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Ultra Petroleum (NYSE:UPL)

Q3 2013 Earnings Call

November 01, 2013 11:00 am ET

Executives

Michael D. Watford - Chairman of the Board, Chief Executive Officer and President

Douglas B. Selvius - Former Senior Vice President - Exploration

Jason Gaines

C. Bradley Johnson - Vice President of Reservoir Engineering and Development

Marshall D. Smith - Chief Financial Officer and Senior Vice President

William R. Picquet - Senior Vice President of Operations

Analysts

Marshall Carver

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Robert L. Christensen - Canaccord Genuity, Research Division

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Brian Foote

Mark P. Hanson - Morningstar Inc., Research Division

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.

Michael D. Watford

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, Reservoir Engineering and Development; Doug Selvius, Vice President, Exploration; and Jason Gaines, Manager of Business Development.

I'd like to point out that many of the comments during this conference call are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the Risk Factors in the Forward-looking Statements section 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, we intend 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 by sharing what we hope to achieve this morning. I want to spend a few minutes discussing our third quarter results and what the remainder of the year looks like. Then, we want to spend more time discussing our recently announced Uinta Basin oil acquisition. To assist in the Uinta discussion, we have an expanded slide deck available for you to follow along with, one where we have attempted to provide more details as 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 3/4 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 income margin 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 realized price for the third quarter for 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 differential due to planned seasonal infrastructure maintenance, coupled with a capacity-constrained market. During the third quarter, our average Pennsylvania basis differential was $0.54 per Mcf, and we would expect this to be around $0.62 for the fourth quarter, and factor using $0.60 for calendar 2014.

Considering the majority of our production is priced outside of the Northeast, we are anticipating a company-wide realized price for the fourth quarter 2013 of NYMEX less 5% to 7%, as outlined in the Guidance section of our news release.

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

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

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

In Pennsylvania, our third quarter production averaged 175 million cubic feet per day or 28% of the corporate total. A noteworthy stepout well in Centre County, to the southwest of its development area, came online with very positive results.

Due to the cost savings we're enjoying in Wyoming and less spending in Pennsylvania, we are reducing our capital expenditure budget for 2013 by 7%, down to $385 million, while leaving production 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 we have reviewed some opportunities in the basin previously with mixed results. But in reviewing the details of this property, we changed our minds in 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. Our discussion is intended to address well performance, more importantly, recent well performance; reserve estimates; geology and why this acreage is unique; well costs; 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 the same slide that we used a week and a half ago, but I want to quickly give a few highlights. Again, it's Uinta Basin oil-producing assets in Northeast Utah. Currently, net production about 4,000 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 believe we can continue with that.

Net risk reserves of 90 million barrels. We've also revised that slide, it's Slide 18 in the deck. And you'll see that we have added a 10-acre downspacing waterflood upside to our resource summary, as a nearby adjacent operator has recently gained approval for such a project. The 90 million barrels of resource opportunity previously identified almost doubles to 173 million barrels. And with that, we think we'll only be recovering about 15% of the oil in place. So quick math suggests that we believe there is over 1 billion barrels of original oil in place in this property. It is not a horizontal acreage play, it is Pinedale all over again, only shallower in oil. It's increased density vertical drilling with stacked pay.

We have what I call proved-like reserves of 37 million barrels, and there's 575 future well locations prior to downspacing. And the first 300 of those 575 wells, which will be the first ones drilled over the first 7 or 8 years of activity, should average over 250,000 barrels of reserves each.

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

Next page, Page 3, the 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 growth for the company, this is a cash flow grower. And it leverages our taxable expertise.

Page 4 is the asset map. I want to make the point that the new Utah opportunity is probably only a 4-hour drive away from our Pinedale activities, so it's close by.

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

Douglas B. Selvius

Okay. Thanks, Mike. I'd like to start on Slide 5 with a slide that compares Three Rivers to Pinedale. The 2 areas are similar in many ways, but there are also some significant differences, and I'll point those out too.

