Ultra Petroleum Management Discusses Q4 2012 Results - Earnings Call Transcript

Feb.15.13 | About: Ultra Petroleum (UPLMQ)

Ultra Petroleum (UPL) Q4 2012 Earnings Call February 15, 2013 11:00 AM ET

Executives

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

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

Douglas B. Selvius - Former Senior Vice President - Exploration

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

William R. Picquet - Senior Vice President of Operations

Analysts

David R. Tameron - Wells Fargo Securities, LLC, Research Division

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Andre Benjamin - Goldman Sachs Group Inc., Research Division

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

Mark P. Hanson - Morningstar Inc., Research Division

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

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

Michael Kelly - Global Hunter Securities, LLC, Research Division

Raymond J. Deacon - Brean Capital LLC, Research Division

Robert L. Christensen - The Buckingham Research Group Incorporated

Subash Chandra - Jefferies & Company, Inc., Research Division

Harris Arch

Matthew Portillo

Operator

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2012 Ultra Petroleum Corp. Earnings Conference Call. My name is Lacey, and I'll be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Mike Watford, Chairman, President and CEO. Please proceed, sir.

Michael D. Watford

Thank you. Good morning, ladies and gentlemen. Welcome to Ultra Petroleum's 2012 Year-End Earnings Conference Call. With me today are Mark Smith, Senior Vice President and Chief Financial Officer; Bill Picquet, Senior Vice President, Operations; Brad Johnson, Vice President, Reservoir Engineering and Development; and Doug Selvius, Vice President, Exploration.

This call will contain certain forward-looking statements that involve risk factors and uncertainties detailed in our SEC filings. All statements other than statements of historical facts included in this call are forward-looking statements. Also, this call may contain certain non-GAAP financial measures. Reconciliation and calculation schedules for the non-GAAP financial measures can be found in our 10-K and other filings with the SEC available on our website.

The SEC permits oil and gas companies in their filings to disclose proved reserves, probable reserves and possible reserves. References in this call to 3P reserves include estimates from each category of reserve are forward-looking statements. Once again, investors can find the disclosure in our 10-K and other filings with the SEC available on our website.

2012, what a year. We're glad it's over, a tumultuous year, one where we sailed through some stormy seas to eventually find ourselves in calmer water. So let's recap 2012. In response to collapsing natural gas prices, we reduce our capital budget from the $1.5 billion in 2011 to initially $925 million in 2012, and then reduced it further targeting $800 million and ending the year at $835 million. Netting this against an asset sale leaves us with a net CapEx of $611 million. We wanted to be net cash flow positive for the year, and we were.

On the production side, we established a new corporate all-time annual production record of 257 Bcfe, which illustrates that a 50% reduction in capital and rig count doesn't immediately impact production. There's a lag effect, which we are just now experiencing, as is the rest of our industry. Natural gas production is declining. This time last year, we had a monthly production rate of about 23 Bs a month; now in the first quarter of 2013, we're down to something over 19 Bs a month.

Financially, we reported $713.1 million of operating cash flow in 2012 or $4.67 per diluted share, which in comparison to our net capital investments of $610.9 million, we generated over $100 million of free cash flow. Our adjusted net income for 2012 was $328.6 million or $2.15 per diluted share. We hedged 184 Bcfe or over 70% of our 2012 annual production and achieved a realized price, including hedges of $4.01 per Mcf for the year. Our realized hedging gains contribute $1.99 per diluted share cash flow. Without the effects of our hedges, our average realized price was $2.79 per Mcf for the year.

Due to the lower natural gas prices, we incurred an additional ceiling test write-down in the fourth quarter of $496.5 million for a total of $3 billion in ceiling test impairment charges for the year. These noncash charges say little about the long-term value of our assets, but they wreak havoc on our 2012 financial statements.

We have some similarly unique issues with our 2012 proved reserves -- proved reserve reporting that speaks little to the long-term value of our natural gas resource. I'd like to ask Brad Johnson to provide the details.

C. Bradley Johnson

Thanks, Mike. Ultra recorded total proved reserves of 3.1 trillion cubic feet equivalent, or Tcfe, as of December 31, 2012. As a result of lower gas prices and a reduced capital investment plan, these reserves are down by 38% from year-end 2011.

First, I would like to discuss the low gas price used for our proved reserves determination. In accordance with SEC rules for calculating price, Ultra's proved reserves were estimated using a relative [ph] price of $2.63 per Mcf. Compared to year-end 2011, the gas price was down 35% and at levels where some of our undeveloped locations in our portfolio are not economic using a PV-10 cutoff. As a result, the company's reported proved reserves are down year-over-year.

In addition to a lower gas price, the capital for proved undeveloped locations is significantly reduced. For 2012, the future development capital schedule for PUD reserves is $1.4 billion, a 66% reduction from a year ago. As with previous years, the company evaluates its inventory of proved locations to ensure they comply with SEC rules and the company's own development plans. With lower SEC pricing, the company's 5-year plan includes a smaller amount of PUD capital relative to last year.

This combined effect of 35% lower gas prices and 66% lower capital investment for PUDs has resulted in 2.3 Tcfe of previous PUDs being transferred from proved to probable. There has been no degradation in the quality or certainty of these resources, but they have been demoted to probable at year-end 2012 due to this lower pricing. And while $2.63 per Mcf is not the expectation for gas prices over a sustained period of time, it is the price that we are required by the SEC to use in determining the company's proved reserves.

