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Questar Corp. (NYSE:STR)

Q4 2009 Earnings Call

February 18, 2010 9:30 am ET

Executives

Richard Doleshek - Chief Financial Officer

Keith Rattie - Chairman, President & Chief Executive Officer

Chuck Stanley - Chief Operating Officer & President of Questar Market Resources

Alan Bradley - President of Questar Pipeline Company

Ron Jibson - President of Questar Gas Company

Sam Brothwell - Vice President, Investor Relations & Corporate Planning

Analysts

Brian Singer - Goldman Sachs

Becca Followill - Tudor Pickering Holt

Robert Christensen - Buckingham Research

Tim Schneider - Citigroup

Operator

Good morning. My name is Stephanie and I will be your conference operator today. At this time, I would like to welcome everyone to the fourth quarter year end 2009 earnings release conference call. 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)

I would now like to turn the conference over to Richard Doleshek, Chief Financial Officer; please go ahead sir.

Richard Doleshek

Thank you, Stephanie. Good morning everybody. This is Richard Doleshek, Questar’s Chief Financial Officer. We appreciate you joining us for Questar’s fourth quarter year end results 2009 conference call.

With me today are Keith Rattie, Questar’s Chairman, President and Chief Executive Officer; Chuck Stanley, Questar’s Chief Operating Officer 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 of Investor Relations and Corporate Planning.

In addition, to issuing our earning release yesterday, on Tuesday we issued an operation update for Questar Exploration Production Company. We put a lot of information out there for your digest and are excited to talk to you about our financial and operating results and our year end reserves.

On Tuesday, QEP reported 2009 full year production of 189.5 Bcfe, which is a company record. We provided details about year end 2009 improved reserves which totaled 2.75 Tcfe, which is also a company record. We reported 2009 full year capital investment in QEP of $1.06 billion and affirmed 2010 production guidance in the range of 210 Bcfe to 215 Bcfe.

Yesterday we issued our earning release which we reported our results for the fourth quarter and full year 2009. We slightly lowered our 2010 EBITDA guidance to account for a lower commodity price forecast, and affirmed production and capital investment guidance for 2010. We will discuss these items today and take yours questions at the end of this call.

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

With regard to our financial performance, I would characterize our fourth quarter and full year 2009 financial results as noteworthy. Our fourth quarter EBITDA was $466 million, which was the second best quarter in the company’s history, only $200,000 lower in the high water mark set in the fourth quarter of 2008. EBITDA for 2009 was $1.64 billion, down to 7% from the record level of $1.76 billion in 2008, even though the natural gas prices in the field were less than half of what they were in 2008.

Factors driving Questar’s full year 2009 EBITDA were 11% increase in production compared to last year of 18 Bcfe. A 54% decline in C level prices on equivalent basis compared to last year, down from $7.53 per Mcfe to $3.49 per Mcfe. That price decline was offset by a $481 million increase in net proceeds from our commodity business portfolio and a 11% decline in combined operating maintenance and production tax expense compared to last year.

Consolidated net income for the fourth quarter in the year was $115 million sequentially, and $98 million from the third quarter, driven by EBITDA that was $92 million higher in the quarter, but offset by higher DD&A, income tax and interest expenses. Net income was $393 million for 2009 compared to $684 million in 2008.

Factors driving net income lower for the year, beside from significantly lower commodity prices were largely non-cash, including higher DD&A expense, a $164 million of mark-to-market losses before income tax on our basis only swaps, and $65 million of gains before income taxes on asset sales in 2008, offset by a provision for income taxes that was $156 million lower in 2009.

For 2009 we will report capital expenditures on the accrual basis of $1.4 billion down from $2.62 billion in 2008. With Questar market resources spending only $1.2 billion in 2009 compared to $2.4 billion in 2008, driven by reserve and leasehold acquisitions spending that was $548 million lower, exploration and development spend that was $317 million lower and spending in our gathering processing business that was $321 million lower than the amount spent in 2008.

Note that we set our 2010 budget at $1.58 billion. From a liquidity standpoint, Questar is in great shape. We have no long-term debt maturity until 2011 and as of the end of the year, which only typically is our peak commercial paper issuance to buy gas for the heating season at Questar Gas Company. We had $866 million available under committed credit lines.

