Questar Q4 2008 Earnings Call Transcript

Feb.12.09 | About: Questar Corporation (STR)

Questar Corp. (NYSE:STR)

Q4 2008 Earnings Call

February 12, 2009 09:30 AM ET

Executives

Stephen E. Parks - Senior Vice President and Chief Financial Officer

Keith O. Rattie - Chairman, President and Chief Executive Officer

Charles B. Stanley - Executive Vice President and Chief Operating Officer

Jay B. Neese - Senior Vice President

Analysts

Shneur Gershuni - UBS

Joseph Allman - JP Morgan

Brian Singer - Goldman Sachs

Sam Brothwell - Wachovia Securities

Faisel Khan - Citigroup

Carl Kirst - BMO Capital

Becca Followill - Tudor Pickering & Co.

Sunil Jagwani - Catapult Capital Management

Operator

Good morning, my name is Katherine, and I will be your conference operator today. At this time I would like to welcome everyone to the Fourth Quarter Year-End 2008 Earnings Release Conference for Questar Corporation.

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

I'd like to now turn the call over to your Chairperson, Senior Vice President and CFO, Mr. Steve Parks,

Stephen E. Parks

Thank you, Katherine. Good morning this is Steve. I'll briefly summarize our strong financial position this morning results for the 2008 and then turn the microphone over to Keith Rattie, our Chairman and CEO.

Keith will provide more color on our results, comment on our outlook for 2009 and give an important update on recent well results. After Keith we'll invite your questions. Other members of Questar's management team are here to answer your questions including Chuck Stanley, President and CEO of Questar Market Resources, Allan Bradley, President and CEO of Questar Pipeline and Ron Jibson, President and CEO Questar Gas.

Our remarks this morning will contain forward-looking statements about the future operations and expectations of Questar Corporation. We make these statements in good faith. We believe they are reasonable representations of the company's expected performance at this time, but actual results may vary significantly from our current expectations and projections due to a variety of factors that are described in our Form 10-K filings with the Securities and Exchange Commission.

Now starting with our strong financial position, Questar's combined short and long-term debt was 41% of total capital at December 31, 2008. The company has $365 million of short-term lines of credit available to support our commercial paper program of which 78 million is currently drawn. In addition market resources currently has 300 million of capacity available under a long-term revolving credit facility. We believe we have sufficient liquidity to support our operating and capital investment plans through 2009. To build some additional liquidity we may issue up to 300 million of five to 10 year debt under our existing market resources shelf registration. If we do we'll use the proceeds to reload the market resources revolver.

Now here is a short summary of our 2008 results. Questar grew net income 35% in 2008 to 683.8 million or 388 per diluted share, compared to 507.4 million or $2.88 per share a year ago. Results included net after-tax mark-to-market losses on natural gas basis only swaps of 49.7 million or $0.28 per share. And after-tax net gains on assets sales of $40.6 million or $0.23 per share. Together these items decreased earnings per diluted share by $0.5. Questar's fourth quarter net income of 121.2 million or $0.69 per diluted share was down 70% from a year ago.

Our fourth quarter results included net after-tax mark-to-market losses on natural gas basis only swaps of $54.3 million or $0.31 per diluted share, and after-tax net gains on asset sales of 1.4 million. Excluding these items we earned $0.99 per diluted share in the fourth quarter. Our market resources subsidiary grew net income 39% to 585.5 million in 2008.

Questar exploration and production grew net income 43% to $408 million, realized equivalent prices for natural gas crude oil and NGL increased 19% more than offsetting the 17% increase in average production costs. Wexpro grew net income 25%, driven by a 37% increase in investment base over the past 12 months. As those who follow our company know under the 1981 Wexpro agreement, Wexpro earns a 19 to 20% after-tax un-levered return on its net investment in the development of the defined set of properties in the Rockies

Gas management grew net income 47% driven by higher gathering and processing margins. Energy trading grew net income 6% to 22.1 million as a result of increased revenues from storage liquids and higher total marketing fees.

Questar Pipeline, our interstate pipeline and storage business earned $58 million in 2008, up 29% from 2007. The increase was driven by higher transportation revenues from expansion projects completed in the fourth quarter of 2007, and by higher NGL sales. Questar Gas, our retail gas distribution utility earned 40.2 million of net income in 2008, compared to 37.4 million a year ago. Our higher gross margin was driven by new customers and higher rates, but was offset by higher operating maintenance and interest expenses. Questar Gas now serves 888,600 homes and business, up 1.7% from the year-ago, despite the economic slowdown.

For more details on 2008 results, you can find our earnings release and the latest version of our IR presentation on the Questar website, at www.questar.com. We also have posted slides on our website that Keith will refer to during his remarks this morning. To view them go to www.questar.com, and click on the View Year-End 2008 Teleconference Slides button on the right side of the screen.

Now, I'll turn the microphone over to Keith Rattie, Questar Chairman and CEO.

Keith O. Rattie

Good morning, everyone. And I'm going to keep my comments on 2008 brief, and focus instead on what we're doing to weather this storm in 2009. I will try to provide more color and hopefully, help you reconcile our revised 2000 earnings and production guidance. As Steve hinted, we do have some good news to report this morning on our latest well results in the Haynesville shale and Bakken plays. I'll get to that later in my remarks.

The bottom line on 2008 is that our employees in all six Questar business segments executed superbly. And when you combine their execution with record high commodity prices particularly, in the second and third quarters of last year, you get the results that we reported yesterday, by far the best year in this company's 81 year history.

As you all know, for most of 2008 it was all about growth. Questar E&P grew production 22% in 2008, to a 171.4 billion cubic feet equivalent. We grew Midcontinent production 33%. Questar E&P grew proved reserves 19% from 18,068 Bcfe at year-end 2007 to 2218 Bcfe at year-end 2008. And that's despite some relatively modest negative revisions due to primarily to lower year-end prices. Questar E&P replaced 304% of its production, at an all end cost of $3.50 per Mcf equivalent, and $3.05 per Mcf equivalent if you exclude negative revisions due to low year-end prices.

In addition, Wexpro, our other E&P company; grew cost of service reserves 5% to 674 Bcfe at year-end 2008. We grew Wexpro's investment base 37% in 2008. Our gathering and processing business, Gas Management grew gathering volumes 35% and fee-based processing volumes 59% in 2008. And our two regulated businesses, Questar Pipeline and Questar Gas both had record years underpinned by system growth.

Now, as we enter 2009, we think we are pretty well-positioned to weather this economic storm. First, our balance sheet is strong, and we will keep it that way. We plan to reduce 2009 capital spending to $1.3 billion. That's down about $300 million from the $1.6 billion budget we announced in our last call, and down nearly 50% from 2008. With lower capital spending at current forward prices, our consolidated 2009 cash flow from operations should cover '09 CapEx and our dividend. We expect to end 2009 with consolidated debt at about 37% of total capitalization, and that's well below our average in the last 10 years. And then Steve has already summarized, in a world where credit is tight, we believe we have adequate liquidity.

Second; and this is more important over the intermediate term, over the past several years we've transformed Questar E&P from a Rockies-centric producer to a multi-basin play. We now have more flexibility to shift capital to where we get better returns in this low price environment. About 40% of Questar E&P's 2008 production came from the Midcontinent's and that share should grow in 2009 as we shift capital to horizontal drilling in our Haynesville and Lower Cotton Valley plays in Northwest Louisiana

We've also expanded our position in the Woodford shale play in the Anadarko Basin of Western Oklahoma and in the Texas Panhandle Granite Wash/Atoka play. We've also built a solid position in the North Dakota Bakken oil play, please note that Questar E&P has 78,000 net acres in this play.

The third highlight from 2008 was the BLM's record of decision in September of last year, which will allow us to optimize development of this world class asset over the next decade. There is arguably no other E&P asset like Pinedale, it maybe the most concentrated unconventional natural gas resource in the world stack pay across a 5,000 foot gross enabled low risk with lower F&D cost than many other major resource play in the U.S. today.