In our news release from earlier this morning, we included the 2 economic sensitivity runs. The first sensitivity is simply an evaluation of our year-end '12 proved reserves that run at year-end '11 pricing of $4.04 per Mcf. This sensitivity has a huge impact on the PV-10 value, increasing it from $2.3 billion to $4.2 billion.

The second sensitivity had been an increase proved undeveloped capital to $4.1 billion, the amount from 2011. This second sensitivity increases reserves up toward 5 Tcfe with a value over $5.2 billion. We believe that this second sensitivity is a better representation of the value of our reserves. It utilizes a gas price that is more indicative of midcycle prices, and it includes a capital program that the company would execute with an improved gas price environment.

The company's 2P reserves, proved plus probable, totaled 11.2 Tcfe. The 2P reserves have a PV-10 value of $13.7 billion when using a $6 natural gas price. Using a $5 price, the PV-10 value is $9.9 billion. Of the 8 Tcfe of probable reserves, over half of these are economic at a $3.50 gas price, and nearly 2/3 of this low-risk resource is economic at $4 gas.

The company's 3P reserves, proved plus probable plus possible, totaled 17.1 Tcfe, with a PV-10 value of $18.9 billion at $6 natural gas price. Using a $5 price, the PV-10 value for 3P reserves is $13.3 billion. The company added over 1 Tcfe of 3P reserves in 2012. This increase is driven primarily by improved well performance in its horizontal Marcellus program. It is important to note that the company's 3P reserves do not yet include future Geneseo development. We expect to add this resource into 3P over the next few years. Now with 2P reserves essentially flat and with 3P reserves growing, the company's asset quality and resource value is affirmed. As gas prices improve, many of our low-risk economic locations will be reclassified to proved reserves.

In addition to the 2 economic sensitivities included in our press release, we have also posted on our website additional information about our 2012 reserves. My comments now finished, Mike is going to resume with some updates on operations.

Michael D. Watford

Thanks, Brad. Let me continue. We finalized the sale of our Pinedale liquids gathering system for $228 million during the fourth quarter. This represented a $158-million book gain on sale and will be recognized equally over the term of the lease.

We used the net proceeds of $224.3 million to reduce our outstanding borrowings under our senior credit facility. The LGS will continue to transport our water and condensate efficiently through the field, minimizing field emissions. As a result of the transaction, we will pay lease rental fee of approximately $20 million in 2013, which appears in the lease operating expense line item on our income statement.

On maintaining our low-cost structure, our 2012 all-in costs were $3 per Mcfe, including both cash and noncash, as well as field and corporate-level costs, all-in costs. On a stand-alone basis, our cash costs were $1.49 per Mcfe. Our cash flow breakeven is $1.35 per Mcfe. Our margins remain somehow healthy. The cash flow margin was 64% and our net income margin was 29%.

Let me summarize some operational highlights for the year. In Pinedale, we resumed completion operations in mid-November. Remember, we suspended operations until gas prices improved, placing 18 new operated wells online with strong average initial production rates of 10.9 million cubic feet per day. One particularly notable completion was an Ultra-operated well with a 17.3 million cubic feet per day initial production rate. The nearly doubling of natural gas prices from April to November affirmed our completion-delay decision. Our field operating efficiencies were not compromised despite suspending operations for nearly 7 months.

For the year, we placed 103 gross, 44 net wells on production. During 2012, we drilled 136 gross, 55 net wells in Pinedale. Drilling wells in less than 10 days is one of our key goals. In 2011, 12% of our operated wells reached total depth in 10 days or less. In 2012, we nearly tripled this percentage to 33%.

We continue to refine our processes and take advantage of opportunities to reduce costs. These efforts include renegotiating service contracts and employing pilot programs. Our target well cost in Wyoming is $4.4 million to drill and complete.

From a resource standpoint, the wells we drilled on the eastern flank of the Pinedale Anticline in 2012 validated our petrophysical oil and gas in place models. More importantly, our third-party reservoir engineering firm's resource estimates remain constant in spite of reduced natural gas prices. Across the Pinedale Anticline, we have identified 58.7 trillion cubic feet of resource, of which 65% or 38.2 trillion cubic feet is estimated to be recoverable over time. Ahead of us, net Ultra, we have an undrilled Wyoming inventory of 2,900 future net wells and $13.6 billion of future development capital.

Shifting to our Pennsylvania operations. Our Marcellus program continues to deliver strong results. We brought 19 gross wells, 5 net online during the fourth quarter, with an average initial production rate of 6.9 million cubic feet per day. For the 117 gross, 47 net wells we brought online for the year, the average initial production rate was also 6.9 million cubic feet per day. We are pleased with the very consistent performance these wells have demonstrated.

For the year, we drilled 68 gross, 28 net horizontal Marcellus wells, with 80% of the activity occurring in the front half of the year. We proceeded with our reduced pace of drilling activity through the fourth quarter, as we continued to decrease investments and preserve capital. We drilled only 5 gross, 3 net new horizontal wells in the fourth quarter, located in our joint venture area with Shell in Tioga County. In our Anadarko joint venture, we have not drilled a well since July, and there are no activity plans for 2013. While our partner, Shell, has been slower to respond, they are also unwinding activity in our joint venture area, and will be down to 1 active drilling rig in March through the balance of '13, 2013.

The 68 gross, 28 net wells drilled and 117 gross, 47 net wells placed online over the course of the year reduced our inventory of wells waiting for completion or pipeline connection by 49, 20 net or essentially in half. We exit the years with 50 gross wells, 27 net remaining in our backlog. Our expectation is to further reduce this inventory during 2013, with only 1 active rig in the play for most of the year.

