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THOMSON REUTERS STREETEVENTS

EDITED TRANSCRIPTUPL - Q3 2013 Ultra Petroleum Corp Earnings Conference Call

EVENT DATE/TIME: NOVEMBER 01, 2013 / 3:00PM GMT

OVERVIEW:

UPL reported 3Q13 adjusted net income of $57.9m or $0.37 per diluted share.

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C O R P O R A T E P A R T I C I P A N T S

Mike Watford Ultra Petroleum Corp - Chairman, President and CEO

Doug Selvius Ultra Petroleum Corp - VP of Exploration

Jason Gaines Ultra Petroleum Corp - Manager Business Development

Brad Johnson Ultra Petroleum Corp - VP of Reservoir Engineering and Development

Mark Smith Ultra Petroleum Corp - SVP and CFO

Bill Picquet Ultra Petroleum Corp - Senior VP of Operations

C O N F E R E N C E C A L L P A R T I C I P A N T S

Marshall Carver Heikkinen Energy Advisors - Analyst

Ron Mills Johnson Rice & Company - Analyst

Bob Christensen Canaccord Genuity - Analyst

Mike Scialla Stifel Nicolaus - Analyst

Joseph Allman JPMorgan Chase & Co. - Analyst

Noel Parks Ladenburg Thalmann & Company Inc. - Analyst

Tim Rezvan Sterne, Agee & Leach, Inc. - Analyst

Brian Singer Goldman Sachs - Analyst

Leo Mariani RBC Capital Markets - Analyst

Matt Portillo Tudor, Pickering, Holt & Co. Securities - Analyst

Brian Foote Clarkson Capital Markets - Analyst

Mark Hanson Morningstar - Analyst

P R E S E N T A T I O N

Operator

Good day, everyone, and welcome to today's program.

(Operator Instructions)

Please note today's call is being recorded.

It is now my pleasure to turn the program over to Mike Watford, Chairman, President and CEO. Please go ahead.

Mike Watford - Ultra Petroleum Corp - Chairman, President and CEO

Thank you, Operator. Good morning and thank all of you for joining us.

With me today is Mark Smith, Senior VP and Chief Financial Officer; Bill Picquet, Senior VP Operations; Brad Johnson, Vice President ReservoirEngineering and Development; Doug Selvius, Vice President exploration; and Jason Gaines, Manager of Business Development.

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NOVEMBER 01, 2013 / 3:00PM, UPL - Q3 2013 Ultra Petroleum Corp Earnings Conference Call



I'd like to point out that many of the comments during this conference call are forward-looking statements that involve risks and uncertaintiesaffecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors and forward-looking statementssection of our annual and quarterly filings with the SEC. Although we believe these expectations expressed are based on reasonable assumptions,they are not guarantees of future performance, and actual results or developments may differ materially.

Also this call may contain certain non-GAAP financial measures. Reconciliation and calculation schedules can be found on our website. Also, weintend to file our 10-Q with the SEC later today. It will be available on our homepage or you can access it using SEC's EDGAR system.

Let me start my sharing what we hope to achieve this morning. We want to spend a few minutes discussing our third quarter results and what theremainder of the year looks like. Then we want to spend more time discussing our recently announced Uinta Basin oil acquisition. To assist in theUinta discussion, we have an expanded slide deck available for you to follow along with, one where we have attempted to provide more detailsas to why we are so confident of our projections.

So let's talk about the third quarter. Our third-quarter production was 57.5 Bcfe. With three quarters of the year behind us, we produced 175.3 Bcfe,which is in line with where we should be relative to our production targets for 2013. We reported adjusted net income of $0.37 per diluted share,or $57.9 million. We generated operating cash flow of $0.76 per diluted share, or $117.9 million for the quarter. Our net income breakeven was$2.78 per Mcfe during the third quarter, while our cash flow breakeven was a low $1.63 per Mcfe. Our 54% cash flow margin and 26% net incomemargin for the third quarter were comparable to second-quarter results.

Looking at our third-quarter expenses, our all-in costs were $2.80 per Mcfe, which includes a very low cash cost of $1.77 per Mcfe. Our realizedprice for the third quarter for our gas sales was $3.41 per Mcf, including the effects of our commodity hedges.

During the third quarter in our Pennsylvania area activity, we experienced periods of widening basis differentials due to planned seasonalinfrastructure maintenance coupled with a capacity constrained market. During the third quarter, our average Pennsylvania basis differential was$0.54 per Mcf and we expect this to be around $0.62 for the fourth quarter, in fact are using $0.60 for calendar 2014. Considering the majority ofour production is priced outside of the Northeast, we are anticipating a Company wide realized price for the fourth quarter 2013 of NYMEX less5% to 7% as outlined in the guidance section of our news release.

Glancing at our Rockies operations, in Wyoming, our production in the third quarter averaged 450 million cubic feet per day, which is 72% of theCompany total, and was boosted by strong well results in our current development area. Year to date, the average IP rate for Ultra operated wellsbrought online in this area is 9 million cubic feet per day.

We continue to make excellent strides in the areas of efficiencies and cost. Our spud to total depth average dropped below 10 days for third quarteraverage of 9.3 days per well. As we continue our completion optimization efforts, we are seeing meaningful cost reductions without sacrificingwell productivity or reserve estimates.

We shared with you earlier in the year that we lowered our year-end 2012 Pinedale well costs of $4.7 million by $300,000 per well to an averagecost of $4.4 million in the second quarter. Due to the collective efforts of our engineering and geoscience teams, our target well cost is nowmeaningfully below $4.4 million, at $3.8 million. This 19% year-over-year reduction in costs serves to enhance our returns as illustrated in the tablein the press release. For a 5 Bcfe well at $4 natural gas price, the return grows to 59% versus 37% higher well cost.

At Pennsylvania, our third-quarter production averaged 175 million cubic feet per day, or 28% of the Corporate total. A noteworthy step out wellin Centre County to the southwest of our development area came online with very positive results. Due to the cost savings we're enjoying inWyoming and less spending in Pennsylvania, we are reducing our capital expenditure budget for 2013 by 7%, down to $385 million while leavingproduction guidance intact.

Now to the Uinta acquisition. Like many of you, the mentioning of a Uinta Basin opportunity didn't cause us to get overly excited early on, as wehave reviewed some opportunities in the basin previously with mixed results. When reviewing the details of this property, we changed our mindsin a hurry. And I think we have done a much better job with the data in today's slide deck of sharing the source of that enthusiasm.

