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Questar Corp. (NYSE:STR)

Q1 2010 Earnings Call

April 28, 2010; 9:30 am ET

Executives

Richard Doleshek - EVP & CFO

Keith Rattie - Chairman, President and CEO

Chuck Stanley - EVP, COO and Director

Analysts

Brian Singer - Goldman Sachs

Carl Kirst - BMO Capital

Gil Yang - Bank of America

Rebecca Followill - Tudor, Pickering, Holt

Ray Deacon - Pritchard Capital Partners

Vivek Pal - Knight Capital

Ross Payne - Wachovia Bank

Gil Yang - Banc of America

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 first quarter 2010 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). Thank you.

I’ll now turn today’s conference over to Mr. Richard Doleshek. Please go ahead sir.

Richard Doleshek

Thank you, Stephanie. Good morning everyone. This is Richard Doleshek, Questar’s Chief Financial Officer. Thank you for joining us for Questar’s first quarter 2010 results conference call.

With me today are Keith Rattie, Questar’s Chairman, President and CEO; Chuck Stanley, Questar’s Chief Operating Officer and President of Questar Market Resources; Ron Jibson, President of Questar Gas Company; Alan Bradley, President of Questar Pipeline Company; and Sam Brothwell, Vice President of Investor Relations and Corporate Planning.

As you know it’s been a busy seven days for us. In addition, to issuing our earnings release yesterday, we issued an operations update for Questar Exploration Production Company on Monday and last Wednesday we announced that we are considering a spin-off of our E&P and midstream field services businesses.

Although the first quarter results are important and noteworthy, we will keep our comments about those results relatively brief and after my remarks Keith will give some more color on operating results and discuss those spin-off. On Monday Questar E&P reported first quarter 2010 production at 51.5 Bcfe, 51% of which came from our Midcontinent positions. We updated development activity in our core operating areas and we raised 2010 production guidance by 2 Bcfe to a range of 210 to 217 Bcfe.

Yesterday we issued our earning releases in which we reported first quarter 2010 results and raised our 2010 EBITDA guidance by $30 million. We will discuss these items today and invite your 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 from our estimates for a variety of reasons. With regard to our first quarter results all of our business units with the exception of Questar E&P generated record financial results and in total contributed 50% of our aggregate EBITDA.

Questar E&P’s results reflect the impact of realized natural gas prices that were 25% lower than a year ago. Our first quarter EBITDA was $433 million, which was down $33 million from the fourth quarter of 2009, but down only $2 million from the first quarter of 2009.

The rest of Questar were the businesses other than Questar E&P generate $218 million in EBITDA in the quarter compared to $190 million in the fourth quarter of ‘09 and $193 million in the first quarter of ‘09.

Remember that Questar Gas which contributed $70 million of EBITDA in the period generates half about half of its annual EBITDA in the first quarter of each year. Other factors driving our EBITDA include Questar E&P’s production which averaged 572 million cubic feet equivalent per day in the quarter compared to 602 million cubic feet equivalent per day in the fourth quarter of 2009 and 521 million cubic feet equivalent per day the first quarter of ‘09.

Questar E&P field level prices averaged 534 per Mcfe in the quarter compared to 415 per Mcfe in the fourth quarter of 2009 and 352 per Mcfe in the first quarter ‘09. And our commodity business portfolio [collected] $9 million of EBITDA in the quarter compared to a $110 million in the fourth quarter of ‘09 and $141 million in the first quarter of ‘09.

The commodities portfolio added $0.17 per Mcfe to Questar E&P’s net realized price in 2010 compared to a $1.99 per Mcfe in the fourth quarter and $3.01 in the first quarter of ‘09. Finally combined operating, maintenance and production tax expenses were $141 million in the quarter compared to a $136 million in the fourth quarter of ‘09 and $129 million in the first quarter of 09.

The relatively higher first quarter 2010 expenses is primarily a result of higher production taxes at Questar E&P driven by higher field level prices. Consolidated net income to the first quarter of the year was $150 million sequentially flat with the fourth quarter of ‘09 driven by EBITDA that was $33 million [low] in the first quarter, but partially offset by lower DD&A expense.

Net income was $83 million higher than the first quarter of ‘09 on essentially flat EBITDA due to non-cash items including DD&A expense that was $25 million higher and out provision for income taxes that was $49 million higher in 2010, offset by a $169 million swing in unrealized gains and losses on basis only swaps before income tax.

We’ve had some questions about our unrealized gains and losses since we released our earnings yesterday and we’d be happy to discuss those during Q&A. For the first quarter 2010 we reported capital expenditure on an accrual basis of $325 million compared to $536 million in the fourth quarter of ‘09 and $263 million in the first quarter of ‘09.

Questar market resources $291 million in the quarter compared to $467 million in the fourth quarter of ‘09 and $242 million in the first quarter of ‘09. Questar Pipeline and Questar Gas in combination spend $34 million in the quarter compared to $69 million in the fourth quarter of ‘09 and $21 million in the first quarter of ‘09.

In summary we had a solid quarter with record financials results in four of our five business units. Net realized commodities prices at QEP were down 10% from last quarter and down 16% from a year ago and Questar E&P’s direct production was down only 5% in the fourth quarter as results of our normal practice of suspending completion activities in the Rockies in the winter, but up 10% from a year ago driven by growth from our Midcontinent divisions.

Our balance sheet remains strong and we’ve approximately $900 million available under committed credit lines, 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. We’re getting a lot of questions on our April 21 announcement that we are contemplating tax free spin-off of our E&P and midstream gathering and processing businesses. So this morning I am going to use most of my time to respond to at least some of those questions about the proposed spin-off. First just some quick comments on the quarter and our outlook for the rest of the year and Richard summarized as well we are off to a pretty good start in 2010.

So as Richard noted consolidated first quarter EBITDA was flat with a year ago despite a 25% drop in net realized natural gas prices. We are raising our consolidated 2010 EBITDA guidance, we have also raised Questar E&P’s 2010 production guidance to 212 billion cubic feet equivalent to 217 billion cubic feet equivalent.

Questar E&P’s first quarter results highlight what we think as one of our competitive strengths and that is that we have one of the lowest cash cost structures in the industry. Questar E&P cash margins held up pretty well in a low price environment in the first quarter.