In summary, we got through 2009 in good shape. Our commodity business, did what it was suppose to do, it inflated the company from the dramatic decline in prices. We throttled way back on capital spending to live within our cash flow and still delivered record production and proven reserves. Our balance sheet is strong and 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. Richard has commented on our press releases on Tuesday and Wednesday which we gave you an update on Questar E&P operations and reported our fourth quarter and full year ‘09 results. I am going to try to add some color to those comments and then turn to 2010 beyond.

We want investors to take note the strategy we put in place a few years ago to expand our E&P business beyond our traditional Rockies focus is working. Questar E&P mid time in fourth quarter production as Richard said was up 46% from a year ago and that of course was driven by growth from the Haynesville shale, Anadarko Woodford Cana shale plays, and our Granite Wash play.

Overall, Questar E&P, fourth quarter 2009 production was up 20% from the year ago quarter and up 26% sequentially from the third quarter of ‘09. Please note that the plan we talked about a few quarters ago to curtail and defer Questar E&P production from last summer to this winter worked. Questar E&P averaged over 600 million cubic feet a day in the fourth quarter of ‘09 as Richard noted we got plus production from wells that we returned to sales after price related shut-inns and curtailments in the second and third quarters.

In 2009, Questar E&P group production 11% replaced 379% of its production and grew year end improved reserves by 24% to 2.75 trillion cubic feet equivalent and did that despite 271 billion cubic feet equivalent of price related revisions under the new SEC rules, the pricing rules. Excluding revisions production replacement would have been 537%.

Please note that we delivered this growth as Richard noted by cutting capital expenditures significantly. Questar E&P totaled 2009 capital investment of $1.056 billion included undeveloped leasehold acquisitions in our core areas of $215.1 million producing property purchases of $6.4 million and exploration cost of $92.9 million.

In ‘09, we allocate a capital to our highest margin place in particular that Haynesville and Pinedale. We also allocated significant or at least sufficient capital to make progress on our Woodford Granite Wash and Bakken plays. Richard noted that hedging increase Questar E&P cash flow by over $575 million in 2009, note also that the rest of Questar Wexpro Gas Management, Questar Pipeline, Questar Gas and Energy Trading generated $656 million of EBITDA in 2009 these businesses as you know contribute cash and earnings that are not very sensitive to commodity prices.

Let me touch on a few other highlights from our ops release and I will refer you to the slides we posted on our website for today’s call at www.questar.com. We’ve been telling investors for sometime that we intend to lease or require additional acreage in the Haynesville play, Questar E&P now has 46,000 net acres in the core of the Haynesville shale play and that’s up nearly 50% from mid 2009.

In our ops release we reported that since our last call we drilled and turned eight Questar E&P operated Haynesville wells for sale, our productivity is up, our completed well costs are come and down, we averaged about $8.5 million per well on these wells and note that we completed one of the wells for just over $7.2 million and I can assure you that there is a sense of urgency on our Haynesville team about continued productivity and cost improvement.

Please note from slide three, that we now have seven operated rigs in Northwestern Louisiana, note also that Questar E&P proved reserves in the Haynesville play jump to 592 billion cubic feet equivalent at year end ‘09. In addition to 276 booked proved on developed locations we have over 925 additional un-booked locations yet to drill assuming 80 acres density, and that’s summarized on slide four.

Let me turn to Pinedale, we completed 96 new wells of Pinedale in ‘09. Note that our Pinedale team drilled a 14,310 foot directional well, despite the total debit in 13 days. We are now consistently under 20 days completed well costs on the last 25 Questar E&P operated wells at Pinedale average less than $4.8 million, and again I can assure you there is a sense of urgency on our Pinedale team about continuing net productivity performance.

Our Pinedale team’s relentless focus on cost matters because we have up to 1,400 low risk development wells yet to drill at Pinedale on a combination of 5 and 10 acres density. Please note that we planned to operate 6 rigs at Pinedale in 2010 and you can get more details on slide five.