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Our discussion is intended to address well performance, more importantly recent well performance, reserve estimates, geology and why thisacreage is unique, well cost, economics, with a page detailing our assumptions, marketing information and a financing update. And as a reminder,it's debt financing.

So let's turn to slide 2 in our deck and get started. Slide 2 is entitled Uinta Basin acquisition overview. And it's same slide that we used 1.5 weeksago, but I want to quickly hit a few highlights. Again, it's Uinta Basin oil-producing assets in Northeastern Utah, currently net production about4000 barrels a day. And you can see on page 9, a new slide we've added that shows the recent rapid increase in production and how we believewe can continue with that.

Net risk reserves of 90 million barrels. We've also revised that slide as slide 18 in the deck, and you'll see that we have added a 10-acre down spacingwater flood upside to our resource summary as a nearby adjacent operator has recently gained approval for such a project. The 90 million barrelsof resource opportunity previously identified almost doubles to 173 million barrels. And with that we think we'll only be recovering about 15% ofthe oil in place.

So quick math suggests that we believe there is over 1 billion barrels of original oil in place on this property. It is not a horizontal acreage play. Itis Pinedale all over again, only shallower in oil. It's increased density vertical drilling with stacked pay. We have what I call prove-like reserves of 37million barrels, and there's 575 future well locations prior to down spacing, and the first 300 of those 575 wells, which will be the first ones drilledover the first seven or eight years of activity, should average over 250,000 barrels of reserves each.

Purchase price is $650 million. Simple undiscounted return on investment is 4.3 times, which we think is exceptional. Again financed only throughdebt. Closing mid-December. 100% operated, 100% working interest, 82% net revenue interest, almost all of it held by production, exceptionalwell economics, derisked acreage, asset is self-funding immediately. We can quickly ramp production, and the asset complements our Pinedaleexperience and expertise.

Next page, page 3 is a repeat from last time very quickly; complementary strategic asset, amazing well economics. It diversifies our cash flow stream,and that's what this is, this is not really a volume grower for the Company, this is a cash flow grower and it leverages our taxable expertise. On page4 is the asset map. Want to make the point that the new Utah opportunity is probably only a four hour drive away from our Pinedale activity, soit's close by.

And I want to ask Doug to talk about our new slide, slide 5.

Doug Selvius - Ultra Petroleum Corp - VP of Exploration

Okay, thanks, Mike.

I'd like to start on slide 5 with a slide that compares Three Rivers to Pinedale. The two areas are similar in many ways, but there are also somesignificant differences and I'll point those out too. First, starting with the two well diagram on the left, the most important similarity is that bothareas involve a thick stack sequence of reservoir sands. The two logs are scaled the same so it's apparent that Pinedale is thicker than the ThreeRivers area, but the depositional sequences are identical.

Looking at the table, one key difference we see as a positive is the fact that drilling depths in Three Rivers are half of what they are in Pinedale. Wedrilled to about 13,300 feet in Pinedale compared to only 7,000 feet in Three Rivers. Moving down the table, it's evident that the rocks in both areasare low porosity, low permeability, tight sands. In other words the rock quality in Three Rivers is just like the rock quality we work with every dayin Pinedale. We know what to do.

Instead of the typical 16 frac stages we use in Pinedale, we only need seven in Three Rivers. And instead of 10 days to drill and case a well, ThreeRivers requires only 7. As a result, Three Rivers wells cost $1.5 million to drill and complete compared to our recent $3.8 million cost in Pinedale.This is another difference and another strong positive in our opinion.

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The IPs and EURs for both areas are listed with one of course being gas and the other oil. But the bottom line here is what really grabbed ourattention. Our returns in Pinedale right now are attractive ranging from 36% to 91%. But the returns at Three Rivers are even better ranging from130% to as high as 600%. The message here is that this is a very strong project. It's similar to Pinedale from a geologic and operational perspective,and it's extremely attractive from an economic perspective.

Moving to slide 6, this is a rerun from the last time. The story here is that Three Rivers is centrally located between a number of very large prolificlegacy fields. It's also clear from the slide that there are two plays here. The green areas shown represent oil production from the Lower Green Riversands and the Wasatch section just below.

The red area represents gas production from the Wasatch and also the Mesa Verde section that lies below it. In other words, there are three intervalswith stacked sequences of productive sands here. Some are oil prone and others are gas prone. We're acquiring Three Rivers for its Lower GreenRiver oil value but we're optimistic about the potential for gas in some of these deeper sands. We think we're geologically positioned to have ashot at both.

Slide 7 is also something we've talked about before, so I just want to emphasize a couple of points without going through it in detail. Three Riversis unique geologically and economically when compared to adjacent fields. No other field in the area has a combination of drill depths, well costand EURs as attractive as the combination we see in Three Rivers. The table addresses all of those points and Three Rivers stands out.

Slide 8 demonstrates the geology that makes Three Rivers unique. Shown as a three well cross-section that starts on the right with Three Riversand then extends west into Leland Branch and Monument Butte fields. It's location is shown on the inset map on the upper right. Each log represents3000 feet of total thickness with reservoir sands colored yellow and the interspersed shales colored brown. And then highlighted in light and darkgreen is the overall Lower Green River section, that's the most distinguishing part.

What makes Three Rivers unique is the thickness and quality of sand in the Douglas Creek and Travis numbers. We have 373 feet of a blocky standin that interval. In Leland Bench just to the west, that same interval only has 120 feet of sand. And then further west in Monument Butte, the overallsection does get a little bit thicker. It has over 300 feet of sand, but the sands there are thinner and are scattered throughout the section as opposedto being concentrated in thick blocky members like we see at Three Rivers.

Now there's value in the thin sands, and in fact, we see a lot of value in the thin sands we have in the TGR 3 and Garden Gulch intervals. But thickersands are typically higher quality and carry the day when it comes to reservoir performance. That's why we like our Three Rivers area.

Now Jason, he has a couple slides addressing production and cost performance in the Three Rivers area, and then we'll follow with a few moredetailed slides focusing on Three Rivers geology and specific well results. Jason?

Jason Gaines - Ultra Petroleum Corp - Manager Business Development

As Doug pointed out, the Three Rivers area is unique and slide 9 also helps show this. The production graph tells a story of the early field developmentof the Three Rivers area. As you can see, production has ramped up over a very short period of time with first production only 18 months ago. Firstproduction in the field began in April of 2012 with only three wells online through September. In May of 2013 and only 13 months from firstproduction, the production had ramped up to 1,000 barrels of oil per day with 14 wells online.