In our Monday operations release, we gave you an update on our major E&P projects, the Haynesville Shale, Pinedale, the Anadarko Woodford Cana Shale play, Granite Wash and the North Dakota Bakken oil play. Note that we are continuing to add acreage in the core of the Haynesville shale, the Cana and the Granite Wash plays, note that we came out of the winter with a good inventory of Pinedale wells. We are starting to complete those now and that should Pinedale production turned up over the rest of the year.

Note also that we’ve drilled in case, so new wells in the Bakken and we are going to start completing those wells next week. Our latest Woodford Cana Shale wells are keepers and note that despite mechanical problems downhole our first operated horizontal Granite Wash well in the Texas Panhandle appears to be very strong. I encourage you to ask Chuck Stanley for more color when we get to Q & A. As Richard noted four of our five major Questar business units Wexpro, Gas Management, Questar Pipeline, and Questar Gas all posted record first quarter net income and in fact all are on track to report record net income this year.

Bottom line is that we have got terrific people running each of our businesses and they are executing very well. So let me turn to the proposed tax free spin-off of our E&P and midstream field services businesses. As we noted in our April 21 press release E&P Co. and that’s place holder name that were using for now, E&P Co. would be comprised of our commodity businesses, Questar E&P, Questar Gas Management and Questar Energy Trading. After the spin-off Questar Corp would remain an integrated natural gas company comprised of Wexpro plus our regulated businesses Questar pipeline and Questar Gas. Questar shareholders of record on the x dividend date would receive one share of the E&P Co. for each share they on a Questar.

Subject to Board approval and other conditions precedent, and I will talk about those in a moment. The spin could occur in the third or fourth quarter of this year. Now I am going to try to respond to the most frequently asked questions from investors and then we will invite you to ask questions. Any questions that we miss when we get to Q&A the obvious first question is why? Bottom line, we think that a spin-off of our E&P business would create two top tier companies and their respective market segments.

Over the past decade you have seen what we done to transform Questar by driving growth in our E&P business. We transformed Questar E&P from what was once primarily a Rockies producer into a multi-base and growth company operating in several of the most economic natural gas plays in the country today. And in doing so we delivered double digit reserves and production growth while maintaining one of the lowest cost structures in the industry.

We think that E&P Co. would continue to be one of Americas fastest growing E&P companies. The E&P Co. businesses reported combined EBITDA of $1.17 billion in 2009 and could generate over $1 billion of EBITDA in 2010, but more important we think we have an attractive inventory of future development opportunities and that’s good visibility on growth.

The Haynesville Shale, Pinedale Anticline, Granite Wash, Woodford Shale and the Bakken, we think that’s a pretty good foundation on which to continue to grow an already successfully E&P business and we are on track as we noted to grow production by at least 12% this year and we believe we can grow production on a compound rate of 12% to 15% over the next five years without an acquisition and with solid returns on capital even at natural gas prices consistent with the current forward curve.

E&P Co. as we noted would also include our midstream field services business, gas management and our marketing business. Both of these businesses are integral to the way we manage our E&P business.

Once, we complete the two major gas processing projects that we’ve got underway in the Rockies. Today Gas Management will throw off significant free cash flow to help fund future E&P growth. In short we believe that E&P investors would find E&P Co. a compelling investment opportunity.

We also believe that yield-oriented investors would find the new Questar Corp to be a compelling investment opportunity. After the spin-off Questar Corp would remain a uniquely integrated natural gas company comprised of Wexpro, Questar Pipeline and Questar Gas and we frankly think that the performance of these businesses tends to get overlooked.

Under the 1981 Wexpro agreement, Wexpro earns a 19% after-tax unlevered return on its net investment in the development if natural gas reserves on behalf of our utility Questar Gas. Over the past decade Wexpro has grown net income fourfold, that of course has been driven by a fourfold increase in its investment base.

Over that timeframe Wexpro produced over 400 Bcf of natural gas for the utility and yet Wexpro cost of service reserve today are 89% higher than they were a decade ago. In fact cost of service reserves today are higher than they were nearly 29 years at the inception of the Wexpro agreement.

Turing to Questar Pipeline, our Pipeline team has growing net income threefold over the past decade and that’s been driven by a threefold increase in transportation volumes. For it’s part Questar Gas has doubled net income over the last decade and that’s been driven by one of the highest customer growth rates in the country and I should add by employees who are among the most productive in the industry.

When you combine these businesses together, they grew net income at a compound rate of over 12% over the last decade. They are on track to generate over $500 million of EBITDA in 2010 and after the spin-off, the new Questar Crop would have the potential to continue to grow net income at high single digit rates over the next five years and beyond.

Questar should generate significant free cash flow to fund future growth projects while also paying a substantial dividend and growing that dividend at a significant rate. So bottom line with this transaction we believe we can unlock significant value for our long term shareholders by creating two top tier companies that are well positioned to continue to create value going forward.

The next question we have got is, are you just sending up a trail balloons? The answer that is no, we don’t do trial balloons certainly not in the case of what would be the most significant strategic move in Questar’s 80 years history. In fact, we took this to the board last August. We’ve been working on it in the earnest since last October. In fact, if you go back even further we were seriously considering restructuring back in 2008 about the time when financial markets collapse.

Next question, why are we announcing this now? We chose to go public a week ago and felt we had to for several reasons first. We have to right size the balance sheet of the two new public companies and to do that we have to work with our banks in the rating agencies. You recall that we issued long-term debt in three subsidiaries including Questar Market Resources.

To separate and spin off our E&P business, we would have to first move Wexpro out of QMR and up to the parent Questar Corp. Then we would have to spin QMR without Wexpro i.e. E&P Co out to Questar shareholders and in doing that we would trigger covenant provisions in Questar Market Resources, public debt and other credit agreements. We may have to offer to purchase QMR bonds under the changing control provisions and we have to renegotiate QMR and Questar Corp. credit agreements to do both of these, we have to put new credit facilities in place.

So to keep this transaction moving forward, we need to begin negotiations with our bank group now. And once you start talking to a large group of banks you are effectively going public whether you intend to or not. In fact, we were reviewing the proposed transaction with our lead arranger banks on April 21, in Houston in about the time we push the same button on our press release.

