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Ultra Petroleum Corp. (NYSE:UPL)

Q2 2009 Earnings Call Transcript

August 4, 2009 11:00 am ET

Executives

Kelly Whitley -- Manager, IR

Mike Watford -- Chairman, President and CEO

Mark Smith -- CFO

Bill Picquet -- VP Operations, Rocky Mountains

Sally Zinke -- Director, Exploration

Analysts

David Heikkinen -- Tudor Pickering Holt

Wendell [ph] -- Bear Stearns

Subash Chandra – Jefferies

Zen Lee [ph] -- JP Morgan

Brian Singer -- Goldman Sachs

David Tameron -- Wells Fargo

Leo Mariani -- RBC

Sunil Jagwani -- Catapult

Marshall Carver -- Capital One Southcoast

Stephen Richardson -- Morgan Stanley

Andrew Gunlock [ph] -- ASB [ph]

Ron Mills -- Johnson Rice

Operator

Good day ladies and gentlemen and welcome to the second quarter 2009 Ultra Petroleum Corp. earnings conference call. My name is Erica and I will be your coordinator for today. At this time all participants are in a listen-only mode. We will be facilitating a question and answer session towards the end of this conference. (Operator instructions).

I would now like to turn the presentation over to your host for today's call, Ms. Kelly Whitley, Manager of Investor Relations. Please proceed.

Kelly Whitley

Thank you, Erica. Good morning, ladies and gentlemen. Welcome to Ultra Petroleum's second quarter 2009 earnings conference call. This conference call will contain forward-looking statements that involve risk factors and uncertainties detailed in the Company's filings with the SEC.

All statements other than statements of historical facts included in this call including statements regarding our financial position, estimated quantities and net present values of reserves, business strategy and plans and objectives of the Company's management for future operations are forward-looking statements.

The company can give no assurances that the assumptions upon which such forward-looking statements are based will prove to be correct nor can the company assure adequate funding will be available to execute the corporation's plan.

Financial results are subject to audit by independent auditors. This call may contain certain non-GAAP financial measure. Reconciliation to calculation schedules for the non-GAAP financial measures can be found on our Web site at ultrapetroleum.com.

At this time I would like to turn the call over to the host of today's call, Ultra Petroleum's Chairman, President and Chief Executive Officer, Mike Watford.

Mike Watford

Thanks, Kelly. Good morning and welcome. Thank you for joining us. With me this morning is Mark Smith, who will discuss the financial side of our business, Bill Picquet, who will provide the operational update and Sally Zinke will talk about our exploration efforts in particular our growing activity in Pennsylvania in the Marcellus shale.

Second quarter of 2009 was a difficult period for the industry, but Ultra delivered strong results. We established a new quarterly record for production of 44.5 Bcfe, an increase of 30% from second quarter 2008. At the same time we decreased our all-in-cost by 29% to $2.43 per Mcfe, and our cash costs also decreased to $1.42 per Mcfe. We believe we are the low cost producer.

We enjoyed healthy margins and at the end of the day this is our margin business. Our cash flow margin was 73% and net income margin was 34%. Strong margins translate into industry leading returns. Our return on capital is 25% with a 63% return on equity. We are unique with a combination of top tier growth at the industry's lowest cost structure. That sets the stage for a strategy of profitable growth.

Today you will find in our release and in our comments additional information on two issues that we think may be misunderstood by some. The first is well sizes in the Pinedale field in Wyoming.

As a list of initial production rates for Ultra operated wells placed on production during the second quarter illustrates we are drilling sizeable wells. The second quarter average IT is approximately 12 million cubic feet per day. When you look at average reserve sizes for the second quarter of almost 7 Bcfe per well, you see clearly that our well sizes are not decreasing.

Bill has more details.

Second issue is natural gas prices and location or basis differentials. The market is changing and we want to make sure you understand what we see occurring with the completion of REX East, Rockies basis is significantly improving. And when we forecast Ultra's likely mix of natural gas sales in the future we see a corporate sales mix that equates to 94%, 95% of Henry Hub, a much different outcome than last few years and I think it only gets better as Rockies gas supply flattens and begins to decrease while more than 2 Bcfe a day of additional takeaway capacity is built. The pipeline congestion issue is moving to other supply areas.

Mark has more to add.

We have a growing opportunity in Pennsylvania in the Marcellus that has the cost structure, margin and scale that we need to build a business. And it's beginning to look like it could be a good size business.

Sally will update us on our growing Pennsylvania business segment.

One additional comment from me before I turn the conversation over to the team and that's on reserves. We ask Netherland Sewell to provide us with a mid-year proved reserve update using the more logical 2009 rules and unrestricted by us. The result is an answer almost twice what we reported at year end 2008. The scale of our business in Wyoming is impressive, but today we may only be trading on our Pennsylvania value with a free option on Wyoming. Mark?

Mark Smith

Thanks, Mike, and good morning. As you've seen from our press release we had a very good quarter operationally despite the continued reduction we've experienced in natural gas prices. We continue to see strong performance in the field with record production levels and reduced costs. REX East increasing takeaway capacity and reduced overall Rockies production we are seeing improved pricing relative to Henry Hub. Most importantly we continue to Exhibit strong margins. Cash flow margins for the quarter were equivalent to roughly year ago levels.

For the second quarter our Wyoming production was up 30% on an annual basis and up 6% sequentially to a record 44.5 Bcfe. Once again our quarterly production registered the highest in the Company's history and was due to our increased activity in Wyoming and our improved drilling efficiencies.

Bill will speak to this in detail.

Natural gas prices were down significantly for the quarter. However, we are seeing the favorable effects of our hedging strategy, our averaged realized gas price for the second quarter was $5.04 per Mcf, 37% lower than our price a year ago, but up sequentially from the first quarter levels of $4.46.

As a result of our increased production levels offset by the decrease in realized commodity prices revenues including effects of our hedges for the quarter registered $229.5 million. Corporate lease operating expenses for the quarter decreased to $0.77 per Mcfe compared to $1.55 for the same period in 2008. This decrease was a result of reduced severance and production taxes due to lower commodity prices combined with reductions in our unit production costs.

Our production costs have improved over last year as our partners have worked to reduce their operating expense levels and our mix of operated wells is increased. This higher mix of operated production provides us with a larger proportion of increased production and hour lower unit costs.

Transportation costs amounted to 13.2 million this quarter or $0.30 per Mcfe on our total production volumes compared to $0.35 per Mcfe last year as higher absolute transportation costs were more than offset by increased production volumes.