In the past five months alone, from May of 2013 through October, production growth has been very impressive. From 1,000 barrels of oil per dayto over 4,700 barrels of oil per day with only 25 additional wells brought online. The production growth of 3,700 barrels of oil per day indicatesthat the new wells brought online during this period are averaging 150 barrels of oil per day per well. And that the 39 producers are averaging 120barrels of a per day per well.

As you see in most field in the early stages of development, there's been an incredible learning curve and this is clearly seen on the productionparticularly in May of 2013. This graph helps illustrate the ability to grow production rapidly in the Three Rivers area, and I will share additional wellproduction details to demonstrate the impacts of this learning curve in some following slides.

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Now turning to slide 10. You can clearly see the learning curve associated with well cost in the Three Rivers area with cost shown for the first 29wells. The first well cost was over $4 million. The well cost fell very quickly, and the third well drilled cost -- with the third well drilled costing lessthan $2.5 million. The average well cost for the last 10 wells was less than $1.5 million. And as you can see, the well cost are now very consistent.This is another example of a steep learning curve that has brought tremendous value to this asset.

Doug?


Slide 11 is intended to demonstrate that Three Rivers has been significantly derisked by over 40 wells. The six well cross-section shows our payinterval at locations broadly distributed across our leasehold position. It's highlighted on the inset map along with blue and red dots showing thewells that have been drilled to date. There are a couple of points to make here.

First it's important to notice on the map that wells have been not concentrated in one particular area of the leasehold. They've been drilled a nicelydistributed across the entire position. That allows predictability and reduces uncertainty and that was very important to us.

Second, the cross-section shows a consistent and predictable pattern of sand deposition across the leasehold area particularly in the importantDouglas Creek and Travis numbers. Some differences do exist, most notably down in the Castle Peak member. And those differences affect wellperformance as you can tell from the EURs noted at the base of each log.

What makes us very comfortable here though is that enough wells have been drilled to understand the different areas, and that has enabled us tobuild very accurate valuation models. What also makes us comfortable is that wells in all of the areas are highly economic.

For more on that, we'll go back to Jason.


I will share some of the impressive well results that have been seen in the Three Rivers area. The top tables on slide 12 tied to the cross-section thatDoug just shared with you, which is displayed again in the lower left-hand corner of this slide. The six wells on the cross-section have an EUR rangeof 151,000 to 558,000 barrels of oil and average 336,000 barrels oil.

Let's camp out on a couple of individual wells for a moment. Starting with well A, the well has been online for 396 days and has an EUR of 260,000barrels of oil. The well averaged 100 barrels of oil per day for the first 30 days of production. As you look across the table, you can see that theaverage continues to increase all the way out to 180 days of production, with the average production of 116 barrels of oil per day for the first sixmonths. This indicates that the well continued to produce at higher rates with the average rate from day 150 to day 180 of 152 barrels of oil perday.

Let's jump to well C on the table. It has been online for 310 days and has already cumed over 60,000 barrels of oil and continues to produce over200 barrels of oil per day to date, after nearly a year of production. And the lower right-hand side of the slide you can see the cumulative productionperformance of these six wells compared to three type curves. The individual well results continue to meet or exceed our expectations. We willcover this in more detail in the next couple of slides.

Slide 13 further illustrates the impressive well performance and learning curve in the Three Rivers area. The graph shows cumulative oil productionversus days online and three type curves are provided for reference. In dark blue, you can see the average well performance of the first 12 LowerGreen River wells. The orange curve is the average well performance for the recent 19 wells, displaying a significant improvement in well performancewith over 50% improvement in cumulative production after 100 days online.

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One other point to make on this slide before moving on, is that the light blue line displayed on the graph is a simple pay out line using $80 net oilpricing. If you project the orange curve along be type curve you can see that these wells payout in less than 150 days, thus explaining the incrediblerates of return that these wells generate.

Moving to slide 14, we have provided data for the same set of wells on the previous slide on a production rate versus time graph over the first eightmonths of production. There are a couple of key points to make on this slide. First you can see the flat initial production profiles realized in theThree Rivers area, and secondly, the performance improvement of the recent 19 wells compared to the first 12 wells is striking.

Let me share a few stats. The first 12 Lower Green River wells shown in dark blue averaged 106 barrels of oil per day over the first eight months onproduction and averaged almost 100 barrels of oil per day during month eight. During the first month of production, the recent 19 wells shownin orange have 50% higher average daily production rates compared to the first 12 Lower Green River wells. These wells averaged 166 barrels ofoil per day over the last 30 days which was 52% higher than the first 12 Lower Green River wells over that same period. Further, these wells haveaveraged 168 barrels of a per day over the first 144 days of production.

I want to reiterate that two key points made earlier on this slide. These wells a very flat initial production profiles, and a significant learning curvehas resulted in much better average well performance.

Doug?


Okay, we have spent some time distinguishing Three Rivers from other surrounding areas. Slide 15 is actually an analog to Three Rivers. It showsa three well cross-section tying two Three Rivers wells on the right to a well three miles north. Projected into this section with a dashed red line isan additional important well that we know a lot about but don't yet have a log for. It's very close to our control, so we have a good feel for whatthe rocks look like.

The geology correlates very well. The Lower Green River in this area is very comparable to the section we see in Three Rivers, maybe just a little bitthinner. But we believer these wells are geologically analogous to Three Rivers and provide a very good production analog and a geologic analogfor what we're going to do there. One of the two wells on the left side of the section has been in line for 200 days and is expected to cum 257,000barrels. The other has been online for over four years and is expected to cum over 0.5 million barrels.

For more details on what this area is telling us, I'll turn it to Brad.

Brad Johnson - Ultra Petroleum Corp - VP of Reservoir Engineering and Development

Thanks, Doug.

Slide 16 shows the production performance from the Rogers 16-43 well located in the East Bluebell area. This well produced over 100 barrels of oilper day for 32 straight months and has produced 171,000 barrels to date in just 4.5 years. This well is located less than three miles north of theThree Rivers area and is a key analog due to its proximity and geologic correlation described by Doug on the previous slide. The flat productionprofile demonstrated by this well occurs in several wells in the East Bluebell area. And we observed the same flat production performance in theThree Rivers area. In fact many of the wells in the Three Rivers area produce at flat rates well above 100 barrels of oil per day.