Even at today's poor Rockies prices we earn returns on Pinedale development that are greater than our cost of capital. The Pinedale record of decision was five years in the making and it demonstrates what our industry can do; what we can get done when we listen to public concerns and then tap the ingenuity and creativity of the people in this business to find solutions to those concerns.

Now let's get to the guidance. Yesterday we lowered '09 earnings and production guidance to reflect both lower capital spending and the significant drop in natural gas and oil prices since we gave our initial 2009 guidance back in October. We now estimate that Questar net income in 2009 could range from 250 to 270 per diluted share, that's down from prior guidance of 305 to 325 per diluted share. As in the past our EPS guidance excludes gains and losses on the sale of assets and mark-to-market gains and losses on basis hedges.

Our new guidance assumes that NYMEX natural gas prices range from 450 to 550 per million Btu for un-hedged 2009 production. Please note, that's down $2 per million Btu from the 650 to 750 per million Btu range we assumed in our prior guidance. We now assume that the 2009 Rockies to NYMEX basis differential will range from $3 to $1.50 per million Btu and that the coming month NYMEX crude oil price will range from 35... 45 to $55 per barrel for un-hedged volumes and that's down from the 70 to $80 assumption in our earlier guidance.

Our '09 guidance assumes capital spending as I mentioned of 1.3 billion, down from 1.6 billion, in the earlier guidance. And let me give you a breakdown on how this... how we're allocating this capital by major business segment.

Questar E&P will get $841 million, that's down over $200 million from the earlier guidance. Wexpro 118 million, that's down from 140 million; Gas Management a 134 million that's down from 200 million; Questar Pipeline a 101 million, that's down from 107 million and Questar Gas 84 million down from 90.

In short we are going to drill fewer wells in '09 and that means lower production growth. Please note that since September we've dropped half our rigs. Questar E&P today has 19 operated rigs compared to our peak 42 in third quarter of 2008. But by high grading our drilling program we still expect Questar E&P '09 production to range from a 180 to a 186 BCF equivalent up 5 to 9% from 2008.

In 2009 we are shifting capital to our higher margin, higher return plays at Pinedale and the Haynesville shale. We plan to run nine rigs at Pinedale in '09, that's unchanged from our October plan; with that level of activity we expect to drill and complete 93 to 95 wells at Pinedale day in '09 as discussed in our last call, Questar E&P has suspended all other gas directed drilling in the Rockies.

We have now also suspended oil directed drilling in the Uinta Basin a massive change since our last call when we told you we plan to drill at least 15 horizontal Green River wells in the Uinta Basin in '09.

Lower prices, lower CapEx and lower production growth obviously mean lower net income for Questar E&P in 2009. Our 2009 EPS guidance also reflects a more cautious outlook for Wexpro and Gas Management. Wexpro's earnings result as you know primarily from that contract base 19% after-tax return on this net investment base.

With lower CapEx and bonus depreciation will slow the growth in Wexpro's investment base and thus growth in Wexpro net income this year. In addition, lower oil prices will have a negative impact on Wexpro growth. Wexpro as you know, shares the proceeds of its modest oil production with Questar Gas customers after recovering the cost associated with that oil production.

High oil prices in recent years have boosted Wexpro net income, and you can verify that by doing the math on Wexpro's average investment base for the year. But at current low oil prices, we're assuming that Wexpro will see little, if any benefit from oil production in 2009. Also Gas Management earnings will likely be down sharply in 2009, due to current poor processing margins, and lower gathering and processing volumes at Questar E&P, and the other third party producers behind our systems drilled fewer wells, and thus delivered less volume.

We're forecasting significantly lower earnings from our marketing shop, Questar Energy Trading. We are unlikely to see the high storage margins that have driven our marketing shops, net income above 20 million in recent years. We're also forecasting flat to relatively flat earnings from our regulated businesses.

Let's turn now to operations starting in the Midcontinent. We now have seven Questar operated rigs in Northwest Louisiana. That's down from 16 rigs last winter. With our revised 2009 capital program, we plan to drill or participate in 35 Haynesville Shale wells in 2009. And on that front we've got good news to report this morning from both our ongoing evaluation of the Haynesville Shale play, and horizontal drilling in the Lower Cotton Valley formation in Northwest Louisiana.

In late January, we returned to our third Questar operated Haynesville well to sales, the Golson 32H. It's located in our Eastern most Woodardville block, and I'll refer you to do new Haynesville slides at the new link titled teleconference slides on our website.

We've got a 91% working interest in the Golson well and it's a keeper. This well flowed to sales at an initial rate of about 23 million cubic feet a day, and it's averaged about 18 million cubic feet a day, with average flowing casing pressures above 6400 pounds over the first three weeks on production. Clearly, one of the strongest wells drilled to date in the Haynesville play.

In addition, this past weekend we turned our fourth Questar E&P operated well, our 83% Shelby 31H well to sales, at an initial rate of over 20 million cubic feet a day, and again with very high flowing pressure. These early results, combined with results reported by other operators on wells in which we have a working interest, continue to suggest that our nearly 31,000 net acres could be in the sweet spot of the Haynesville play.

You'll note from the new Haynesville slides on our website that some of the best Haynesville wells drilled to date have been on or near our acreage. Now the carry out of course is that we don't have much production history on these wells. So, we don't know how they'll perform long-term. But the Golson and Shelby wells in particular, appear to be as strong as the best Haynesville wells reported by other operators.

We're currently preparing to complete our fifth Questar operated Haynesville well, and we're drilling ahead on three more. We are also pleased with initial results reported by our Tulsa team from horizontal drilling in the Lower Cotton Valley formation. You'll recall that we characterized horizontal development of the Lower Cotton Valley formation as upside, when we made our Louisiana purchase a year ago.

In early January, we turned our first Questar operated horizontal Lower Cotton Valley well on our Thorn Lake block to sales and an IP of about 8 million cubic feet a day. Then in mid-January, we turned to Questar operated horizontal lower Cotton Valley well in our core Elm Grove block to sales in an IP of about 9 million cubic feet per day. Both strong wells, which may cause us to shift our focus from vertical to horizontal development of the Lower Cotton Valley on our Thorn Lake block, and on other less developed acreage.

Turing to the Western Midcontinent very briefly, our Oklahoma City team made a major contribution to Questar E&P production growth in '08. We continue to see strong results from the Atoka Granite Wash wells drilled in the Texas Panhandle. And we're also pleased with early results in the emerging Anadarko Woodford shale play in Canadian and Blaine Counties in Western Oklahoma. With our revised capital program, we plan to drill or participate in 20 Woodford shale wells in '09. Time doesn't permit me in these remarks, to cover recent well results, but Chuck can give you more details in Q&A.

Let me move to the Williston Basin in North Dakota. Our Rockies Legacy asset team managers also have some encouraging news on our first Bakken well in this play. Our first Questar operated horizontal Bakken well IP at about 960 barrels of oil equivalent per day in late January. And is averaged about 700 barrels of oil equivalent per day over the first two weeks in production and that's consistent with our expectations. You may want to refer to our updated Bakken slide on our website.

Now unfortunately the Bakken play is not economic at current oil prices and well costs, so we've released the rig under the terms of our leases, we have to drill only one more well in 2009. We're going to defer that well to the second half of this year.

Briefly Wexpro, about 60% of that $118 million capital program we planned for Wexpro in 2009. It's targeted for Pinedale with the affects of bonus depreciation. At that capital level we expect Wexpro to end 2009 within an investment base of about 440 million that's up roughly 7% from year end 2008.

Turning briefly to our regulated businesses, '09 shapes up to be an important year for Questar Pipeline. We plan to invest $42 million to increase firm transportation on Overthrust Pipeline from Opal to Wamsutter by 300 million cubic feet per day. This investment involves the addition of 32,000 horsepower of new compression on Overthrust, is underwritten as usual by long-term contracts, this time with a major Green River Basin producer.

Our pipeline team also expects to finalize long-term contracts to add 600 million cubic feet a day of capacity to Overthrust to move gas from Wamsutter in Canada West or deliveries to Kern River Pipeline and ultimately to Ruby Pipeline. This $122 million expansion project essentially completes a 36 inch by-directional pipeline loop of Overthrust in the heart of the fastest growing, producing basin in the Rockies to greater Green River Basin.