Our DD&A rate registered $1.01 per Mcfe in the quarter; G&A expenses on a unit basis were flat over last year at $0.13 per Mcfe while interest costs registered $0.22 per Mcfe. The net effect of all these factors was a $0.98 per Mcfe or 29% year-over-year decrease in overall corporate costs to $2.43 per Mcfe.

Our cash fuel level cost decreased 4% on a unit basis over last year to $0.49 per Mcfe. Operating cash flow registered 168.5 million for the quarter, providing a 73% cash flow margin, as a decline in realized gas prices was offset by our production growth in our continued focus on operational improvements and cost reductions.

Adjusted for the non-cash unrealized losses associated with the mark-to-market position on our hedges we recorded adjusting earnings of 78.3 million for the quarter providing a 34% net income margin and $0.51 adjusted earnings per diluted share.

In terms of returns for the second quarter on an annualized basis our return on equity was 63% and our return on average capital employed was 25%.

Cash provided by operating activities during the quarter amounted to $108.5 million with cash used in investing activities totaling $160.2 million. These investment activities were primarily comprised of 160.5 million in oil and gas property investments.

Over the quarter net cash provided by financing activities totaled 46.6 million consisting largely of 43 million in net borrowings on our senior bank facility.

We ended the second quarter with approximately 11 million of cash on hand and 764 million in debt. I recall that our senior debt capacity is just over 2 billion and we believe our liquidity allows us to fund far more than our 735 million 2009 planned investment program due to use of our cash flow from operations combined with our revolving credit facility.

In considering our price outlook for the remainder of 2009 I want to draw your attention to the summary table with historical and forward basis differentials to Henry Hub that we provided on Page #5 of this morning's press release. We've seen basis differentials improve from a low of 57% in Henry Hub in 2007 to currently roughly 90%.

We are currently selling gas in Wyoming on a spot basis at $3.13 or 89% of Henry Hub at $3.52. This narrowing in Rockies basis has occurred while Dominion South basis has improved from a low of 104% of Henry Hub to currently 105%. We've seen increased capacity out of the Rockies on first REX East and ultimately we will see it with Ruby as well.

We've also seen reduced drilling activity in the Rockies resulting in declining production levels in the region, while gas is becoming congested in other regions. As a result we see a tightening in the markets view of basis going forward. When one considers this in light of our overall corporate mix of production and we see our basis going forward improving to approximately 94% to 95% of Henry Hub.

We currently have approximately 60% of our remaining 2009 forecast natural gas production hedged through fixed price swaps at a weighted average price of roughly $5.80 per Mcf. For calendar 2010 we have approximately 98 Bcf hedged at approximately $5.49 per Mcf. For calendar 2011 we have about 70 Bcf hedged and a price of roughly $5.56 per Mcf. A summary of our hedge positions also included in this morning's press release.

In terms of guidance we are maintaining our full year 2009 production guidance at 172 Bcfe to 177 Bcfe. Guidance for the second half of 2009 is in the range of 85.4 Bcfe to 90.4 Bcfe. Wyoming lease operating expenses are expected to run $0.25 per Mcfe, gathering $0.27 per Mcfe and transportation at $0.39. We currently expect our DD&A rate to run roughly $1.03 per Mcfe and we see G&A costs at approximately $0.14 per Mcfe for the year.

Now I will pass it off to Bill for an update on our operations.

Bill Picquet

Thanks Mark. In Wyoming in the second quarter Ultra brought on stream 64 gross, 26 net new producing wells. The average initial 24-hour sales rate for these new producers was 8.5 million cubic feet per day. Ultra's operated Pinedale wells averaged 11.7 million cubic feet per day while the nonoperated wells averaged 6.7 million cubic feet per day.

The high for the quarter was from the Ultra operated Riverside 4B1-11D, which floated 15.6 million cubic feet per day. At the end of the quarter there were five Ultra operated rigs drilling in Pinedale in a total of four non-operated rigs also active on Ultra interest lands in Wyoming.

The average reserve size on wells drilled in our Ultra operated program increased to 6.9 Bcfe per well during Q2 2009. This increase in reserve size is due to year round access to better parts of the field granted in the September 2008 record of decision. During Q2, almost all of our operated drilling and completion activity in Pinedale has been in a more prolific Riverside and Mesa areas of the field.

We are now able to access these areas of the field without seasonal restrictions going forward. For the better part of the next decade most of our wells in our Wyoming program will be drilled in these areas.

At mid-year our third-party reservoir engineering firm evaluated our Wyoming reserve base looking particularly at our proved reserves using the new SEC guidelines for year end 2009. If Ultra chose to relax our self-imposed three-year pud limit our third-party estimate of proved reserves would almost double from year end 2008 levels of 3.5 Tcfe to a new total of 6.7 Tcfe without drilling a well. This is just a further evidence of the low risk of Ultra's reserve base. We are now drilling in the best areas of the field and further confirming the outstanding quality of our reserves.

Our operating efficiency in Pinedale continues to improve. In the second quarter we averaged 21 days, spud to TD for Ultra operated pad wells, a 9% improvement over the average for Q1 2009. During the quarter our average rig release to rig release was 24.4 days, down over 20% from our Q1 average of 30.6 days. This is the product of increased pad drilling with year round access and all of our rigs being equipped with the ability to skid from well to well. 74% of Q2 wells were drilled in less than 20 days; spud to TD.

With year round access we are drilling more pad wells and have significantly fewer rig moves. In Q2, we doubled our percent of wells drilled in less than 20 days versus Q1. We've transformed our drilling operation from a fleet designed to drill individual wells on single pads to a fleet with state of the industry pad drilling technology.

We've implemented dramatic changes in our drilling program over the course of this transition. The most significant changes include the use of oil based mud, drilling under balanced with latest bid in directional technology and the use of bid drill well on paper process on each well to optimize each segment of each well. This go-oriented approach to drilling coupled with the integration of outstanding operational and technical team capability is producing excellent performance

As noted in our press release we've gone from a fleet wide average performance of 61 days per well spud to TD and a cost of $7 million per well to our Q2 2009 performance of 21 days spud to TD at an average cost of 5.25 million per well. Our record well is now 14.3 days spud to TD and our costs are currently at the $5 million level and already about 20% of our wells are coming in below $5 million, further evidencing room for future cost improvement.

We expect to continue reducing drill times and costs. Our target for the perfect Pinedale well using today's technology and a fit for purpose rig is 12 days spud to TD and we don't expect technology to seize to improve.