We continue to be pleased by the results from our 3 Geneseo wells drilled early in 2012. While no new wells are drilled in the fourth quarter, to date, Ultra has participated in drilling 6 Geneseo horizontal wells, with 4 wells currently online and producing. Production data from these wells, in addition to extensive log, core and seismic data demonstrates a net Geneseo resource of 3.3 trillion cubic feet under Ultra's leasehold position. 2/3 of that resource is economic at today's prices.

We've identified 2,500 future net wells across our Marcellus acreage associated with $16.3 billion worth of future development costs. As Brad mentioned earlier, these estimates do not include Geneseo development opportunities. We made significant progress on reducing well costs through 2012 in our Marcellus acreage. In our Shell joint venture, well cost decreased from $7.8 million per well early in the year to approximately $7.2 million at year-end 2012. There is still significant room for improvement, but well costs are heading in the right direction.

Similarly, in our Anadarko joint venture, well costs decreased from $7.5 million per well in early 2012 to $6 million per well. Two key drivers of the cost reductions are increased stage spacing and target interval modifications.

In Colorado's DJ Basin, our results in the Niobrara have been disappointing. Although our core and log data indicate the presence of oil in the rocks, the petroleum system is immature, under-pressured and not commercial. This has been verified by completion of test results from both a vertical and a horizontal well. Ultra assembled 139,000 low-cost acres and deployed it over the past 2 years and has no significant lease expirations until 2014. We'll continue to monitor industry activity in the region but have no immediate plans for additional exploration in the area.

Our current new ventures effort is focused on identifying other plays that have the ability to impact our portfolio while leveraging our expertise and resource plays as a low-cost operator. We're evaluating those plays while actively working to identify points of entry through acquisition opportunities in 2013.

So going forward into 2013, we plan to continue with our capital discipline and invest where we have positive returns at today's commodity prices. In 2012, the size of our resource actually grew, and that's without giving credit to the Geneseo. We have the resource captive and we'll continue to focus on returns. In 2013, we again plan to have our cash flow exceed our capital expenditures. Our natural gas production will dip a bit, and we think that is the right answer in today's environment.

Our extended plan for 2014 through 2016: at market natural gas prices, as is growing production by 40%, cash flow by 120% and net income by 200%, while maintaining CapEx equal to or less than cash flow. We think this forecast is very conservative because we don't see natural gas prices remaining at current market levels.

2012 was a very difficult year. 2013 is a bit of a settling-out year, and then we begin moving forward in our next 10-year growth period with increasing returns. This concludes my prepared remarks. I would now like to open up the line for questions. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from the line of David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Mike, if you – or you just gave us '13, and of course, being an analyst, I'll ask you for '14. Can you give us any color on how things look as -- on the Pinedale? Marcellus, obviously, some of that's out of your control. But in the Pinedale, how things look as far as volumes headed into '14 based on this CapEx plan and the $415 million?

Michael D. Watford

Well, our plan is to basically keep the Wyoming production flat, and that's at that sort of 100 to 165 Bs a year level, and Brad can correct me as I'm just talking here. But we think for 2 -- that $250 million a year, we can keep Wyoming production flat for a long time. And given that we've got $16 billion of identified capital projects there, I think it was $16 billion, wasn't it, we can keep it flat for well past my lifetime. But no, right now, we're just at today's gas prices, that's what we're going to do with it. And in 2014, I mean we have a plan that takes us from 2013 through '16 where we resume the forward-curve gas prices. We're spending plus or minus cash flow every year and it has us dipping down in production in 2013, and then we start to grow again in 2014 moving forward. And in 2015, '16 numbers are impressive, both in terms of volumes and cash flow and whatnot. That sort of -- I think in 2014 through 2016, [indiscernible] gas price of about $4.24 -- $4.25 on average which is about $0.05 above where it was this morning when I walked in here so.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. No, that's helpful. And then if I think about just the financial snapshot, looks like you're okay on the debt to EBITDA. Can you confirm those covenants? Looks like 2.2 or whatever. Looks like you guys are fine on that front. But for 2013, should I think about cash flow -- CapEx side plus or minus equal to cash flow? Is that the right way of thinking about that? I'm just trying to make sure my model's teed up right.

Michael D. Watford

Right. I mean, our model suggests, and we're using $3.50 gas price for 2013, is that we have $100 million of spend, capital $415 million and we have cash flow about $515 million. So we have $100 million of free cash.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

$100 million of free cash flow for you, okay.

Operator

And our next question will come from the line of Joe Allman with JPMorgan.

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

Mike, in terms of the $1.4 billion of future development costs, could just give us how that's spread out over time, year 1, year 2, year 4, year 5?

C. Bradley Johnson

Yes, I can comment. This is Brad. That $1.4 billion FDC is related to the PUD capital. I think it's important to note that, that only represents about 1/3 of the capital that we have in our 5-year plan. And that's the result of PUD locations in our plan that got demoted out into probable due to low gas price. As Mike mentioned, we have a reduced capital program for 2013, with an expectation that will pick up in the out years. And that trend also is translated into the FDC capital among PUD locations out in the next 5 years.

Michael D. Watford

Most -- more of it is back-end loaded.

C. Bradley Johnson

Yes, it is a back -- very similar to how we have 5-year line for all locations among all categories.

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

Okay. So for example, like out of that $1.4 billion, like how much is in the reserve report for year 1 spending?