Questar Pipeline and its partner Alliance still intend to bring another major pipeline company in to our Rockies Alliance Pipeline we call it RAP, its our proposed 1000 mile 42 inch bullet pipeline from the Eastern terminus of our Overthrust Pipeline at Wamsutter through Cheyenne and then straight to Chicago. Although we've postponed plans to conduct an open season on RAP until market conditions improve.

Finally and turning to our Utility business; some of you may have read that Utah Governor Jon Huntsman, Jr. in its state of the address... state of the state address two weeks ago proposed a partnership with our utility Questar Gas to build a natural gas corridor comprised of natural gas filling station along major interstate highways in our state.

Our utility team's going to do its part to turn our governor's vision into a reality and we hope a blue print for the rest of the country. Governor Huntsman understands that this country is swimming in natural gas and indeed the story of the year in U.S. energy in 2008 maybe the amazing breakthrough in the exploitation of the massive amounts of natural gas in plays and shale formations across the country. I'd simply put, this should change to paradigm for U.S. energy policy it should turn that paradigm on its head. Governor Huntsman has joined others and calling for the substitution of natural gas produced in America for gasoline refined from foreign oil.

But let's hope it doesn't stop there, after years of focusing on supply its time for policy makers in the natural gas industry to turn its attention to marketing and the demand side specifically the electric power generation market.

Now here is a question? How many of the 535 people that we elect and send to Congress know that 40% of Americas nearly 1 million megawatts of existing installed electric power generation capacity is built to run on natural gas. That's a whopping 30% more capacity than the total U.S. installed coal fire capacity, but incredibly the average utilization of Americas existing gas fire power plants today is only 25% versus 75% for coal.

The implications here are profound; just a mere 10% increase in average utilization of our existing gas fire power plants from 25% to 35% with increase U.S. electricity supply by the equivalent of 40 to 50 base load coal or nuclear plants at an incremental cost, that's a fraction of the all in costs of new coal, new nuclear or wind power plants.

Now, let's moreover half of the nearly 400,000 megawatts of installed gas fire capacity has been build since 1995; whereas most of this country's coal and nuclear plants are 40 to 50 years old. But, you wouldn't know any of this. From what you hear, from policy makers in Washington, nor from what you read in the paper or here on TV.

The public disclose on energy shows a bias for massive new spending, on so-called clean coal, nuclear and wind power, while at a much lower cost and environmentally sound alternative, the greater use of natural gas, domestic natural gas in our existing gas fire power plants rarely gets mentioned. That's in part of the perverse consequence of both misaligned incentives for regulated utilities and unfounded theories that America is running out of natural gas.

With U.S. natural gas supply clearly able to grow as we've seen over the last few years, the natural gas industry now more than ever needs to get its act together. We need to educate the public and policy makers, and we need to protect and grow our market for our clean, abundant and affordable and American made product.

In summary, 2009 shapes up to be a tough year for the U.S. economy, tough year for the natural gas industry, and thus for Questar. We're binding down the hatches. We're going to weather the storm. Markets will improve, they always do. And when they do, we think we'll be well-positioned for the recovery.

And with that, we'll be glad to open it up for questions. Katherine?

Question-and-Answer Session

Stephen Parks

Katherine?

Operator

Yes, sir.

Stephen Parks

Provide the information for asking questions now.

Operator

(Operator Instructions). And our first question, and I'll just apologize we have the time, if I am saying your name incorrectly I do apologize. Our first question comes from the line of Shneur Gershuni with UBS. Your line is open.

Shneur Gershuni - UBS

Thank you. That was actually pretty good. All right, good morning guys.

Stephen Parks

Good morning, Shneur.

Shneur Gershuni - UBS

Just had a couple of quick questions. I guess, maybe if we can just start with guidance, kind of wanted to understand some of the inputs a little better. You kind of gave us the inputs to figure the top-line revenue growth, and kind of want to understand what are your constants inputs and you'd mentioned that Gas Management you expect to be down sharply. I mean, are you expecting no third party volumes this year. Or if you can sort of give us a percentage of where you expect that to be down, and also where you think the frac spread is going to be on that side and if there is any changes to your gathering margin as well too. And also, if you can sort of give us a little bit of color with respect to LOE and DD&A for the E&P segment as well and so?

Stephen Parks

I'll let Chuck Stanley. I think he's got the data on our plan in front of him, handle that one. Shneur, thanks for the question.

Charles Stanley

Good morning, Shneur. On QGM, gathering and processing business, as you know the former frac spreads are horrible, compared to last year. We had record pricing for NGLs ethane, propane, butane, and others that were led obviously by $145 oil during the middle of the summer. We saw ethane prices and the other NGL prices collapse along with oil in the second half of the year. And particularly in the fourth quarter, things got really bad. I think margins were negative. We ran our plants for third or the four quarter, in ethane rejection.

Today, the margin balances around on ethane are few pennies positive, to may be a nickel positive, compared to ethane margins of as much as $0.70 at the peak last year. So, we're looking at revenues from NGLs that are down sharply down are down to 10% of peak levels in our forecast going forward.

We anticipate that plant margins and frac spreads will be down over 50% from our '08 actuals. And that will of course, drive through to net income. Combined with that we are obviously seeing a curtailment in drilling both QEP and Wexpro directed drilling in some of the key plays that Wexpro serves, particularly in Uinta Basin, where as you'll recall, we said that we had shutdown all gas directed drillings.

So, the Gas Management assets there will rise or decline further down, not only for processing volumes, but also gathering revenues. We're seeing third parties cut back in a similar manner. At this point it's difficult to forecast those volumes. So we're being a bit conservative, basically flat it's like forecasting flat throughput on our gathering systems and not much grow.

So the big change is a dramatic decline in processing margins, gathering revenues are going to be about flat year-over-year, but the big decline in frac spreads is going to lead to lower revenues and hence lower net income. Now combined with that in our processing business you will recall we've deployed a lot of capital in those assets over the past several years, including last year large project to expand the gathering system from Pinedale down to processing complex with Blacks Fork and Emigrant (ph) Trail. Those capital investment have significantly increased the DD&A in our business

We, last year had an DD&A rate of about $28.7 million, we are forecasting over $47 million of DD&A in that businesses, this year, as a result of the increased investment in property and plant equipment. That plus additional interest cost because we actually allocate capital and charge interest to our individual subsidiaries we'll also press downward our net income. A $12 million interest expense last year going up to over $15 million in... I am sorry I'm looking at the wrong number. A $4 million interest expense going up to almost $15 million in '09. So those are the components that are driving the decrease in net income in QGM.

Now turning to E&P business, maybe the best thing to do is just spend a couple of minutes and may be answer a number of calls that are in the queue, and I apologize that this is your question but just to help you reconcile our guidance from last fall to right now. The best way to think about it is to look at... most of the downward revision is in Questar E&P as you would expect. We've already talked about the gathering and processing business. The big changes are driven by changes in price, obviously as Keith mentioned a couple of dollar decrease in natural gas prices and a large decrease in oil prices.

Oil prices and gas prices alone versus to gas prices, decreased our guidance by about $39 million. Oil prices of about $23 million and then additionally the decrease in volumes we've guided... downward guided volumes decreased gas revenues by $28 million and oil by $4 million. So those are the largest components in our downward revision. Even though we are 70% hedge, the huge hit that we're taking on pricing on un-hedged volumes is having a profound impact on revenues and therefore net income.

Amortization rate has about $17.8 million negative hit on net income, over our guidance that we gave at the end of the third quarter. That hit is primarily due to two things; one, we did have some negative reserve revisions at year-end that impacted amortization rate and some of our successful efforts pool. But more importantly as we shift drilling and production activities to the Midcontinent region and particularly the Northwest Louisiana, which has a higher DD&A rate of refining and development cost compared to Pinedale, where we've been driving a lot of our production growth in the past. The volume... DD&A as reflected in our income statement is a volume related average. So as we grow production in these higher cost areas our DD&A rate is going to go up.