First, starting with the 2-well diagram on the left, the most important similarity is that both areas involve a thick stack sequence of reservoir sands. The 2 are scaled the same, so it's apparent that Pinedale is thicker that the Three Rivers 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. We drill 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 areas are 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 day in Pinedale. We know what to do.

Instead of the typical 16 frac stages we use in Pinedale, we only need 7 in Three Rivers. And instead of 10 days to drill and case a well, Three Rivers 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.

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 our attention. Our returns in Pinedale right now are attractive, ranging from 36% to 91%. But the returns at Three Rivers are even better, ranging from 130% to as high as 600%.

The message here is that this is a very strong project. 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 last time. The story here is that Three Rivers is centrally located between a number of very large, prolific legacy fields. It's also clear from the slide that there are 2 plays here. The green areas show and represent oil production from the Lower Green River sands and the Wasatch section just below it. The red area represents gas production from the Wasatch and also the Mesaverde section that lies below it. In other words, there are 3 intervals with stack sequences of productive sands here, some are oil prone and others are gas prone. We're acquiring Three Rivers for its Lower Green River 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 a shot at both.

Slide 7 is also something we've talked about before, so I just wanted to emphasize a couple of points without going through it in detail. Three Rivers is unique geologically and economically when compared to adjacent fields. No other field in the area has a combination of drill depths, well cost and 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 3-well cross-section that starts on the right with Three Rivers, and then extends west into Leland branch and Monument Butte fields. Its location is shown on the inset map on the upper right. Each log represents 3,000 feet of total thickness with reservoir sands colored yellow, and the interspersed shales colored brown. And then highlighted in light and dark green 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 members. We have 373 feet of blocky sand in that interval. In Leland branch, just to the west, that same interval only has 120 feet of sand. And then, further west in Monument Butte, the overall section does get a little bit thicker and has over 300 feet of sand, but the sands there are thinner and are scattered throughout the section as opposed to being concentrated in thick, blocky members like we see at Three Rivers.

Now there's value in the thin sands. In fact, we see a lot of value in the thin sands we have in the TGR3 and Garden Gulch intervals, but thicker sands 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 more detailed slides focusing on Three Rivers geology and specific well results. Jason?

Jason Gaines

As Doug pointed out, the Three Rivers area is unique and Slide 9 also helps show this. The production graph tells the story of the early field development of 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. First production in the field began in April of 2012, with only 3 wells online through September. In May of 2013 and only 13 months from first production, the production had ramped up to 1,000 barrels of oil per day, with 14 wells online. In the past 5 months alone, from May of 2013 through October, production growth has been very impressive, from 1,000 barrels of oil per day to 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 indicates that 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 120 barrels of oil 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 production, particularly in May of 2013. This graph helps illustrate the ability to grow production rapidly in the Three Rivers area, and I will share additional well production details to demonstrate the impacts of this learning curve in some following slides.

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

Doug?

Douglas B. Selvius

Slide 11 is intended to demonstrate that Three Rivers has been significantly derisked by over 40 wells. The 6-well cross-section shows our pay-in over that location is broadly distributed across our leasehold position. It's highlighted on the inset map along with the blue and red dots showing the wells 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 1 particular area of the leasehold. They've been drilled and nicely distributed 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 important Douglas Creek and Travis members. Some differences do exist, most notably down in the Castle Peak member, and those differences affect well performance, 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 to build very accurate valuation models. What also makes us comfortable is that wells in all of the areas were highly economic.

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

Jason Gaines

I'll share some of the impressive well results that have been seen in the Three Rivers area. The top tables on Slide 12 tie to the cross-section that Doug just shared with you, which is displayed again in the lower left-hand corner of this slide. The 6 wells on the cross-section have an EUR range of 151,000 to 558,000 barrels of oil, and averaged 336,000 barrels of 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 260,000 barrels 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 the average 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 6 months. 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 per day.

Let's jump to Well C on the table. It has been online for 310 days, and it's already cumed over 60,000 barrels of oil and continues to produce over 200 barrels of oil per day today, after nearly a year of production.