Second, we’ve got a lot of work to doing internally to separate in E&P Co from the rest of Questar. As I would mentioned that we’ve operated as an integrated company for 80 years, we got to put new policies, systems and practices in place before E&P Co can conduct businesses as a standalone public company.

As such, we felt we reached a point in this process where we need to get a lot of our employees involved to help us do all of this. So, it’s time to tell all of our employees what we’ve been working on.

Third, mindful that this transaction is still subject to board approval. We expected that our announcement would help validate the core premise and that is that a separation of our E&P business should unlock shareholder value. We will let you be the judge and whether or not the market’s reaction to the announcement is validating that.

Four, we need to engage other key stakeholders for example, we have reviewed this proposed transaction with both Moody’s and S&P as you may have seen both agencies issued press releases on April 22. We are meeting with both agencies in New York next week, and we’ll also brief state regulators and other state officials

Next question, what are the other conditions precedent? Well, an addition this final board approval this transaction is subject to a private letter ruling from the IRS confirming that the spin off of the E&P Co will not be a taxable event for Questar shareholders or the company. Please note that we submitted our request for the PLR couple months ago.

Depending on IRS workload it can take two, three months or longer to get a PLR. Our outside counsel has maintained an ongoing dialogue with the folks inside the IRS who are processing our request.

As to other conditions precedent obviously, there are unforeseen market events beyond our control for example, if there would to be another collapse of the financial markets more credit market terminal etcetera any of those unforeseen events could affect the timing of a transaction.

Our next questions why not wait until natural gas market fundamentals improve. Well various fundamentals in the U.S natural gas market today various market conditions are clearly a consideration, but this is about long-term strategy, not about timing the market. It’s about creating two top tier companies that we think will be well positioned to complete in very different segments US natural gas market and to do so throughout commodity price cycle.

I think most of the analyst on the sale side that published research on Questar over the past several years with likely adjust that the chronic gap between our share price and some of the parts market valuation as existed pretty much in both high price and low price environments and we think this gap is really the consequence of that transformation of Questar into predominantly in E&P company.

Impact, inside the boardroom I have described that Questar today is being stuck in the middle. Too much E&P from more risk investors, but too much non-E&P for many E&P investors.

Many institutional investors who would like to own a company like E&P Co are perhaps being deterred by the complexity of our corporate structure and in turn yield in investors who might find a company comprised of Wexpro, Questar Pipeline and Questar Gas compelling investment can do shy away from Questar Corp today because of the inherent risk in volatilities that results from our ongoing emphasis on growth in our E&P business.

So simply what we believe this transaction could eliminate and unlock value for shareholders over the long-term irrespective of what happens to natural gas prices in the short term.

Next question, would this transaction require the approval of federal or state regulators.

Now, a spin-off of our non-regulated E&P in midstream fielded services business would not affect the corporate structure of either Questar Pipeline or Questar Gas, both would remain subsidiaries of Questar Corp. The transaction also would not affect Questar Gas customer rates or service, know what it impact the utilities, unique relationship to Wexpro under the Wexpro agreement.

In fact, we think the transaction could benefit Questar Gas customers over the intermediate longer term. Just one example, as you may have noticed after our announcement, S&P plays the BBB plus senior unsecured debt ratings to both Questar Pipeline and Questar Gas on credit watch with positive implications.

We’ve assured local officials that Questar Corp. would remain headquartered in Salt Lake City and would remain committed to the same corporate citizenship that’s been a hallmark of this company for eight years. Now all of that said, we have restyled to both Utah and Wyoming regulators in the spirit of partnership mindful that their stakeholders in this transaction, they have a duty to look after the interest of our utility customers and the community.

We’re going to keep them appraised as we move forward, but I repeat this transaction does not require regulatory approval and I should add nor does it require shareholder approval.

Final question, and then we’ll go to Q&A, when we are only going to name the management teams, we would name the management teams once all precedent conditions have been satisfied and we get final board approval to move forward with the transaction. So let me summarize, a separation of our high growth in E&P and Midstream Field Services businesses from our mostly regulated businesses may be a logic step in our long-term strategy that has served all Questar stakeholders pretty well over the past decade.

As transaction is still subject to final board approval but now may be the time to take that step. We’ve got lot of work to do but the roadmaps are in place. Few stakeholders have been engaged we are putting a lot of effort and tried into what could be a momentous step in the history of this 80 year old company. With that operator let’s open it up for questions.

Question-and-Answer Session

Operator

(Operator Instructions). The first question is from the line of Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs

Can you talk in more detail on the Haynesville just specifically with regards to the chokes or the modified flow backs? What do you seeing some of those wells whether it’s the ones you announced to any prior wells that you choked back and what are your current views on EUR implications?

Chuck Stanley

We would view the results from this list of wells that we turned to sales in the past quarter its being comparable to the earlier wells that we completed and reported the higher rates and 20 million to 30 million cubic per day initial rates. These wells are being substantially choke back we are attending to minimize draw down at the formation in order to avoid any damage sort of reservoirs.

We have a small group of wells that we are practicing this modified flow back procedure on today and what we see is at any given point on the cumulative production curves a higher falling bottom hole pressure compared to wells that we flow back basically unconstrained. So after recovering a Bcf of gas, we’re seeing a 15% to 20% higher in flowing bottom hole pressure compared to a well that flowed back hard initially.

We don’t know exactly why, this behavior is occurring, but we suspect it’s a combination of more evenly de-watering the fractures along the entire length of the lateral potentially avoiding closure of the near well bore fracture and allowing for a complete dewatering and flow back of the entire length of the fracture and a few other sort of thesis on why it works, but the empirical evidence seems to suggest that these wells over the long haul going to recover more of gas than the well has floated back hard initially, because of lack of damage of total incomplete dewatering of the individual fractures.

Brian Singer - Goldman Sachs

When you think about the new curve or E&P curve, which would have the unregulated gathering and trading biz gathering processing and trading business, how do you think about production growth in the context of capital spending versus cash flow? How does the cash flow from the gathering, processing and trading business play into higher thinking about CapEx versus cash flow?