We have also given you an update on our Cana Shale Play in the release on Tuesday. Note; on slide six that Questar E&P operated wells have recently IPed at rates ranging from just below 5 million cubic feet a day to over 7.5 million cubic feet a day. We currently have one operated rig in this play and we planned to add another rig in the near future.

Moving to the Granit Wash play, Texas Panhandle were currently completing our first Questar E&P operated horizontal well that’s the time per year well in Wheeler County it shown on slide seven and eight. We are drilling a head on our second operated horizontal well and we planned to add a second rig in this play later this year.

Note also that we are participating in several non-operated wells and as I said in the other locations, I can assure if you want to our Oklahoma City office there is a sense of urgency about getting our first few operated horizontal wells down in the Granite Wash play and continued productivity improvements in the Woodford play.

Let me turn to our Bakken oil play, North Dakota; recent wells drove by both Questar E&P and other operators in this play have confirmed that the Bakken fairway extends onto Questar E&P’s 80,000 net acres. In December, we turned our third operated horizontal well to sales with a peak 24 hour rate of over 1,400 barrels of oil equivalent per day.

In fact as wells produced over 27,000 barrels of oils equivalent in the first 30 days that’s an average of over 900 barrels of oil equivalent per day. We are calling attention to this well, its significant because its two miles from the nearest Bakken producing well. As shown on slide nine, we drove in case to our fourth Questar E&P operated well and we are drilling ahead on our fifth operated well.

To hold our cost down, we are going to differ completions on these wells until spring and as I said in the other areas our Bakken team is very focused on costs and productivity improvement. We planned to run one rig in 2010 and note that will drill our first test at the three forks formation on our acreage in the near future.

Also note that we now have a working interest in 27 producing wells in the Bakken play. So quick summary, Haynesville shale, Pinedale Anticline, Granite Wash, Woodford shale, Bakken oil. We think that’s a pretty good portfolio of E&P assets, it’s the foundation of our plan to turn up the growth and drive shareholder value in the years ahead. I urge you to ask Chuck Stanley for more color when we get to Q-and-A, let me turn now to our outlook for 2010 and beyond.

We expect Questar E&P production to range from 210 to 215 billion cubic feet equivalent in 2010 that would be up 11% to 13% from ‘09. Now those are the use of follow us know that Questar E&P’s first quarter production typically declines sequentially from the fourth quarter, in large part because we choose not to incur higher costs to complete Pinedale and other Rockies wells in the winter.

In 2010, we are allocating about $900 million of capital to Questar E&P about 60% of that to our Haynesville and Pinedale place we are allocating most of the remaining capital to our Woodford shale, Granite Wash and Bakken place where margins and returns also appear attractive on the current forward curve. Please note that over 90% of Questar E&P 2010 CapEx is for identified low risk drilling locations in our core plays.

Now forward natural gas and oil sizes have decline since our last call, so yesterday as Richard noted we took our 2010 EBITDA guidance down to reflect those lower prices for un-hedge Questar E&P production. We have summarized our assumptions in the table and the release. Also note that we have hedged about 167 billion cubic feet equivalent of our 2010 natural gas and oil production, 156 Bcfe with fixed price swaps and another 11 with collars, and there is a table at the end of our release that summarizes those hedges.

Let me turn briefly to comment on our other business; starting with our second E&P company Wexpro, we are allocating $100 million to Wexpro in 2010. We estimate that Wexpro’s investment base could grow from about $432 million at year-end 2009 to about $460 million at year-end 2010.

Now you will recall that Wexpro develops reserves on behalf of Questar Gas on a define set of properties in the Rockies and earns a 90% un-levered after tax return on its net investment.

2009 was the 28th year of operations under the 1981 Wexpro agreement and Wexpro produced in its 28 year a record 48.2 Bcf of natural gas for Questar gas. In 2009, Wexpro also replaced its production and reported record cost of service reserves at the year end and after 28 years Wexpro still has a large inventory of future drilling locations that will drive significant future growth.

Let me turn to Questar Gas Management, our midstream business. We are allocating $289 million of capital to our midstream team in 2010 and this could be a transforming year for this business. We are building 420 million cubic feet per day deep cut cryogenic natural gas processing plant next to our existing Blacks Fork processing of about 100 mile south of Pinedale.