Ultra's completion activity continues to benefit from efficiency gains and service cost reductions. Year-to-date through Q2 we pumped a total of 1,510 frac stages, averaging almost 25 stages per well compared to just over 2,900 total stages and 22.7 stages per well during the full year in 2008. We averaged $73,000 per stage for 2009 year-to-date compared to almost $77,000 per stage in 2008.

We expect our completion cost to continue to decrease in the second half of 2009. Our current cost per stage is averaging about 65,000. Benefiting from the continuity of the equipment and personnel in our frac operations. Our improving cost per stage performance is the product of both added efficiencies in our operations and continued reductions in the cost of services.

With that I'll turn things over to Sally.

Sally Zinke

Thanks, Bill. We ended last quarter with a total of 16 delineation wells drilled in Pinedale. Three of those wells were waiting on completion at the end of Q1 were completed during Q2 to culminate our planned Pinedale delineation program for 2009.

The program for 2009 has exceeded Netherland Sewell predrill reserve estimates for those locations by more than 25% with an average post-drill EUR estimate of over 5.4 Bcf and an average IT rate of over 8.4 million cubic feet per day. Of particular note is delineation well on the east side of the War Bonnet area, the War Bonnet 5D-113, which IP-ed for over 12.4 million cubic feet per day and has an estimated EUR of 13.3 Bcf against a predrilled estimate from Netherland Sewell zero. With this program and wells like this one we are continuing the expansion of the defined areas of field as well as growing both production and the estimated recoverable reserve net to Ultra.

Our low quality pay or LQ program from near well bore sand lenses beyond wireline depth of investigation and below Netherland Sewell conventional pay cut off is continuing with one to four stage addition per well at steadily dropping per stage frac costs now below $65,000 per stage as Bill indicated.

Our recognition of the reserve and production additions from these zones has now made these completions part of our standard and routine completion operations. Our analysis and work on defining the expected reserve additions from completion of normally pressured shallower stages in the land, also continues to progress on the Pinedale anticline.

We are continuing our ongoing assessment of increased sensitivity drilling, ongoing pressured data collection in five acre pilot well. The series of five wells completed in Q2 2009 as part of this analysis have exceeded the pre-drill Netherland Sewell estimate and have an average IP of 9.3 million cubic feet per day, and average EUR of 4.6 Bcfe per well, suggesting that Netherlands Sewell estimates for reserves for future five acre Ultra wells may be too low.

Looking at Ultra's Pennsylvania exploration, early horizontal Marcellus well successes have been very encouraging and as a result we will be escalating our activity. Our area of interest is located in north central Pennsylvania in Potter, Tioga, Bradford, Lycoming and Sullivan counties in an area where we already have steeper horizon success with (inaudible) production and eight gross, four net, Oriskany sandstone wells.

We have 100 square miles of 3-D seismic with an additional 92 square miles to be shot later this year, covering approximately 40% of our acreage position. There are currently 13 gross, 7.5 net vertical Marcellus tests and nine growth, 4.5 net horizontal Marcellus wells with lateral sections ranging from 3,500 to 4,000 feet. This is an area of strong key geologic parameters indicating good success for horizontal Marcellus exploration.

We have an average 150 feet of Marcellus shale thickness increasing to the south and east across our acreage. The area is in the dry gas generation window. Across the five county areas, the Marcellus is a depth ranging from 4,000 feet to 7,000 feet providing a good pressure regime.

Our Marcellus section has good silica content to promote hydraulic fractures. The volume of shale gas generated is greater than 125,000 Mcf per acre foot. And the present day hydrocarbon index based on geochemical analysis matches the sweet spot of the Barnett.

In this promising area I think it is important to note that our approximately 320,000 gross and 170,000 net acre leasehold position standing an area about 40 miles wide and 30 miles across is not scattered or a shut gun acreage distribution, but is comprised of primarily contiguous leases that will allow us to form producing units and execute on a horizontal development program.

Our exploration drilling to-date has successfully assessed in areas 20 miles wide with horizontal wells and additional 10 miles beyond that with vertical tests. To-date we have drilled a total of nine gross, 4.5 net horizontal Marcellus wells with a tenth horizontal currently drilling. Seven of those wells have been completed with two waiting on completion.

Three horizontal and one vertical Marcellus wells are now producing to sales with an additional two horizontals expected to be connected later this week. The first two horizontal wells went on sales on July 17 at a combined rate of over 12 million cubic feet per day. We expect to drill and complete a total of 24 gross, 16.5 net additional horizontal Marcellus wells by year-end 2009. Total wells drilled on our Pennsylvania acreage in 2009 is expected to be 35 gross, 22 net including two Oriskany test drilled in Q1.

From an operational perspective we have aggressively moved to establish our access to water, materials and supplies, services and infrastructure. We currently have four pipeline tab with a total capacity of 80 million cubic feet per day with plans for expansions over 300 million cubic feet per day by year end 2009.

Gas gathering and water handling pipeline systems that will allow us to complete and connect most wells as they are drilled are being installed in advance of drilling. We are using our project expertise gained from Pinedale to design the Marcellus program to facilitate water access, water movement and water reuse as well as leveraging directional drilling proficiency that builds operational staff has developed in Pinedale.

We have multiple water access points with a combined capacity of 25,000 barrels per day with an average completion of 12 stages requiring 76,000 barrels of water. This access will enhance our ability to accelerate Marcellus activity. We have sufficient water access and storage to accommodate a four rig drilling program. And back to you, Mike.

Mike Watford

Thanks Sally. In 2009, we've chosen to moderate our growth in a weak commodity price environment by limiting capital expenditures and not accelerating development. We believe that we've been good stewards of capital since economic returns.

Our low costs allow for strong margins even in this environment which continues to propel forward our profitable growth strategy. The scale of our assets is impressive with the potential to double proof reserves and with our resource estimate currently approximating 20 trillion cubic feet, almost six times our proved reserves.

Prices for our primary product natural gas are increasing on a relative basis due to changes in location differentials brought on by new pipeline construction. For Ultra our net corporate price improves even more with local production in the Northeast.

And we see our Northeast business segment where we are currently merely scratching the surface growing rapidly. More importantly, this Northeast business is adding significant profitable scale to our existing Rockies business that enhances our profitable growth strategy.

Left unresolved today is how fast do we go. In 2009, we placed more focus on hedging and healthy capital structure so we can run level load versus boom bust drilling program. It is clear to us that we can grow annual production by 10% to 15% over our three-year planning period 2010 to 2012 by investing cash flow. With low levels of debt we can do more.