Chuck Stanley

First of all, we believe as Keith mentioned in his comments that the midstream field services business is integral to and complimentary with our upstream business, for a couple of reasons: One, in our core areas, at Pinedale, Haynesville, we believe that owning and operating infrastructure lowers our overall operating costs, allows us to pre-build our systems in anticipation of growing production volumes and these large gas processing facilities that we have under construction in particular the Blacks Fork facility in Western Wyoming, which has the largest gas field and the rockies dedicated to it for life will represent a long-term opportunity to generate significant cash flow that we can reinvest in our upstream business.

So we’re extracting additional value from the wellstream coming from the Pinedale Anticline production and these projects represent fairly lumpy, there are large initial investments and then they become an enduring long term source of free cash flow to support other parts of our business. So when we think about the cash flow from our midstream business, when our Blacks Fork 2 plant comes online in 2011 and in combination with the Iron Horse plant, which is down in the new innovation.

We’re anticipating a near doubling of EBITDA out of our midstream business, because of the large amount of liquids it will recovered from those plants and that’s in combination with the other ongoing expansions of our system that we have in process or planned over the next several years.

So with that additional source of cash flow and looking at our five-year plan we’ve already told you that we believe that we can grow production in the 12% to 15% annual production growth over the next five years. Our five-year plan on forward prices shows a significant amount of free cash being generated from our upstream and midstream field services and trading businesses over the five years.

Keith Rattie

We gave a lot of thought internally to where gas management or midstream business should fir in this separation and we concluded that not in addition to the operational factors that Chuck has reviewed the way it has been integrated into our E&P activities, we felt that the best way to approach this was to put the commodity businesses together and more fee-based businesses together and granted in the first quarter of this year Gas Management, 78% of its operating revenues came from fee-based activities, but as we build these new processing plants, that more of it will be exposed to the frac spread.

Chuck Stanley

By the end of 2011 about half of our EBITDA stream will be coming from commodity side of our G&P business from the liquids recovered in our plans, obviously part of the processing strategy is a play on the differential between oil and natural gas prices, which enhanced the economics of process.

Operator

Your next question is from the line of Carl Kirst of BMO Capital.

Carl Kirst - BMO Capital

Few questions, just Keith with respect to the timing of the spin post the private letter ruling. The Board of Directors approval, is that actually become the last step such that the spin happens you know immediately posted to the board, does the Board approve and then you go off into effectively renegotiating your letters of credit et cetera I’m just curious how that timing works?

Keith Rattie

We’re working those in parallel. I will let Richard give you a little more color on the process of restructuring our balance sheet. Let me just give you the basic timing on this Carl. The board approval, if we get final board approval with probably the subject to finalization of some material agreements which of course would include the credit facilities. But once we ask the board and presumably get final board approval, the clock would really start rolling. In earnest we will be getting ready to get the roadshows of the two respective management teams and would not long after that likely announce the X dividend date and the transaction date.

Richard Doleshak

We are going to go ahead and launch the syndication of the credit facility at the Questar Corp as soon as we get board approval, we have already got the lead rangers working on it , but the broad syndications won’t happen until after we get the board approval and the same thing with the amendment to the QMR credit facility,. We are talking to the lead banks about how we want to amend it, we won’t launch that general amendment process until after board approval.

Carl Kirst - BMO Capital

A follow-up from Brian’s question, the Haynesville check. How long do you need before you get comfortable that we actually will ultimately see higher recoveries? Is it another few quarters? Is it another few years? I mean, what's that point that gives you extra comfort that the modified flow back will indeed give you better results?

Chuck Stanley

I guess that totally, intellectually honest answer is, after the well has been depleted, one can surmise from a basically cumulative production versus pressure plot that if a well after recovering say 50% of its projected reserves as a higher flowing pressure than one that has been unconstrained, that the ultimate recovery

Of course, we can’t predict what will happen 10, 15 years from now, but if you look at it just from an MPD or present value perspective, you quickly overcome the apparent higher economic value of having well that will produce at 30 million or 40 million cubic feet a day for a couple of months and then decline very rapidly versus one that you constrain at 10 million or 15 million cubic feet a day and let it basically plateau for that period of time.

If you recover another Bcf of incremental reserves from the well, there is this concept from my youth about maximum efficient rate in oil and gas facilities and you can spend a lot of extra capital on well site facilities, separators, dehigh equipment, et cetera to accommodate a flush production rate of two or three times the stabilized rate on these wells and the economics for putting out additional facilities, additional top site facilities to handle a couple of months 25 million cubic feet or 30 million cubic feet a day rate, are quickly consumed when that well comes off at a fairly high decline rates. So we’re trying to not only manage production to avoid reservoir advantage, but we’re also trying to optimize returns here by focusing on the rate at which we generate the highest returns at any given gas price for the shareholder.

Carl Kirst - BMO Capital

Just trying to better understand how we are targeting the next few wells of the Granite Wash. I know there are several different targeted zones, obviously Colony, Panhandle, et cetera. Is each separate area targeting one specific zone? I'm trying to get a better understanding for the risk reward. Is it possible that one area, one zone could work, but perhaps in the same area another zone wouldn't? I'm trying to get a better sense of perhaps the risk reward of the next few wells and kind of where are we in the science project of this?

Chuck Stanley

A couple of key concepts, you were talking previous discussions that there is a vertical segregation of the shallowest horizons, the Cherokee, the Caldwell, the two zones that we’re targeting and the first couple of wells tend to be liquids rich and we saw the results of the [Perrier] well. We’re not happy with the well, because we still have some of the frac zones that aren’t open to the well bore. We still have some junk in the well, but it shows the productive capacity of over $10 million a day and 600 barrels and all that.

In should point that that 1400 plus Btu gas stream is the equivalent of another 1600 barrels a day or of liquids. So this is really a 7 million cubic feet a day, dry gas well and a 2200 barrel a day liquid producer, which is a pretty substantial component value in the liquid stream.

The shallower zones tend to be liquids Rich, Carl. The distribution of those zones, we need some more sub-service control, but we’re pretty sure that we have the shallow liquids rich horizons present over a large part of our acreage, you will see that the wells that we’re currently drilling at this home well and particularly down in the southern part of our acreage shown on the slide eight from our ops release. That is targeting the Atoka section, which is the deepest horizons in the Granite Wash and it tends to be dry. We have to drill with deeper section in order to save the leases, so that we will hold by production in the entire section above the Atoka.

