Ultra Petroleum Management Discusses Q1 2014 Results - Earnings Call Transcript

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 |  About: Ultra Petroleum Corp. (UPL)
by: SA Transcripts

Operator

Good day, everyone, and welcome to the Ultra Petroleum Corporation's First Quarter 2014 Earnings Conference Call. [Operator Instructions] Please note, this call may be recorded. [Operator Instructions] It is now my pleasure to turn the conference over to Mr. Mike Watford, the Chairman, President and Chief Executive Officer. Please go ahead.

Michael D. Watford

Thank you, operator. Good morning. Welcome to Ultra Petroleum's first quarter 2014 earnings call. With me today are Mark Smith, Senior Vice President and Chief Financial Officer; Brad Johnson, our new Vice President -- our new Senior Vice President of Operations, congratulations. And congratulations to Bill Picquet, on his retirement. We miss him. Hope he's listening, taking notes. Also joining us is Doug Selvius, Vice President of Exploration; and Kent Rogers, Vice President of Drilling and Completions.

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

Also, this call may contain certain non-GAAP financial measures. Reconciliation and calculation schedules can be found on our website.

Also, we intend to file our 10-Q with the SEC later today. It will be available on our homepage or you can access it using SEC's EDGAR system.

We had a very good quarter. And for us, after 2 years of decreasing capital expenditures in response to lower natural gas prices, we are growing again. Albeit, in a measured manner with a continued focus on returns.

Our first quarter Wyoming natural gas investments are returning 50% to 80%, depending on well size, and our Utah crude oil investments are returning 400% to 500%. With that underpinning, let's take a look at the quarter.

Our earnings are up 131% to $135.4 million or $0.80 -- or $0.87 per share, and cash flow increased 63% to $201.1 million or $1.30 per share.

Crude oil production is up 145%, and we generated expanded margins during the quarter. We are increasing capital expenditures in Pinedale and Uinta and decreasing in Marcellus.

For the quarter, we sold our natural gas at a premium to Henry Hub in Wyoming and at a significant discount in Pennsylvania. Our first quarter cash flow exceeded our capital expenditures by $75 million.

For more details, let me turn it over to Mark and Brad. Mark?

Marshall D. Smith

Thanks, Mike. We registered an impressive quarter. As we laid out in our last call, our oil production was up meaningfully during the quarter, resulting in a significant change in our production mix. Oil volumes increased 98% sequentially to 658,000 barrels during the quarter. This amounted to 7% of our production mix and a much greater 17% of our revenue mix.

This was offset in part by our natural gas production, which was down sequentially to 53.3 Bcf due to our disciplined capital investment program as we move through 2013.

We shifted our investment focus away from Pennsylvania and first the Wyoming, and then Utah as we moved through the year. As a result, we expect the first quarter natural gas volumes will represent our inflection point, and then we'll see increasing natural gas volumes as we move through 2014, driven by higher-value Wyoming production.

We see 2 key factors positively affecting our overall production mix as we move through the remainder of the year. First, we see our mix of oil production growing well with the natural gas due to our emphasis on growth and our high returning Utah asset base. We think this results in the second quarter production mix of roughly 9% of volumes and 24% of revenues. Second, we see growth in our Wyoming natural gas volumes far outpacing the natural settle in our Pennsylvania volumes due to our reallocation of capital through our higher-returning Wyoming asset base. As a result, we see Wyoming production volumes increasing from 71% of our natural gas volumes in the first quarter to roughly 75% of our natural gas volumes in the second quarter.

We see this mix continuing to grow as we move through the year. From a pricing standpoint, our realized oil price before hedges registered $83.22 per barrel for the quarter. And when coupled with our significantly increased volumes that I discussed, our oil revenue increased 134% over the first quarter of 2013 levels to $55 million.

On the natural gas front, our price was up 42% year-over-year to $4.96 per Mcf, including the effects of our commodity hedges. Removing these effects, we realized an average price of $5.10 per Mcf in the first quarter.

Looking at regional pricing, we realized a positive $0.23 differential on Wyoming, while our actual Marcellus pricing was Henry Hub less $0.93 per MMBtu. Due to this increase in overall pricing, our natural gas sales revenue was up 34% over the prior year levels to $272 million for the quarter. On a combined basis, then, total revenue increased 45% year-over-year to $326 million.

From an expense perspective, our all-in cost increased slightly as expected to $3.17 per Mcfe during the quarter. This increase was driven by the Uinta acquisition, combined with increased production taxes due to higher natural gas prices.

As we reported this morning, our adjusted net income for the quarter was $135.4 million or $0.87 per diluted share, well ahead of consensus estimates. From a cash flow perspective, we reported $201.1 million or $1.30 per diluted share.

We discussed in the last quarter the opportunity for overall margin expansion in 2014. Our year-to-date results reflect these expected margin increases. In Utah, we're experiencing fuel level margins of roughly $62 per barrel, better than our acquisition economics. In Wyoming, our fuel level margins were $4.46 per Mcfe for the quarter. Our strong fuel level margins underpinned the strong returns we're seeing in these areas and are a key factor in our decision to reallocate capital.

On a corporate basis, our adjusted net income margin was 43% compared to 26% 1 year ago, and our cash flow margin increased to 63% from prior levels of 55%.