Turning to slide 17, we've included four different reserve forecast for the Rogers 16-43 well. Note that we've included an exponential forecast as alow side case. However, hyperbolic declines are observed in Lower Green River oil wells and is certainly validated by this well's performance overthe last two years. We have assigned a B factor of 1.6 to this well and we currently estimate the UR to be 530,000 barrels. While there is someuncertainty in estimating the final shape of the decline curve, it is important to point out that these wells and those also in the Three Rivers assetdemonstrate a flat production profile that generates exceptional returns and allows for robust production growth with just a one rig program.

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When developing a model to value this asset, it is important that the duration of the flat production be incorporated into a type curve. It is alsovery important to recognize the magnitude of the oil production rates that a single well produces during this flat production period.

The Rogers 16-43 well is not an anomaly. Several wells adjacent to this example demonstrates similar performance and in Three Rivers Jason alreadyshared results on slide 12 that mimic this performance. With a representative sampling across our field where the average actual -- actually exceedsthe Rogers well during the first 180 days. We believe we are conservative with our type curves and risking of future development wells whenassessing the Three Rivers asset. In our model, initial rates were constrained to no more than 200 barrels of oil per day and the flat productionperiod was limited to a range of four months or less on those future wells.

Slide 18 tabulates the resources and values we have assigned to Three Rivers. The proved developed reserves represent 9.9 million barrels of netremaining reserves and a PV-10 value of $265 million, just over 40% of our purchase price. As we roll our model forward by just one year, we expectthese reserves to nearly double in value, reaching a value of $506 million by year end 2014, or 78% of our purchase price represented by PDPreserves.

The second row of this table includes the bookable offset locations on just 40-acre spacing. The net remaining reserves of 27 million barrels havea PV-10 value of $470 million. These 130 locations represent the inventory we plan to drill over the next few years and have an average EUR perwell of 258,000 barrels.

The next two rows in the table represent additional 40-acre and 20-acre probable and possible locations. At this time, our 3P reserve numbers aremade up of a down spacing, a field that is already delineated similar to Pinedale, these locations have essentially zero geologic risk. This incremental53 million barrels results and our 3P reserves totaling up to 90 million barrels. With our current estimates of original oil in place for the Green Riverformations, this represents a recovery factor of just 8%. Based upon a modest one rig development pace and even with an additional 15% to 25%risking applied to future locations, the 3P reserves have a PV-10 value that exceeds $1.1 billion.

We have previously recognized that there is also additional upside equaling 83 million barrels in the Green River formation. Today we have decidedto include this row as an update, the previous version to this slide. These contingent reserves would be realized with further down spacing and/orwater flooding similar to what has occurred in the nearby Monument Butte field. The total net resource of 174 million barrels, representing a veryreasonable 15% recovery of oil in place, one could quickly understand why we are really excited about the value of this asset.

Slide 19 includes single well economics. While the Upper Green River generates healthy returns with just 100,000 barrels assigned to those wells,it is a much higher reserve potential and well deliverability of the Lower Green River that delivers outstanding returns. And so we plan to prioritizeour development to the Lower Green River over the next few years. At the top of the slide, you can see the single well economics for a range ofEURs and oil price. We've also included an analysis of allocating the purchase price back to just the Lower Green River wells and we have calledthis acquisition burden returns.

Please note that the returns to the Upper Green River from the 100,000-barrel case doesn't change. This was intentional as we chose to allocatethe purchase price only to the Lower Green River locations. We do so in a manner that is proportionate to the present value of each element of theLower Green River locations. We find this analysis instructive when comparing investment opportunities within and outside our current portfolio.And based on the returns tabulated in this analysis, it becomes clear why we are excited to add Three Rivers.

Additional economic metrics are included at the bottom of the slide. F&D costs are very compelling across the asset. And with payouts of less thana year for the Lower Green River wells this asset will generate significant returns and cash flow for Ultra.


Page 20 we have the production growth slide. Showing a four-year comp and annual growth rate of about 50%, which more than likely we willexceed. Page 21 is my favorite slide, which is cash flow contrasted with CapEx going forward. The asset is immediately -- generates free cash. Thisis a one rig scenario where over the first five years of its productive life at strip pricing and it pays for itself. And then we have a few decades of freecash going forward.

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There's been some questions out there asked if we'd go two rigs say starting 2015 that we'd have to raise equity. Well I think that dark blue bar isseveral multiples above the light blue bar, so there's plenty of room for this asset to fund two if not three rigs in the area.

And I'd like to go into the last page here of the handout, there's a listing of the key assumptions. We're trying to be very transparent in how we'veworked these into our economics and I think you'll see that we're very conservative in how we've developed our economics.

Now I'd like to ask Mark to speak to marketing issues.

Mark Smith - Ultra Petroleum Corp - SVP and CFO

Thanks, Mike.

From a marketing perspective, we believe it's an optimal time to acquire assets in the Uinta basin. Over the last several years refinery expansions,new rail facilities have worked to take away many of the capacity issues in the area for black wax crude. In terms of refining capacity, it's beenexpanded recently such that current capacity is about 48,500 barrels a day. And continued expansions are underway. The majority of which willbe in place through 2014 for another 25,000 barrels a day.

In terms of rail capacity, we see analogous history here to the Bakken, where we're moving from manifest cargoes to unit trains. We see meaningfulcapacity additions with new facility supporting multiple unit trains here. As in the Bakken, we expect these unit train options will increase volumesand decrease rates as well as provide diversification to markets. More specifically, we see product moving to refineries on the East Coast, the WestCoast as well as Gulf Coast and Mid-Continent regions.

And we're also seeing many facilities around the country adding capability to handle heated cargoes. And we see good demand as the crudeprovides good yields for refineries with fluid fracking capabilities. And so we're confident there will be a growing market for these barrels overtime.

In terms of contracted volumes for the acquisition, they're split between local refineries and rail. Over half, or roughly 3,000 barrels a day, are underterm contracts to Salt Lake City refineries largely based on a percentage of NYMEX netback price. The remaining contract capacity currently about2,000 barrels a day is under a term rail contract. This volume started moving by manifest rail in September and it transitions to unit train capabilitybeginning in the spring of 2014.

The contract can be expanded to move additional volumes up to 10,000 barrels a day and pricing under the contracts based on NYMEX less a fixedprice. So on an all-in basis, crude associated with the acquisition is currently selling for netback price of approximately 80% of NYMEX.