Carl Kirst - BMO Capital

Chuck, are these well being twinned? Or just Atoka only?

Chuck Stanley

We’ll drill the Atoka first, sales productions from the deepest horizon the Granite Wash interval and that will hold that interval and all of the shallower intervals under the lease and then after the lease is held by production, we can come back and target shallower horizons. So, there’s a variety of targets out here anywhere from, four or five targets in some areas to over a dozen targets in other parts of our acreage and we’re targeting the intervals where we have the best control.

We wanted to build some shallow wells to establish the presence of our productivity in the shallower section in the Caldwell and Cherokee zones, So Morrison is targeting a Cherokee horizon, which is just below the Caldwell, Edwards rather is targeting the Cherokee horizon, which is just below the Caldwell. The (inaudible) was in the Caldwell. Those are the liquid rich zones. The (inaudible) home well is targeting an Atoka interval as is the Morrison well. We will continue to evaluate the shallower horizon after we basically prove up all of our leases and are able to hold on to our leases by production.

Operator

Your next question comes from the line of Gil Yang with Bank of America.

Gil Yang - Bank of America

Just follow up on that questions or the answer. I wasn't clear. You're drilling into the Atoka with the verticals or horizontal well?

Chuck Stanley

All of these are horizontal wells, but the basic concept of few clause in some of these were variant. We drilled to the deepest horizon that we believe is perspective and by establishing production in that deepest horizon, we hold all of the other intervals above it by production and then we can come back after we build up the deeper section and develop the shallower sections

Gil Yang - Bank of America

How many horizontal Atoka's do you need to drill to hold your position?

Chuck Stanley

I don’t know probably 15 or 20. Some of the sections already have vertical producers in them and those wells hold the portion of our leasehold.

Gil Yang - Bank of America

Was the mechanical problem related to the formation at all? Or was it just sort of a one- off type thing that happens occasionally?

Chuck Stanley

I think everything that one can conceive, it could wrong, with the [Perrier] well went wrong with it, the Caldwell zone which is the shallowest horizon out here, tends to be the lowest pressured, there was some offset production from a couple of old vertical wells that we think may have introduced some partial depletion into the reservoir, but the rock quality in the Caldwell is excellent, the porosity and permeability from the samples that we recovered.

We’re not sure exactly what happened, we were basically drilling out the frac plugs in the well and the coil tubing and motor got stuck. We suspect that it was a piece of a frac plug that basically wedged or key seeded us in the lateral. We fished on the coil tubing, basically for over a month we were able to basically extract all but a few hundred feet of coil tubing and motor,

We then kicked the well off and it started flowing. We now think that after the well closed for a while and we cleaned it off, we still go back in and fish the remaining portion of the coil tubing, motor out of the hole. There is going to be a lot of debate I’m sure in our shop as to when we take that risk because every time we go back in and start fishing, you put your existing production at risk, but at some point we're going to have to get that stuff out and go ahead and drill up those last three frac plugs.

We’re not the only ones that have experienced problems with the shallower horizons with having coil tubing and motor stuck in these laterals and it’s a long distance. The initial flow back of these shallow horizons doesn't generate a lot of volume to flush the well to keep the plug parts and sand moving. So there is a lot of risk of getting stuck. So we’re talking about strategies that we can use to help mitigate the risk going forward in the shallower horizons. I think it's a matter of experience. So I have all the confidence in the world that our team will figure out how to do it as we gain more experience in the area.

Gil Yang - Bank of America

In the Haynesville, I guess you don't have an indication yet how much higher (inaudible), but could you venture a guess?

Chuck Stanley

I would guess that there is Bcf or more incremental recoveries from these wells just based on what we are seeing. And we have been pretty conservative in our initial booking of the wells and we believe and it is our hope that overtime as these wells continue to perform that we will be able to increase the reserves assigned to the PDP wells, approved as oil producing wells and that will ultimately influence our view of the proved undeveloped locations.

As a reminder our average producing well on our acreage in the core of the Haynesville, it’s booked at about 6.8 Bcfe, our gross basis, all of our proved undeveloped locations booked at 6 Bcfe. We’ve only assigned two development locations at 648 per unit. So, we’ve got a lot of room to increase reserves in our Haynesville property as we gain more confidence in well performance which will ultimately dictate the reserve assignments in the proved developed producing wells and also more confidence in the ultimate spacing of the wells and add additional PUD locations in each individual unit.

Gil Yang - Bank of America

And just to finish up on that, how should we think of the decline curve for the wells on restricted flow rates? Is it flat for six months and then starts to decline? Or is it just a sort of exponential decline through it's whole life or is it still hyperbolic early on?

Chuck Stanley

They exhibit basically a plateau period, they are basically are flat and so, flat reductions, declining pressure and then after six months or slowly break over and then they follow the normal hyperbolic decline curve that we described previously for an un-constraining well and ultimately they will applied now into next initial decline after after several years.

Gil Yang - Banc of America Merrill Lynch

Okay, and do you then at that six months breakpoint, the plus or minus obviously but at that six months breakpoint do you then let it follow unconstrained like you would normal or you still restricted it?

Chuck Stanley

Well, in absence if you hold a constant choke with flowing pressure decline ultimately the well will behave hyperbolic decline curve with a constant choke, so it in essence makes its unconstrained production performance after six months plus play plateau or so.

Gil Yang - Banc of America Merrill Lynch

Okay

Chuck Stanley

We don’t anything to open the choke on the well; we just let it basically start to decline naturally, when it does.

Operator

Your question is from the line of Rebecca Followill of Tudor, Pickering, Holt.

Rebecca Followill - Tudor, Pickering, Holt

Two questions for you. One, what will be the hedge policy on E&P Co? Will you put on additional hedges before you do a spin? Or just stick with what you have?

Keith Rattie

We wouldn’t put hedges on slowly because of the transaction Rebecca. Hedge policy as opposed to separation were at likely be different than the policy that you’ve seen from us going back to its inception in 2002. But probably would hedge laps at least in the near term going forward and may use different types of hedge instruments to reflect the different perspective for an appetite for risk

Rebecca Followill - Tudor, Pickering, Holt

Okay, thank you. And then, I know people have asked several questions on the timing. But just so I'm clear one more time, to beat a dead horse, first thing really critical is the Private Letter Ruling. And, at that point, once you have it do you go back to the board and that's when you get the go ahead? Or is there some other precedent before there is board approval?