On the lower right-hand side of the slide, you can see the cumulative production performance of these 6 wells compared to 3 type curves. The individual well results continue to meet or exceed our expectations. We will cover 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 production versus days online, and 3 type curves are provided for reference. In dark blue, you can see the average well performance of the first 12 Lower Green River wells. The orange curve is the average well performance for the recent 19 wells, displaying a significant improvement in well performance, with over 50% improvement in cumulative production after 100 days online. One other point to make on this slide before moving on is that the light blue line displayed on the graph is a simple payout line using $80 net oil pricing. If you project the orange curve along the type curve, you can see that these wells pay out in less than 150 days, thus explaining the incredible rates 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 8 months 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 the Three 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 8 months on production and averaged almost 100 barrels of oil per day during month 8. During the first month of production, the recent 19 wells, shown in orange, had 50% higher average daily production rates compared to the first 12 Lower Green River wells. These wells averaged 166 barrels of oil per day over the last 30 days, which is 52% higher than the first 12 Lower Green River wells over that same period. Further, these wells have averaged 168 barrels of oil per day over the first 144 days of production. I want to reiterate the 2 key points made earlier on this slide, these wells have very flat initial production profiles, and a significant learning curve has resulted in much better average well performance. Doug?

Douglas B. Selvius

Okay. We've spent some time distinguishing Three Rivers from other surrounding areas. Slide 15 is actually an analog to Three Rivers. It shows a 3-well cross-section tying 2 Three Rivers wells on the right to a well 3 miles north. Projected into the section with a dashed red line is an 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 what the 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 bit thinner. But we believe these wells are geologically analogous to Three Rivers and provide a very good production analog and a geologic analog for what we're going to do there. One of the 2 wells on the left side of the section has been online for 200 days and is expected to cume 257,000 barrels. The other has been online for over 4 years and is expected to cume over 0.5 million barrels. For more details on what this area is telling us, I'll turn it to Brad.

C. Bradley Johnson

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 oil per day for 32 straight months and has produced 171,000 barrels to date in just 4.5 years. This well is located less than 3 miles north of the Three Rivers area and is a key analog due to its proximity and geological relation described by Doug on the previous slide. The flat production profile demonstrated by this well occurs in several wells in the East Bluebell area and we observed the same flat production performance in the Three 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 4 different reserve forecast for the Rogers 16-43 well. You'll note that we have included an exponential forecast as a low side case. However, hyperbolic declines are observed in Lower Green River oil wells and is certainly validated by this well's performance over the last 2 years. We have assigned a B factor of 1.6 to this well and we current estimate the EUR to be 530,000 barrels. While there is some uncertainty 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 asset, demonstrate a flat production profile that generate exceptional returns and allows for robust production growth with just a 1-rig program.

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 also very important to recognize the magnitude of 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 demonstrate similar performance, and in Three Rivers, Jason already shared results on Slide 12, that mimic this performance, with a representative sampling across our field where the average actual actually exceeds the Rogers well during the first 180 days. We believe we are conservative with our type curves and risking of future development wells when assessing the Three Rivers asset. In our model, initial rates were constrained to no more than 200 barrels of oil per day and the flat production period was limited to a range of 4 months or less on those future wells.

Slide 18 tabulates the resources and value we have assigned to Three Rivers. The proved developed reserves represent 9.9 million barrels of net remaining reserves and a PV-10 value of $265 million, just over 40% of our purchase price. As we roll our model forward by just 1 year, we expect these reserves to nearly double the value, reaching a value of $506 million by yearend 2014, or 78% of our purchase price represented by PDP reserves.

The second row of this table includes the bookable offset locations on just 40-acre spacing. The net remaining reserves of 27 million barrels have a 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 per well of 258,000 barrels.