And we're also depleting of course in these Midcontinent plays our lowest cost over pools and replacing the higher cost gas. So overtime, we would expect to see that cost continue to go up as we push growth now in the higher margin plays in Northwest Louisiana and particularly Haynesville.

I suspect overtime that we will see overall operating costs LOE in particular go down. We will look at that at year-end, especially as here in the Rockies we procure a lot of consumables in particular, methanol that we use to prevent the gas from freezing off of the well head (ph) in bulk, and those prices still reflect a different world when we acquire those consumable chemicals at beginning of the winter.

Other costs inputs into our business on the margin side and other LOE... trucking costs, fuel et cetera, are all going down. So I would expect that we'll see improvement in our cost structure going forward on the controllable costs. I think that about covers it. I may be... answered the wrong question. But let me pause and see sure if you've got the data you need now.

Shneur Gershuni - UBS

No, actually that was very helpful. Thank you for all the color and the details on it. But, I also I am getting this sense from listening to your responses that you're clearly looking to air on this side of being conservative rather than bullish and so forth. Am I correct to kind of read it that way?

Charles Stanley

Well, I would hope that you'd know by now that we're trying to give you guidance that we feel very comfortable with. We are at a point right now where I find it very difficult to predict where costs are going to land. The other thing that people have asked us individually and I'll just address that too and may be help you to think through that. Well costs are coming down. There's no question that day rates are coming down, fuel is coming down for drilling the rigs. We're seeing the inputs on well construction across the board; cement, tubulars et cetera come down.

There's some stickiness in that versus oil country tubular goods. We procure obviously way in advance of when we need the stuff because we can't afford to have drilling rigs sitting there circulating while we wait for pipe to show up. So there is a lag in the cost of consumables in particular casing and tubing, that we have an inventory that will be pushed through. So, you'll see a decline, but not an instantaneous decrease in well cost.

But keep in mind that lower drilling costs takes quite a while to push through the DD&A calculation because you're adding new reserves and even if you add them at near zero cost, you're adding reserves to a 2.2 Tcf base and on a percentage basis that lower cost will take a while to flow through the cost structure.

Shneur Gershuni - UBS

Sure. I was just wondering if you can comment on the... your successes in the Haynesville a little bit. Given these two new wells that you've got listed in the slides therein, so forth are... can we assume that the fact that you are continuing to drill this that you continue to believe that it's an exciting play even in this current environment and does it sort of... do the recent results sort of change your view about how many of these you can book on a per location basis? Or is it too early to see a revision upwards?

Charles Stanley

Well first of all, I think that my view, my personal view and I think Keith probably shares... I don't know, I won't put words in his mouth; the play has gone from skepticism to the cautious optimism, to a much more technically convinced and commercially convinced bullishness on the play. As we've seen not only our results which are admittedly small number statistics and a couple of wells, the first two wells we drilled but I can come back and talk about those in more detail in a minute. But the last two wells we drilled which we believe are representative of a good well that was drilled in zone completed with 12 or 13 frac stages, basically following the recipe of our friends and partners at Petrohawk who have, I think perfected the completion design of the... at least in the area that we're operating in of for example; Haynesville well.

These results are very consistent, not only with results that Petrohawk has achieved but at least with Golson well, I think with... the well will fall in the upper part of the results that they have reported today. We put a very detailed slide... a couple of slides on our website. One that just shows... it colors out our two latest wells and then in color code shows the IPs of wells, our initial potential of wells around our acreage, and on our acreage. And you can see the number of wells that are in a red or pink color that are greater than 15 million cubic feet a day or greater than 20 million cubic feet a day.

They indicate what in our mind is a suite spot in and around our acreage and with the activity that's going on by others, in particular Petrohawk, we de-risk substantially the large part of our acreage position. And certainly these two wells that we've just completed on the Eastern part of the acreage in the Woodardville area, you raised some of the concerns I had about consistency. And that I want to just make a comment about the second well that we drilled, which is immediately West of the Shelby well that we reported this morning.

The Golson well, and I am sorry, not the Golson well, the Wiggins well which we reported at an IP of about 7.4 million cubic fee a day. That well we now know was probably not drilled in the suite spot, the most porous part of the Haynesville. We know that from detailed analysis that we did after the well was completed (ph) and the nature of the well when we were fracking it. So that's an anomaly that is not representative of the... what we would expect a well drilled in the porosity and in frac with 13, probably 13 stages.

There is another well that was drilled by another operator to the West that has a low IP. That well also had a mechanical problem. So, if we throw out the wells if we know that have mechanical problems. We see additional rates of 15 million a day or even greater on all the wells that have been drilled around our acreage. So what does that mean for our reserves? Too early to tell. These wells are obviously, very early in their life. They've been producing for maximum of about six months, in and around in the vicinity of our acreage. Very strong results.

Obviously, these are shale flows, so they are declining quite rapidly. But we're seeing wells that have been off six months or so, are showing production rates still at 50% or so of IP, which I think is a pretty representative of what we would expect on a tight curve.

We think, at a minimum these wells will cover 5 B's or so of gas per well. That number could be a lot greater. Certainly, with a minimum 100 Bcf per section, it's easy to forecast reserves recoverable, at least accessible on 80 acre density of 8 Bcf or more, and still be comfortable with the recovery factors.

So, with that I probably gave you a long winded answer. But, we're quite excited, and quite pleased, with the results of these things that we play on our acreage.

Shneur Gershuni - UBS

Great. And I did have one last question, I guess for Keith, it's kind of a two part. With respect to basis differential, obviously based on your guidance numbers, you're still concerned about it, despite the fact that everybody is starting to shut in production at the Rockies. I guess, do you think that there is a possibility that it can improve over the course of the year as volumes come down.

And then secondly, you've talked in the past about aggressively pursuing opportunities to try and get more outlet capacity. Are you taking the panel off, narrow on that a little better or are you still pushing aggressively to get some more pipelines, don't say to take outside of the Rockies?

Keith Rattie

Thanks for the question Shneur. We do see basis tightening in the Rockies. We've seen that over the last several months. There is a couple of things going on here. First of all as you know, the fundamental driver of basis in the U.S. pipeline grid is the variable cost of transportation. And the primary component of variable cost of transportation of course is compressor fuel. So, when the NYMEX price of natural gas falls from $10 to 470, 480, the cost, and thus the basis is just naturally going to tighten.

And then the second factor, the one that you mentioned is the declining level of activity. We... our analysis, ignoring hedges and firm transportation on the long haul pipes out of the region; we believe that the Pinedale Anticline maybe the only major play in Rockies that's economic at current prices.

So, we are going to see, we've seen already a sharp drop in the rig count, something like 30% of the rigs that we're drilling at peak last September, have been laid down. That trend will slow a little bit, but we continue to see other operators announcing cutbacks in their capital program. That will have the impact of taking pressure off of basis, this summer and probably, over the next couple of years; which in turn mutes the appetite, if you will, of major Rockies producers, for committing to take long-term capacity on proposed new export pipelines.

Wherein Allan Bradley and his team are in constant dialogue with Rockies producers. We do believe that when market conditions improve, the industry is going to start focusing again on the need for another major export pipeline headed East out of the Rockies and this is after the El Paso moves forward hopefully with the Ruby project and public indication from El Paso is that their project remains on track.

Other competing export pipelines, I can speak out as a Rockies producer and based on conversations with Rockies producers, RAP is the clear front runner in that race. But it's not prudent for us in the current uncertain environment to go out for an open season and potentially have that open season sale. So we're going to postpone that until we get better visibility on the market, probably in the second half of this year.

Shneur Gershuni - UBS

Great. Thank you very much.

Operator

Our next question comes from the line of Joe Allman with of JP Morgan. Your line is open.

Joseph Allman - JP Morgan

Yes. Thank you and good morning everybody.

Keith Rattie

Hi, Joe.

Joseph Allman - JP Morgan

Hey, I guess a question on the Haynesville Shale. what kind of capacity do you have right now to move the gas out of the... out of the play?