Now I'd like to open the call to questions. Erica?

Question-and-Answer Session

Operator

(Operator instructions). Our first question comes from the line of David Heikkinen with Tudor Pickering Holt. Please proceed, sir.

David Heikkinen -- Tudor Pickering Holt

Good morning, guys. And good quarter and wanted to ask some questions as you think about that three-year plan of, how do you balance spending in the Pinedale and spending in the Marcellus and what do you think about from a capital intensity over that time frame on an annual basis?

Mike Watford

Well, David, I think that Pinedale has fantastic economics and low cost as evidenced by our lowest cost in the industry here this quarter this year, allows us to have very healthy margins even in a low commodity price environment. So we are not going to abandon Pinedale. I think you will see us go to a level loading there of a flat capital of $450 million, $500 million, maybe seven rigs, eight rigs, we'll see, and although Bill continues to get more productive so every rig costs us more money every year, even the low costs were down, because of more well being drilled per rig. And I think will you see us flex up and down here for the next couple of years what we do in the Marcellus and deeper horizon in Pennsylvania. I think we are real serious about our ability and based on continual good success that we've seen in the first nine wells really that you will see us go towards that 100 well program in 2010, if not more. So I'm not giving absolute numbers but we have some another core area to develop in the Northeast and I think you are going to see us spend more of our CapEx there.

David Heikkinen -- Tudor Pickering Holt

And the 100 wells, is that a gross well count? I mean, what will your net well count be?

Mike Watford

I don't have a net well count. It's a gross well count, it is just a starting point in the conversation. We don't have any capital budget for 2010 yet.

David Heikkinen -- Tudor Pickering Holt

And then average 50/50 joint venture with east, how much acreage do you own that would be outside that?

Mike Watford

I think of the 320,000 acres we have 30,000 acres, 100% in the other is with east.

David Heikkinen -- Tudor Pickering Holt

Okay. So thinking about it as a 50% working interest on that well would be a good starting point as well.

Mike Watford

Probably not, no, probably low because I think you will see our ability to drill wells, we will pick up the pace pretty rapidly. We have a rig starting here on our operating production, when, Bill?

Bill Picquet

Next week.

Mike Watford

Next week and we are convinced that we can drill these wells faster than what you've seen most folks drill wells there so far based with some of the technology we've used in Wyoming.

David Heikkinen -- Tudor Pickering Holt

As we think about 30,000 acres can you orient me as far as where your 100% acreage is? I think I've seen some maps that have the east area, just trying to get an idea of where your activity is going to be?

Sally Zinke

Our 100% acreage travels the Potter, Tioga county line and most of the acreage with east is due east of that.

David Heikkinen -- Tudor Pickering Holt

And from a well results standpoint the wells that you've had so far have those been on your 100% lands or are they on the other lands?

Sally Zinke

To-date the horizontal wells have been on the joint venture acreage.

David Heikkinen -- Tudor Pickering Holt

Okay. I think that's it. Thank you.

Mike Watford

Thank you.

Operator

Our next question comes from the line of Wendell [ph] with Bear Stearns. Please proceed.

Wendell -- Bear Stearns

I hope I'm not with Bear Stearns. I think it would be Bernstein but all the same. When you look at the comparison to the Marcellus and the Pinedale clearly your return on capital employed in the Pinedale is best-in-class. How much do you think you need to bring down the equity in the Marcellus to make it comparable to the economics that you are currently getting in the Pinedale?

Bill Picquet

This is Bill. Just looking at what we would consider kind of middle of the road typical well economics, if you have a reserve of three Bcf and well cost of about $3.25 million per well which is about what we've experienced so far as far as the almost 4,000 foot laterals we've been drilling to-date, that gives you an internal rate of return of 84% at $6. And F&D in the $1.30 range. So we kind of like those economics. And so far our well results are actually better than that based on our sampling of wells to-date.

Wendell -- Bear Stearns

Okay. And those Marcellus rates you gave out in the press release, are they 24-hour or thirty-day numbers?

Sally Zinke

You are talking about the five wells with the test of 5.3 million?

Wendell -- Bear Stearns

Yes.

Sally Zinke

Those are kind of mixed so….

Mike Watford

It's a range of nine hour tests to 40 hour tests across the pipe wells, so.

Sally Zinke

(inaudible) I was going to say as a comment, the two wells that we did put on production exceeded those test rates. So I think those are good ballpark numbers.

Wendell -- Bear Stearns

Do you have a rough estimate for what you expect the 30-day average to be over those five wells?

Bill Picquet

No, we are still fairly early with the first two going to sales.

Mike Watford

We only have about two and a half weeks of production on our first two wells. So it's premature for us to give you 30-day estimates.

Wendell -- Bear Stearns

Okay, great. And just a last question. You've obviously highlighted I think quite rightly the pud rule changes create a lot of room for interpretation and you put a very sensible limit on that. But how do you think investors should look at pud reserves and improvement reserves going into the end of the year given what, was there relatively a big spread in the industry?

Mike Watford

I don't know there's going to be a big spread in the industry, but I think these are much more logical rules. Doesn't make any sense that you can only book the nearby well when you have a full steel that you drilled up on the corners and extensively and you know what's in the middle so that didn't make any sense to us and this has to do with the third-parties estimates certainty. I just think that's a better way. It will change what you do, but for us it's not going to change what we do. We are still going to apply the principles of trying to match development capital with reserve additions so you won't see us include in our previous results those total.

Wendell -- Bear Stearns

Okay. Great. Thank you.

Operator

Our next question comes from the line of Subash Chandra with Jefferies. Please proceed.

Subash Chandra – Jefferies

Yes, it's, continuing on the reserve question, I don't think it was in here, maybe it was, what would reserves have been mid year with the three-year limit?

Mike Watford

We didn't even look at it, Subash. It would have been more. We just didn't look at it.

Subash Chandra – Jefferies

Got you. Would it be the right approach to sort of look at without the three-year limit what the percent change was year over year and I assume the same thing for the three-year limit? Probably not right.

Mike Watford

Probably not. But that's why we provided the unrestricted year end number of the 4.82 compare to the 6.72 to try to give you a bit of an apple-to-apple, we are trying to portray. I mean, we are ultraconservative. We know that. You folks probably know that. We just want to do give a sense of the derisking of the resource. And we want folks when they run their NAV, they give real value for what is proved in other folks inventory. That's what we are trying to do

Subash Chandra – Jefferies

Got you. And in the Marcellus are you doing micro seismic on these wells?

