Ultra Petroleum Corp. Conference Call to Discuss Strategic ... · 10/21/2013 · OCTOBER 21, 2013...

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EDITED TRANSCRIPTUPL - Ultra Petroleum Corp. Conference Call to Discuss StrategicAcquisition

EVENT DATE/TIME: OCTOBER 21, 2013 / 2:00PM GMT

OVERVIEW:

UPL provided an update on Uinta Basin acquisition.

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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 & CEO

Mark Smith Ultra Petroleum Corp - SVP & CFO

Doug Selvius Ultra Petroleum Corp - VP, Exploration

Jason Gaines Ultra Petroleum Corp - Manager, Business Development

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

Bill Picquet Ultra Petroleum Corp - SVP, 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

Brian Singer Goldman Sachs - Analyst

Brian Corales Howard Weil Incorporated - Analyst

Ron Mills Johnson Rice & Company - Analyst

Noel Parks Ladenburg Thalmann & Company Inc. - Analyst

Joe Allman JPMorgan Chase & Co. - Analyst

Leo Mariani RBC Capital Markets - Analyst

Subash Chandra Jefferies & Company - Analyst

Marshall Carver Heikkinen Energy - Analyst

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

Robert Lee - Private Investor

John Nelson Citigroup - Analyst

Mark Hanson Morningstar - Analyst

David Howard ITG - Analyst

Prudash Bora Indiabulls - Analyst

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

Operator

Good day ladies and gentlemen, and welcome to the Ultra Petroleum conference call to discuss strategic acquisition. My name is Tracy, and I willbe your operator for today.

(Operator Instructions)

As a reminder, this call is being recorded for replay purposes. I would like to now turn the call over to Mr. Mike Watford, Chairman, President, andCEO. Please proceed, sir.

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

Thank you, Tracy. Good morning everyone. Welcome to our conference call announcing our Uinta Basin oil acquisition. With me today are mynormal cast of characters, Mark Smith, Senior Vice President, Chief Financial Officer; Bill Picquet, Senior Vice President, Operations; Brad Johnson,

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OCTOBER 21, 2013 / 2:00PM, UPL - Ultra Petroleum Corp. Conference Call to Discuss Strategic Acquisition



Vice President, Reservoir Engineering and Development; Doug Selvius, Vice President Exploration; and a new voice on the call, 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 uncertaintiesaffecting outcomes, many of which are beyond our control and are discussed in more details in the risk factors and forward-looking statementsection 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. Finally, wemay use terms like risk reserves or resource potential or other descriptions of volumes of resource or reserves that the SEC rules would prohibit usfrom including in SEC filings. Investors should review our reserve disclosures and our SEC filings, which are available on our website or on the SEC'swebsite.

Okay. Hope you all have had an opportunity to read the press release this morning that came out bright and early. It's an excellent summary of thehighlights of the transaction. The reason for our call this morning is to provide more details. We plan to do that in two ways. First, there's a, I believeit's a 13-page presentation slide deck which you can access by clicking on the right word or two in the press release or by going to our web page.We plan to walk through that, and then after completing that, we will open the call for some limited questions and answers.

So let's get started with the presentation. Those of you who have followed us for a number of years understand that historically we have not beenvery acquisitive. The challenge for us has been to find a strategic opportunity that fits us from a return, growth, and technical standpoint. We believetoday's Northeast Utah oil acquisition almost perfectly fits our strategy of profitable growth. It's very complementary to us on a number of differentlevels.

With that, let's just jump all the way to of our little presentation, slide deck, and talk about Ultra's new venture strategy for a moment. Theobjectives with our small but focused group was to identify the best geologic provinces and plays in North America, develop detailed in-houseknowledge base and familiarity, and then for us, identify points of entry that made sense. We wanted to focus on strategic, complementary fit. Wethink this acquisition does that exceptionally well. We want to prioritize high rate of return resource-type plays. We are and continue to be commodityagnostic, but we will note this is oil, and we are targeting plays that leverage Ultra's operational expertise, and we focus on returns, not merelycash flow growth, but the overall return impact on our portfolio.

For more nuts and bolts on the opportunity in front us on Page 4. Northeast Utah oil producing asset, current net production about 4,000 barrelsof oil a day. Net risk reserves, it's a very important number to us, is about 90 million barrels. Proved-like, or acquisition-based, economic reservesof 37 million barrels. Purchase price, about $650 million. Simple undiscounted acquisition return on investment is 4.3 times. We're going to financeit through debt at the subsidiary and parent level. Mark will talk about that in a minute.

It's an operating property with 100% working interest, 82% average net revenue interest, and 79% held by production. Very strong well economicsat current well costs, and we know we'll be able to drive those lower. A derisked acreage position with stacked pay potential. What I really like isthe asset is immediately self-funding in year one, and pays for itself in about five years. Ability to quickly ramp production, and importantly, veryimportant for us, it complements the Pinedale expertise. With that, I want to ask Mark to talk for a moment about the debt financing.