The next 2 rows on the table represent additional 40-acre and 20-acre probable and possible locations. At this time, our 3P reserve numbers are made up of a downspacing -- a field that is already delineated. Similar to Pinedale, these locations have essentially 0 geologic risk. This incremental 53 million barrels results in our 3P reserves totaling up to 90 million barrels. With our current estimates of original oil in place for the Green River formations, this represents a recovery factor of just 8% based upon a modest 1-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's also additional upside equaling 83 million barrels in the Green River formation. Today, we have decided to include this row as an update to the previous version of this slide. These contingent reserves will be realized with further downspacing and/or water flooding, similar to what has occurred in the nearby Monument Butte field. The total net resource of 174 million barrels, representing a very reasonable 15% recovery of oil in place, one can 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 the much higher reserve potential and well deliverability of the Lower Green River that delivers outstanding returns. And so we plan to prioritize our development to the Lower Green River over the next few years.

At the top of this slide, you can see the single-well economics for a range of EURs 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 called this 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 allocate the 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 the Lower 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 than a year for the Lower Green River wells, this asset will generate significant returns and cash flow for Ultra.

Michael D. Watford

Page 20, we have the production growth slide, showing a 4-year compound annual growth rate of about 50%, which more than likely we will exceed.

Page 21 is my favorite slide, which is cash flow contrasted with CapEx going forward. The asset is immediately -- generates free cash. This is a 1-rig scenario, where over the first 5 years of its productive life at current [ph] pricing, it pays for itself, and then we have a few decades of free cash going forward. There's been some questions out there as to if we go to 2 rigs, say starting 2015, that we'd have to raise equity. Well, I think, that dark blue bar is several multiples above the light blue bar, so there's plenty of room for this asset to fund 2, if not 3 rigs, in the area.

And I'd like to go onto the last page here of the handout, is a listing of the key assumptions. We're trying to be very transparent in how we've worked 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.

Marshall D. Smith

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 been expanded recently such that current capacity is about 48,500 barrels a day. And continued expansions are underway, the majority of which will be in place through 2014, 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 meaningful capacity additions with new facilities supporting multiple unit trains here. As in the Bakken, we expect these unit train options will increase volumes and decrease rates, as well as provide diversification to markets. And more specifically, we see product moving to refineries on the East Coast, the West Coast, 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 crude provides good yields for the right refineries with fluid cracking capabilities. So we're confident there will be a growing market for these barrels over time.

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 under term contracts to Salt Lake City refineries, largely based on a percentage of NYMEX net back price. The remaining contract capacity, currently about 2,000 barrels a day, is under a term rail contract.

This volume started moving by manifest rail in September, and it transitions to unit train capability beginning 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 contract is based on NYMEX less a fixed price. So on an all-in basis, crude associated with the acquisition is currently selling for a net back price of approximately 80% of NYMEX.

Now I'd like to move on and take a look at things from a financials perspective, more specifically how we're currently financing ourselves and how we see ourselves financing or how we see ourselves being financed in light of the acquisition. I want to go on and address key financial aspects of 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 on a pari passu basis at the operating company level. The operating covenants here or the operative covenants, rather, here are backward-looking debt to EBITDA covenant and a forward-looking PV9 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 covenants at the operating subsidiary will stay the same. The covenant at the parent level, though, will be different. It will be an interest coverage covenant and it will become the operative covenant for the company going forward.

Now 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 the property is well-defined, it is largely derisked. The wells are relatively low cost, can be drilled quickly, have strong returns and pay out in a matter of months. As a result, the project is self-funding. One rig in the field with a capital investment program of $68 million a year results in a risk production forecast doubling from the 4,000 barrels a day currently to 8,000 a day just 1 year out.

Now Brad spoke to the PV-10 or the PDP component over time. From a financial perspective, we've also looked at the asset in terms of its borrowing capacity over time. So when one looks at the PDP category alone, with bank pricing parameters, $60 net flat for all-time with the 1-rig program on a risk basis, a PV9 more than doubles to $460 million at the end of the first year alone.

Now taking these attributes and translating them at the corporate level, the acquisition provides good diversification, both geographically and geologically. It further supports our disciplined capital allocation 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 1 rig running in the Uinta against a current base case absent the acquisition. A number of points in this analysis stood out.

Production growth increased a modest 5 percentage points over base levels without the acquisition, but revenue growth was up 18 percentage points and EBITDA growth is up a meaningfully-- a meaningful 28 percentage points over base levels. So the acquisition translates into modest levels of top line growth but even higher levels of cash flow growth going forward.