Sally Zinke

We have a plan to do micro seismic in the second pair of wells that we operate on 100% acreage later in August.

Subash Chandra – Jefferies

And Riverside Mesa what is the total number locations you have, total number, I guess, non-war bonnet drilling locations in the Pinedale?

Mike Watford

Upward of 1,000 wells left to drill there.

Subash Chandra – Jefferies

Got you. Okay. And final one, Mike. I don't know if I heard you right. You said before I guess in your intro that investors are paying for Marcellus in getting the Wyoming option free or want to clarify if I heard that right or if I got it all wrong.

Mike Watford

The two subtles are you trying to say? That's not my style.

Subash Chandra – Jefferies

Yes, just wanted to make sure you have that order right and if you can clarify or repeat.

Mike Watford

I think (inaudible) VP of marketing who came up with his comments at a board meeting here a week ago that it appeared that our current market value was closer to what other companies are focused on the Marcellus what their values are and we have similar acreage, probably some reserves therefore you are getting a pre-option on Wyoming and Pinedale. I think just simple math if you can do this, I hate doing it but I want to use it for comparison is if we just assume 60% of our net 130,000 acres is productive and Sally is pretty comfortable if you go through all the announcements that she's done that we're going to have a larger percentage in that productive and that we have concentrated acreage position so we don't have scattered town lots of itty bitty pieces.

So, we're going to be able to put together very large drilling units. But 60% of that's 102,000. If you develop it at a 100-acre space, which is probably wrong, it's probably less than that, but you got 1,020 locations and you pick your reserves, net reserves, three Bs or 3.5 Bs or four Bs, we don't have enough production history to have those curves to have confidence, but what we are seeing, that suggests that what the other people are saying that have a more constitute position there or have been there for a longer period of time or thing, the low numbers, but you do the math and you get 3 to 3.5 Ts and you put whatever value you want on that, couple of bucks, that's $6 billion to $7 billion I think.

That's we're trying to say is that we've been quiet about the Marcellus opportunity we've had time to work it. We are pretty excited about now. You are going to see us aggressively go after it; probably add to our acreage position, and we think we can drill those wells to. I think our partner up there went from 15 days drilled the horizontal section to 13 days. We think both of us will be down to ten days within 60 days. So we are going to get after it.

Subash Chandra – Jefferies

Makes sense to me and agree with the math. And then just one final one, did you say three to four for guidance purposes you maybe referred to three to four rigs earnings in the Marcellus. Did I hear that correctly?

Bill Picquet

That's correct. What we said was if we could easily sustain a four rig program and we expect to have about that level of activity assuming we are successful.

Subash Chandra – Jefferies

Thank you.

Bill Picquet

Thanks, Subash.

Operator

Your next question comes from the line of Zen Lee [ph] with JP Morgan. Please proceed.

Zen Lee -- JP Morgan

Good morning. In terms of your reserves the 6.7 Tcfe, what percentages puds were the PD?

Mike Watford

Most of its puds. We can't get you the exact number but we will get that to you later. I mean our proved reserves at year end 2008 if you recall was about 62% puds. That's just because we are early in the development of the field. Again if you recall less than 10% of the field is developed. But we had the outlines of the field we feel pretty good about that. Although Salice Group [ph] continued drilling Asian drilling, where we continue to see a better and better results than what (inaudible) would suggest. So but we have, I don't know what it is, 1.5, 1.60s PDP, we can get the numbers out later.

Zen Lee -- JP Morgan

Okay. And compared to the year end number, 4.8, how much of that Delta is due to the SEC rule change?

Mike Watford

Well, it's 4.8, 6.7, right?

Bill Picquet

We said that's without drilling a well.

Mike Watford

That's, we also drill some wells in the first half of 2009. That's we are trying to do the comparison. But we're just…

Zen Lee -- JP Morgan

Right. But the 6.7 is a midyear, right?

Mike Watford

Definitely right.

Zen Lee -- JP Morgan

Versus 4.8, that's your year end number. So the 4.8T is also based on 2009 guidelines?

Mike Watford

No, it isn't.

Bill Picquet

No.

Zen Lee -- JP Morgan

Okay. So I'm trying to figure out the difference between 6.7 and 4.8, how much is due to the SEC rule change and how much is due to your organic reserve at?

Mike Watford

I don't know. We didn't work that number. I don't have that number available for you right now.

Zen Lee -- JP Morgan

Okay. Regarding Marcellus, how much are you going to spend on infrastructure second half of '09 and 2010?

Mike Watford

Well, we are spending a fair amount in 2009. How many miles of pipeline are we building, Bill?

Bill Picquet

We expect to have about 50 miles of gathering system installed by year end in areas of development.

Mike Watford

I don't have the exact number, but it's a significant amount.

Zen Lee -- JP Morgan

Okay. So that 50 miles gathering line will give you access to 300 million cubic feet per day?

Mike Watford

Well, that plus, it's already exists. We are building gathering systems in the areas where we're developing the properties. We have four distinct gathering systems and four different parts almost in four different counties. As Sally suggested we've done pretty expansive or extensive exploration efforts both drilling vertical wells last year and horizontal wells this year and now we are starting to go after the horizontal shale in a larger basis and connect our gathering systems as we drill the wells. We have sort of five separate gathering systems in, I guess four or maybe five at counties that we're some already partially exists, the others are currently under construction.

Zen Lee -- JP Morgan

Okay. All right. Thank you.

Operator

Next question comes from the line of Brian Singer with Goldman Sachs. Please proceed.

Brian Singer -- Goldman Sachs

Thanks. Good morning.

Mike Watford

Good morning, Brian.

Brian Singer -- Goldman Sachs

In the Pinedale if we add up your 23 operated wells that you highlighted, some of the initial production rates is about 268 million cubic feet a day. Obviously you don't have 100% of those wells. It's before royalty. They weren't online for the entirety of the quarter although I guess it also doesn't include the 40 or 41 or so non-operated well. Question is, I'm wondering if you could speak to the decline rates versus these IPs, any abnormal backlog and provide color on how we should translate the rates into the 20 million a day increase in gas production from the first quarter to the second quarter and your expectations for what seem to be flattish production guidance during the second half?

Mike Watford

Wow, you did that all without taking a breath.

Brian Singer -- Goldman Sachs

Thank you. I think I did take one breath in there.