Mark Smith - Ultra Petroleum Corp - SVP & CFO

Thanks, Mike. As many of you know, we currently finance ourselves through a combination of bank debt and longer-dated senior notes on a paripassu basis at the operating Company level. That the operative covenants at this level are essentially a backward-looking debt to EBITDA covenantand a forward-looking PV-9 covenant. We'll finance the acquisition through borrowings under our bank facility and new senior debt at the parentlevel. The covenants at the operating subsidiary will stay the same. We expect the covenant at the parent level to be different. It will be an interestcoverage covenant, and we expect this to become the operative covenant going forward.

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Now, let me share with you how I view the financial aspects of this asset. First, as you heard from Mike, the property's well-defined. It's been largelyderisked. Second, the well's a relatively low cost, can be drilled quickly, have strong returns and pay-out in a short period of time. As a result, theproject's self-funding out of the gate. Third, with simply one rig in the field resulting in the capital investment program of roughly $68 million peryear, risk production is forecast to almost double from roughly 4,000 barrels per day currently to 8,000 barrels per day one year out. Finally, if onelooks at the PDP category at a bank price deck of 75 -- excuse me, $75 WTI flat, with the one rig program on a risk basis, PV-9's forecast to morethan double to $460 million at the end of the first year alone. Very strong.

I'll now turn it back to Mike to address the complementary and strategic nature of the asset.


Thanks, Mark. We're on to Page 5. What's very important for us is the complementary strategic assets here, how it blends together with what wehave. We look at that in three ways. Excellent well economics, it diversifies our cash flow and revenue stream, and it leverages our technical expertise.In terms of well economics, we have, first point there is greater than two of those, 100% IRRs at the strip price at current well costs, and we get,four, five pages back into the presentation you see that most of those returns are 500% and 600%. At $80 oil, even $75 oil, we have robust economics.So it clearly adds to the returns in our portfolio today.

Immediate increase in production cash flow through the PDP component. We believe we can quickly ramp production, and we're adding valuethrough a higher priced commodity. It's similar Pinedale tight sand geologic characteristics, that's key to our technical team. We think we canoptimize the asset value with technology and cost efficiencies. Pad drilling, we've done that for a decade. 2,000-foot gross integral with multistagefracs, and a regulatory environment competency with a mixture of federal, state, and fee leases and the oversight that goes with that.

The next slide is just a quick asset map. Starting on the right, or the east, part of the slide is Ultra's shale gas Marcellus position in North CentralPennsylvania, some 260,000 net acres. As we go west in Southwestern Wyoming, we have our Pinedale and Jonah field assets, tight gas, and thenjust a stone's throw to the south, 150 miles away in Northeast Utah, is the new oil opportunity in the Uinta Basin. The next slide goes to where weare and some geology. We're going to let Doug Selvius walk you through the next couple of slides.

Doug Selvius - Ultra Petroleum Corp - VP, Exploration

Thanks, Mike. Page 7, we're focused in now on the Northern part of the Uinta Basin. What we're showing here are the legacy fields in the area, andthen we put our Three Rivers project in context with those fields. It shows the queue production, we'll just start off at the northwest. You seeAltamont and Bluebell field, it's 312 million barrels and over 0.5 trillion cubic feet of gas. The main operators there are Devon, El Paso, Bill Barrett.

Just to the west of us is Monument Butte field, 72 million barrels and a 0.25 Tcf of gas. That is operated primarily by Newfield with Berry has a smalloperation off to the west side. And then the other large field to the southeast of us is Natural Butte's, Wonsits-Red Wash. That's a gas field, producingfrom a different section than we'll be targeting, a different petroleum system. It's made 2.3 Tcf and 18 million barrels of oil, and you see how weare located nicely right between all three of these very large assets. But the point we want to make is that Three Rivers is unique. We're not really-- we're different from all three of these.

And let's go to Slide 8 and talk about that a little bit more. Slide 8 is a table that compares just a couple of key metrics among all of these largeassets and Three Rivers. First starting on the left, you see Three Rivers. We're targeting the Lower Green River formation. Our wells are 7,000 feet.We drill them, complete them for a cost of $1.5 million. And our target EURs, depending on the formation we're focused on, are 160,000 to 380,000barrels of oil. Now let's compare that to the other, to the legacy assets.

Altamont, Bluebell, this is information from investor presentations. Bill Barrett there advertises that their typical well cost is 13,000 feet -- typicalwell depth is 13,000 feet, excuse me, and they do that, drill and complete them for a cost of $3.6 million. They're targeting EURs of 300,000 barrelsper well. They're deeper, more expensive, and their EURs are in the range of ours. Monument Butte, just off to the west, Newfield advertises they'redrilling 5,000 feet vertical wells for the Green River formation, they're drilling them for $1.1 million, and they're target EUR is 100,000 barrels.