Now further, given that the acquisition's debt financed, not with equity or equity-linked security, the transactions immediately accretive, of course. But looking at it further in more detail on a debt-adjusted basis, the transaction's accretive on both-- to both earnings and cash flow after roughly the first 4 months of the transaction.

With that, I'll turn it over to Mike.

Michael D. Watford

Thanks, Mark. A few closing comments about 2014. We mentioned last quarter that we have contracted for 2 additional new-build drilling rigs for Wyoming. The first arrives this month, November of 2013, and the second in February next year. So we have the opportunity to operate 4 rigs in Pinedale for 2014, 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 will spend less money in Pennsylvania and we will operate 1 rig in Utah.

So early capital expenditure thoughts for 2014 are somewhere between $520 million and $560 million, for a 7% to 8% production growth and EBITDA growth 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 provide more information at our February 2014 call.

With that, operator, I'd like to open it up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from Marshall Carver with Heikkinen Energy Advisors.

Marshall Carver

I did have a couple of questions. One on Slide 22, on the single well curves. I'm a little confused by the -- you've got 2 bullet points for Lower Green River type curve 1. It says 130 barrels of oil a day flat 1 month, 200 barrels a day flat 3 months. So does that mean it's going to be about 130 barrels a day for the first month and then 200 averaging over the first 3 months, implying that the production will go up? Could you give a little color behind that?

Jason Gaines

Sure. These is Jason Gaines. Really what we see during the first month of production on these wells after frac-ing them is kind of the cleanup period. So what we've modeled is 130 barrels of oil per day would be that cleanup period that you see for a single month. And then the following 3 months would be essentially be a flat production profile at 200 barrels of oil per day prior to derisking.

Marshall Carver

Okay. That's helpful. And then jumping back to Slide 12 where you give the areas A, B, C, D, E and F. Do you have the approximate number of locations in each of those areas? And what those number of locations be similar to the -- would you expect them to be similar to the EURs you've detailed?

C. Bradley Johnson

Marshall, this is Brad. I think if you turn to Page 18, what we've tried to demonstrate there is that the next 130 wells in the program have an average of 2 feet [ph] a day [ph]. So if you looked at that page you could find an understanding of the average performance over the next 130 wells. 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 you back 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 of those buckets.

Marshall Carver

Okay. And one final question. The improvement in well costs quarter-over-quarter, what was the major driver behind that? And is $3.8 million a realistic number heading forward or should it possibly go up a little bit as we move forward?

William R. Picquet

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

Operator

And we'll take our next question from Ron Mills from Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Just a little bit of 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 move from 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 to assume that there are 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 like it includes some sort of risk factor.

Unknown Executive

There's definitely some geologic variability in the field that was identified. I don't know if Doug pointed it out in some of the slides. I think the other thing to recognize is the vintaging of these wells. Some of the early wells drilled in the field, some of which are on the east, were some of the early wells. 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 and continue to optimize that, but there's -- that variability's there and but on an average basis, the results are just compelling for us.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

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 the differences that has caused that performance to be tracking more the 380000-barrel curve versus the 258,000 barrels and whether they were completion design or well design, is that also, can that also be applied across most of the acreage?

Jason Gaines

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, the completion techniques and hydrating that. The second one would be the operational optimization as far as pumping units, where our pumps are set and those type of operational improvements. And then the third would be geographically, sorting the high-grade portfolio much like we'll continue to do.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

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 1 year on the assumptions you just provided. You remain free cash flow positive. Is this -- what do you think the sources or the uses of that free cash flow is? Is it a continued deleveraging over time? Or does it result in terms of what you talked about potentially, this asset that you're acquiring offering the ability to fund not just 1 but 2 to 3 rigs?