C. Bradley Johnson

I'll have to get back with you on that, Joe. I don't recall that specific number.

Michael D. Watford

It's not a big number, Joe, but we can get back to you with it.

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

Okay, great. And then in -- what was the percentage of PUDs at -- with the year-end '12 reserves? And then were the negative revisions, was it all PUDs or were there some PDP tails as well?

C. Bradley Johnson

Sure. The first question on percentage, as a result of the reduction in PUDs moving to probable, our current undeveloped percentage is 39% of 1P reserves. The previous year, we were at 60%. So we went from 60% to 40% as a result of the 2.3 Ts getting demoted. The second question on revisions, we'll be posting some details on our revisions in the K in a week or so. But the revisions are going to be about 2.5 Ts, and we talked about the 2.3 transfer from PUD to probable. 97% of our revisions are related to price and price alone.

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

Okay. Were there some PDP tails that went away as well?

C. Bradley Johnson

There are some PDP tails that do go away when you drop from $4 to $2.63. It's in the out years on these long-life reserves. They have no PD impact. But there are some portion of that.

Operator

And our next question comes from the line of Brian Corales with Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

Regarding the CapEx in the Marcellus, so that's 100% Shell-operated capital. Are they -- do they plan to drill, keep 1 rig active through the whole year?

C. Bradley Johnson

Yes. That's pretty much -- the $105 million is pretty much Shell with a little bit of capital spilling over in the Anadarko AMI as we're bringing wells online this -- in the first quarter. And that is a 1 rig program that starts -- well, let me be back up. They drop the 1 rig in March and then hold 1 rig through the rest of the year, as Mike stated earlier.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then in either partnership, is there any HBP issues or has that all been taken care of?

Douglas B. Selvius

Well, from a leasehold standpoint, we're really in pretty good shape. This is Doug. 56% of our leasehold is HBP. We've got 7% expirations this year, less next year. So we're really in good shape from a leasehold standpoint.

Operator

And our next question comes from the line of Andre Benjamin with Goldman Sachs.

Andre Benjamin - Goldman Sachs Group Inc., Research Division

As we look 3 or 5 years out since you do have a 5-year plan, I was wondering if you could shed any light on what you think the level of production and more -- the likely mix of production for the company would be? Do you think it'll still be closer to the 70-30 Pinedale, Marcellus or closer to, say, 50-50 and what would be the main driver of that?

Michael D. Watford

Well, when we build our models, we have more confidence in the outcome of the operated properties. So we preferentially build the models with showing more capital growth, more activity in those areas that we operate, which means that Wyoming, that may not come to pass exactly that way. But we show more growth in production from Wyoming than we do from Pennsylvania from our Lance as -- tight gas asset as opposed to the Marcellus asset. We also think that, that'll give us some pricing benefit too. Because if you look at pricing now, the Rockies prices are above Marcellus. And I think most folks see that continuing for a good number of years because Rockies production is declining. Clearly, it's declining, and the Marcellus is not. So on the other side -- so I think growth reduction in the Rockies, that'll just help us from a revenue standpoint, too.

Andre Benjamin - Goldman Sachs Group Inc., Research Division

And given you continue to add to the total resource of the company and the reserve life continues to grow, following the Pinedale midstream deal, would you ever consider selling any of the, say, tail resource in either the Pinedale or the Marcellus given you probably won't get to it, as Mike said, in his lifetime or anytime soon?

Michael D. Watford

Well, I think it would make more sense to consider selling it when we have a $5 gas price out there versus a $3 gas price. So certainly. I mean, right now, we don't want to encourage any more natural gas development. We think it's the wrong answer. We don't understand why anyone is growing natural gas production. Makes no sense. So again, if we think that natural gas prices are much stronger 18 months from now, then that will be the right time to think about those kind of considerations.

Operator

And our next question will come from the line of Leo Mariani with RBC.

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

You talked a little about potential acquisitions to kind of replace the Niobrara. Just wanted to clarify, were you guys pretty much just talking about greenfield leasing and new projects? Or are you guys giving any consideration to acquisitions of producing properties?

Michael D. Watford

Well, I think we'd love to have one that gives us lots of running room with a little bit of production. But it needs to be bite-sized, something we can scale up. And we have a couple of ideas, targets, areas that we want to play in, in mind. And we think it's important for us to focus more on that in 2013 than we did in 2012. 2012 we were just trying fix things, cut CapEx, get ourselves rebalanced, get the ship righted, wherever the term is. Carnival Cruise Lines, we just got that ship into shore and got it [indiscernible] business. But so now we're going to look hard at some other opportunities.

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

Okay, that's helpful. And I guess, obviously, your partners in the Marcellus have dramatically cut activity, close to nothing here. In your discussions with these guys, are they giving you any indication of what type of gas price you need to see to get activity back into that $4, $4.50, just any color you have around that would be helpful?

Michael D. Watford

No, I think it's closer to $5. I think -- I don't think they have any interest in re-engaging with a large effort going from 1 rig to 10 rigs until you can see much stronger commodity prices out there. I don't think $4 or $4.50 gets it done.

Operator

And our next question will come from the line of Mark Hanson with MorningStar.

Mark P. Hanson - Morningstar Inc., Research Division

This might be directed to Mark Smith. A question for you on, I guess, the other covenant that I've seen in your credit agreement relating to the present value of the properties to funded indebtedness. I'm not sure how the banks actually calculate the present value, but it looks like with the PV-10 of $2.3 billion and debt of $1.8 billion, you guys would be in violation of that covenant right now of less than 1.5x. Maybe you could just speak to that.