Charles Stanley

Joe, we've got capacity on CenterPoint's line to Perryville. We also have the ability to... we're connecting our Southern area to Gulf South hub, our pipeline system that allows to back our gas over to Carthage. We have not experienced any transportation problems, but as you know as it does not take a lot of 20 plus million day wells coming on in an area, to start to back things up. It's a concern for us, obviously the ability of the pipeline developers in the region to get new pipe installed and get installed rapidly is going to continue the growth in production out of this region.

Which is one of the reasons why we have not moved more rigs in to this area and pushed aggressively develop our acreage, it's going to be 12 months or so. We've got the first compression project design that will start to add incremental capacity in 18 months or so or we'll see a new piece of pipe installed in the area. So it's going to be a small for a while frankly and we're concerned about that.

Joseph Allman - JP Morgan

Okay. So in short can you put the some numbers to that, so like at this point you think you've got... I mean how many million cubic feet a day capacity that will take you to what 12 months from now and on that point? What's the increment for Questar?

Charles Stanley

Well we hold for now on about 35 million a day to Perryville. We have that all capacity, I am going to discuss the absolute numbers on that, but in aggregate we're able to easily move a 100 plus million a day right now, incremental above where we are. We have also signed up, again I prefer not to talk about numbers in specific projects. But we have signed up for additional capacity on new projects that you've read about that have been proposed by industry to develop interstate pipes to hold gas out in that region.

Joseph Allman - JP Morgan

Okay, got you. Okay, that's helpful. And then on the Woodford Shale in the Anadarko Basin, what kind of pricing do you think you need to get a rate of return that's above your cost to capital?

Charles Stanley

On the forward strip, we see returns which are acceptable at obviously at current spot price where it's marginal. But let's see, if we look at just on a fix basis of $5 or so would generate an acceptable return at the well head.

Joseph Allman - JP Morgan

Okay. And could you go over the economics and so you're looking at what is like 8 to $10 million wells and you're looking at 3 or 5 Bcf per well?

Charles Stanley

There are 8 to $10 million that we are seeing the well cost come down. 8.5 completed well cost. The type curves are... we're using a different type curve in different parts of the field, but anywhere from 4 to we've seen results that would indicate up to 5.5-6 Bcf of reserves. In the Eastern part of play, we see higher Btu gas, up to 1,200 Btu gas as we move to the West and to the deeper part of the play, the Btu content drops off, but the returns on a forward strip are in the 15 to 16% range based on the $8.5 million well cost and a 4 Bcf type curve... 4 Bcfe, I'm sorry type curve.

Joseph Allman - JP Morgan

Okay, that's helpful. And then a similar question...

Stephen Parks

By the way Joe that's after-tax rate of return which is important.

Joseph Allman - JP Morgan

Okay, that's helpful. Thank you. And then same question for the Bakken; I mean so what is it about the Bakken, where the economics aren't working that caused you to move that rig. Is it just the differentials are so wide right now and you can't actually move the oil on a pipe or what?

Stephen Parks

That's part of it. The differentials that we're seeing in the Bakken play right now are in the $15 range or in some instances up to $20. None of the oil that we're producing is moving immediately out of the area we're trucking it to a pipeline inlet some distance away from that producing area which is obviously adding to the costs. But we're getting slightly better differentials than some other producers in the more remote parts of the Wilson basin.

Two things that surprise is part of it, the other thing that we wanted to do or as we wanted to get a well drilled, we're moving away from control obviously and we wanted to get this well down; get it on line and produce it a while, and a watch performance before we made a commitment to drill the next one.

We're also waiting on some permits; we want to drill... we'll drill at least one additional well on our block this year and we'll watch prices obviously and may decide to drill more. But we want to get a good spatial sampling other over a large 78,000 acre lease hold out here to understand the distribution of the middle Bakken and also the potential in the Saanich (ph). In the first well we drilled we did not encounter any porosity in the Saanich or Saanich equivalent section beneath the Bakken; but we know, we're aware of well controls to the West that has indicated presence of the Saanich quite close to the Northern part of our acreage.

We'd like to get some production history make sure that we understand the EUR potential of the middle Bakken in the area that we just drilled. One of our partners... one of the major operators to the North has proposed a well about six or seven miles south of the first well that we drilled out here. That well will likely be drilled this summer, so we'll get a... another well drilled on our acreage, but operated by another industry player out here sometime this summer.

So we're we being in cautious, frankly this acreage we don't have any significant lease expiries driving us out here. We can drill these wells and be patient and we want to see some performance before we just slog off and drill another one.

Joseph Allman - JP Morgan

Okay it's very helpful. And then lastly on the reserves then what was the volume of the negative reserve revision and what was that... was that crude developed tail that went away or a PUD tail or just a PUD that went away?

Keith Rattie

The total volume was 152.9 Bcfe. It was a combination of three things; pricing related revisions that obviously are truncated the reserve life on wells particularly, oil wells and oily gas wells or gas wells that produced lot of calcite (ph) in the Rockies. Also we had some PUDs book that at the year-end pricing just fell of the books because they weren't economic at year-end pricing. But it was... I can't point to one single factor and I suspect that's the case with most producers, a large number of wells suffered small negative pricing performance related revisions as a result of the rapid decline in pricing compared to a year ago.

Stephen Parks

Joe one other thing, we did sell some reserves in place last year as well, just below 20Bs, had a little bit of an impact as well.

Joseph Allman - JP Morgan

Got you. But those negative revisions do you think they are mostly crude developed more so than PUDs?

Stephen Parks

No, it was a combination of both. I don't know... off the top of my head I can't tell you ratio but it's probably a lot of PUDs that came off. I would say probably 70%, 65% this is... I am guessing, because I can't... I don't have the number in front of me.

Joseph Allman - JP Morgan

I understand.

Stephen Parks

65% PUDs and the remainder PD because.

Joseph Allman - JP Morgan

Okay.

Stephen Parks

What would happen is we'd see a performance/price related negative revision on a PDP well. And then, it would push all of the PUDs around it down or off, of the books; depending on where these revisions took place. Particularly, as you would expect, particularly, bad in the Uinta Basin, which as you know or you should know is our highest cost producing area and also historically, our lowest price area.

So, the combination of high cost and low price tended to the impact reserves there. And the other thing is that... and this is may be something you don't realize of that well stream in the Uinta Basin, about 25% of it is oil or NGLs. So, the big drop in oil and NGL prices had the most profound effect on reserves in the Uinta.

Joseph Allman - JP Morgan

Okay, it's all very helpful. Thank you very much.

Stephen Parks

Thanks.

Operator

Our next question comes from the line of Brian Singer with Goldman Sachs. Your line is open.

Brian Singer - Goldman Sachs

Thank you. Good morning.

Keith Rattie

Good morning, Brian.

Brian Singer - Goldman Sachs

I just wanted to follow-up on some of the other Haynesville questions asked earlier. When we look at just the impact from the two wells you announced this morning, it's pretty substantial on your overall production. And I wondered, how you are thinking about Haynesville wells rates in your production guidance, relative to the rates that we've seen so far?

Keith Rattie

We have forecast production based on risks rates. And I think we were using, Jim Neese, is here this morning. So, I can look him in the eye, and ask him; I think we are using 8.5 million a day IP on these wells?

Jay Neese

That's correct.

Keith Rattie

On a gross basis, okay. So, obviously there's two... there's multiple components of risk Brian. One of them is, while our friends at Petrohawk have helped us de-risk our acreage position substantially, with... there is still a lot of real estate out here that we don't have a well bore in. The other concern that we have about volumes is just the speed at which we can drill, complete, connect, and turn these wells to sales.

So, and we have put all of those components the geo... what I would call geological technical risking, and the sort of connection, production constraint, timing, risking into our production forecast. And, not a lot of high science there; we were basing our early forecast on our well results, sort of outside of the region. And if you look at the map that we posted on our website, you can see 10 to 12 million cubic foot a day gross un-risked well streamed and haircut some for risking. May be a 25% risking, got you down to the number that we were using.