Keith Rattie

Rebecca, we’re working in all of those precedents that I described more or less in parallel, the ongoing discussions with our banks about the debt restructuring in QMR obviously we would want both these entities to start live at with appropriate balance sheets for the respective market segments.

But those are the two primary considerations and the reality is that we are going to look at all of the issues in totality and when we think we’ve addressed the key elements and we have put visibility on our ability to go ahead and implement and that’s when go to the board for final approval.

Rebecca Followill - Tudor, Pickering, Holt

As far as public announcements, what should we expect out of you, though, will you announce that you've received the Letter Ruling? And what are the next announcements that we should look for?

Keith Rattie

We would not publicly announce that we’ve received the Private Letter Ruling. We don’t want to put undue emphasis on that of getting condition for the transaction. A lot of things could happen but my debt response to the question is you probably won’t see another press release on us until us going back to the board.

Operator

(inaudible) of Barclays capital.

Unidentified analyst

First, can you give us a little bit more clarity on the targeted capital structures for both the [Spinco] and the pro forma Questar Corp.? And then, related to that, to the extent you can control the ratings outcome, what are your thoughts on high yield versus investment grade at the E&P [Spinco]?

Richard Doleshek

Okay, well I would love to be able to the control the ratings of the agencies, but we’re going to see then, we preview the transaction within the last week, we’re going to go see them next week and walk through what our plans are in terms of capital spend and capitalization. And as the press releases from the agencies said, Moody's went ahead and affirmed the rating of the gas company, the pipeline company and the commercial paper rating at the parent and put the QMR debt on a negative watch.

S&P indicated a positive outlook for the gas company, pipeline company and negative outlook for the E&P company, and clearly if Moody’s being at BA3 any negative implication would take it to non-investment, and I think QMR companies to non-invest investment grade.

So we’d love to be although tell a compelling story, I think the biggest issue that faces the E&P company is scale, if you look at the credit metrics that exist today, I can do a math too in investment grade level, but the size the operation is scope of the operations just I don’t think get us across the total but we’ll make our cases wherever they come out.

With regard to the cash structures, I think it’s fair to say that, what we have in terms of bilateral lines at the corporate level, we needed to expand those a little bit just to make ensure we have adequate working capital for what’s going to go on in those operations. With regard to the E&P company, I think the capital structure that you see today the $800 million revolving credit in the $1.15 billion of notes a part doesn’t changed much after the spend.

Unidentified Analyst

So is it fair to say you are comfortable operating the E&P business at the high yield category?

Richard Doleshek

It is and we certainly have planned in mid assumptions that we aren’t able to maintain that’s investment grade rating and will be a cross over credit, a high non-investment credit cross over credit

Unidentified Analyst

Okay. And I guess that begs the question, S&P? Do you have a sense of what they were thinking there? Do they are up to BBB plus, because they rated under a different methodology?

Richard Doleshek

Exactly and if they are three notches downgrade to get to BB plus. And again we don’t have any getting indication from them and what they are thinking in terms of that multiple notches they did say the words multiple notches in their press release, so my guess there is that even if we were split rated investment grade, non- investment grade we’re going to treated like an non-investment grade company

Operator

The next question aligned of Ray Deacon with Pritchard

Ray Deacon - Pritchard Capital Partners

Chuck, I had a question about the Cana, and just was wondering is your gas, is it wet gas there? And do you get about 30% above NYMEX? Does that sound right? And I saw that one-off increase their plants to process in the area. I was just wondering what you see as the potential there for production over the next, four years, or five years?

Chuck Stanley

Really a great question. Our acreage basically spans the entire play. The center of our acreages and where you see all of the current drilling activity on slide six and our OPS release is sort of in the heart of the wet gas fairway as you go to the south and west also if you draw a diagonal line across the northwest corners to the southeast corner of the map and as you move off to the southwest corner of our map that the gas gets drier and drier to the point were the liquid yield is negligible.

As you go to the north and east, outside of the current fairway where a lot of the activity is occurring. You see a couple of wells have been drilled over there. It’s basically an oil play. The dominant phase is oil. There is a large component of condensate and in some instances we think black oil or volatile oil updip. So in the heart of the play, this is 1200 Btu gas, you get at the current sort of gas to oil and NGL ratio.

You get a 25% or so uplift in the realized aggregate wellstream pricing as opposed to the dry gas stream. As you go downdip, the uplift becomes less and less, which is why I think you see industry activity concentrated in the center of our map there. We have one rig working in this area, at any given time we have anywhere from 15 to 20 outside operated wells in various stages of drilling and completion.

We are participating in a large number or in a fairly high percentage of all the wells being drilled in this play at some working interest. Now our working interest, averages a little under 18%, about 17.7%, so we get a lot of outside operating proposals. We participate in wells anywhere from a 2% interest up to 25% or more, but on average about 17.7% working interest. We see this play being a significant future contributor to our production stream and to our cash flow.

Ray Deacon - Pritchard Capital Partners

Do you see any near term resolution to the permitting issue in the Bakken? And could you move to a two rig program in 2011 or any thoughts there?

Chuck Stanley

Without being completely committal we believe that we’re seeing more and more permits pop out of the (inaudible) affairs in North Dakota. We’re hopeful that we can put a second rig out there in the third and fourth quarter of this year. We certainly don’t want to stand up a rig and drill a couple of wells and then lay the rig back down. We want to be sure that when we add a second rig, that we have a sufficient number of permits in front of that rig, so that we don’t have to start and stop because that’s not how you gain efficiencies and how you learn how to drill these wells quicker and cheaper.

The other thing facing us is just the delineation of our leasehold. By that time we should have a couple of three more wells down, which will help us understand two things: One is the distribution of the middle Bakken fairway which we believe covers most of our acreage although the eastern edge of our acreage still remains to be tested and you can see on our latest investor update or operations on slide nine, the Bakken and you can see, some wells overrun the extreme eastern portion, to the east of our actual leasehold block that are colored blue.