Marshal D. Smith

I mean it's important to note that there's a difference between the SEC pricing that Brad has to use and the price deck that the banks use. Last year, our PV covenant placed the limit on our debt at $3.2 billion. So it gave us a $1.8 billion of outstandings. When you look at things in terms of a flat gas price, which is pretty close where the banks are, I think the banks are going to be in the April redetermination period, we have over 40% headroom. We had about 40% headroom last year, so that gives us plenty of room for any fluctuations that might be there with respect to the banks. We just don't see any issues with the forward-looking [indiscernible] of it.

Michael D. Watford

Yes, let's be clear. The banks get to set their own price and their price is not at the $2.60 number. The price is at $3.25 or something like that.

C. Bradley Johnson

And growing.

Michael D. Watford

And growing as you go forward. It mirrors what the forward curve is, although low on the forward curve. So there's a big difference. So we want to strongly disagree with your assertion that we're in violation of it. We're not. We have plenty of headroom. We have more borrowing capacity.

Operator

Our next question will come from the line of Noel Parks with Ladenburg Thalmann.

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

As we talk about the time down the road when we're going to see gas prices come back. I'm just thinking, in the meantime, in the Marcellus and also in Pinedale, what are you seeing there on the land front? Either smaller operators, who have leases expiring or, I don't know, potentially for you to pick up bolt-on acreage. Are people just letting undrilled acreage go? Are they renewing? And if so, kind of what sort of prices? Do you have a sense?

C. Bradley Johnson

I don't have real clarity on that. People are letting leases go. Prices, as you know, a couple years ago were up to $4,000, $5,000 an acre. And we're nowhere near that anymore. They're drifting down closer to $1,000 to $1,500 an acre at top rates now, and below that. Are we actively out looking to acquire bolt-on positions right? No, we're really not. We're more in a holding pattern, just waiting to see what's going to happen out there. We're waiting for things to get better.

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

Okay, great. And I guess along a similar line, as we talk about the interim until you see some rebounding gas prices. What are you seeing for service costs in Wyoming? Especially since you reinstated some activity there, labor, day rates and so forth.

William R. Picquet

This is Bill, Noel. We are seeing cost of services go down. We made mention in our release about the fact that we've renegotiated a lot of our service contracts, and that has resulted in lower costs, particularly in Pinedale. But we've also seen that in the outside operated activities in Pennsylvania as well. So we think that higher costs are going to be going down in 2013. And as a result of both continuing improvements in efficiencies, as well as cost of services.

Michael D. Watford

Hold on. Bill, do you want to speak to where we think our capital program can go?

William R. Picquet

Yes, we see the opportunity, both in our operated program in Pinedale and in Shell's program in Pennsylvania, for as much as a 10% drop on our cost of delivering wells in both those venues. I'm not sure exactly how fast Shell will get there in Pennsylvania, but there's a prize of as much as $30 million, maybe plus a little bit, net to Ultra in 2013, if we achieve those types of efficiencies, combined with cost of service reductions.

Michael D. Watford

That means that our capital budget drops by as much as $30 million.

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

Right. And just to clarify, so where in particular, are you seeing the improvement most? Is it labor, is it equipment?

William R. Picquet

It's across-the-board as far as costs are considered, but it's -- we see the most opportunity in completions.

Operator

And our next question will be coming from the line of Ron Mills with Johnson Rice.

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

Mike, on the 2014 to '16 outlook, I just want to make sure, clarify a couple things. The 40% production growth and 100% cash flow growth, and 200% earnings growth. Are -- those aren't necessarily CAGR numbers, that's just over the 3-year period, correct?

Michael D. Watford

That's right. That's from the beginning of 2014 to the end of 2016.

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

And did you say at a later point that, that's based using the forward type curve to drive your internal cash flow estimates to then basically fund your -- maintain your CapEx levels as your cash flows?

Michael D. Watford

Yes. I mean, it was -- the curve changes daily but it was predicated, basically, on a $4.25 average gas price over the 3 years. I mean it starts a little lower and builds up over the 3 years.

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

Okay, perfect. Just to follow up on a couple of the acquisition questions with you and your ventures group. Is there anything in particular that your new venture guys are chasing? Are you commodity-agnostic in their pursuit? At this point, do you -- is it still a desire to target some liquids or are we almost at the point in the cycle where your guys may be able to take advantage of gas assets being able to be cheaper? Or how do you all approach your new ventures business?

C. Bradley Johnson

Well, first, we're focused on resource plays. Just to answer the question right up front, we are commodity-agnostic, but the things we're happening to be focusing right now tend to be more liquids-rich plays. We're focused on those. We're looking all across North America for plays that make good economic sense to us right now.

Michael D. Watford

The challenge we have in looking for gas opportunities is that we have about the lowest cost gas asset there is out there, and our PUD development capital, right now, I think is about $1.15, $1.16 per Mcfe. Our 2P development capital is $1.46, $1.47. So I mean, it's just hard for us to find other gas opportunities that compete with that. So it sort of drives us towards the oily side.

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

Understand. And when you say oil or liquids, is it oil or NGLs or both?

Michael D. Watford

Both. It looks good black, so...

Operator

And our next question comes from line of Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

For 2013, the D&C budget of $365 million, I was hoping you could you just split that out between new wells being drilled versus wells that are waiting on completion, that will be hooked in the pipe.