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And then finally, off to the southeast, which is really again a different animal, Natural Butte's field, QEP is drilling 10,000-foot wells for theMesaverde/Wasatch section, which is near the two formations directly below the Green River. So they're going for a slightly deeper cycle of sands.They're spending $2.3 million per well and targeting EURs of 2.3 Bcf. So if you compare Three Rivers now to these three legacy assets, it's clear we'requite different than them from a cost and an EUR standpoint.

Let's go to the next slide, and there's a little bit more information on that, Slide 9. To drive this point home, I've got here a stratigraphic cross-sectionthat just ties us to Leland Bench and Monument Butte. You can see where the cross-section runs on that inset there in the upper right. There's threelog sections here. Our area, Three Rivers, is on the right, Leland Bench is in the middle and Monument Butte on the left-hand side. Sands are coloredyellow here. That's what, of course, we're targeting. Shales are colored brown. We did that just to provide a visual representation or comparison ofthese three areas. You're looking at from top to bottom about 3,000 feet of interval. Again, as Mike said, it's probably the bottom 2,000 to 2,300feet of this interval that's of most interest to us.

But let's focus in on the lower Green River that you see --you can see where that interval is on the left side of the cross-section there, it's highlighted.And then in the green are two members of the lower Green River, the Douglas Creek and the Travis. If you look at our Three Rivers log, in thatinterval you can see there's quite a bit of yellow, and it's blocked up. We have 373 feet of sand in the Douglas Creek and Travis intervals. If youcompare that now to the Leland Bench just to the west of us, they've only got 120 feet of sand. And if you go over to central Monument Butte, aNewfield well there, they have almost as much sand as we do, there's a big difference in that, that sand is spread across a much larger interval. Andit's really an amalgamation of a lot of thin sands that gives them their 338 feet.

If you look over at us in Three Rivers, it's a thinner interval but it's a thick stacked sequence of blocked-up sand that you see highlighted in yellowthere. That's what distinguishes us from these other areas. That's what's giving us the good EURs. One last thing I would point out on this slide, ifI had been able to include a Pinedale log section on here, it would be strikingly similar. Mike has alluded to the fact that this is very much ouroperational expertise, and it is. Pinedale is a stacked-up sequence of sands, just like this is. We've got over two dozen sands that we will be completingin these intervals, and that's very similar to what we see in Pinedale. Plain, tight stacked sands is something we're very good at. This lends itself tothat very well.

So now I'll turn it to Jason, just to talk a little bit more about valuations.

Jason Gaines - Ultra Petroleum Corp - Manager, Business Development

Sure. Thank you, Doug. I'll cover a few of the highlights of the compelling resource value of this opportunity. This asset currently has 9.9 millionbarrels of oil, of proved net reserves associated with 43 wells. The 40-acre offset locations account for another 27.5 million barrels of oil of netreserves. For a total of 37.4 million barrels and the discounted PV-10 of $735 million at strip pricing. Future additional 40- and 20-acre locationsadd an additional 53.2 million barrels of net risked resource for a total of 90.6 million barrels of oil, and a discounted PV-10 of over $1.1 billion. Thisresource summary does not include any upside for secondary or tertiary recovery or alternate deeper stacked pay horizons, for that matter. Thesehighlights explain our enthusiasm for this opportunity and illustrate the value of it.

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


Thanks, Jason. The next slide, Slide 11 I believe, is entitled Profitable Well Economics. We'll go to the bottom half of the slide first where we'veshown different EURs, different expectations of reserve sizes per well, which is our normal style we do with the existing assets. And we have a rangeof from 380,000 barrels to 100,000 barrels. We have the depth, well cost, $1.5 million in most cases, the internal rate of returns, we've done a strippricing. We also have this done at $80 oil, $75 oil, $100 oil, if you have any interest. But we have returns of 500% to 600% on the high side. On thevery lowest side is 60%. We have F&D costs of $5 or $6 a barrel for the bigger reserve areas and $12 to $15 for the lesser so. We have payout inmonths, not years. And we have for us, which is important, a long reserve life.

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Now let's go to the top part of the slide where we're trying to show some similar information but at different prices, different oil prices. You seethe returns again are anywhere from 600% at strip, to 380%, 345% at $80 oil, well above that at $100 a barrel on a single well returns. The bottomportion of the upper half of the slide, though, is the one that I find very interesting. That's where we have burdened the future development wells,the future development locations with the acquisition cost. So that we're truly looking at apples-to-apples comparison of returns on our futureinvested capital, picking up our historical cost of buying the property. That's where strip prices, we're at 80%, 85% on the low end, 60% IRRs. At$80 oil we're still at 50% and 60% IRRs. That's part of the compelling nature of the economics of this opportunity.