Mike Watford

Well, let's start at the end of the question and work our way backwards. The flattish production guidance for the remainder of the year is just so we hit that 175 sort of Bcfe number. Our style is to under promise and over deliver. I don't think it's any different now. We've also built in some, if there's some lousy, gas prices are dollar in October we are building in our ability to shut in our production, things like that. So that I mean 175 will not be a hard number to get as we move forward that wouldn't be a challenge to it, but I will just take that off the table. But we don't see any reason to increase it now given what's going on in our world. We have the typical decline rates. I don't know how to answer the detail. We have that little wedge chart we've shown you before Brian that shows every year's capital budget, how the production comes on, it's lagged after the year, time you spend it, get most of the benefits for the prior year's CapEx in the following year. And every year is declining with the new peak year so, I don't know how to easily answer your question here and Bill is going to say something so I'll be quite.

Bill Picquet

I guess I'd just say, Brian, as far as well performance is concerned, no surprises as far as decline rates are concerned and as you know it varies from well to well significantly. Bigger wells have higher initial production, but decline faster too.

Mike Watford

I think the surprising thing we've seen, and I'll let Bill and Sally jump on it is the five acre well results. This is the first time that we've used the directional tools to more adequately or accurately base or bar hole location (inaudible) where we know exactly where they are where the ellipses are created accurately so we can minimize drainage or independent appearance with nearby wells and by doing a better job of putting the bottle hole location in those wells we're seeing better results.

Bill Picquet

Effectively what we are doing is getting them exactly where we want them with use of (inaudible) durable and that type of directional control and then drilling them faster in a more accurate pinpoint where we want them. And results are proving to exceed expectations by about 15% versus the pre-drill EUR on the once that we drilled like that so far. So that's pretty exciting.

Mike Watford

We can sustain a 10% to 15% improvement in recoveries of all the five acre wells we're going to drill in the field over the next 30 years that is a big reserve number. And we are the first ones that we think in the field between ourselves and our partners using the rotary (inaudible) to sort of the finally tune our location, the bar hole in the five acre wells.

Bill Picquet

Getting routine press at this point.

Brian Singer -- Goldman Sachs

Thanks. I guess if just picking up on one of the points you mentioned there if you look at the higher rate wells, the 12 million a day to 15 million a day well, where are they after three months or so and how does that compare to say where you were previously drilling maybe some slightly lower rate wells, let's say those in the 7 million to 9 million, where were they or where are they after three months?

Bill Picquet

I will have to go back and look at the individual curves, Brian. I don't have all that stuff right at my fingertips.

Mike Watford

We'll just get back to you on the details.

Brian Singer -- Goldman Sachs

Okay. And then I guess in the Marcellus, can you talk to your existing acreage position and whether you are happy with that position or whether you would if there are other joint venture opportunities or other acreage either nearby or in other parts of the Marcellus whether you see that as an area of expansion on the acquisition front?

Mike Watford

Are you out leasing acres, Brian?

Brian Singer -- Goldman Sachs

I am unfortunately from California and do not have property there.

Mike Watford

We are delighted with our acreage. I think Sally kind of gave you four, five reasons why we think we are in a delightful area, we are not going to suggest to you there aren't some other delightful areas, but we're certainly not in an ugly area. I think it would not be a right answer for us to tell you where else we have interest in acquiring (inaudible) but we do have interest in acquiring additional acreage.

Brian Singer -- Goldman Sachs

Great. Thanks.

Mike Watford

Thanks, Brian.

Operator

Our next question comes from the line of David Tameron with Wells Fargo. Please proceed.

David Tameron -- Wells Fargo

Hi, morning, let me take you through couple of questions. First, the IP rates in Wyoming, are those 24-hour tests or are those initial IP, what's the metric there?

Bill Picquet

Those are 24-hour sales volumes.

David Tameron -- Wells Fargo

Alright. The PV 10 number, Mike, is that a $5 per Mcf, is that a hub price?

Mike Watford

No, we don’t do hub price or anything, that's an Opal price, that's the way our financials work.

David Tameron -- Wells Fargo

Opal price, that's what I meant. Okay. Rig, how many rigs do you guys have running right now?

Bill Picquet

Six operated actually in Pinedale, we just got one of our new build delivered and spud its first well last week. So, and four non-operated. And the Marcellus we have one non-operated rig currently drilling and one operated.

David Tameron -- Wells Fargo

And that level in the Pinedale is, is that what you anticipate being at for the rest of the year?

Bill Picquet

It's going to grow a little bit in Pinedale. Mike mentioned seven or eight rig numbers go forward.

David Tameron -- Wells Fargo

Okay. And one more question. Can you guys talk about what the capacity utilization has been on REX and what you anticipate happening over the next few months? Obviously you guys have shut in gas in prior years. Can you just walk through that decision matrix?

Bill Picquet

Just to answer your capacity utilization question, David, since REX east opened up it's been running almost 1.8 Bs a day every day, for that one short period of time when they are doing some special work.

Mike Watford

What you've seen is REX East is running full and you've seen some of the other pipes that serve the Rockies lose volume. I think you've also seen someone brought this to our attention yesterday, storage, for example, you haven't seen any adds to western storage in the last couple of weeks.

David Tameron -- Wells Fargo

No.

Mike Watford

It has to do with hot weather, pud has to do with more gas moving away from the traditional market areas that Rockies gas serves moving back to the Midwest to almost northeast to Lebanon Ohio point.

David Tameron -- Wells Fargo

So if you think about potential shut-ins over the next two months?

Mike Watford

We were already in to August and August gas prices are $3 for spot volumes in Wyoming and our cash cost structure of $1.40, you have what is that, 50% margins at a cash cost structure of I guess more than that, at a cash cost, all in of 240, then clearly we make money, we make earnings. I don't know what other company actually has earnings, net income at $3 gas price. There's no reason for us to even consider shutting in there. If gas prices get down to $1.50, yes, we will shut in the whole field, mean we don't to flow for, in economics or if you wait till December and you sell for $4, $5 or $6 versus selling for a $1 in October there's no reason doing that. We've run on numbers, Mike's doing a nice job of presenting to the board, what happens if we shut in 25 Bs over couple of months and really there's hardly any impact to our financials.

David Tameron -- Wells Fargo

Alright. Sounds good. Thanks.

Mike Watford

Thank you.

Operator

Our next question come from the line of Leo Mariani with RBC. Please proceed.

Leo Mariani – RBC

Yes, good morning here folks. Follow-up question here for you in the Marcellus. You guys are talking about the one non-operated rig right now you are running. You are going to add a rig to operate acreage next week. Obviously, you've increased your capital spending out there and want to drill more wells. What are the plans for the rest of the year to add rigs? Is there another rig coming from on that piece or another operated rig coming? Just trying to get a sense of what you are expecting now in you are in?