Michael D. Watford

Well, we'll have to get back with you on that.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. And then, any sort of color, some help with that 40% growth between, I guess it was 2014 through 2016. And just the assumptions behind it, it just seems that – maybe we could look at 2014 first, and thoughts there. Budget's come down, it's about 25% what it was of 2011. And maybe you could talk about just the assumption on the existing production decline and what you see for '14. How you actually start getting growth going in the right direction, given the cut in CapEx in previous years.

Michael D. Watford

Well, the CapEx starts going up in 2014 through '16 to match the increasing cash flow because of improving gas prices. And so we're using, again, it's a $4.10 gas price, I think, 2014. I don't have it exactly in front of me. But $4, it's $4 gas price, and we binge [ph] cash flow, essentially, and our production starts going up. We have the models, we can talk about that some other time. But the message is that we've had growing production since 1999 until 2013. 2012 was a train wreck. 2013 we're rebalancing everything and we want to make sure we're cash flow positive. We want to continue that going forward or at least we have a plan that continues that going forward with just following the futures curve basically in terms of pricing, gas prices. And with what we can do with the existing assets, because we have plenty of opportunity at very low development cost. So if we just apply our internally generated cash flow to that, we start growing production again in '14, '15 and '16. And we get to some very large numbers that -- where the strip is in terms of pricing.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. And then just the declining rate we should put on existing production, what's a fair rate to apply to you?

Douglas B. Selvius

Well, our corporate decline rate, going into 2013, annual nominal decline is 26%. And of course, that drops off pretty significantly in the out-years as well. 26% this year, drops to 16%, for example, in 2014.

Operator

And our next question will come from the line of Ray Deacon with Brean Capital.

Raymond J. Deacon - Brean Capital LLC, Research Division

I was wondering if, is there any way for you to carve out the Geneseo and potentially operate yourself or is that not a possibility? And just any more details about kind of where you see the economic breakeven in the Geneseo and where is it most prospective.

C. Bradley Johnson

There's really no way for us to dissociate it from the Marcellus and operate that piece. They're tied up. It's across our acreage position. On where we were see a prospective, the 3.3 TCF that Brad referred to a little earlier, that represents 45% of our acreage position being prospective. I mean that's probably a little bit conservative. We've kind of talked, the last few quarters, of about 60% of our acreage looking prospective for the Geneseo. And some of the lines get a little fuzzy as to exactly where the economic geologic cutoffs are, I guess. But 3.3 TCF is a pretty good number.

Michael D. Watford

That's a net number.

C. Bradley Johnson

Correct.

Raymond J. Deacon - Brean Capital LLC, Research Division

Net, right. Okay, got it. And I mean do you think that -- I mean, are we talking, instead of $5 sort of gas price where you'd be willing to put capital to work, just in theory, do you think you or Shell or Anadarko might begin to drilling the Geneseo sooner than $5 or…

William R. Picquet

I can comment. On the Geneseo economics, we have places in our AMIs where we think the Geneseo is equal if not better than the Marcellus. And so part of the determination, in the next few years, is what resource brings the data to drive the early development. There are a number of locations that are economic at $3 and $4 gas, just like many of our Marcellus locations are.

Michael D. Watford

Yes, we don't see much difference between our development costs between the 2.

William R. Picquet

That's right. It's really an issue of co-development and prioritizing in certain areas.

Raymond J. Deacon - Brean Capital LLC, Research Division

Okay, got it. Do you see well costs coming down from where they are now, over the next few quarters?

C. Bradley Johnson

Yes, just talking in terms of current cost, our program is built on a $4.7 million cost in Pinedale. But we see the potential for that to come down 10% during 2013. So that's kind of back to that 10% number that I mentioned a minute ago. And in Pennsylvania, we mentioned that Shell's cost ended the year at $7.2 million. We think that there's an equal amount of potential for moving that number downward.

Operator

And our next question will come from the line of Robert Christensen with Buckingham Research.

Robert L. Christensen - The Buckingham Research Group Incorporated

In Wyoming, Pinedale, how much of your gas -- you're doing about 0.5 billion a day up there. How much of that gas is sort of older vintage and declining just de minimus-ly? What is the base level of sort of production if I had to ask the question another way?

C. Bradley Johnson

This is Brad. A majority of our gas in Pinedale is from wells that have been online for a number of years. And that's why we're seeing our base declines reduce and flatten out. We're making about $640 million a day equivalents in Pinedale. Much of that was in place on previous capital investments. So as we ramp down, you're going to see a lot more base production and [indiscernible] production in Wyoming, in the coming years.

Robert L. Christensen - The Buckingham Research Group Incorporated

How much of the production might be 4 years or older, I guess, would be another way for me to reframe the question. I really want to get at the exact kind of guidance as to the base, it's declining at 2%, 3% a year.

C. Bradley Johnson

Here's one number I think I can share that'll help you, and then we can follow up with more details. Looking at wells that were online in 2010 or earlier, make up more than half of our production, currently today.

Robert L. Christensen - The Buckingham Research Group Incorporated

Okay, that's helpful. Mike, I guess the question -- my final one is, I want to believe in gas prices, but you're a pretty observant guy and in the circles. Why do you think U.S. supply is falling? I think it is, but any color on that would be appreciated.