And I'd like to move on and take a look at things from the financial perspective, more specifically how we're currently financing ourselves and howwe see ourselves financing -- or how we see ourselves being financed in light of the acquisition. I want to go on and address key financial aspectsof the acquisition and then how that translates into our overall corporate performance.

Just a reminder, we're currently financing ourselves through a combination of bank debt as well as longer dated senior notes. These are both ona pari passu basis at the operating Company level. The operating covenants here, or the operative covenants rather, here are backward lookingdebt to EBITDA covenant and a forward-looking PV-9 covenant.

Given the acquisition, we'll finance ourselves with borrowings under our bank facility, as well as new senior debt at the parent level. The covenantsat the operating subsidiary will stay the same. The covenant at the parent level though will be different. It'll be an interest coverage covenant andit will become the operative covenant for the Company going forward.

And in terms of key financial aspects of the asset, I just want to reinforce some of the points made by Brad, Doug and Jason. We consider that theproperty is well defined. It's largely derisked. The wells are relatively low cost, can be drilled quickly, have strong returns and pay out in a matter

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of months. As a result, the project's self-funding. One rig in the field with a capital investment program of $68 million a year results in a risk productionforecast doubling from the 4,000 barrels a day currently to 8,000 barrels a day just one year out.

Now Brad spoke to the PV-10 of the PDP component over time. From a financial perspective, we've also looked at the asset in terms of its borrowingcapacity over time. So when one looks at the PDP category alone, with bank pricing parameters $60 net flat for all time, with one rig program ona risk basis, that PV-9 more than doubles to $460 million at the end of the first year alone. Taking these attributions and translating them at theCorporate level, the acquisition provides good diversification both geographically and geologically. It further supports our disciplined capitalallocation processes. And further we've analyzed the Company's overall financial performance under numerous scenarios.

The acquisition is not simply about production growth; rather it's about stronger growth in revenue and even higher levels of cash flow growth.Specifically, we compared one rig running in the Uinta against a current base case absent the acquisition. A number of points in this analysis stoodout. Production growth increased a modest 5 percentage points over base levels without the acquisition. But revenue growth was up 18 percentagepoints and EBITDA growth is up a meaningful 28 percentage points over base levels. So the acquisition translation to modest levels of top linegrowth but even higher levels of cash flow growth going forward.

Further, given that the acquisition is debt financed, not with equity or equity link securities, the transaction is immediately accretive of course. Butlooking at it further in more detail on a debt adjusted basis, the transaction is accretive to both earnings and cash flow after roughly the first fourmonths of the transaction.

With that I'll turn it over to Mike.


Thanks, Mark.

A few closing comments about 2014, we mentioned last quarter that we have contracted for two additional new build drilling rigs for Wyoming.First arrives this month November of 2013 and the second in February of next year. So we have the opportunity to operate four rigs in Pinedale for2014, which is our current plan. To the extent we see deterioration in natural gas prices, we can back off that, but that's where we are now. We willspend less money in Pennsylvania. And we will operate one rig in Utah.

So really capital expenditure thoughts for 2014 are somewhere between $520 million to $560 million for a 7% to 8% production growth and EBITDAgrowth of over 30%, or $200 million. So $800 million of EBITDA against $550 million more or less of capital in 2014. We'll finalize this and providemore information at our February 2014 call.

And with that, Operator, I'd like to open it up for questions.

Q U E S T I O N S A N D A N S W E R S

Operator

(Operator Instructions)

Marshall Carver, Heikkinen Energy Advisors.

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Marshall Carver - Heikkinen Energy Advisors - Analyst

Yes, good morning and thank you for the additional details on the acquisition. I did have a couple of questions. One on slide 22 on the single wellcurves. I'm a little confused by the -- you've got two bullet points for Lower Green River type curve 1, it says 130 barrels of oil a day flat one month,200 barrels a day flat three months. So does that mean it's going to be about 130 barrels a day for the first month and then 200 averaging over thefirst three months implying that the production will go up, or could you give a little color behind that?


Sure, this is Jason Gaines. Really what we see during the first month of production on these wells after fracking them is the cleanup period. So whatwe've modeled is 130 barrels of oil per day would be that cleanup period that you see single month. And then the following three months wouldbe -- would essentially be a flat production profile at 200 barrels of oil per day prior to the risking.


Okay that's helpful, thank you. And then jumping back to slide 12, where you give the areas A, B, C, D, E and F. Do have the approximate numberof locations in each of those areas and would those number locations be similar to the -- would you expect them to be similar to the URs you'vedetailed?


Marshall this is Brad. I'll speak to that. I think if you turn to page 18, what we've tried to demonstrate there is with the next 130 wells in the programhave an average of (inaudible). And so if you looked at that page, you can find an understanding of the average performance over the next 130wells. We weren't planning to provide detailed counts by area at this time. But you can see the range on table 12. Brackets the average that youback calculate on slide 18 when you take the reserves, be sure to divide by 0.82 and then divide by well count to get an average EUR in each ofthose buckets.


Okay, thank you. And one final question, the improvement in well cost quarter over quarter, what was the major driver on that? And is $3.8 milliona realistic number heading forward or should I possible go up a little bit as we move forward?

Bill Picquet - Ultra Petroleum Corp - Senior VP of Operations

Marshall, this is Bill. Most of that was incompletion cost improvement. We've been really focusing on optimizing frac stages and individual stageselection. And so most of that reduction was based upon add and what we're saying is great cost reduction with essentially no change as far aswell performance is concerned. So that's sustainable. We're actually a little bit below that number right now.


Okay, great. Thank you very much.

Operator

Ron Mills, Johnson Rice.

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Ron Mills - Johnson Rice & Company - Analyst

A little bit of a follow -up on Marshall's last question. If I look at slide 12 and look at A, B, C, D, E and F, what's driving the big differences as you movefrom A to F? You obviously -- the western side looks to be a little bit better and given that you're concentrating in the next 130 wells, is it safe toassume that they're really more in the A through D area? And if so, if you look at those EURs, the 258 versus the 260 to 500,000 barrels it looks likeit includes some sort of risk factor.