The Page 11 is the self-funding development slide, which shows -- Page 12, I'm sorry, which shows our future planned CapEx run rate with one rigin the field contrasted with cash flows at strip oil prices. You see in 2014 where we're looking at $68 million, $70 million of capital against $160million-plus of cash flow, and you see how we have consistent capital for about a decade, and we have cash flows well in excess of that capital fora couple of decades. What I find striking is at strip prices, as this is depicted, the asset fully funds its development capital on an annual basis, andthen by year-end 2018 fully has paid for the $650 million acquisition price, and we have decades of free cash going forward.

I think Jason talked about a 90 million barrels of reserve with a PV-10 of $1.1 billion, October 1 of 2013. I'd like to note that at the end of 2018 on agoing-forward basis the PV-10 at that point in time is still $1.1 billion. So I think it is fantastic that it pays for itself and we have $1.1 billion of PV-10in five years. Page 13 shows near-term production growth. We can quickly ramp production, and we think we can double over next 12 to 14 monthsand have a four-year compound annual growth rate from this asset of about 50%.

With that, I would like to ask the operator, Tracy, to open up the line for Q&A.

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

Operator

(Operator Instructions)

Your first question comes from the line of Brian Singer from Goldman Sachs. Go you ahead, sir. You're now live.

Brian Singer - Goldman Sachs - Analyst

Thank you. Good morning.


Good morning, Brian.


Are your EURs that you're assuming, your completion techniques and the proved reserves, in line with what was being done by the previousoperator? Or could you mention if there are differences how you are planning the development any differently, relative to what was being donebefore.


I'll let Brad or Jason take a stab at that.

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Sure. I think the general assumption is that we will achieve what they were achieving with the methods that they had in place. I think they had hada lot of key learnings that we'll continue to take forward and improve those as we can.

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

(Multiple speakers) I'm sorry. This is Brad. I'll add to that, that the EURs we're using here are risks, and they're based upon existing producing wells.So there's no aspirational EUR built into this model.


No, if anything, it's a conservative EUR.


Great. Thanks. And then as my follow-up, should we view this as a one-off niche opportunity where you've identified a high rate of return area thathappened to be for sale, or should we view this as a broader commitment to the Uinta Basin or Uinta Basin oil where we could see Ultra do additionalacquisitions of similar magnitude?


I think you should view it as if we have more opportunities that look like this, regardless of where the basin is, or whether it's oil or gas, If it has thissort of return base to it, you'll see us do many of these. I'd love to do these thing all day long. I don't care Uinta Basin or someplace else.


Great. Thank you.

Operator

Thank you. Your next question from Brian Corales from Howard Weil. Go ahead, sir.

Brian Corales - Howard Weil Incorporated - Analyst

Can you talk about the takeaway options, or is this an asset that, I mean, it looks like you all are running one rig for the foreseeable future. Do youhave the ability to accelerate with takeaway?


From a takeaway capacity, Brian, we currently have contracts in place up to 5,000 barrels a day. It's a mix of truck and rail, some to Salt Lake City,rail throughout most of the US. Rail is expandable to total capacity of 13,000 barrels a day, April 2014.

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We have plenty of room to ramp it up. We want to start with one rig so we get comfortable with the asset. We learn more about it before weaccelerate.


Okay. And then can you just give a rough margin per barrel? I know, I'm assuming this is the [wax] of your crude. Can you talk about what the opcosts are, and kind of what your net backs are?


We're using about a 20% differential. So let's just say $100 oil, call it $20. We start with $80, and Jason, you're going to have to help me with thesome of what the operating costs are.


Sure. I would say that when you start looking at severance and add valorem in this area, you're on the order of 8%, 8% to 9%. And then op costson a per well basis are actually very, very reasonable, significantly lower than you see in other basins, perhaps like you see up in the Williston. Ithink you'll be looking at something on the order of $10,000 per well per month. If you look at that wells coming online at a couple hundred barrels,that gives you a decent idea of kind of where we'll shake out.


We're talking about $6.50 of taxes off the $80 and about $3 to $4 of op costs?


Correct, yep.


So we're talking about $10 a barrel off the $80, reducing it to $70, Brian.


That's helpful. That's helpful. Perfect. Thanks, guys.


Thank you.

Operator

Your next question, from the line of Ron Mills from Johnson Rice. Go ahead.

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Ron Mills - Johnson Rice & Company - Analyst

Thanks. Question, just on the -- a follow-up on Brian's prior question. On the op costs, Jason, is that $10,000 per well, is that fixed cost? Does thatinclude the variable cost? And the reason I'm asking is the second part of that question is, what's kind of a type curve if you look at your variousEURs on Slide 11 in terms of what can we expect in terms of IP rates and decline curves, et cetera?


Sure. The cost that I mentioned there would be an all-in cost. It would be all-inclusive. Maybe just to speak to the type curves for a moment is, theway that the wells are produced on pump, they are rate-limited early in life. And so we see that being something of value, and also helps explainwhy we can ramp production so quickly in this area with rate-limited production for up to six or eight months on some of the wells.