Michael D. Watford

Why? I mean, I think it's falling because people are withdrawing capital. We're not the only ones that have reduced capital. We were probably earlier and more aggressive just because we're 100% natural gas. But even our big partners, Shell and Anadarko, have seen the wisdom of withdrawing capital from the dry gas plays. And it takes a long time to make the decision to withdraw capital and shutdown those rigs or move them to a different area. But once you do it, if it's sticky on the way down, it's going to be a whole lot stickier on the way up, because you're not going to want to commit capital and go get permits, and build locations and sign new rig contracts, and get crews and redirect your staff, until you know that you can put forth a pretty significant capital program over several years. So gas prices going from $3.25 to $3.75 is not going to get anything done. And so there's no doubt that tremendous amount of capital has been withdrawn. And all the international JVs, all those things are nearing their end in terms of outspending cash flow by gross amounts. All that just means less and less CapEx. And we have declines. This stuff declines, people don't understand that, and they want to put a light switch to it, where you just flip the switch, where rig counts drops, they want to see production drop. It doesn't work that way and it's not going to work that way, when rig count goes up, production's not going to go up. So there's no doubt in my mind that production is declining. Whether it's declining rapidly enough to get us closer to balancing with demand, I mean, we're not there yet. That's clear. But when you have days like yesterday, where you have a pretty good storage withdrawal number, but it's not quite what the average was and you have a significant falloff in gas prices because money flows in the futures markets, it's just kind of you scratch your head and say, okay, where's the fundamentals of the business? And there are no -- I mean, if we are one of the low-cost producers in the U.S., if not the lowest, and you see what happens to our reserves at $2.63 gas, and you see what happens to our business, then how can anyone else even begin to invest at $3 gas? If you're really looking at fully loaded corporate cost, not just individual unique wells. So I'm -- there's no doubt that there's tremendous amount of capital has been redrawn. And you'll see that as you continue through 2013, what I really think is going happen is, you're not going to get enough gas price response throughout '13, so you're going to have 2014 with the same lack of capital being invested. So we'll have 2 years of decreasing production. So we'll see if we get there or not.

Operator

And our next question will come from the line of Subash Chandra with Jefferies & Co.

Subash Chandra - Jefferies & Company, Inc., Research Division

Mike, in hindsight, in the Marcellus, do you wish you'd done it differently? Would you, for instance, had wanted to operate or be bigger? Or do you think like the current situation sort of indicates the approach that you took?

Michael D. Watford

Yes – dare I answer this honestly? The biggest cost and performance issue we've had in the Marcellus is when Shell bought East Resources. And we haven't had the same performance there and we haven't just had the same cost structure there. And absent that, we've done fine. If there was a relationship with Anadarko, we'll operate an area [ph]. And so, yes. I mean, I think we made the right steps. Some other events happened out of our control, and we just learned something there. And what we've learned is we're not likely to going into non-operated positions again, is what that tells us.

Subash Chandra - Jefferies & Company, Inc., Research Division

And as far as Shell goes, I guess there's some expectations they'll reduce costs. But they have the [indiscernible] realtime operations center. It looks like a lot of technology is put into the drilling those Pinedale wells, and far more than I've seen by some independents. But the cost variance is so wide, what else can they do? I mean, it almost feels like they just have a different priority list. One, maybe safety first above all else, perhaps, or something else? So I'm trying to understand. Like, given the amount of technology they put into the Pinedale, how legitimate are expectations for them meaningfully taking cost out?

William R. Picquet

I'll address that one. This is Bill. Actually, their performance in Pinedale cost-wise is only slightly above the competition. So they've managed it fairly efficient as far as Pinedale costs are concerned. They're just not drilling very much up there right now. In Pennsylvania, they're moving toward the performance that we expect them to get to. They're just a little bit slower in getting there.

Michael D. Watford

Well, and Bill's talking about the capital side of the equation, if you look at operating cost on a per well basis, they're still thinking in Pinedale, they're 3x us.

William R. Picquet

Yes. LOE-wise, they're a long way behind. But if we're talking about drilling and completion performance, they eventually catch up. They're just a little bit slower getting there.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. Then a final one for me. So I guess, to Ron's question, you said that sort of indifferent between oil and NGLs. And I imagine NGLs is just a real pain in the neck, and sort of are you -- is that okay to take on the challenges of NGLs, where you are truly indifferent between that and free-flowing oil, let's say, and then take on some sort of pricing risk in the NGL business?

Michael D. Watford

Well, I think our view of the NGL pricing would be current market or less. So I don't think we would go to some historical percentage of crude pricing for us. I think we understand what NGLs are in oversupply now, much like natural gas is in oversupply. And I think that you have to be sensitive to that. And if you run your economics, pricing NGLs at a lower value, then we're safe so.

Subash Chandra - Jefferies & Company, Inc., Research Division

And the additional, I guess, operational burdens that probably all on costs as well, that's an I guess, acceptable challenge for Ultra?

Michael D. Watford

So it's a margin-based business [indiscernible] if we have healthy margins there and return on capital is sufficient, I mean, I don't want to do anything. We dropped our return hurdle to 20% last year, because of lower commodity prices. But as long as we hit our return hurdles, we're okay.

Operator

And our next question comes from line of Harris Arch with DuPont Capital.

Harris Arch

Just have a question on the net debt balances. So think you had about $2.1 billion of debt and then less the proceeds from the midstream, about $1.9 billion or so. As we get into -- we're in 2013, 2014, what's your expectation of net debt? Do you expect that to be relatively flat, increasing, decreasing? And kind of coupling that with, you're talking about looking at acquisitions. Do you envision that, that would take net debt up or would you be spending within cash flow?