Michael D. Watford

Yes, I think I said 1. We have the opportunity to accelerate here once we get a better understanding and know exactly where we want to go and what we want to do. I mean, we have a development plan for 2014 for this asset that has some downspacing tests, has some waterflood tests. So we want to get after it pretty early in understanding how we're going to put this together in totality. Because if we're going to go to a waterflood kind of an effort, we'd just as soon go there sooner rather than later in terms of planning it and reducing CapEx. I don't know that we have -- we are concerned at the level of debt we're going to take on December of '13. We're very comfortable by the time we get to December 14, it's reasonable. And by the time -- we've gotten 3-year projections which have us at 1 3/4 times trailing EBITDA by 2016. So we're kind of underlevered at that point in time with our current plan. So I mean I think we're looking for another one of these type of opportunities.

Operator

And we'll take our next question from Bob Christensen with Canaccord Genuity.

Robert L. Christensen - Canaccord Genuity, Research Division

Mike, did I hear right? It sounds like new rigs are arriving and the old rigs are going to keep working in the Pinedale, so a 4-rig program?

Michael D. Watford

Yes, sir, you heard that.

Robert L. Christensen - Canaccord Genuity, Research Division

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?

Michael D. Watford

Next to 0. Brad will get the actual numbers.

C. Bradley Johnson

Right. Currently, or as of 30th September, we had 4 wells waiting on completion and 0 wells waiting for hookup.

Robert L. Christensen - Canaccord Genuity, Research Division

And a year-ago, what would that level have been?

C. Bradley Johnson

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

Operator

And our next question comes from Mike Scialla with Stifel.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

On those new-built rigs, are those -- so I would assume those are under contract right now. If gas prices were to weaken, you said you've got some 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?

William R. Picquet

This is Bill, Mike. The new rigs are under contract and as Mike said, 1 arrives this month, 1 arrives early in 2014. We also have flexibility in the contracts on the existing 2 rigs that would allow us to make decisions dependent upon gas prices. So that's solely dependent upon those 2 rig contracts. And no, those rigs would not be used in Uinta. They're much bigger than what's required in the Uinta.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

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

William R. Picquet

Well, 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 a breakout period with the new rig. But the same drilling company, same type of rigs, same people operating the rigs. So we're very confident that performance will be good.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And switching over to Pennsylvania. Do you still have any production shut in at this point?

Michael D. Watford

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

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then just 1 other for that area. You'd mentioned on your last call seeing some activity from some of your peers marching toward your acreage in the Utica. Any update there? And any chance that you would consider drilling a Utica well next year?

Douglas B. Selvius

This is Doug. We have no plans to drill a Utica well this year. The activity continues in the area. You can read Natural Fuel Gas or Seneca's latest release. West of us they've announced some good results. So the play continues. It's encouraging. It's moving our way and we're just going to continue to monitor it at this time.

Operator

And we'll take our next question from Joseph Allman with JPMorgan Securities.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

On Slide 21, you show the CapEx going out to 2025. And I just wanted to check what the assumptions are for that? Does that much the total CapEx or the total activity that you lay out in Slide 18 on the table, excluding the waterfloods?

Jason Gaines

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

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. Great. That's very helpful. And then just you made the announcement for this acquisition on October 21 and the stock has underperformed. Mike, what are the biggest reasons you think for the underperformance?

Michael D. Watford

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

Operator

And we'll take our next question from Noel Parks with Ladenburg Thalmann.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

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

Michael D. Watford

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 just don't have any data to help you with there.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

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

Douglas B. Selvius

This is Doug. I can add a little bit of insight here. We showed several slides demonstrating how this area is unique geologically and stratigraphically in 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 Wasatch section, below the Lower Green River. It wasn't until they drilled wells through the Lower Green River looking for something deeper that they realized 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't think -- we're speculating, but I don't think the other offset operators really expected that either.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

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

Douglas B. Selvius

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 fully capable of picking up this ball after the transition period and running with it. And we have some ideas on how to grow. But that's down in the future right now.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay. Great. And can you give us a little bit of a sense sort of looking ahead, just how -- as you do more drilling across the area, what PUD bookings might look like 1 year or 2 out? I know you guys are on the conservative end of how you recognize PUDs But just as far as maybe number of locations you think or even locations per well drilled you'd hope will find their way into PUDs over the next couple of years?