When this plans completed in the third quarter of 2011, it will be fully loaded with volumes dedicated for the life of the Pinedale field from the Questar E&P operated acreage on the Northern part of the Anticline and other dedicated during river base in production.

Based on the current forward Frac Spread this project could generate over $16 million of EBITDA per year. Later this year gas management should complete construction of the $150 million cubic feet a day, iron horse, deep cut cryogenic processing plant adjacent to our existing stage coach processing hub in the Uintah Basin. Iron horse returns on capital are underwritten fee base contracts from third-party producers this plant will also be fully loaded when it goes into service.

Our timing on both of these projects appears to be good, construction cost are down significantly from the boom years of 2006 and ’08, and I can assure you there’s a sense of urgency on our midstream team about bringing in these projects on schedule and within budget.

As we discussed in our last call, Gas Management has also entered the gas gathering and treating business in the Haynesville Shale Play. Our Louisiana entry strategy will look a lot like the strategy that produced more than 10-fold increase in earnings from our Rockies’ midstream business over the last decades. We’re building and gathering CO2 treating facilities to handle both Questar E&P and third party volumes.

Now let me turn to our regulated businesses starting with Questar Pipeline in late 2009. Our pipeline chain completed two key expansion projects, that together at 300 million cubic feet a day capacity on Overthrust pipeline, and recall that Overthrust runs through the heart of the Green River Basin from the Opal Hub to the Wamsutter Hub. In 2010 we’ll expand Overthrust again with a 43 mile 36 inch pipeline route west of Rock Springs, Wyoming.

This $100 million project is underwritten by long term contracts to move gas west for delivery and to Green River Pipeline and ultimately to the Rudy Pipeline. In total, we’ve allocated $161 million of capital to our pipeline business in 2010, and I can assure you that our pipeline team as they did in 2009 is focused on executing these projects ahead of schedule and within the budget.

Finally, we’re allocating $128 million of capital to Questar Gas, our utility in 2010. This will include capital to replace and expand older theatre lines. Our utility earned its allowed return for the fifth year in a row in 2009. Questar Gas’s rates remain the lowest in the Continental U.S. Our employees are among the most productive in the industry. Questar Gas running third among 73 U.S. gas utilities and lowest O&M cost per customer.

Our employees are also serving customers well. Our customer satisfaction ratings today are at an all time high. So let me summarize; Questar’s successfully adjusted to tough market conditions in 2009. We turned up the growth in the fourth quarter and we’re off to a good start in 2010.

Operator let’s open it up for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Brian Singer - Goldman Sachs.

Brian Singer - Goldman Sachs

I wanted to follow-up on the Haynesville and how you’re completing the wells there, or really flowing those wells with your modified procedures. Can you just talk to you what your expectations are for decline rates and EURs, if that’s all different from your earlier completions, and may be a little bit of color and may be its still early on how that wire house or well is holding up?

Keith Rattie

Thanks Brian, this is a good opportunity to bring Chuck Stanley in.

Chuck Stanley

As we mentioned in ours release and you saw in the table, we’ve deliberately changed our flow back procedures. We’re still stimulating the wells using the same frac line, 16 stages, and pumping about the same amount of fluid and sand, but we and other operators have noticed that the wells that have flowed back hard on initial flow back and cleaned up.

Over the long term at any given point in the production history if you look at a cumulate production of a bcf or a cumulate production 2 bcf, wells that are flowed back hard on bigger chokes tend to have lower flow and pressures at any given point on the cumulative production curve than a well that is choked back and not flowed hard. We don’t know exactly what’s going on down haul.

We can speculate that flowing the wells really hard may cause partial closure of some of the fractures; it may allow some fractures to dewater, while others remain water locked. It’s probably some combination of those things, but in the end what we’re doing now is trying to minimize the draw down in the bottom hole portion of the well out in the lateral, and we’ve tried to keep the choke size down to 14x60 force to 16x60 force maximum choke size. That compares to earlier wells that we reported that had choke sizes in that 24 to 26x64’s range, and allowed us to make initial rates of 20-plus million cubic feet a day.