There's definitely some geologic variability in the field that was identified, and I know Doug pointed it out on some of the slides. I think the otherthing to recognize is the vintaging of these wells. Some of the early wells drilled in the field, some of which on the east were some of the earlierwells. And so there's a learning performance, a learning curve factor that's mixed in here. And we're anxious to dive into that in a lot more detail isa continued to optimize that. But there's -- that variability is there and -- but on an average basis the results are just compelling to us.


Okay. And then from a -- the economic standpoint, if I look at the most recent 19 wells on slide 13 versus the first 12 wells, what were some of thedifferences that has caused that performance to be tracking more the 380,000-barrel curve versus the 258 and whether they were completiondesign or well design, is that also -- can that also be applied across most of the acreage?


Ron, this is Jason again. I think really what you're seeing there is a combination of the learning curves being applied. One would be specifically thecompletion techniques and hydrating that. A second one would be the operational optimization as far as pumping units, where pumps are setand those type of operational improvements. And then a third would be geographically, sorting the high grade to the portfolio, much like we'llcontinue to do.


Great and then one last one, Mike, probably for you. You talk about the fourth quarter for this year basically being free cash flow for the Company.You fast forward one year on the assumptions you just provided. You remain free cash flow positive. Is this -- is it -- what do think the sources orthe uses of the free cash flow is? Is it continued deleveraging over time or is it result dependent in terms of what you talked about potentially thisasset that you're acquiring offering the ability to fund not just one but two to three rigs?


I think that's it, Ron. We have the opportunity to accelerate here once we have a better understanding and know exactly where we want to go andwhat we want to do. We have a developed plan for 2014 for this asset that has down spacing tests, has some water flood tests. So we want to getafter it pretty early understanding how we're going to put this together in totality. Because if we're going to go to a water flood effort, we'd just assoon go there sooner rather than later in terms of planning it and reducing CapEx.

I don't know that we have -- we are concerned with the level of debt we're going to take on. December 5, 2013 we're very comfortable by the timewe get to December 14 it's reasonable and by the time we've got three-year projections which have us at 1.75 times trailing EBITDA by 2016. Sowe're kind of under levered at that point in time with our current plan. So we're -- I think we're looking for another one of these types of opportunities.

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I'll let someone else jump in and get back in line. Thank you, guys.

Operator

Bob Christiansen, Canaccord Genuity.

Bob Christensen - Canaccord Genuity - Analyst

Yes Mike, did I hear you right, it sounds like new rigs are arriving and the old ones are going to keep working in the Pinedale, so a four rig program?


Yes, sir, you heard that.


And -- okay. And I guess how many wells are in the Pinedale that -- right now that have been drilled but not cased and completed brought online?What is your inventory level relative to a year ago wells drilled cased but not completed?


Next to zero, but Brad will get the actual numbers.


Currently, or as of 30 of September, we had four wells waiting on completion, and zero wells waiting for hookup.


And a year ago what would that level have been?


A year ago was 21 wells waiting on completion. So we've gone from 21 to 4 on the Ultra-operated wells.


Good, thank you very much.

Operator

Mike Scialla, Stifel.

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Mike Scialla - Stifel Nicolaus - Analyst

On those new built rigs, are those -- so I would assume those were under contract right now. If gas prices were to weaken, you said you've gotsome flexibility with those, would you just pay a fee or could you actually move those into Uinta? Would they be applicable to that asset as well?


This is Bill, Mike. The new rigs are under contract and as Mike said, one arrives this month and one arrives early in 2014. We also have flexibility inthe contracts on the existing two rigs that would allow us to make decisions dependent upon gas prices. So that's solely dependent upon thosetwo rig contracts. And those rigs would not be used in the Uinta, they're much bigger than what's required in the Uinta.


Got it, okay. And then the $3.8 million well cost, do the new build rigs have any impact there? Do think -- where do those costs go with the newbuilds?


Last time we brought new builds into the field the cost didn't change at all, in fact it continued to go down. As usual, you'll have a little bit of abreakout period with a new rig. But same drilling Company, same type of rigs, same people operating the rigs, so we're very confident thatperformance will be good.


Okay and switching over to Pennsylvania, do you still have any production shut in at this point?


This is November 1, right? So I don't think we have any as of this point. If you had asked me that question yesterday, we'd have a different answer.


Okay.


Okay.


And then just one other for that area, you had mention on your last call seeing some activity from some of your peers marching toward your acreagein the Utica. Any update there? And any chance that you would consider drilling a Utica well next year?

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This is Doug. We have no plans to drill a Utica will this year. The activity continues in the area. You can read National Field guys or Seneca's latestrelease, west of us they've announced some good results. So the play continues, it's encouraging, it's moving our way and we're going to continueto monitor it at this time.


Got it, thank you.

Operator

Joseph Allman, JPMorgan Securities.

Joseph Allman - JPMorgan Chase & Co. - Analyst

On slide 21 you showed a CapEx going out to 2025, and just want to check what the assumptions are for that. Does that match the total CapEx orthe total activity that you lay out in slide 18 on the table excluding the water floods?


Yes, that matches the 575 well locations that you essentially saw in that resource summary that Brad covered.


Okay great, that's very helpful. And then you made the announcement for this acquisition on October 21 and the stock has under performed, Mikeare the biggest reasons you think for the under performance?


Well I think many folks out there didn't treat our announced acquisition with neutrality. I think they treated it with a negative bias. And that causedus to put forth more information today to show why that's in error. So, that's my view.


Got you. That was great presentation today by the way, so thank you.

Operator

Noel Parks, Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann & Company Inc. - Analyst

A general question, so often with an acquisition that comes out of the blue in an area that not a lot of people are familiar with, I'm wondering aboutthat old question about why hadn't any of the other operators other than the one that you're acquiring from discovered this opportunity right inthe thick of all this other legacy Uinta Basin activity?

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Well you're asking us to guess why other folks bid on the property, didn't bid on it and what their assumptions were. So I don't have any data tohelp you with there.


Well more why isn't this a field that was explored 10 years ago or something like that? Is it technology, is it that there's some rock characteristicthat threw people off and made them think this is too tight, it can't work?


This is Doug. I can add a little bit of insight here. We showed several slides demonstrating how this area is unique geologically and stratigraphicallyin that Lower Green River section. What I will point out is that this area was initially evaluated and drilled to test the deeper section, the Wasatchsection below the Lower Green River. It wasn't until they drilled wells through the Lower Green River looking for something deeper that theyrealized how unique, what they had in this area was. It was just a nice pile of sand in the Lower Green River. I think it surprised them. And I don'tthink, we're speculating, I don't think the other offset operators really expected that either.