And Mike, it sounds like you said you would do acquisitions like this all day long. Within this Uinta Basin alone, this sounds like this may have beenan auction process. Is there expandability in this particular basin in terms of ability to consolidate incremental, private, and more mom-and-popoperators? What does the landscape of this market look like?


Bill, you want to tackle that?

Bill Picquet - Ultra Petroleum Corp - SVP, Operations

Well, we see some opportunities to expand. We believe that the quality of this asset speaks for itself, but we will be gaining expertise in the basinand we'll be evaluating those other opportunities. As Mike mentioned, we're looking for quality as far as value's concerned. So we'll be very carefulto identify opportunities that we think match up well with this opportunity. But we do see some other growth opportunities in the basin.


Okay. Perfect. Let me jump back in queue. Thanks.


Thanks, Ron.

Operator

Thank you. Your next question from Noel Parks from Ladenburg Thalmann. Go ahead, please.

Noel Parks - Ladenburg Thalmann & Company Inc. - Analyst

Good morning.

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Good morning.


Talk a little bit more about the past activity in the field that you're buying. The prior owners, were they actively developing it for a number of years,or would you consider it more sort of relatively neglected? I don't know if they were capital-constrained.


It's relatively new. It's relatively new development. They've been active drilling for over a year in the field, and as we mentioned, you drill themrelatively fast. So we have quite a bit of production history on the wells that have been producing.


Okay. Great. With the transaction, are you bringing onboard any people from the old owner, or are you taking it over entirely on your side?


The field people will be an opportunity to bring onboard. We're well-staffed as far as the opportunity's concerned, as far as capabilities on staff inUltra from a technical perspective.


Thanks. That's it from me.

Operator

Thank you. Your next question from Joe Allman from JPMorgan. Go ahead, you're live.

Joe Allman - JPMorgan Chase & Co. - Analyst

Thank you. Good morning, everybody.


Good morning.


For the acquisition, so how much acreage are we talking about that you're buying? And then how spread out are those 43 proved developed wellsacross that acreage?

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We've got 8200 acres is what we've acquired, and it's been well evaluated and derisked by the wells that have been referenced of 38 wells. It's beendrilled across the entire position.


That's helpful. In terms of CapEx, I think Mike, in the past you said that if we hit $4 gas then you might spend, I think the number is $675 million, ifI'm not mistaken. The strip for next year is close to $4. So what kind of -- are you looking at ramping up the legacy assets? And in your slides we seehow much you're spending here, about $70 million. Could you just give us a sense of how much you plan to spend, and how that affects whatyou're thinking about in terms of raising debt and whatnot?


Well, make sure we all understand, we're not providing 2014 capital program update at this point in time. But having said that, now let me attemptto halfway answer your question. We have plan in effect for 2014, at least a thought, that we would run anywhere between three to four rigs,operated rigs in Wyoming at Pinedale, and that we would try to cut back to next to zero in Marcellus, which is almost happening. And then wehave a little outside operated, I guess, with Queststar in Pinedale. We're going to look at this now.

We have the flexibility with the rig fleet in Wyoming to go to two rigs over the course of the year if we want to, or stay at -- or three or four. Wehaven't made the final decisions there yet. We've got to get this deal closed. It's not in the purchase and sales, it's not closed yet. We're anticipatingsometime in December for that to occur. We want to be return-driven.

We have a slide which is not part of what we passed to you but it's part of our board presentation which shows, for example a 5B Pinedale well at450 gas with a 55% IRR and contrasts with the opportunities we have here at $75 a barrel oil, which is the bank price deck, with returns burdenedwith the acquisition price, acquisition cost of 60%, 55%, 60%, at strip prices it's 90%. So we're going to carefully watch oil prices, may do some oilhedging as we move forward, and as we get this thing closed we'll have a better idea in terms of the gas side. We have the flexibility now, with theoriginal plans, we weren't going to spend all of our cash flow in 2014. We were still going to under-invest during this sort of low cycle in thecommodity, in the natural gas side. We've yet to firmly decide what we're going to do, but clearly we're going to pick up $160 million of additionalEBITDA from this one asset. It's important to us. We're going to have the ability to fund the full program that we originally thought about doing in2014.


Great. That's all very helpful. Thank you.

Operator

Thank you. Your next question from Leo Mariani from RBC. Go ahead, please.

Leo Mariani - RBC Capital Markets - Analyst

Hey, guys. Can you maybe talk to these differences in EURs that you use, and I guess your range is pretty wide at 100 to 360. Can you give us somemore color around that, and is there an average number you guys might have on the 38 wells? And it looks like this field is just oil. Is there anyassociated gas at all? Can you talk to that?