I think probably just to get at the root question here Brian, if we compare the wells that we’ve recently completed, first of all, the earlier wells after cleaning them up, we choked them back to 10 million cubic feet to 12 million cubic feet a day which resulted in fairly high bottom whole pressures.

We see some wells that have been on since, the first well in the table in our recent release, the Bakken well that had an IP of slightly over 20 million a day. It averaged after we choked it back about 13.3 million cubic feet a day. It came to about 400 million cubic feet just in the first month on production. It’s been on production now 116 days. It’s keen to a little over 1.5 billion cubic feet of gas, and it’s still making 13.2 million a day, so that’s making basically the same rate that it was after we cleaned it up and choked it back.

I’ll compare that to some of the more recent wells. For instance the warehouse well that you asked about came on at 13.3 million cubic feet a day, and averaged 12 million cubic feet a day during the first 30 day, so it came to a little over 360 million cubic feet of gas. It’s now been on for a total of 74 days and has schemed about 790 million cubic feet, so three-quarters of a bcf, it’s still making about 11 million cubic feet a day.

In short, once we choke these wells back, we’ve yet to see significant decline in the first 60, 90, 120 days that they’ve been online, but what we do anticipate is with the smaller choke sizes and higher bottom hole pressures that the ultimate recovery on these wells will be higher.

Brian Singer - Goldman Sachs

Separately, can you just confirm your uncompleted inventory, any remaining shut-in’s; is that all kind of done with or is there anything left?

Chuck Stanley

We didn’t get all other wells that Pinedale completed. We got closed down by cold weather. I think we still have half a dozen or so wells, but as you know normally we shutdown completion activity at Pinedale and carry wells through the winter and will start up again in March when the weather warms up. So we will have our substantial inventory there, but that’s normal. In the other areas, just the normal course of backlog, getting rigs moved off and getting completion crews moved in.

Operator

Your next question comes from Becca Followill - Tudor Pickering Holt.

Becca Followill - Tudor Pickering Holt

On the reserve numbers on Haynesville, what are you guys booking per well on Haynesville?

Chuck Stanley

Our average EUR on the PDP wells that we operator or participate in, it’s about 6.5 bcfe and there’s a range around that. Obviously we’ve got some wells booked close to 10 bcfe on the high side.

The proved undeveloped locations, and this is all gross gas not net gas; the proved undeveloped locations are booked at 6 bcfe each, and just a little bit of more color on the booking methodology. We have booked a maximum of two proved locations per 640 acre unit or section. If there is one PDP well, we’ll book a maximum of one PUD; if there no PDP wells in the section, we’ll book a maximum of two PUDs per unit.

To help you do the math, our average working interest on those undeveloped locations is 42%. So if you try to back into the reserve number, I think that gives you all the information you need, except for NRI and our NRI is a little under 80% on average.

Becca Followill - Tudor Pickering Holt

Second question is on production. I know that seasonally the first quarter normally is lower than the fourth quarter, but the fourth quarter was so big this year because of the flush production, and incremental production coming online. So should we look for even a bigger decline in the first quarter or is there an offset with some of the Haynesville?

Chuck Stanley

Yes, we will see a decline and it will be magnified some, because of as you correctly identify the flush production that we saw in the fourth quarter as we both bought wells that have been curtailed back up to full productive rate. We had wells shut in as we’ve discussed in previous calls, that act as a mini storage project, and when those wells come back on, they come out on a higher rate than they were producing at when they were shut in.

We also rapidly work through our backlog of standing wells that had not been completed. So yes, there will be a more dramatic decline in the first quarter as we don’t get back to well completions until the end of the first quarter and into the second quarter, so that decline will not be reverse until the end of the second quarter.

Becca Followill - Tudor Pickering Holt

The last question, which I missed the opening remarks, so you may have already addressed it. The question is on everyone’s mind is structure, any thoughts on where you stand on looking at that or the process?

Keith Rattie

I commented in those prepared remarks as we hit each one of our operating areas about a sense of urgency in our operating divisions about performance improvement, I can assure you and investors that that same sense of urgency extends to the management team and the current CEO’s office when it comes to our chronic valuation gap. I can also assure you that the urgency walks right out of the CEO’s office into the Boardroom.

