. Rattie
Well, your question basically was we still have a portion 25% or so of our second half volumes are unhedged. We were exposed to commodity prices. As Chuck described, we have the flexibility to bring production on. And our goal this year is to bring our annual production in between the goal posts on that $180 to $186 guidance. We’ve a lot of volumes that our curtailed. Now if you were to tell me that we’re going to be facing a $4 NYMEX in the fourth quarter through the end of the year that may influence our judgment about whether or not we actually bring volumes back on. Another point that I will make as you note Joe, we drilled and cased 56 wells at Pinedale this past winter. But our practice is to defer completions. We don’t try to complete wells in the winter. It costs a lot and there are a lot of operational issues. So if you go back over several years that’s given the certain seasonality to our production profile we generally are flat to down in the second quarter of the year before production volumes turned up. That’s going to change with the shifting emphasis on the Midcontinent. But it’s still a factor.
Joseph Magner – Tristone Capital
Okay. And then just, I guess one sort of follow-on question there. These wells especially the Haynesville they are $9 million plus to drill and complete. Lot of variables go into the calculation, but how much time do you feel like you have or you can drill a well like that and than defer the completion before it makes the whole investment on economic. Do you have a window, you keep in mind 30, 45, 60, 90 days where you have to turn it on no matter what in order to protect the economics? Or is it just so variable that just sort of case by case?
Keith O. Rattie
Really, the thing it drives that, Joe, is a correct price and the feature price. So if this is the case today there is almost $3 difference between the current price and next year’s price you can defer until the beginning of next year. And still generate a positive present value in the deferral. You also have the opportunity to drill and case wells and incur only half of the well cost, then coming and do the completions closer to the time when you are schedule to production. Eliminates in my mind 90% plus of the risk and allows you to have a pretty high confidence that the volumes will come out on a given date and a given rate.
So the question you can tell me the price today and the future price I can tell you exactly how long you can defer it without creating negative PV or I can tell you how much reduction in rate we can sustain for a given period of time. What I am looking at is I can go out today and I can hedge 2010 production volumes from a Haynesville well is about $6 a little over $6. I can bring the well on today at a lower rate and preserve some of that plus production keeping in mind that these are 80% first year decline wells. And so into that higher price nearly doubled that price in 2010 and generate positive PV by doing so and that’s what we are doing.
Joseph Magner – Tristone Capital
Okay. Thanks.
Keith O. Rattie
Sorry. I can’t be specific, but that’s the basic direction.
Joseph Magner – Tristone Capital
I appreciate, there are a lot of variables and you need to know some of those in order to have those specifics. I was just curious how much flexibility you had and sounds like there is a quite a bit.
Keith O. Rattie
There is. The primary variable is the forward curve, which is in steep contango over the next six months.
Joseph Magner – Tristone Capital
All right. Thank you.
Keith O. Rattie
While we are between questions. Let me just also go back and answer I think it was Ray Deacon's question on Pinedale. Our operating costs of Pinedale are very low, they are $0.18 in the past month. $0.20 on average for the past year. Our full cash costs, which is I think the question that Ray asked which would include G&A, allocated G&A and interest is little over $1. So basically cash breakeven costs at the well here is about a $1. So that I hope that answers Ray’s question.
Operator
And so we have a question from Robert Christensen from Buckingham Research. Go ahead, please.
Robert Christensen – Buckingham Research
Yeah, question one on the Pinedale. You say you drilled a 100 wells this year, 20 will defer completion. How many well were drilled last year, I guess 2008 will be the comparable number?
Keith O. Rattie
Bob, I don’t remember the exact number. I think we’ve reported 80, 83, 84 wells last year. I don’t have that number on the top of my head, but it was in the 80s.
Charles B. Stanley
Yeah. It was mid 80s, Bob, somewhere in that 80, 85 range for Pinedale.
Robert Christensen – Buckingham Research
Thank you. The second question…
Keith O. Rattie
So the key point is 20 more wells with on an average 3 or 4 less rigs working for the year just because of the efficiency improvements.
Robert Christensen – Buckingham Research
Sure. About the same number will be bought on production a 100 less 20…
Keith O. Rattie
Yeah. That’s right.
Charles B. Stanley
That’s correct.
Keith O. Rattie
Yeah. That’s right.
Robert Christensen – Buckingham Research
Okay. The second question not to get to involved, I guess but like to the Haynesville well which you said basically to yourselves less is more maybe. Why were you tempted to do play science or test science with less is more on this well. Has anybody else had success with less is more, because generally what we read and here is that more frac stages, more profit is better. What tempted you on this one?
Keith O. Rattie
The fact that ultimately this play is going to be developed on fairly tight horizontal spacing. And looking at optimal frac design and drainage to effectively stimulate our rock volume around a horizontal well bore and not create problems in the adjacent well bores by fracking into them or causing basically conduits for high leak off and therefore screen out in subsequent wells that are drilled and fracked...
Robert Christensen – Buckingham Research
Thank you.
Operator
Sir, I show no more questions in the queue at this time.
Keith O. Rattie
Well, we want to thank everyone for participating in our call today. A recorded replay will be posted soon on our website at questar.com. Thanks for your interest in Questar. Good day everyone.
Operator
This does conclude today’s conference call. You may now disconnect. Thank you.
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