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I'll let you guys, Brad or Jason, answer it. But I'm sorry that we can't just give you an average reserve number across the whole field. (Laughter). Itdoesn't work that way.


Yes, I would say that the range is pretty easy to explain. You have the upper and lower Green River section. The lower Green River is more prolificthan the upper. We recognize that in the ranges. Then even across the field, we recognize, as Doug mentioned, we've done -- with the wells thathave been drilled there, the field has been well delineated, and we recognize that there are better areas in portions of the field which explain thehigh side of that, and again the low side I would say is easily explained in looking at the upper Green River section in contrast to the lower.


Okay. Any information on gas? Is there no gas associated? I guess a lot of the other fields around you guys have some gas. You guys don't haveany there or --?


Sure, so quick answer there is right now the gas is being used in the field. There is a gas gathering system that's been installed. It's not tied into asales point today. We expect that to be done by year end, at which time we'll start selling the gas that's not utilized in operations. It's not a significantstream, specifically when you look at the value of the asset today.


There's gas tied in by the end of this year?


Yes, sir.


And you say not significant. Is there a percentage you can put on that?


Not currently.


Okay. Thanks.

Operator

Thank you. Your next question from Subash Chandra from Jeffries. Go ahead, sir.

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Subash Chandra - Jefferies & Company - Analyst

Just curious, the $1.5 million, what was -- is that consistent with the prior operator and is that a pretty good mean number to use, or was there sortof a wide range of well costs for the prior operator?


It's consistent with the other operator. They were experiencing that cost performance in the field today with the rig that we will be continuing onwith. We do see some opportunities, once we particularly get to more pad drilling. That's cost associated with essentially drilling one well perlocation and moving with every well. So as we get further into the development, we think we'll see some efficiency improvements. You've seenwhat we've done in Pinedale on a percentage basis. The opportunity to improve here is probably percentage-wise not what Pinedale was, butwe're starting from a much better point, and this is a great opportunity for us to acquire optimization skills.


And so the $70 million-ish well cost, I'm sorry, $70 million CapEx program, pretty safe to just divide by $1.5 million and get the annual well count?


Yes.


If I could, just a final one for me. Might be a little early to think about 2013 reserves, but do you think there's still some sensitivity on the revisionside to gas prices after being -- after last year seemed to have washed out some of that, or do you feel pretty -- you feel like 2012 took into accountthe five-year drilling window and all that kind of stuff?


2012 was devastating in terms of negative reserve revisions for natural gas companies, with, what, we'd have, a $2.62 average price for the year?Something like that.


Yes.


So no, we're well above that average in 2013. The number starts with a $3. So our issue, quite frankly, is we don't need to book any reserves fromthis oil acquisition in order to have ridiculously low F&D costs for 2013 because of all the gas reserves that come back on the book. So no, we haveno issues of negative reserves on the natural gas side.

Remember, we had five Ts a year in 2011. Those five Ts haven't gone anywhere. I think we have a slide in the current deck presentation that talksabout if we just restored capital and volumes from those PUDs back in year 2011 we'd have 5.25 Ts a year in 2012. So we'll have the ability to bookmost of those, if not all of those, but most of those we want to. So we had a little over 3Ts at the end of the year, I guess, 2012.

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We can easily add a T against whatever our capital ends up being for the year and have ultra-low F&D costs. That's why we're not -- there's 9.9,almost 10 million barrels of PDPs that Jason mentioned. We've got to book that. We don't have a choice. But all the remainder of the PUD locations,which gets you up closer to 37 million barrels, we'll just look at that and see if we really want to book any of it.


Thank you.

Operator

Thank you. Your next question from Marshall Carver from Heikkinen Energy. Go ahead, please.

Marshall Carver - Heikkinen Energy - Analyst

Yes. In terms of the wide range of well sizes heading forward, would you all be focusing on the lower Green River the next few years to get to drillsome of the bigger wells, or is it going to be a mix of lower and upper, and we should target somewhere in the middle for expected recoveries onaverage over the next few years?


That's a Brad or Jason.


Yes, I think the easy answer there is yes, that when you look at the opportunity set, we will high grade the opportunity set. There will be someadditional delineation work that occurs naturally, but we'll high grade to the best areas, and specifically the best horizons as well.


Okay. And with regards to the spacing, it looks like the average EURs for the 20-acre locations is less than half what you're showing for the 40-acrelocations. Have there been down-spacing tests to make you think that, or what's the history been with down-spacing? Have there been lots of40-acre spacing tests to give you confidence around that number?


I think the numbers are probably not quite as easy to look at and break that out. I think that what you're seeing there is that there is -- we do expectthere to be a degradation in the 20-acre performance. At least we've risked it that way. There have been a handful of pilots that do not show thatnecessarily yet. But we have taken into account some degradation, and then also when you start looking at the upper Green River 20-acre locations,again, that discrepancy, you'll see that weigh in on the 20s.