Certainly, as we see more results around our acreage, we can start to de-risk from a technical perspective, the predicted IPs. But, we still have the concerns about gathering constraints, and downstream pipeline constraints that I think are still legitimate components of risk that we need to include in our forecasting.

Brian Singer - Goldman Sachs

That's helpful. And I guess, maybe asking an earlier question in another way, to the extent that you see rates, let's call in the 14 million or 15 million a day plus range gross gross initial production rates for the wells that you plan to drill. What percent of the wells you plan to drill do you actually think you could get online tied into sales in relatively short order after completion?

Stephen Parks

That's a... yeah, these wells... first of all they're taking quite a while to drill. We're still learning how to drill them. Our drill times have been 50 days or so. Then we've had some delays in fracking wells, and just to get organized and get frac water on location. I mean, these are huge fracs. So, we've tended to use central frac, smarter storage facilities to basically put water in large tanks, or large frac tips and then pump from those to the location.

And moving the water around, and then getting organized to frac these wells, probably adds another 15 to 30 days. And connection has not been an issue with respect to wells that have been relatively close to the interstate pipeline grid. So, like the Shelby and Golson wells, as well as the other two wells that we drilled in the southern part of our acreage, the Wiggins and the Woodford (ph) are within are literally a stones roll over the interstate pipeline quarter that comes through from East Texas on its way to Perryville. The Northern part of our acreage is more challenged, because it's on the West side of the river for the most part and there are some capacity constraints there on CenterPoint's gathering system that they are working on, but we have to rely on third parties to de-bottleneck their system to move more volumes.

Keith Rattie

I think I have mentioned in our prepared remarks, Brian that we plan to participate in 35 wells this year. And I don't know what the average working interest is going to be on those wells. Jay probably has that number, but we've got a risk our ability to get them all completed and turning to sale.

Charles Stanley

Yeah if we, Brian if we look at our average working interest across all of those wells, it's a little less than 50% between 45 and 50% so that gives you an idea on net volumes and keep in mind you've to subtract an average royalty in here to probably 80% or NRI would be 80% so 20% royalty.

Brian Singer - Goldman Sachs

Thanks. And if I could, if I could ask one more question. How are you currently thinking about the midstream in regulated businesses relative to the E&P business from the perspective of combined entity versus separation? And somewhat separately? And do you see opportunities beyond the E&P business in that... in the Louisiana area to the extent that that becomes greater percentage of your E&P production?

Keith Rattie

The answer to the second question is yes. We are interested in building our presence in the core plays that we talked about on this call today. And we'll look cautiously, but opportunistically at ways to do that in this distressed market environment. And we have no plans this year to restructure the company if that was the basic question you were asking. It's something that we always look at.

We think in this environment our other businesses complement our E&P strategies in our core operating areas. We, for example desperately need our pipeline team to be a catalyst for another major export pipeline out of the Rockies. We and the other operators at Pinedale could put the pedal at the metal and grow production. But we'd outstripped the current available capacity if we did so. So that new capacity needs to get built and we think the pipeline complements our corporate strategy in that regard.

And we talked on regular basis about how integrated our gathering and processing business is with our E&P business. The utility is a counterparty of the Wexpro agreement, the two work well together to optimize both the development from the shareholder perspective and the utilization from the rate payer or customer perspective of the gas from Wexpro properties. And we see benefits to that in the short term. In the long run, I continue to believe there will come a right time and place for us to do something different.

Brian Singer - Goldman Sachs

Thank you.

Operator

Our next question comes from the line of Sam Brothwell with Wachovia. Your line is now open.

Sam Brothwell - Wachovia Securities

Hi good morning guys. Lot of our questions have been touched on. But may be just two quick ones. One on the NGL side, how should we be thinking about some of the economics, particularly correlation and perhaps basis in this environment. And secondly, does your guidance for this year anticipate any cycle time or efficiency improvements in some of your new plays such as the Haynesville or is it a little too early to be thinking about that?

Keith Rattie

It's for Chuck. Sam, thanks for the question.

Charles Stanley

Good morning, Sam. On the NGLs, each component of the NGL stream obviously has a different end use. The ethane component is the one that is most sensitive to economic activity and as you know ethane inventories have built since the hurricane last fall that impacted petrochemical complex along the Texas Gulf Coast and that inventory has been slow to come down. The problem's being exacerbated by a dramatic drop in industrial demand for ethane, ethylene and for plastics, not only for consumer products, but for industrial use as well.

From anecdotal evidence and from talking to people on the NGL side of the business, our customers for the NGL. There are some signs of life albeit weak signs of life. Inventories coming down some, ethylene demand picking up but it's too early to forecast. I think what's going to happen to ethane. We are basically caring a breakeven frac spread with our plans running in ethane recovery for model.

The obvious question or maybe the underlying question that you asking is, how does the processing business in the Rockies look compared to the Gulf Coast region. And I think you know the answer, the answer is that the gas processing or NGL extraction in the Rockies mountain region remains economic unfortunately because of the wide base is differential compared to Haynesville (ph) pricing and we'll be competitive with plans in the Gulf Coast region because of that. So, modest margins in ethane, propane, butane and the heavier fraction again correlated with industrial demand and in particular refining demand. And what we've seen is a slackening of demand for those products as well as you would expect in the weak economy.

So we are pretty guarded on our view of the processing businesses as a standalone business right now, is a cyclical business when it's good it's good it's really great and once normal it's not so good. So we are in the not so good part of the cycle right now. As you know we are at a minimum processors of necessity we have to process gas, our own equity gas and that of our third party customers to remove enough liquids from that gas to reduce the hydrocarbon due point to meet interstate pipeline specs.

We have a large amount of processing business protective with what I call reversionary contracts or contracts that revert back to a fee based arrangement when the frac spread is upside down. So that the processing business is not hurt by negative NGL margins when gas is being processed just to meet due point on industry pipelines.

So that's I hope I answered the first question. I'll answer the second question and you can follow-up. We have not on our new plays assumed any efficiency gains and the reason for that is, we're still very early in these plays. I will tell you that I think that there is an opportunity to significantly improve our drill times and efficiencies in these plays as we learn more about them and how to drill them.

I was down in the field about a week ago and talking to one of our bit experts who has worked for us for a number of years and is one of the people who is responsible, there is a lot of people who are responsible, but one of the team members is responsible. For us drilling record well at Pinedale we just past quarter drilled a well to 14,300 plus feet in about 18 days. If you would have told me five years ago that we could drill a 14,300 foot directional well at Pinedale in 18 days, I would have said you're crazy. But, right now those people are focused on, trying to drive down the drill time and costs on these Haynesville wells.

They are though wells to drill, hard to hose, to take a toll on mud motors and on measurement well drilling tools, horizontal drilling into a very thin I mean its several hundred feet thick but relatively thin suite spot in the Haynesville that we found through our own painful experience to be a lot less well behaved structurally than we would have thought it to be. And that was one the wells that we have with the Wiggins well where popped in and out of the hose interval in the Haynesville.

We've also on and Shelby well had to basically side track that well to get it back in porosity because of the structure of Powder Basin that we were not anticipating so, we're on a steep learning here Sam, I think that there are opportunities for significant efficiency gains. I think for the first time may be in the past five years we have an opportunity at places like Pinedale to crystallize those efficiency gains into reductions in well costs. For the past five years, we've been offsetting escalation in all inputs in the drilling business and completion business, by getting better and better at what we do to maintain flat well cost, hopefully in this environment, we'll be able to realize lower costs.

Sam Brothwell - Wachovia Securities

Okay, thanks for all the details. Just if I can turn real quick back to the NGL question; as we think about your barrel, is it weighted more to the heavy end, I'm kind of trying to get at, thinking about the correlation to a crude price that we should be thinking about trying to model that business?

Stephen Parks

Sam, the ethane price as you know in an environment like this bounces off a floor set by the BTU equivalent of natural gas. And as Chuck has described, the ethane margin... we've been in and out of ethane recovery on the Rockies plants. You have to also look at the higher cost for TNF for Rockies ethane recovery.