Bill Picquet

Nonoperated rig coming in very near future so that would take us to a total of three and plans to add to that as we go out to the end of the year. So by early next year we are going to be averaging in the four rig level on an ongoing basis.

Mike Watford

We are talking about drilling 24 additional horizontal wells between now and year end with two to three rigs.

Leo Mariani – RBC

Okay. So you are going to average four rigs by kind of the end of the year, it would be around four. Is that one op and three non-op or are you going to bring another op in by the end of the year?

Bill Picquet

One op and three non-op.

Leo Mariani – RBC

With respect to your Marcellus acreage is all the stuff you have in New York or Pennsylvania or is any of that in New York?.

Sally Zinke

Our acreage position is totally in the five counties I mentioned. It's all in Pennsylvania.

Leo Mariani – RBC

Okay. Jumping over to the REX pipeline is there any downtime scheduled outline for maintenance you guys are aware later this fall?

Mike Watford

Not that we are aware of, no. There is maintenance scheduled in other pipelines serving other supply area of the U.S.

Leo Mariani – RBC

And in the Marcellus are you guys going to drill on your wells on 3D and have you been doing that thus far?

Sally Zinke

Our operated wells will probably all be drilled based on 3D. Some of the non-op has been based on 2D seismic. It's our intention on the wells that we drill to try and use the seismic to help define our lateral position to avoid faults in, other kinds of geo-hazards and maximize where in the Marcellus we happen to want our land.

Leo Mariani – RBC

Okay. And do you guys have a sense of what the geology looks like on some of your acres going on do you think it's heavily fall I know you are still shooting 3D over there and don't have a ton of 3D but obvious have some?

Sally Zinke

We have drilled enough vertical tests across the acreage position to have a pretty good feel for what it looks like from that standpoint and we do have a fairly significant amount of 2D seismic that gives us the larger fault position so we are pretty comfortable with what areas are heavily faulted and what areas are not.

Leo Mariani – RBC

Okay. Is there anyway to even qualitatively characterize whether or not you think you got a fair number of faults out there or do you think your acreage is pretty clean?

Sally Zinke

There are some fairly large regional faults through the area, but we see the Marcellus as having potential on both sides of that so it's just a matter of planning your units and your lateral drilling to accommodate where those faults are.

Leo Mariani – RBC

Okay. Thanks a lot, guys.

Operator

Our next question comes from the line of Stuart Wyman with Catapult. Please proceed.

Sunil Jagwani -- Catapult

Hi, good morning, this is actually Sunil Jagwani. My question was around the takeaway capacity that was mentioned, I think I saw 300 million cubic feet. Just to clarify is that gross or net?

Mike Watford

That's just a gross pipeline interconnect capacity.

Sunil Jagwani – Catapult

So just trying to understand what kind of takeaway capacity you guys could have say by the end of 2010, net to Ultra, can you help us with that number?

Mike Watford

No, we can't. The best we can give you is 300 million at the end of 2009 right now. We haven't put our budget.

Sunil Jagwani – Catapult

For the end of 2009, that 300 million, at least 50% of that would be net to Ultra, correct?

Mike Watford

More than 50% because some of it is interconnect. We have 100% of the gas behind it. I don't think you should read anything into the interconnect capacity meaning that's what production is going to be.

Sunil Jagwani – Catapult

Well, the reason I ask the question is because as you look at companies like Range and Cabot [ph] takeaway capacity seems to be the delimiting factor for how fast they can produce. And if it's different for Ultra maybe you can explain that.

Mike Watford

I don't think it's different. I think we are just further ahead. I think we realized with our live in the Rockies, and structure is key with its gathering gas processing plants or interstate pipeline takeaway capacity, and in Pennsylvania we don't need processing where we are so it's just a matter of gathering and compression and the access to interstate pipeline. (inaudible).

Sunil Jagwani -- Catapult

And just last question, unrelated to the first one, if we get gas prices at the strip or at what the strip shows currently for 2010, is it possible that more than half of your CapEx could go to the Marcellus compared to the Pinedale?

Mike Watford

I don't think so, no.

Sunil Jagwani -- Catapult

Alright. Thank you.

Operator

Our next question come from the line of Marshall Carver with Capital One Southcoast. Please proceed.

Marshall Carver -- Capital One Southcoast

Yes, just a couple of quick questions. In the Marcellus you gave, you said that all five wells tested greater than 5.3 million a day. What was the range on that? Were they all right around there or what the range or could you give me an average on those wells?

Mike Watford

He's going to look for it. Marshall, would you ask another question?

Marshall Carver -- Capital One Southcoast

The next question, with your partner East and them giving a capital infusion, does that change their drilling plans and allow them to accelerate and how would the wells elected, is that on a well by well basis? Could you drill faster than they would want to go or could they drill faster than you wanted to go or how would that play out?

Mike Watford

Well, let's start off. If someone who walk in and hand you $350 million, would that give you more money in your pocket to invest?

Marshall Carver -- Capital One Southcoast

Yes.

Mike Watford

Okay. We got that answer. Number two is the East folks are fine folks, we get along great in terms of putting the plans together. I mean, they are aggressive. They see the ability to create tremendous value for themselves and in their minority shareholder so I think we are in tandem. But it's APs well by well but we have conversations about programs and about areas and you really have to think out where you’re going to build a gathering system. At the same time you're going to drill wells. All of it has to come together and you have to have common agreement on that combined investment and I think it's a good partnership.

Marshall Carver -- Capital One Southcoast

So with the potential for 100 wells next year parts of those would be 100% UPL, but the remainder that would be with the partnership that would be fully up for that in all likelihood.

Mike Watford

(inaudible) I think they would be beating on the tables.

Sally Zinke

To go back to look at the flow test information, actually the lowest one is 5.3, the highest one is 7.4, and the other ones are kind of spaced down in between average is going to be above six.

Mike Watford

Again it goes to our conservative nature.

Marshall Carver -- Capital One Southcoast

Thank you.

Operator

Our next question comes from the line of Stephen Richardson with Morgan Stanley. Please proceed.

Stephen Richardson -- Morgan Stanley

Good morning. Quick question probably best for, Bill, but can you talk a little bit about the, looks like proportion of wells drilled in Pinedale below 20 days went up pretty substantially and your well costs are coming down but maybe talk about a little bit about where you are on the year end target of 5 million a well and what the drivers from here of that could be?