And I'll add to that, regarding down-spacing. We looked at some analog fields nearby, Monument Butte for example, where they're down to 20s,pursuing 10s, and we have a lot of experience on assessing down-spacing potential and risking that properly. And we've done that so here. So youwill see a risk haircut, if you will, as we down-space and the numbers we share on a risk basis.

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Okay. I'll probably hop back in the queue. Thank you very much.

Operator

Thank you. Your next question comes from Matt Portillo from TPH. Please proceed.

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

Good morning, guys.


Good morning.


Just a quick question in regards to, I guess, a follow-up question. Could you give us a little bit of color as to how we should think about initial IPrates here on a 30-day basis, or kind of initial rates? And then just roughly how we should think about the PDP decline, or the first-year decline onthese assets?


I'll try to field this one. I think it's a little bit difficult to answer without describing it in a lot of detail. But what we do see is that in the lower GreenRiver we see wells that come on, clean-up over the first month, and are flat for two to six or seven months. So it's difficult to provide an initial declinerate. What I will say is with that constrained rate on pump, what you see is the initial decline after you actually see a decline, is much shallower thanyou see in many of your gas-type fields. So I don't know if that was helpful or not.


I might add to that as well. If you look at Slide 4, we talk about net production and well count, and you look at 4,000 barrels net, that's really 5,000barrels gross coming from 38 wells. And you're talking about 130 barrels a day on average among the producing wells currently. Some of thosewells have been online for several months. That will give you a feel for the early rate performance, and as Jason mentioned earlier, we see flatproduction for some time. And then at some point decline sets in, and I think the key thing for us, and we look at the wells and look at the economics,the returns and the payout are so quick on these wells that the value of this asset is based upon these early time profiles that are flat and very goodrates, given the investment per well.


Thank you.

Operator

Thank you. Next question from Robert Lee from Encodia. Go you ahead.

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Robert Lee - - Private Investor

Yes. Hello.


Good morning.


Good morning. I'm a retail investor, but I have a significant position. Pardon the naivete of this question. The concept of zero economic profits, itseems like the IRR of this is so stratospheric that it's hard to believe. You don't get an IRR like this without significant risk somewhere. What's thestory here? Why does somebody sell an asset like this that returns this kind of -- that has this kind of return on investment?


Because they've made a very hefty profit on their basis in it and their early development, and they were interested in selling it and taking theirprofit and going to the house.


But why so low? Would you have been interested in this if it had been 25% or 30% more expensive?


We're not going to talk about that.


Okay. All right. In any event, it's thrilling to wake up one morning and see this. So thank you.


Okay. Thank you.

Operator

Thank you. Your next question from John Nelson from Citigroup. Go ahead, please.

John Nelson - Citigroup - Analyst

Congratulations on the acquisition. Just curious if you guys see horizontal development potential across the acreage, (technical difficulties) plansto potentially test that?

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This is Doug. I'll answer that one. There is some horizontal work being done in the area off to the west in Monument and Butte, and also in the verysouthern and southwesterly parts of Altamont Bluebell. It is happening in the area. We see potential opportunity there, but right now we're justreally focused on getting the vertical development kicked off and successful and up and running. That's something we will look at down the road.It could happen. But as I pointed out on Slide 9, our geology is a little bit different as well. It's just something we've got to assess going forwardafter we get the vertical play going.


Fair enough. Then just a question on the net-backs that were discussed earlier. Some of your peers talk about the differential being closer to about16%. Just wondering, the 20% number you guys threw out there, is that conservatism, or would that be sort of the incremental rail costs or anycolor you could provide there?


I think it's a combination of both. We have additional cost associated with the railing, but we also in our -- an abundance of caution, our economics,we risk the PDP reserves about 15%. We risk the developmental wedge by 25%, what we could have done. We're trying to put some additionalrisking in the discount associated with the oil or transportation cost so we are very comfortable with the returns we expect.


That's all I had. Thanks.


Thank you.

Operator

Your next question from Mark Hanson from Morningstar. Please proceed.

Mark Hanson - Morningstar - Analyst

Good morning, guys. Congrats on the announcement here. Can you provide us some more info on what the balance sheet might look like oncethe acquisition is factored in? Specifically debt-to-EBITDA, if you can, debt-to-PV9, and then the interest coverage ratios?


I'll tell you what, why don't we get back to you on that?

Mark Hanson - Morningstar - Analyst

Sure. Thank you, guys. Congrats.

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Operator

Thank you. Your next question from David Howard from ITG. Please proceed.

David Howard - ITG - Analyst

Good morning, gentlemen.


Good morning.


My question is around the Wasatch. Just wondering, is that a zone that you guys have the rights to, and do you see any prospectivity into it?