Now, looking at it over a long term prospective, if we’d own the shares for the entire decade just ended, you would have realized about a 470% total shareholder return and that would have been good enough to rank No. 30 out of the 500 companies in the S&P 500. Some management teams might be contempt with that, but we’re not and we can do the math on our valuation.

We’re getting feedback. Sam gets feedback from time-to-time that we need to do a better job telling our story, perhaps we need to be more promotional. I don’t believe you can talk your way to a better valuation. I think it takes execution. You folks can just form the results that we just put up and over the last several quarters, whether we are executing. I can tell you that if good execution fails to close the valuation gap, then we’re going to have to do something different. I appreciate the question.

Operator

(Operator Instructions) Your next question comes from Robert Christensen - Buckingham Research.

Robert Christensen - Buckingham Research

The question I have is about, I guess at this stage, pilot projects of chocking back these Haynesville wells. It seems early days to make a statement that the EUR’s would be increased with half a year of this exercise of chocking back wells. What evidence do you have that the EUR’s would truly increase?

Don’t we just defer this high pressure problem downhaul? I wouldn’t characterize the problem, but the closure and stress and all that downhaul, don’t we just defer that and comeback with EUR’s that might be less. I mean isn’t it early days to make the statement. I mean a number of companies are taking this to this level.

Chuck Stanley

You’re right. It is early days. Interestingly we’ve seen this phenomenon in other reservoirs not shales, in tight gas sands and other areas in our operations where we changed our flow back methodology and reduced the drawdown at the reservoir horizon and overall saw better well performance and higher EUR’s compared to direct offset wells in almost identical rock.

Yes, it is early, but there’s I think a very strong reservoir engineering and empirical relationship between flowing bottom hole pressure and cumulative production at ultimate recovery and if we take well A, which has flowed back hard and cleaned up with basically a unconstrained flow back and we look at the flowing pressure at 1 bcf of cumulative production and it’s lets just say 8,000 pounds and we look at a well that is aided and has been flowed back on a smaller choke to avoid drawing down the reservoir pressure at 1 bcf, we might see 9,000 pounds.

So if we extrapolate that into the feature, one would presume that the flowing pressure at any given point on a cumulative production curve would be higher and ultimately what defines the ultimate recovery from a gas well is abandonment pressure. So at any point along the curve you’d be higher on the flowing pressure and therefore prolong the point to abandonment.

You’re correct; we don’t have a lot of data on this, although it is interesting that other operators are observing the same phenomenon in other shale plays. We see indications of the same thing in the Cana Shale play that we are also an operator in and as I mentioned we’ve seen in tight gas sand reservoirs and other basins. I think as an industry we’ve conditioned the analyst community to focus solely on initial production rate and unfortunately that may not be the most prudent headline for ultimate recovery and ultimate economics of the play.

Robert Christensen - Buckingham Research

How many wells in the Haynesville do you need to drill to hold your leases?

Chuck Stanley

Bob, I don’t have an exact number. A large amount of our leasehold is held by production by shallower, Hosston and Cotton Valley wells and no pew clauses that sever the shallow rights from the deep. We are very comfortable with our current drilling program. We can more than save our leases. We’ve got some leases that are still under primary term, but they’ve got a significant term left on them. It’s less than 30 in total.

Robert Christensen - Buckingham Research

I have another question if I may. Your DD&A rate seems high still and I know that the success you’re having should bring it down overtime. I was just wondering under successful efforts of counting, if prices for natural gas were to go up, would we have any kind of mid-year, mid-quarters type adjustments where you’d bring revisions back on. I’m not just familiar with the accounting and certainly the rules have changed, which could materially lower your DD&A rate?

Richard Doleshek

Sure, Bob. It’s Richard. If you look at our DD&A rate, QDP over the last three quarters, the high water mark was three or seven and the second quarter coming down to 263 in the fourth quarter; and as you guys observed with the reserves that were booked, most of those being on the proved undeveloped side, it really only impacts our lease hold DD&A rates.

So I think it’s fair to say that the DD&A rate should modestly trend down through the year, but even if we brought a lot of those reserves back due to upper prices and the visions there, most likely it’s not going to materially change the DD&A rate.