Bill Picquet

Well, essentially, we are regularly producing wells at the $5 million level right now and recently about 20% of the wells we've drilled have been below 5 million. So we are on the track to achieve that type of cost structure for the remainder of the year if not better. And what was the second question? I'm sorry.

Stephen Richardson -- Morgan Stanley

Just where do you think that goes going forward? For example, do you have pipe inventory from last year or from a different cost price environment, for example? Or is there anything else that could take that lower into next year?

Bill Picquet

We are just now getting into less expensive pipe. So I'm confident that we are going to achieve that 5 million, maybe slightly below regularly. So you will always have kind of a mix. But as far as drilling efficiency is concerned we are very encouraged by the fact that we just keep wilding away as far as the number of days per well are concerned. So we see the possibility to continue to bring that lower. As I said we see the perfect well right now with today's technology at about 12 days. Obviously, you are not going to drill the perfect well every time you go out. Our record right now is 14.3. So there is room to move down. We keep wilding away at that every time you take a step down your costs should track down with it. We are really excited about continuing to chip away at that cost per well.

Stephen Richardson -- Morgan Stanley

Thank you.

Operator

Our next question comes from the line of Andrew Gunlock [ph] with ASB [ph]. Please proceed.

Andrew Gunlock – ASB

Good morning, couple quick questions. I assume the Marcellus gas will all be sold east of Clarington, is that right?

Mike Watford

Yes, the four interconnects we currently have are one with Dominion South and three with Tennessee.

Andrew Gunlock – ASB

Right, what's the price in NYMEX I would guess, right, is that the STUs?

Mike Watford

Historically it's a premium to NYMEX.

Andrew Gunlock – ASB

And the earlier question on the investment of KKR into east resources if I'm not mistaken about $350 million. Mike, help us read into what that might mean for the value of your acreage. And my other question is with your clean balance sheet what is private equity bringing to them that you couldn't bring to them? Why weren't you the preferred buyer here if you can share any insights into that at all if you are willing to do so on a call?

Mike Watford

No, I don't think I will on a call, but what was the other question?

Andrew Gunlock – ASB

Well, the other question is what is the 350 mean in terms of valuing you in the Marcellus, is there anything you can give us on that reported price in the paper what your acreage might have a value?

Mike Watford

I don't think there's any way to do an easy per acre comparison because that was an investment in a corporation of a company with all their assets which beyond just their Marcellus acreage.

Andrew Gunlock – ASB

I see. So that investment includes both the utility and the pipes and all the other businesses that go on there, is that right?.

Mike Watford

Whatever east resources owns.

Andrew Gunlock – ASB

And then last question on the Rockies. You mentioned about you've been dead right on the improvement in the basis. For how long do you think it continues? You mentioned that it would continue to tighten for the immediate future, but if you would look out a few years do you expect Rockies to continue to trade in this 90%, 95% range for a few years or do you think this is just temporary?

Mike Watford

I'm not trying to say that Rockies itself trades at 90%, 95%. We are trying to say that our going forward mix of sales will be in that 94%, 95%. But we do see Rockies, I mean, all the various folks that quote basis differential going forward are all that 87%, 88% of basis differential for 2010, 2011, I don't think that's aggressive on their part, anything else conservative.

We're finally going to have some positives happening to Rockies producers or at least those that can make money in this gas price environment because you have enough pipeline capacity to take all the gas to market and have extra pipeline capacity and you still have commitments to build additional pipe of about 2 to 2.1 Bs a day, which comes on in 2010, 2011.

And all those projects still have the green light to go forward. So I don't think you are going to see any increase in Rockies production or gas supply beyond the eight Bs a day, whatever it is eight quarter Bs a day, now, the export capacity, but I do think you add another two Bs of takeaway capacity, but you will have a little more competition for Rockies gas. There is still plenty of Rockies gas. I think it helps us as opposed to any of the shale place and we have to be sensitive of that Marcellus what happens. Many of that shale plays, the other folks have used this term “congestion of shale gas.” I think you are going to see that in other place what we've enjoyed in the Rockies for three years or four years is about to happen to the other players.

I wish them well. It just means more infrastructure has to be built and they will have times when there's maintenance issues and they lose access to market and they have very low gas prices. So over time their basis differentials will decrease or enlarge and ours will get better. And I'm really looking forward to it. We are looking at 2010 with sort of a 50/50 split of, take simple math, 200 Bs of production, 100 Bs sold in the Northeast, 100 Bs sold in the Rockies, with 88% basis differential and a 103%, 104% basis differentially, add that, you get 94%, 95%. So it works for us.

Andrew Gunlock – ASB

I appreciate the comments. Thank you.

Operator

Our next question comes from the line of Ron Mills with Johnson Rice. Please proceed.

Ron Mills -- Johnson Rice

Just want to do clarify on the 20 Tcf resource potential I assume that still excludes any potential from the Marcellus?

Mike Watford

That has some Marcellus in it.

Ron Mills -- Johnson Rice

That does include some. And then how much of that is related to the low quality pay delineation or increased density. I guess X Marcellus, are you still somewhere around that 14 or 15 Ts that you had discussed previously?

Mike Watford

Yes, that's correct.

Ron Mills -- Johnson Rice

Everything else has been answered. Thank you, guys.

Mike Watford

Thanks.

Operator

Our next is a follow-up question from the line of Subash Chandra with Jefferies. Please proceed.

Subash Chandra – Jefferies

I just dial and back to that conversation about IPs and first month averages, I was looking at the public data, I believe some sampling of wells it looks sort of first month average 4.5, 5 million a day, but that sort of the peak first month. So we don't have the exact 30 days like you guys do, but A, is that sort of on the right track on what you are seeing for a mean in the second quarter program or even in the '09 program to-date?

Bill Picquet

I'll go back and confirm the data, Subash, but that sounds about right. Some wells will be a little higher, some well won't, but we will confirm it for you.

Subash Chandra – Jefferies

Okay. So that six point, the Q2, the 6.9 Bs would then conform with that first month average in that 4.5 million a day to 5 million per day?

Bill Picquet

Like I said I think that sounds about ballpark or we will go back and look at the curves and get you the real data for that well soon.

Subash Chandra – Jefferies

Okay. Great. Thank you.

Operator

There are no further questions at this time.

Mike Watford

Well, thank you. If anyone has additional questions please contact Mark or Kelly, how's that? Bye-bye.

Operator

Thank you for your participation on today's conference. This concludes the presentation. Everyone have a great day.

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Source: Ultra Petroleum Corp. Q2 2009 Earnings Call Transcript
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