Marshal D. Smith

Harris, it's Mark here. As Mike said earlier, we're looking at maintaining CapEx within cash flow over the next period of time. So and that's based on our current forecast from our existing production. So we're seeing, basically flat debt. Around $1.8 billion or so is going out over that forecast period that Mike talked about, and that would be exclusive, if anything, that might be associated with any acquisitions we'd make.

Harris Arch

If you were to make potential acquisitions, are you contemplating something maybe $100 million, $200 million? How big or small would you go? I'm just trying to get a sense of how much incremental debt you might incur.

Michael D. Watford

Yes. And we're not going to be able to help you with that today.

Operator

And our next question will come from the line of [indiscernible] with CDP Capital.

Unknown Analyst

Mike, I apologize if you kind of answered this, but you were talking about the -- in your models, '14 through '16 how things start turning around nicely. And I think you were talking at prices that represent the -- about the strip or maybe just slightly above the strip. And if that's the case, I'm wondering how willing you are to start hedging out there. Or if you can update us hedges that you might be willing to do into the '14 beyond area, if the cash flows and economics look okay?

Michael D. Watford

No, we're not willing to hedge up at the prices available out there today. I think 2014 has got $4, and that's where we've got a plan built. And no, we think there's far more upside than downside there. So no, we're not willing to hedge there.

Operator

And our next question will come from the line of Robert Benson [ph] with Amica [ph].

Unknown Analyst

A lot of us are hoping for a consolidation in the industry. Have any larger energy companies approached you about a merger? Or do you expect any larger energy companies to approach you about a merger?

Michael D. Watford

I appreciate your question. But, obviously, we can't answer that here today.

Operator

And your next question will come from the line of Matt Portillo with Tudor, Pickering and Holt.

Matthew Portillo

Just one quick question for me. I was wondering if you could provide some color on the timing of completion for the backlog blow down. And just how we should think about kind of the wells completed over the next few quarters, both in the Pinedale and the Marcellus? And I guess, just as a second question, with the drop in gas price that we've seen over the last few months, should we expect that will be more back-half weighted? Are you going to continue to blow down that backlog?

C. Bradley Johnson

Yes, this is Brad, I'll speak to both Wyoming and Pennsylvania. Both of those areas, from a completion standpoint, are slightly front-loaded for the year. As we work the backlog off in Wyoming, we will complete more wells in the first half of the year than the second. That's also the case in Pennsylvania, as Anadarko's winding down their program, and bringing wells online this quarter, we also expect completions to be front-loaded in Pennsylvania.

Operator

And our next question is a follow-up question from the line of Joe Allman with JPMorgan.

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

The table you provided in the release, the sensitivity table I think is pretty interesting. But could you just tell us what your main message is from that table?

Michael D. Watford

Well, I think the main message is that, with SEC requirements, we had to write-down a lot of reserves and a lot of value. But we didn't really lose anything, based on where current prices are. Most everything, we refer back to the $4 case of last year, and that's pretty similar to the case in 2010, our SEC prices. A point of fact here that I think a $3.50 to $3.60 gas price, almost all those PUD reserves come back in our books. So the message is, don't look at proved reserves for valuation of the enterprise, because gas prices have already rebounded from the trough of 2012. And they're not where we think that -- where we want them to be, and they're certainly not back to $4 yet. But we didn't lose any long-term value of the company. In fact, we're slowing down our capital investments so we capture more of that longer-term value at higher gas prices.

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

Got you. Does the table also tell us that the change from $2.63 to $4.04 doesn't change PDP volumes very much?

Michael D. Watford

Yes.

William R. Picquet

That's correct. That's right, and so the tail reserves are small. And keep in mind, the tail reserves are way out in the future. So the value -- and you can see the table, you pump up the price to $4 and the PV gets restored very quickly. And then you invest more capital and you get volume and PV, collectively.

Michael D. Watford

Yes. And I'm simpleminded, Joe, you know that. But I look at what we have and our 2P are all with the right amount of capital over the right amount of time is all proved reserves. There's no doubt about that. And I think we're going to be a $5 gas price in 24 months and that enterprise value is $10 billion. And so I'm just waiting for that to roll back around.

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

[indiscernible] if you just changed the capital, sensitivity 1 versus sensitivity 2, where you -- just change your capital. I mean, it really drives a significant amount of value when you just spend the money on the PUDs.

Michael D. Watford

It is. It's huge. But we had to withdraw the capital because gas price knocked those PUDs off.

Operator

And our next question is a follow-up question from the line of Ron Mills with Johnson Rice.

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

Bill, just one for you. You talked to – mentioned a couple of times about renegotiating your service contracts. Should I -- does that mean that you're already started to see those well costs already come down versus the $4.7 million that you averaged in 2012 if your current wells are already being drilled under the new contracts or is there more room to move? I just want to clarify that.

William R. Picquet

Already seeing them come down, Ron. Those are effective -- almost all of those are effective 1/1/2013. So reduced cost of services are in effect. And we're also continuing to work on efficiencies and we think we're going to see some nice gains as far as that's concerned.

Operator

Ladies and gentlemen, this concludes our question-and-answer portion of today's call. I will now turn the call back over to Chairman, President and CEO, Mike Watford, for closing comments.

Michael D. Watford

Thank you. We appreciate your time today. If you have additional questions, please don't hesitate to contact Kelly Whitley or Julie Danvers. And have a good weekend. Bye.

Operator

Thank you for your participation in today's conference. This concludes your presentation. You may all disconnect. Good day, everyone.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Ultra Petroleum (UPL): Q4 EPS of $0.51 in-line. Revenue of $217.2M misses by $44.23M. (PR)