Robert Christensen - Buckingham Research

Isn’t that painful, I mean you just gave the exercise at $3.60 gas after you net out gathering compression and all that. I mean $2.90 is your fixed cost and the real gas price is pretty much on the border of your DD&A rate. How do you explain it? I mean this keeps me so much at faith and stock on a profitability basis?

Richard Doleshek

Certainly if you’re looking at it on a full cycle return basis, which is what DD&A attempts to model. If you look at our cash basis, we’re lifting the molecules out of the ground at less than $1 per mcfe, which is LOE in production taxes and then you add $0.36 and $0.34 for G&E and interest respectively.

So on a cash basis we are clearly doing very well, and then when you look at your full cycle economics including your investment base for your lease hold, as well as your development dollars that you get into, assuming you’re not covering all your costs, but the hedge portfolio really helped us in 2009. So, on a full cycle basis we are still net case or net positive on after DD&A basis.

Chuck Stanley

Bob, this is Chuck again. One other comment that I would make is that there’s a profound lack of comparability between a full cost E&P company and the successful efforts company because of the ability or the requirement under full cost accounting. It takes ceiling tests impairments and basically impairs away billons of dollars of past investments.

The standard for a successful interest company is a quiet a bit higher bar in order to take an impairment charge. So if you look back at our history of impairments, they’ve been relatively modest compared to that of other full cost companies and as a result we carry those costs and you see the full history of our investment in our E&P business reflected in our DD&A rate rather than one that has been significantly reduced by taking ceiling test rate down overtime.

Keith Rattie

Final comment, if you look back over the last several quarters in the low priced environment we test at the end of each quarter for impairment of our E&P properties, and you’ll see that our write-downs for impairment have been very minimal.

Operator

Your final question comes from Tim Schneider - Citigroup.

Tim Schneider - Citigroup

If I look at slide seven on the Granite Wash, I noticed that you updated the top end guidance range, I guess on the EUR’s to 12b’s per well. I was just wondering what the incremental news flow was on that?

Chuck Stanley

Tim, this is Chuck. Just looking at that well results and we participated in several of the outside operative wells that have made the headlines recently and looking at the performance of those wells over a short period of time and knowing what we know about some of these Granite Wash reservoirs, we believe that on the high end it could be as high as 12 bcf.

Tim Schneider - Citigroup

If I look at it on the cost side, the incremental cost then would only be $400,000 because the top end of the cost goes from $8 million to $84 million per well?

Chuck Stanley

Right, that’s just more refinement on our view on completed well costs on some of these deeper Atoka laterals, where your measured depth is substantially deeper than the shallower coal well and Cherokees announced and just knowing what we know about drilling costs out there.

Tim Schneider - Citigroup

As far as timing goes, when do you think the well is going to be completed, the one that you’re currently completing?

Chuck Stanley

Well, the [Tom Perrier] well is down, it’s fracted, unfortunately it’s been one of those wells that bad things normally come in threes and I think we’re on five now for bad things. So right now we have coil tubing stuck in the well during drill outs. We’re going to have to fish that out and finish the drill out before we can get the well to sail, so hopefully fairly shortly.

That well has been basically troubled from the beginning and had difficulty drilling it. We had some shallow drilling problems that forced us to side track the well several times before we even got into the horizontal lateral and we got side tracked by delays related to weather on the completion. So I have given up trying to predict the date, but it’s close to coming on production.

The Edwards well is flooded and is getting ready to start building the corner to turn horizontal. We’ve got another rig working over in Oklahoma, in the Oklahoma portion of the Granite Wash play drilling an offset to our rock sand well that we reported several quarters ago.

Operator

At this time there are no questions in queue. I will turn it back over to management for closing remarks.

Keith Rattie

We want to thank everyone for calling in today to listen to Questar’s conference call. You know how to get a hold of us. We’ll continue to post information on our website www.questar.com. Thanks for your interest in Questar.

Operator

Thank you. This concludes today’s conference call. You may now disconnect.

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Source: Questar Corp. Q4 2009 Earnings Call Transcript
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