NGL prices over the long term tend to correlate particularly, propane which is the primary of the C3 (ph) plus is the primary component of the NGL barrels that we removed tending to move somewhere around 70 to 80% of the price of crude on a BTU basis. It's been... we deviated from those long-term relationships lately. But I would expect over time we'd get back. Propane as you know, competes with naphtha and other petroleum liquids products, in speed stock and in petrochemical crackers. Ethane competes with propane.

Sam Brothwell - Wachovia Securities

Okay. Thank you very much.

Operator

Our next question comes from the line of Faisel Khan with Citigroup. Your line is open now.

Faisel Khan - Citigroup

Good morning, guys.

Stephen Parks

Good morning, Faisel.

Faisel Khan - Citigroup

Just going back to the reserves for a second, I think I got all reserve revisions, that... on reserve growth did you guys book the 270 Bcf from the acquisition... so did you book all of that, or was there some held back?

Charles Stanley

Faisel, Chuck. We started... I will just walk through this for everybody on the call. We started the year with 1.867 Tcf of reserves. We had a negative 152.9 Bs of revisions. We added through drilling, and I would point out to you that when you see your 10-K, we have a very strange category of reserve as in... they are called revisions due to increased density of Pinedale, which most people would throw into the revisions category. But it's actually additions in anybody else's book, and that's a long story. I won't go in to it on this call. But, if you have questions, please call us. So, our adds totaled 400.8 Bcf. So, net of revisions our adds were 247.9 Bcf.

Faisel Khan - Citigroup

Okay.

Charles Stanley

We purchased in place 292.4 Bcf. So, our total reserve adds net of revisions were 540.39 Bcf. We sold... as Keith mentioned, 18.5 Bs of reserves in place. So, our total growth was about 521.8 Bcf.

Faisel Khan - Citigroup

Got you.

Charles Stanley

That's a 28% total growth number. And then of course, you need to subtract from that our production for the last year, which was a 171.4. And that should reconcile if I didn't misspeak any of the numbers to the 2.218 Ts at year-end '08.

Faisel Khan - Citigroup

Okay. That makes sense. And then on the... on your basis only swaps that you guys have for this year. What would happen in a situation where Henry Hub prices were say $3 in MMBtu. I mean do those swaps basically become ineffective, the basis only swaps?

Charles Stanley

Well, the basis only swap will generate either a positive or a negative cash flow, based on the relative value of that basis swap to the current basis. So, if the basis was $2, and the swap was $3, then it would generate a negative $1 of cash flow per unit.

Faisel Khan - Citigroup

Okay. But you don't necessarily have to produce the gas associated with those...?

Keith Rattie

These are not FAS 133.

Charles Stanley

Well, these like every other derivative we have in our portfolio are papered instruments or derivatives.

Faisel Khan - Citigroup

Sure.

Charles Stanley

Not physical deals. So not only the basis loss, but the fixed price loss generate revenues without the physical flow of the underlying commodity. But in order to qualify as cash flow hedges under FAS 133, the derivatives are matched to volumes I'm looking at Parks and he is nodding his head. So I said it right.

Faisel Khan - Citigroup

Okay. I got you.

Stephen Parks

And the hypothetical, you mentioned $3 Henry Hub price. The mark-to-market on our basis hedges will be quite will get quite a bit negative from where it was at year-end. And that will have an impact on our reported earnings.

Faisel Khan - Citigroup

Got you. Okay. And then just you guys talked about shifting a lot of the CapEx to the Midcontinent, to the south from the Rockies. Given that shift in CapEx what would you expect your... how would you expect your production mix to kind of change over the course of the year, from Rockies versus kind of Midcontinent and Louisiana, East Texas?

Charles Stanley

Yes, it's still going to be about 60-40. We're still going to get good growth out of Pinedale. And Pinedale will... volume growth will supplant the decline in Legacy and Uinta Basin divisions that we won't be deploying capital in. And then of course, we expect good growth out of the Midcontinent region as well. But Pinedale capital's is great vision; it generates a lot of incremental production per dollar of CapEx expended. So, the royalty ratio won't change now. Some of this is already zeroed in, on the risking that's gone on. Obviously, the volumes that we forecast from Pinedale are risks at a lot lower risk factor than the volumes that we're forecasting from Haynesville. So the 60:40 mix reflects that risking, if overtime we de-risk that volume and you could see the relative ratio increasing from the Midcontinent.

Faisel Khan - Citigroup

Okay. I got you. And then just kind of a theoretical question; what would have to happen for you guys to taking another look at your CapEx budget and maybe take another slice of it?

Keith Rattie

Lower, even lower commodity prices combined with results that aren't consistent with what we're building into our plans for this year Faisel, would be the short answer on that. We're as Steve summarized while we do see signs that the credit markets are thawing and there is an appetite for intermediate term debt for investment grade issuers was like Questar market resources, we're going to run our business this year on the premise that we are going to with our cash flow from operations, we'll cover our capital spending and our dividend. So if something impacts cash flow from operations in this environment, we'll probably make further cuts.

Faisel Khan - Citigroup

Okay, got you. And Steve can you just remind us again what were the-- you wanted to rise some medium term intermediate debt, what were those numbers again in terms of how much you can raise?

Stephen Parks

Well we have an existing shelf in place for $300 million.

Charles Stanley

250 plus. It can be expanded.

Stephen Parks

It can be expanded... $300 million with an expansion feature. We will consider issuing five year notes probably in market resources and use the proceeds to reload the multi-year Questar market resources revolver, if conditions in particular terms for placement of that debt are acceptable to us.

Faisel Khan - Citigroup

Okay I got you. Thanks guys for the time. I appreciate it.

Stephen Parks

Thanks Faisel. We're going to... we're getting some feedback from several folks on the call that we're taking too long to answer number one; and we're... they'd like to have us try to limit to one question, so everybody can get through. I'll ask you to try to help us on that.

Operator

Thank you, sir. Our next question comes from Carl Kirst with BMO Capital. Your line is now open.

Carl Kirst - BMO Capital

Hey, good morning guys and also appreciate the time here. Kind of just picked this question, Chuck with respect to the shifting around in the capital declining service costs, well costs; previously we've been thinking about 650 million as far as the base CapEx to kind of keep replacing production, is that still a fair number or is that shifted around?

Charles Stanley

Carl, I haven't done it with the decreased costs that are coming through 650 is probably high. How much high, it depends on two things; one, as we see the cost come costs reductions come through on day rates et cetera we'll see well costs go down. The other thing is a de-risking of Haynesville. Because Haynesville wells if we de-risk them would move the needle substantially on production replacement per dollar capital employed.

Carl Kirst - BMO Capital

Okay, now that's helpful. And I apologize I did actually have this, one other just because I am a little confused. Why if it's kind of being treated as rate based would we be flouting back on Wexpro?

Charles Stanley

It's very simple. Wexpro obviously develops gas on behalf of the utility earns a lot of return on that investment base. But that gas supply over the long haul needs to be competitive with alternate sources of gas on the open market and looking at the forward curve in the Rockies, we can drive Wexpro development, we have lots of low costs, low risk opportunities, but we have to manage that investment so as to keep the competitive advantage that Wexpro offers the utility or otherwise the paradigm is broken.

And frankly we believe that service cost, drilling and completion costs have ways to go and rather than continuing to drive capital in that business, we think letting off the accelerator not completely, not slamming on the brakes but letting off the accelerator to let the costs adjust for long investment opportunity in Wexpro and ultimately allow for the development of more gas and ultimately allow for the investment of more capital in that business.

Wexpro is tied obviously; Wexpro's capital budget is tied substantially to Questar E&P at Pinedale because the wells that are being drilled at Pinedale this year are joint Questar or Wexpro wells a large percentage of them. So as we slowdown a bit and if there is and we were thinking about a dozen rigs at Pinedale and we're keeping nine rigs out there and we're looking at that frankly, as the year goes on we just won't get as many wells drilled as we had recently had hoped.

Carl Kirst - BMO Capital

Great. That's helpful. Thank you.

Operator

Our next question comes from the line of Becca Followill with Tudor Pickering and Holt. Your line is open.