Yes, this is Doug. We do have the rights to the Wasatch. It has already been tested productive in some wells on our leasehold, and it definitelyproduces on leaseholds surrounding us. That's true for both the Wasatch and for the Mesaverde formation that's slightly deeper. So we seeperspective. We'll be evaluating that as we go forward and right now do we -- we don't have any plans for it. We're going to be focusing on thelower Green River, but we do see upside potential in both the Wasatch and the Mesaverde formation.


Thank you. And then when you talk about the lower Green River and focusing on it, do you co-mingle with the upper Green River, or is an upperGreen River a separate well?


Those are separate wells.


Any reason why you can't co-mingle? Is it just an engineering thing, or is it a regulatory thing or --?


You could co-mingle, but from a production perspective it's not practical in this case.


Thank you.

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Operator

Thank you. Your next question from [Prudash Bora] from Indiabulls. Go ahead.

Prudash Bora - Indiabulls - Analyst

Hi. Good morning. I want to understand the infrastructure costs when you're ramping up the production from 4,000 to 8,000. What sort ofinfrastructure facility do you require to separate those (inaudible)?


You want to handle that, Jason, the midstream costs?


Sure. Right now the gas gathering system is largely constructed, under construction right now, being tied into a sales point. Because they're, again,we talked a little about the value of the gas there. It's an associated stream. It doesn't take a large infrastructure expansion to handle that gas stream.On the oil side, the oil could be handled at individual well locations. That's how the lion's share of the oil will be handled. So there's not a significantadditional future infrastructure cost that we envision.


Okay. And second question is, what sort of tax costs you're considering for next five year, and what are the transportation costs? I assume thenetback which are calculated for the revenue item is on the cost of the [back stream] oil, but have you included the transportation cost?


Yes, the discount, the 20% discount we've talked about includes transportation costs.


Okay. And what sort of tax rate for next five years, what would be the tax rate, what sort of income tax we'll be paying on this property for next fiveyears?


We shouldn't be paying any income tax.


No taxes?


No taxes. We just pay a severance tax to the state, but no income taxes because of the write-offs we had last year with the low gas prices.

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Right. Okay. Thank you.

Operator

Thank you. Your next question from Ron Mills from Johnson Rice. Please proceed.


My horizontal question was asked. Mark for you, you talk about doing some of the debt at the parent level and some of the sublevel. What are theprimary differences there for that level of distinction? There's obviously a reason, right?


We currently finance at the operating subsidiary level, Ron, and so you can kind of envision a fence around the operating subsidiary and theapplication of those covenants. When we finance at the parent level, it's above that. So then the covenants at the parent level become operative.


Okay. From a timing standpoint, sometime in December I'm assuming you will have the debt in place concurrent with that expected closing?


Yes.


Thinking about early or later in the month?


We've got some due diligence to do. It's kind of hard to give a date on that one.


Perfect. Okay. Thank you.

Operator

Thank you. Next question from Noel Parks from Ladenburg Thalmann. Please proceed.

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Just a couple other things. Just looking at the risk profile of these properties, and it's essentially an exploitation play, development exploitation itseems to me. This really couldn't be more different than your early marshlands play in Appalachia or the Niobrara, for very early stage at the timeyou got into those. So I'm just curious, how long have you had had this property on your list of possibles, and could you just talk a little bit abouthow your new business process got you to these?


I'll field that one.


All right.


I was just going to talk about new ventures. As Mike mentioned early in the discussion, what we've done is a broad look as far as basins are concerned,and we're developing expertise in opportunities that fit our capability set and also have high value, and this one fit that to a T. And from time totime we'll hopefully find more of these opportunities, but we'll also be looking for opportunities to develop greenfield exploration plays.


Just my question on how long you've been pursuing it, is this a relatively recent opportunity that arose, or something you've sort of had an eye onfor a long time?


Let's stay away from that one.


Okay. Fair enough. And then just my last one. Sorry if you mentioned this already. Do you have any hedge plans, hedging plans for the oil? I'mtrying to remember if in your old China oil days if you were hedgers of the commodity then or not.


I'm trying to remember what the -- I don't think we hedged any Chinese oil before, no. Currently have about what, a little less than 4,000 barrels aday of condensate production that originates in the Wyoming asset. We don't hedge it. It's not a big enough piece of the mix to sort of do thatwith, I think. Given the economics around this asset and the sunk costs going into it, the plus or minus $650 million, we're going to give someserious consideration to hedging either it or our condensate production in Wyoming. We don't have any hedges in place now but we're going tothink about it.


Great. That's it from me.

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Thank you.

Operator

Thank you. I would now like to turn the call over to Mike Watford for the closing remarks.


Thank you all for listening to us and asking the questions today. We appreciate your participation. Should you have additional questions, pleasecontact the Investor Relations group, either Ms. Whitley or Ms. Danvers. And we hope you have a very good day. Thank you very much.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.

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Ultra Petroleum Corp. Conference Call to Discuss Strategic ... · 10/21/2013 · OCTOBER 21, 2013...

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