C. Bradley Johnson

Sure. This is Brad. If you turn to Slide 18, where we describe the resources. And I think row 2 describes those locations there that could be bookable from the offset standpoint. I also mentioned in my remarks about what the PDP growth would look like as we go forward. So as we add 45 wells a year, we've already got 43 wells, you're looking at PDP doubling in 1 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.

Michael D. Watford

I mean, volumetric PUD booking here is just, doesn't really move the needle, for the corporation, given all the PUDs that we removed from our bookings last year 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 this transaction because of the ability to make money, the profitability of it, the cash flow growth. It's not really volumetrically-driven, and certainly not reserve-driven.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Great, and just one last one. Maybe this is for Mark. With this transaction, just thinking about the cash outlay and what that might do to sort of the book value for 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 spinning out legacy mature areas at Pinedale, royalty trust type structure or MLP type structure?

Marshall D. Smith

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 for us from a tax perspective sort of one way or another. We've got a meaningful tax position that's been set in place as a result of capital spending in prior years, well ahead of this acquisition. So our tax position is independent of this acquisition, from my perspective.

Operator

And we'll take our next question from Tim Rezvan with Sterne Agee.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Just wanted to clarify a question on the Uinta rig ramp. I know folks are asking you to add rigs, you haven't even closed on the deal yet. But obviously, you're excited. So you talked about 1 rig next year. Is the delay more related to just kind of getting acclimated with the asset than it is on any kind of leverage or cash flow issues?

Douglas B. Selvius

Well, as Mike mentioned, we've planned to do some drilling to evaluate some pilot projects on spacing and waterfloods, and that's going to be key to how we decide to develop the field. So we want to get that information early on. If we think it's appropriate to ramp up from our corporate perspective, we'll consider that.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay. So you will be doing pilot tests with that 1 rig?

Douglas B. Selvius

Right.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay. I appreciate that clarity. And 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?

Michael D. Watford

The first 12.

Douglas B. Selvius

The red dots represent the first 12 wells drilled, maybe that's not real clear. And the color, the green dots, represent the second 19.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay. And just to clarify your earlier comments then, obviously there is some geographic variability but you'd expect that, as you apply the learnings you've had in place, that some of the variability may compress, is that fair to say, in regards to wells being C versus everything else?

Michael D. Watford

I think that's a fair conclusion. We would expect our understanding of that vulnerability to improve and then with prioritizing and high grading, we would expect our performance to tighten up from a P10, P9 ratio.

Operator

And we'll take our next question from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

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

Marshall D. Smith

Brian, this is Mark. We've taken the time to -- we've not only looked at -- first, as it relates to the local refining capacity and the situation there, I think it'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 relationships with Salt Lake refiners currently. They've spent a lot of time, energy and effort over last several years to expand capacity, to where it is today to handle these waxy crudes and we know that's increasing going forward. We've also had conversations, we're in the process of continuing those conversations and dialogue with the entities that can rail crude out. And they have relationships with end users and we are in the process of developing those relationships ourselves as well. So multiple conversations on multiple fronts.

Michael D. Watford

But this oil is already showing up in Cushing, for example, and 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-quality oil in terms of once you get it into a refinery and a cat cracker and whatnot. So it's 30 gravity. You have to deal with 100 degrees pour point on the wax, but as long as you take care of that, it's pretty good oil.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And then shifting towards Pinedale. Given that you now have separate outlets for capital spending based on oil, how should we think about how variably your Pinedale rig count could be next year, depending on the gas price environment? And perhaps you could comment on capital budget volatility as well?

Michael D. Watford

Well, I think we're trying to be conservative with the capital budgets, going to get us some cash flow again. And because we want to continue to do that, especially on the natural gas side as we see -- as we wait for natural gas prices to recover. We have very good returns at $3.50 and $3.60 gas in Wyoming. So it's 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 just total CapEx compared to cash flow. Where you see where we'll withdraw capital is the Marcellus. We don't agree with folks who don't see growing basis differential there. We lived through that in Wyoming a decade ago. I think in the first half of 2008, I was reminded the other day at the board of meeting, that the differentials up there were $3 Mcf. So we see that kind of a nightmare happening in Marcellus and that's why we're using $0.60 differentials in our forecasted cash flow 2014. So you'll see us withdraw capital there and on our natural gas part of [indiscernible] in Pinedale.