Becca Followill - Tudor Pickering & Co.

Hi I have two short quick questions. One how much Haynesville production is built in to your guidance of 180 to 186 Bcfe? And two, would you consider any equity here?

Keith Rattie

I'll answer the first question, I don't know. And I don't think I have anything here that I can tell you the breakout, I mean I can tell you what the forecast for the division is, we've got about 50 Bs or so forecast in the Eastern Midcontinent division and that compares to 44 last year. So most of that increment Becca would be Haynesville.

Becca Followill - Tudor Pickering & Co.

Okay.

Stephen Parks

And issuing equity, no plans to issue equity at this point. We may at some point consider just having... to have all of the flexibility we need putting the shelf registration in place, but again we don't have any plans to do that. Obviously with our shares where they are today, the issue would be use of proceeds and we believe we have a balanced program that can be funded from cash flow from operations and no plans to issue equity.

Becca Followill - Tudor Pickering & Co.

Great. Thank you.

Operator

Our next question comes from the line of Stewart Winman with Catapult Capital. Your line is open.

Sunil Jagwani - Catapult Capital Management

Hi, this is actually Sunil Jagwani and thanks for taking my call. I just have one or two very quick questions. Firstly, if you had the option to do a well today in the Haynesville versus the Pinedale and you could only drill one well, which one would you drill. Did you hear that?

Keith Rattie

I am thinking. I think somewhere the Pinedale well is.

Charles Stanley

Yes, we're drilling Pinedale on a combination of 5 and 10 density, so on average the wells that we're drilling at Pinedale and lower IP's and lower EURs and hope what we're seeing in the Haynesville today. I am a little cautious on that, just because of the early part of our earning curve it remains still. But, I would think that the Haynesville well incrementally would generate more production per dollar of capital and probably also higher returns?

Keith Rattie

Yeah, we're modeling better margins from the Haynesville, even with the risk to volumes that Chuck has given early or giving you in time, the summary of the tight curve. The only point I would add to that Sunil is that we get a three for one, when we invest capital in Questar E&P and parts of the development of Pinedale, Wexpro sometimes participate in QEP operated wells. And of course, the volumes flow through our gathering business. So when I look at it from my perspective total forth, I'd probably favor Pinedale at this point, when you take into account risk.

Sunil Jagwani - Catapult Capital Management

I understand. So basically, if I were to draw this to theoretical conclusion, when the Haynesville evolves and develops a little bit more. It does seem like, and then its de-risk there were a bit more, it seems like it would attract some capital away from the Pinedale, where that question to be raised into the Haynesville, correct?

Charles Stanley

It's Chuck again. Most of the, if you keep in mind that the Haynesville wells are more expensive than Pinedale wells. The actual refining costs maybe a little higher in the Haynesville. And certainly are today on a risk basis than Pinedale. There's two questions; one is the realizations in each one them (ph) and the clear concern over takeaway capacity in each well. And then, as Keith mentioned, there are knock on economic benefits unique in Questar that may not be enjoyed by other companies.

One is the co investment in many of the wells of Wexpro. And then, the downstream benefits of our gathering and processing business as other companies may not have there Pinedale producers. The Haynesville is challenged by gathering and processing bottlenecks gathering mode and that's the necessity bottlenecks. And interstate pipeline takeaway capacity as you said rightly, will be important over the next year or so.

Sunil Jagwani - Catapult Capital Management

Okay. And then, just last quick question also on the Pinedale. We've heard a lot of things surrounding regulatory issues, one of which was, I guess the ozone issue. Can you just I guess, give us the both points regarding the specific issues, regarding regulation that are or light hamper activity in the region, because most of it just sounds like noise. So, I just try to clarify from you guys, and change always. Thank you.

Charles Stanley

I think the key takeaway there is that last fall we received the record decision from the KOM (ph) on the development of Pinedale under the supplemental EIS. That supplemental EIS considered air quality, it considered the impact of industry activity on development. We think that that document is... and the work around it, which were years in the make, eventually went back to the original EIS and record decision built on that provides a regulatory framework which frankly is unprecedented in it's scope and magnitude, as far as required reductions in air emissions, an 80% required reduction in air emissions over the 2005 baseline.

Installation of Woodford gathering systems which reduces emissions from truck as well fugitive emissions from tanks, hard carbon vapors (ph). The ultimate electrification of compression in areas as volumes, and as activity drives more and more compression horsepower as the wells decline.

But, the ozone issue is real. There have been measured ozone levels in all region that have part of the maximum specified by the EPA. It's a fascinating problem, unique in that area, where bright white snow on the ground, combined with a strong sunlight in an atmospheric conversion creates a little factory for ozone that ramps up very short period of time. And then goes away almost as quick as it appears. And we are working with a number of folks who are studying the problem to try to help us understand the unique situation at Pinedale that causes it. It is a concern, but, I think it's a manageable concern, and something that we as an industry group are working to address.

Keith Rattie

And we think it was addressed in the SEIS and record of decisions, as you know. We've committed, as an industry to cutting baseline emissions by 80% from the 2005 baseline. And we'll go a long way towards addressing whatever components of the ozone issue is actually related to industry activity, which is another topic.

Sunil Jagwani - Catapult Capital Management

And just to be clear, so is this issue actually forcing you to curtail... I know the gas prices are weak. But, if that wasn't the case, would you be somehow restricted in drilling because of this?

Charles Stanley

No. There've been no curtailments. We as an industry have obviously, been concerned about this. We've been talking to the folks at the Wyoming DEQ, they have the primary role in regulating air admissions in the stilt well (ph). We looked at ways to minimize the impact of our activities... whatever impact we're having on those... on issue out there, by avoiding doing things that might exacerbate the problems during periods of time when the atmosphere is inverting (ph).

When you have these very special... very clam days which if you've been to Wyoming, dead calm day in Western Wyoming is few and far between, and the atmospheric conversions are few and far between. But when we see those particular weather conditions setting up, we try to avoid refueling rigs, we try to reduce construction on locations, things that could contribute... we don't know what the true culprit here is. It could be other activities completely unrelated to the oil and gas emission, mining activities, power plants et cetera that could be contributing this. We don't know what the ultimate cause is, but we're doing everything we can to make sure that we're not causing it.

Sunil Jagwani - Catapult Capital Management

Okay, thank you very much.

Operator

Thank you. Our last question comes from the line of Ray Dekan (ph) with Pritchard Capital. Your line is open.

Unidentified Analyst

Yeah, hey Chuck; real quick one how many permits do you have lined up in the Bakken for one, prices to recover and how difficult is the environment there to get permits. I guess what's been your experience so far and has EOG's shutting in of their volumes helped differentials at all versus that 15 to $20 number you talked about earlier?

Charles Stanley

Well Ray. First of all thank you for patience. We let the question get away from us today. The... we've got 16 permits in various stages. We're expecting a bunch of them to pop out here very quickly. These are on Indian lands and inside the Fort Berthold reservation. And as a result we have to go through the process with the DIA to get the permits. They frankly... it's been an area that's seen virtually no industry activity or very rare industry activity for a decade or more. So they are scrambling to get up to speed in processing permits. We feel like that after this first batch comes out we have more than enough to keep in front of a drilling program.

The second question, I can't tell if the shut-ins have had an impact yet. Obviously, EOG is just one producer in the Williston, I know they shut in about half of their production or they said they were shutting in half of their production. I am not sure when they did that. And I haven't... don't have any current information today on whether the differentials would move. I would suspect that the differentials will move in over time if you take in supply out of the market. It just makes sense. Although, if other producers are continuing to drill and complete wells it may not move it as much as one would hope.

Unidentified Analyst

Thanks very much.

Charles Stanley

You bet.

Operator

At this time there are no further questions in queue.

Stephen E. Parks

We want to thank you all for listening to our call today. You can get a taped replay of our remarks on our website at www.questar.com. Once again thanks for your interest in Questar.

Operator

Thank you for using the conferencing services. You can hear a recording of this call at our encore replay at 1800-642-1687, referencing ID number 8217391. Thank you.

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