Those wells are 500 barrels a day or less, so they’re starting to define the eastern limit of the fairway. we’re seeing our wells close to a 1000 barrels a day, the first several wells and so, we know that the fairway sort of threads along the eastern edge of our block to the middle Bakken.

Right now, we are currently drilling our Three Forks test and we believe that a portion of our acreage maybe up to half of it is prospective for the Three Forks. We need to sort of understand the distribution of the Three Forks and the middle Bakken fairways so that when we go in for full field development, we basically set up a rig on a pad. We build a horizontal lateral in the middle Bakken and then we skid the rig over just like we do at Pinedale and drill a basically parallel, but deeper Three Forks well. To minimize rig moves, optimize fracing and completion and facilities and also minimize our footprint out there on the ground, especially adjacent to the lake where topography is a bit of a challenge especially on the western part of the acreage.

Operator

Your next question comes from the line of Vivek Paul with Knight Capital.

Vivek Pal - Knight Capital

Real quickly, it seems like the proforma leverage on the spin off entity is going to about 1.5 times, given that you’re expecting $1 billion EBITDA and a 13% to 15% debt, is that a fair number?

Keith Rattie

Yes, I think we haven’t rolled out what the capital structure is going to look like for the E&P Company we spin it off, but again we think that the leverage level is going to be probably a bit lower than that on a spin-off basis.

Vivek Pal - Knight Capital

It seems like you are hedge 75% for next year, a little over five, so you still expect about 840 I believe is your mid range for the E&P business?

Chuck Stanley

Vivek, our hedge level for next year is about 50%.

Vivek Pal - Knight Capital

I mean for 2010?

Chuck Stanley

For 2010, it’s 75%, right. We gave EBITDA guidance in our earnings release for the remainder of 2010. We’re in a 840 to 870 range for most of our E&P.

Vivek Pal - Knight Capital

And for next year you are saying about 15% edge? Will you unwind some hedges just because you want to be less hedged? Or you are going to stick with what you have?

Chuck Stanley

I think we will stay where we are, the hedges are in the money, so keep in mind that when you look at our hedged position, fairly unique in the way we report them. We report them as net to the well hedges, so they include the basis differential and the processes.

They were put on at a higher price and they are in the money. We would not unwind hedges just to free up cash. We leave our hedge position in place. You heard Keith answer the question earlier, philosophically as a E&P company, we understand that investors in part buy the stock for exposure to commodity prices, but as a low cost producer and as a resource player with drilling programs that are dependant upon sort of a levelized activity to really drive efficiencies through our operation in places like Pinedale, Haynesville and other place.

We believe that a hedging program helps a sure minimum level of cash flow is necessary in order to really become a premier and we believe we are a premier. A low cost developer and producer of gas and oil. To draw your attention and for the first time in our press release, we’ve disclosed hedges in 2012 and 2013, you will see that on a net to well basis. In 2013 for example, we hedged almost 50 B’s in the Rockies at net to the well number about $6.

Those were put on sometime ago at an environment where NYMEX was close to 7 and the intent there was to protect our development program at Pinedale.

Vivek Pal - Knight Capital

Given that your leverage is going to be fairly low, are you thinking like some of your other peers in the space to look more into oil assets and in terms of M&A. Have you thought about it because it seems like you already will be 4b or 5b credits so, with the ratings out of the way, do you think it's time to actually make some acquisitions and diversify into oil or any thought processes on that?

Chuck Stanley

I begin to wonder, if there are enough oil assets in the world for all of the (inaudible) to satisfy their appetite. If we have a couple of oil plays in our portfolio that we’re working on. We’re not quite ready to talk about in detail, because we’re actively acquiring acreage. We also have a long-term oil project in Uinta Basin in the shallow Green River sands and carbonate intervals where we have one rig active right now drilling horizontal developmental wells.

We’re actually reentering old vertical wells and drilling horizontal laterals to target thin conventional reservoirs, conventional meaning we don’t have to fracture and stimulate them, but we’re seeing excellent results from that program. We are pushing the limits of that play in the areas where there are no vertical on our wells and we’re seeing encouragement there as well.

The other activity that we have in our portfolio as I mentioned earlier are large processing plants under construction, which are really a fundamental play on the differential between oil and gas prices, or in this case, natural gas liquids and gas prices in our Gas Management field services business as we extract liquids from the gas stream that would otherwise be sold as methane. Enjoy the uplift and value associated with that processing business.

Vivek Pal - Knight Capital

Is there potential for any compensation to the Questar entity for spinning off Wexpro. Because when you were doing the Market Resources bonds, when you were issuing them, Wexpro was part of the deal. Now it's not going be part of the deal. Is there potential for anything to make the bondholders feel better about investing in the company?

Chuck Stanley

Yes, there’s really no consideration for the distribution of Wexpro out of QMR to the corporate entity. It just given the right assets in the right location and certainly you try to say what’s the value of Wexpro, lots of valuation issues and so, there’s no consideration for Wexpro distributed to court before the E&P companies spun out.

Vivek Pal - Knight Capital

And the change of control? It will the be triggered if one of the agencies put you to below investment grade, right? That's your compensation, I guess?

Chuck Stanley

That’s correct. The change of control provisions, it’s a two-step process. One is the shareholder of QMR and the second one is the downgrade.

Operator

(inaudible) with Raymond James.

Unidentified Analyst

Just a quick question. How many wells in the Pinedale do you have waiting on completion right now and how does that compare to last year?

Chuck Stanley

I can’t tell you the exact number that we have, about 25 wells, either waiting on completion or that we are working on, we work on wells. We work on multiple wells simultaneously on a pad, so that inventory is about the same as last year. In fact, it may be a little less at the time of the year than it was last year, because we got started a little earlier on the completion schedule, because the weather was better this year than it was last year in late March or early April, and we were able to get out on a ground start for asking the wells sooner than we did last year.

Unidentified Analyst

When did you start fracing that wells in the Pinedale this year? Or are you planning on doing?

Chuck Stanley

We basically got out on the ground in early March, I can’t remember whether it was the first week or early in the second week, but in the first half of March, we were out on the ground. Last year, I don’t believe we actually got on the ground until April sometime, mid-April?

Unidentified Analyst

Got you. And then one other question. In the Granite Wash, can you talk about the difference between the Caldwell and the Cherokee formation? I'm not sure where they stack as far as depth. And would you expect on liquids?