Thanks, that's what I was wondering. And the prior owners of the property, do they have a land operation going actively at the time you begantalking and are those land then that you would have access to yourselves?


Well they have an active land department that's working the property and looking to grow it I guess. But we have our own land staff that's fullycapable of picking up this ball after the transition period and running with it. And we have some ideas on how to grow it, but that's down at thefuture right now.


Okay, great. And can you give us a little bit of a sense looking ahead, how as you do more drilling across the area, what PUD bookings might looklike a year or two out? I know you guys are on the conservative end of how you recognize PUDs. But as far as maybe number of locations you thinkor even locations per well drilled you hopeful find their way into PUDs over the next couple of years?


Sure, this is Brad, if you turn to slide 18 where we describe the resources. And I think row 2 describes those locations that are -- that could bebookable from an offset standpoint. I also mentioned in my remarks about the PDP growth would look like as we roll forward. So as we add 45wells a year, and we've already got 43 wells, you're looking at PDP doubling in one year from a reserve and value standpoint. From a PUD standpoint,we'll be looking at our PUD pool at the year end and we'll provide more details on that at year end.

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Volumetric PUD booking here is -- doesn't really move the needle for the Corporation given all the PUDs that we removed from our bookings lastyear with 2012 cyclically low gas prices. So we have several Ts of the gas to bring back there with higher gas prices. So this is -- we're doing thistransaction because of the ability to make money, the profitability of it, the cash flow growth. It's not a really volumetrically driven and it's certainlynot reserve driven.


Great and one last one, maybe this is for Mark. Would this transaction just thinking about the cash outlay and what that might do to book valuefor the Company, on a blended basis, does this transaction make it any more possible or any less undesirable from a tax basis to look at spinningout legacy mature areas at Pinedale, royalty trust type structure or MLP type structure?


Noel, Mark here. I want to assure you we're continually looking at our overall portfolio of properties for ways in which we can optimize that portfolio.The acquisition of this asset doesn't necessarily do anything forth from a tax perspective certainly one way or another. We've got a meaningful taxposition that has been set in place as a result of capital spending in prior years well ahead of this acquisition. So our tax position is independent ofthis acquisition from my perspective.


That's all for me, thanks.

Operator

Tim Rezvan, Sterne, Agee.

Tim Rezvan - Sterne, Agee & Leach, Inc. - Analyst

I wanted to clarify your question on that you went to rig ramp, I know folks are asking you to add rigs, you haven't even closed on the deal yet, but--


That's how we feel.


Yes, well obviously you're excited. So you've talked about one rig next year. Is the delay more related to getting acclimated with the asset than itis on any kind of leverage or cash flow issues?

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Well as Mike mentioned, we plan to do some drilling to evaluate some pilot projects on spacing and water floods, and that's going to be key tohow we decide to develop the fields. So we want to get that information early on. We think it's appropriate to ramp up from a corporate perspective,we'll consider then.


Okay so you will be doing pilot test with that one rig?


Right.


Okay, I appreciate that clarity. And then quickly I had a question on what you presented in slide 12 with the well results across your acreage. First,can you address what those red dots are on the lower left portion of the slide?


It's the first 12. The red dots represent the first 12 wells drilled. Maybe that's not real clear in the color. The green dots represent the second 19.


Okay, and to clarify your earlier comments, obviously there is some geographic variability but you'd expect that as you apply the learnings you'vehad in place that some of the variability may compress, is that fair to say in regards to wells being (inaudible) verse everything else?


I think that's a fair conclusion. We would expect our understanding of that variability to improve and then we're prioritizing the high grading wewill see -- we would expect our performance to tighten up from like a P-10, P-9 ratio, if you will.


Okay, that's all I had. Thank you for the color.

Operator

Brian Singer, Goldman Sachs.

Brian Singer - Goldman Sachs - Analyst

You talked about railing crude out of the basin out of the Uinta Basin to the East, West and Gulf Coast. Can you talk to what gives you the level ofconfidence that the refineries in these area can take this oil, your oil, given its waxy nature and is that based on conversations with refineries or isit based on market confidence or the potential for partnering with other producers?

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Brain, this is Mark. We've taken the time to -- we not only looked at -- first as it relates to the local refining capacity and the situation there, I thinkit's important to note that we have those relationships as a result of our condensate in the Wyoming area to begin with. So we've got relationshipswith Salt Lake refiners currently. They spent a lot of time, energy and effort over the last several years to expand capacity to where it is today tohandle these waxy crudes and we know that that's increasing going forward.

We've also had conversations, we're in the process of continuing those conversations and dialogue with entities that can rail crude out. And theyhave relationships with the end users and we're in the process of developing those relationships ourselves as well. So multiple conversations onmultiple fronts.


But this oil is already showing up in Cushing for example in some of the Gulf Coast refineries. And it's very good quality oil if you got a cat cracker.And so it's -- there's no sense of a less cloudy oil in terms of once you get it into a refinery a cat cracker (inaudible) so it's [30] gravity. You have todeal with 100 degrees propylene on the wax. But once you take care of that, than it is pretty good oil.


Great, thanks. And then shifting towards Pinedale, given that you now have a separate [outlet] for capital spending based on oil, how should wethink about how variable your Pinedale rig count could be next year depending on the gas price environment? And perhaps you could commenton capital budget volatility as well.


Well I think we're trying to be conservative where the capital budget's going to be less than cash flow again. And because we want to continue todo that, especially the natural gas side, we see as we wait for natural gas prices to recover. We have very good returns at 350, 360 gas in Wyoming.So it is hard to suggest that we don't spend capital there when you have returns of 30%, 40% at those kind of gas prices.

So the issue to us is total CapEx less compared to cash flow. Where you see we'll withdraw capital is the Marcellus. I mean we don't agree with folkswho don't see growing basin differential there. We lived through that in Wyoming a decade ago. I think in first half of 2008 I was reminded theother day at the Board meeting that the differentials up there were $3 Mcf. So we see that kind of a nightmare happening in Marcellus. And that'swhy we're using $0.60 differentials in our forward forecasted cash for 2014. So you'll see us withdraw capital there and on our natural gas (inaudible)Pinedale.


Great, thank you.

Operator

Leo Mariani, RBC.

Leo Mariani - RBC Capital Markets - Analyst

A couple questions here on Uinta. Do you guys have a theory as to why these wells have been inclined to flat over the first several months here?