Operator

And we'll take our next question from Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

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

Douglas B. Selvius

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

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

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

Jason Gaines

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

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Got you. That makes sense. I guess in terms of the next several years, you talked about most of the activity in the Lower Green River. I mean, should we think about the add is literally like 90% plus? Is there any kind of number you can put on that in terms of what percentage Lower versus Upper Green River?

Douglas B. Selvius

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

Michael D. Watford

In the next decade.

Douglas B. Selvius

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 slide and you see the capital reduction 10 years out, and that's the Upper Green River program following the Lower Green River program.

Michael D. Watford

And then as part of the logic why we didn't allocate any of the acquisition price to Upper Green River development locations in the future, because we didn't put any value on that in the acquisition. So it seemed fair.

Douglas B. Selvius

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

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. That makes perfect sense. Just with respect to drilling permits, just trying to get a sense of how far in advance you guys are permitted. And maybe just some color on what you think the permitting process is going to look like there for you guys over time?

William R. Picquet

This is Bill. We have enough permits to run the 1-rig program for next year, essentially in hand at this point in time. And we're working through the process of optimizing in how we permit as we go through the transition. And as we do in our Pinedale operations, work closely with the agencies and make sure that we're well suited as far as the sequence that we drill in.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

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

Marshall D. Smith

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

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Is there anything you guys may be doing on the marketing side to try to -- or hedging side to kind of lock in and prevent basis blowout potentially from hurting you guys down the road?

Michael D. Watford

No, we're -- again, we went through the Rockies issue when we bought firm capacity on Brex [ph]. And we're kind of stung with that fixed cost charge we have. So our view is the folks buying on the firm transportation in the Marcellus are going to get stung in 3 or 4 years too. I mean you got to look at total cost. If you're investing in pipelines or buying firm transportation, you still have to factor that into what your returns are. No, we have a different view.

Operator

And we'll take our next question from Matt Portillo with TPH.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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

Jason Gaines

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 longest production 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 producing well in this area. There again, some of the information that Brad shared on the Rogers well, that well's been online for 4.5 years and work as a very good analog to the production performance that we're seeing in the Three Rivers area.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Perfect. And then I guess just in regards to maybe a bigger picture question in regards to hedging, both oil and gas. I was just hoping we could maybe get an update, given where curves are today, kind of in '14 and '15, how you guys are thinking about both of those commodities and potentially locking in some of the prices?

Michael D. Watford

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

Operator

And we'll take our next question from Brian Foote with Clarkson.

Brian Foote

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

Michael D. Watford

The differential has to do with increased expenditure, increased or decreased expenditures in Pennsylvania, however you want to view that, that's the differential there. And I don't know that I want to get into the details as to the '14 capital budget since we really haven't gotten it all fleshed out yet. So you'll just have to save that for another day.

Unknown Analyst

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

Michael D. Watford

That's correct.

Operator

And we'll take our next question from Mark Hanson with Morningstar Equity Research.

Mark P. Hanson - Morningstar Inc., Research Division

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

Michael D. Watford

That's still the view. I mean I think if we look at -- we use Genscape year-to-date data. If we compare 2012 average production of what, 64.2 Bs a day to 2013 average of year-to-date production of 64.6 Bs a day, it's gone up, but it's not a big mover. Again, domestic production has been pretty flat since middle of -- well, since well over a year ago. And again, I think, we're getting through some of the uncompleted, unconnected wells in Marcellus, and I guess we have that in Utica. But I think that backlog disappears first half of 2014 or reduces significantly, and the current drilling paces won't maintain this level of production.

Operator

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

Michael D. Watford

Well, thank you. If you have any other questions, please don't hesitate to get hold of us today. We'd love to answer them and hopefully, we've done a more complete job of sharing our enthusiasm for 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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