Chuck Stanley

The Caldwell is the shallow as those our Granite Wash horizons and you’re challenging my memory here. I wish I had a mid-continent the geologist sitting beside me is little of land man. James he is sitting here and he doesn’t remember either. So you got Caldwell and them immediately beneath it is the Cherokee and then you down into a 100 other local names that I can’t remember, especially when you putting me on the slide like this and then you get down into the Atoka washes, which are the deeper section. And there is a different name for every ranch and every forum out there depending on where the first well was drilled, where that sands recognized? So the shallower stuff is the liquids rich oily parts of it.

The Caldwell being shallowest in the Cherokee and there’s two or three other zones and I can’t remember the names other than you get down into the Atoka washes, which were basically dry gas. There’s very little liquids content, there’s a slightly higher VDU content, but it’s not appreciable it doesn’t have a lot of uplift. Over in Oklahoma, the Roxanne well that we just resold that on in our previous rock sand well, those were build in what’s was the called the Colony Wash, which is a shallower Granite Wash section tends to be in liquids of this. The Atokan section in Oklahoma is not as well developed. So the primary target in Oklahoma is the shallower Colony Wash. Does that help?

Unidentified Analyst

Yes, that did. So, the Cherokee and the Caldwell, as far as liquids contribution that you're expecting, may be a little bit less than Cherokee but not significantly less? Is that fair?

Keith Rattie

I think that the liquids content in the Caldwell and Cherokee are very similar, relatively similar. As you go deeper in the section into the Atoka section, which is the where the two wells are currently drilling or targeting the Morrison and Methodist Home well. We’re targeting Atokan section that well is 1500, 2000 feet deeper and it is drier, negligible, free liquids and a lower Btu gas than the 1400 Btu gas. So we reported in the Perrier well.

Ross Payne - Wachovia Bank

Yes. This is Ross Payne. Quick question for you. As you looked to right size of the balance sheet, it looks like the regulated Questar is perhaps under levered. Does it make sense to throw some more debt onto it and throw some cash towards the E&P operations so it can grow quicker?

Richard Doleshek.

Ross, this is Richard. Again, we’re trying to make sure we get the capitalization right and the primary objective, with regard to regulated companies is to make sure we keep or increase their credit range because their cost of capital is very, very important and so we’re going to make sure we don’t over lever this guys when the spin occurs and we’re still working on the final capital structure and that will be one of the details that we announced when the board finally increase the transaction.

Ross Payne - Wachovia Bank

Okay, and on the Questar Resources side, are you amending or you redoing a bank facility? And do you anticipate that to be secured or unsecured?

Richard Doleshek

We’re amending that credit facility and it’s contemplated that it will be unsecured on the go forward basis. We’re trying to keep all the debt structure at QMR on an unsecured basis.

Ross Payne - Wachovia Bank

Okay. The 150 that’s coming due in 2011, you expect that to be a bond deal or financed through the bank facility?

Richard Doleshek

Our guess is that, we would refinance the maturing our long-term indebtedness with long-term indebtedness and we’ll be happy to read that piece of paper to 7.5% coupon so that’s the highest piece of cost to debt in tomorrow’s debt structure today.

Ross Payne - Wachovia Bank

Okay. Finally, you may have a shot with S&P, how hard are you going to fight for that? And how realistic is it in your opinion?

Richard Doleshek

Again, that the conversations that we had with the agencies have been very constructive. They certainly understand what our position is in terms of what the leverage of the companies looks like. We’re going to make our best effort in our best case, with regard to having a resource base with the E&P company that we don’t need to make acquisitions, we can grow it on sound, and then I think the piece of it probably haven’t focused on is the gas processing business and how much of that is fee driven; how much of that is liquids driven.

And I think, when we got to talk to them we’ll make sure they understand that it is not just a drilling developed company, which got another laid to it and that support the credit structure. So we’ll work hard to try to get them deceived at our ways. We will see what happens.

Operator

Follow-up questions from the line of Gil Yang of Banc of America.

Gil Yang - Banc of America

Chuck, looking at slide six from your presentation today. In the Cana, you went from 26,000 acres up to 29,000 acres net. And, that’s roughly I think 10%, 12% increase in acreage, something like that. But your unbooked location count went up by 25%. What happened there? Was there any de-risking? Or is there just some funny working interest issue there?

Chuck Stanley

Part of this is just the ongoing de-risking as we drill more wells and we get a better sense for the gas in place and ultimate recovery on a per section basis and we’re feeling more comfortable that the ultimate spacing out here will probably be 80 wells per 640 acreage unit.

Gil Yang - Banc of America

Okay. So can you boil the 1900 locations down to, is that 80 acres? I did that math doesn't work either. But it's sort of, some of its 80 and some of its 160 and depending on which region, how much of each you get is total number of locations?

Chuck Stanley

I think the other source of confusion here. We’ll have to address this. The 1900 is a gross location count. (inaudible) acres is a net acreage account. So there is really it’s impossible for you to do the sort of the empirical relationship that you’re trying to do between gross location counts. We may have a 1% interest in a section and have a 1% at gross locations. The proportionality of increase in net acreage and locations interest is shouldn’t be obvious because it isn’t obvious to you. There is no direct relationship between the net acres increase in number of those locations.

Gil Yang - Banc of America

I would agree that it may differ by a little bit, but they shouldn't off by, they should be pretty close, I would think. The proportionally, the changes should be pretty close.

Chuck Stanley

It depends how many net acres are there in a unit. You can one net acre in a unit and basically has and eight gross locations but only have 1640 up of an interest in that unit, so again, the proportionality is not necessarily given.

Gil Yang - Banc of America Merrill Lynch

Okay. I understand. Maybe we could talk about it offline a bit. Thanks.

Operator

(Operator Instructions). At this time you have no further audio questions, I would turn the call back up the Keith Rattie for early closing remarks.

Keith Rattie

Well. Thank you, operator. We appreciate everyone with me listening in today. You can get a replay of this call on our website www.questar.com. We also are available to answer any of your questions thanks for your interest in Questar.

Operator

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

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Source: Questar Corp. Q1 2010 Earnings Call Transcript
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