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Yes, the wells are constrained. They're constrained at the surface either through artificial lift or facilities. So they definitely have higher deliverabilitypotential and that's something we're eager to optimize.


Got you, okay. You guys clearly lay out some really good data on the slides here. So you have your 12 older wells, your 19 newer wells. I think therewas 8 other wells on production that we didn't see any data from. Can you guys comment on that?


I'll speak to that, this is Jason. Really, the focus was to look at the Lower Green River. There's three Upper Green River wells producing as well. Andthen there's a handful of wells that came online so recently that it's not meaningful to include those in the normalized plots. That being said, acouple quarters from now we'll have good information on those as well.


Got you, that make sense. In terms of the next several years you talked about most of the activity in the Lower Green River. Should we think aboutas literally 90% plus? Is there any kind of number you can put on that in terms of what percentage Lower versus Upper Green River?


It's going to be pretty much exclusively Lower Green River unless we see something to change course.


In the next decade.


And that 's what's reflected in that slide, Mike's favorite slide with the capital and the cash flow outlay. You can see -- basically you look at that slideand you see the capital reduction 10 years out and that's the Upper Green River program following the Lower Green River program.


And it's probably logical that we didn't allocate any of the acquisition price to Upper Green River developmental locations in the future becausewe didn't put any value on that in the acquisition, so didn't seem fair.


And just a reminder, it's not because Upper Green River is not economic. Go look at the table, it's got great returns. It's second-tier to the LowerGreen River at the time. So we're going to prioritize to the highest value opportunity.

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Okay, that makes perfect sense. With respect to the drilling permits trying to get a sense of how far in advance you guys are permitted and maybesome color on when you think the permitting process is going to look like there for you guys over time?


This is Bill. We have enough permits to run the one rig program for next year essentially in hand at this point in time. And we're working throughthe process of optimizing how we permit as we go through the transition. And we'll -- as we do in our Pinedale operations work closely with theagencies and make sure that we're well suited as far as the sequence that we drill in.


Okay, that makes sense. And in terms of the Marcellus, you talked about nothing shut in today, are you guys anticipating potential shut ins as weget into the winter or you think this is more of a shoulder season shut in issue as we get into next year?


Leo, Mark here. We think it's more of a shoulder month issue, we think we'll see some strengthening in pricing as we go through the winter months.


Okay, is there anything you guys may be doing on the marketing side to try to -- or hedging side to lock in and prevent basis blow out potentiallyfrom hurting you guys down the road?


No, we're -- again we went through the Rockies issue when we bought firm capacity on [Brecks] and we're stung with that fixed cost charge wehave. So our view is the folks buying all the firm transportation Marcellus are going to get stung with that in three or four years too. You've got tolook at total cost if you're investing in pipelines or buying firm transportation, you still got to factor that into what your returns are. So no, we havea different view.


Okay, that make sense. Thanks a lot.

Operator

Matt Portillo, TPH.

Matt Portillo - Tudor, Pickering, Holt & Co. Securities - Analyst

A few quick questions for me. In terms of the Uinta acreage they you're currently operating, I was wondering what the longest well that you haveon production is in terms of the data that you have in hand? And then a second quick follow-up question to that in terms of the A well where youprovided the 180-day rate, I was curious if you had the 396-day rate or where that's currently producing?

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So I think maybe one thing to draw your attention back to was slide 9 where we talked about production. You can see the earliest -- the longestproduction well that we've had on production came online back in April of 2012. So you're at the 18 month mark as far as the most mature producingwell in this area. They're again to some of the information that Brad shared on the Rogers well, that well has been online for 4.5 years and worksas very good analog to the production performance that we're seeing in the Three Rivers area.


Perfect, and then in regards to maybe a bigger picture question in regards to hedging, both oil and gas, I was hoping we could maybe get anupdate given where our curves are today in 2014 and 2015, how you guys are thinking about both of those commodities and potentially lockingin some of the prices.


Well I think we're going to look very seriously at hedging on the oil side because we're among those that think oil prices decrease over time likethe forward curve suggests. But on the gas side, we're on that side that says natural gas prices will increase over time. So we're less likely to hedgegas.


Thank you very much.

Operator

Brian Foote, Clarkson.

Brian Foote - Clarkson Capital Markets - Analyst

Your CapEx budget of $520 million to $560 million, I understand that $68 million of that is the Uinta acquisition. The rest of it, can we think aboutthe -- and I know the question was asked about the volatility around it, but what kind of pricing assumptions went into that? And the resultantproduction growth, some of that of course is Uinta, but what assumptions in terms of well cost et cetera go into the $520 million to $560 million?And the $40 million differential is what I'm most interested in.


Well the differential has to do with increased or decreased expenditures in Pennsylvania, how you want to view that, that's the differential there.And I don't know that I want to get into the details 2014 capital budget since we really haven't been all fleshed out yet. So we'll have to save thatfor another day.


But the resultant -- I heard correctly that you said it drives 7% to 8% all in production growth.

22







That's correct.


Okay, great. All right, thanks.

Operator

Mark Hanson, Morningstar Equity Research.

Mark Hanson - Morningstar - Analyst

Thank you for the detail on Uinta. This might be more for Mike. I know you previously shared your view that the domestic natural gas market isnear at peak in terms of production. And with yesterday's EIA numbers showing August volumes remaining stubbornly high, I'm wondering if theinternal view there of Ultra is still a near-term rollover in production if that still holds?


That's still the view. I think if we look at, and we'll use Genscape year-to-date data if we compare 2012 average production of what 64.2 Bs a day to2013 average year-to-date production of 64.6 Bs a day. It's gone up but it's not a big mover. Again, it's -- domestic production has been pretty flatsince middle of -- since well over a year ago. And again, I think we're getting through some of the uncomplete unconnected wells in Marcellus, andI guess we have that in Utica, but I think that backlog disappears first half of 2014 and reduces significantly. And the current drilling paces won'tmaintain this level of production.

Mark Hanson - Morningstar - Analyst

Thank you, appreciate it.

Operator

Thank you, I'd like to turn the call back over to Mike Watford for closing remarks.


Well thank you. If you have any other questions, please don't hesitate to get a hold of us today. We'd love to answer them and hopefully we'vedone a more complete job of sharing our enthusiasm with the Uinta Basin acquisition and have a good day.

Operator

This concludes today's program. You may disconnect at this time. Thank you and have a great day.

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