EBITDA margin registered 72% compared to prior levels of 67%, while return on capital employed increased from 16% in the first quarter of 2013 to 25% this quarter. Again, strong performance.

Now shifting to our balance sheet. I want to quickly comment on the natural de-leveraging we see occurring over the course of 2014. When we simply analyze our first quarter performance over the remainder of the year, we arrive at a 2.7x debt-to-EBITDA level.

On the 2014 calendar year basis, consistent with our planning and forecasting work, we view our current debt to 2014 EBITDA level at the same 2.7x. Our work also shows us as we move forward during 2014, the debt to forward EBITDA level will trend down to less than 2.2x. We have $585 million of availability under our senior credit facility providing ample liquidity and highlighting the strength of our balance sheet. So we believe debt issues are behind us.

Now shifting to product marketing. Our plans for Uinta crude production includes a combination of delivery to the local Salt Lake City refinery market, as well as transportation outside the basin via rail. Our first quarter marketed volumes averaged roughly 5,700 barrels per day with about 70% delivered to local refineries and 30% transported by rail outside the basin. And we continue to see the evolution of the rail markets with more consistent unit train service to support increasing basin production to continued buildout and expansion of loading facilities within the basin, as well as new market destinations outside the basin.

And as our production profile continues to grow, we believe the expansion via rail capacity is the best option to place our barrels. Furthermore, as rail transportation becomes increasingly viable, that we also expect basis differentials to narrow within the basin. We've already seen early indications of tighter pricing in the first quarter. The marketing agreements we assumed as part of the acquisition traded an average reduction to WTI of $24. During the first quarter, we were able to narrow this differential to less than $22 a barrel and we anticipate differentials to average less than $20 per barrel for the average -- or for the balance of 2014.

Now looking forward to our extended plan. We're forecasting exit rate gross production of 11,000 barrels per day, 9,000 net in 2014. Currently, we have a portfolio of contracts that allows us to dispatch 5,000 barrels per day to local refineries and agreements to place minimally 2,000 barrels a day rail capacity, which will expand to 7,500 barrels per day. So in aggregate, the capacity of our marketing arrangements is currently at 12,500 barrels per day, sufficient to meet our anticipated steady growth in production volumes as we move beyond 2014.

Now I'll pass the call over to Brad for an update on our operations. Brad?

C. Bradley Johnson

Thanks, Mark. During the first quarter, Ultra drilled 30 wells and brought on line 38 wells in Pinedale. In mid-February, a new build drilling rig arrived and began drilling in the Warbonnet area. You may recall that Ultra committed to these 2 new builds last summer with a 69-month delivery time. The lead time for a new build has since increased and is currently at 12 months. This rig, along with the rig that we added at the end of last year, has doubled our operated rig count from 2 to 4. We expect to run these 4 rigs for the remainder of 2014.

This level of activity should result in the drilling of 107 operated wells in 2014 and 81% increase to the activity last year. As we continuously pursue efficiencies in all aspects of our Pinedale operations, one example this past quarter was the initiation of a bi-fuel system that allows for natural gas to displace diesel at the fuel source from the drilling rig. The initial results had been impressive. In addition to reducing emissions, we have also realized the cost savings of nearly $30,000 per well. We have plans to expand this technology to other rigs in the fleet.

On April 23, there was a fire at a natural gas processing complex operated by Williams in Opal, Wyoming. Fortunately, Williams has reported that there were no injuries. This complex is one of 2 that processes Ultra's gas from Pinedale. All of Ultra's natural gas was diverted to the other processing plant and the interruption to flows of Ultra's gas was minimal. The initial interruption to Ultra's net production rate was approximately $24 million a day with a duration of 19 hours. Within a few days, Ultra's line pressures and gas production in Pinedale returned to normal levels and the total volume deferment was less than 40 million cubic feet of net production. This morning, Williams reported that 2 of the processing trains will return to service and are working toward putting into service additional capacity of that plant.

As we look forward into the remainder of 2014, our plan of increased investment in Wyoming is on track. Our 4-rig program has been at full-speed since early March, and our production is now increasing in the field. We expect our production in Wyoming to grow from about 430 million cubic feet equivalent per day at this quarter to an average of 530 in the fourth quarter of this year, or about 23% growth in 2014.

As gas price continues to strengthen on the Rockies, we expect our capital program of $400 million in Pinedale to deliver the following metrics: 50% to 80% rate of return on individual wells; greater than 20% production growth in the field; and the generation of $750 million of operating income from this asset alone.

Now in Pennsylvania, our production averaged 173 million cubic feet equivalent per day for the first quarter. Our capital program has been reduced significantly. Only one well was brought online this quarter and was located in AMI operated by Shell, with 5 additional wells expected to come online this summer.

And now to Utah, since taking over operations in our newly-acquired Utah asset in mid-December, Ultra has been focused on 3 things: maintaining the continuity of operations, implementing efficiencies and advancing our understanding of the sub-surface properties that drive the outstanding well performance of this field.

Regarding operations, we have maintained a continuous drilling program through this winter. Since taking over, we have drilled 17 wells and increased the producing well count from 40 to 65 wells. Production has increased 60% in the last 4 months. We have increased our approved permit inventory to over 6 months of activity at our current pace, and we are now selling associated gas through an interconnect that was commissioned in February.

Ultra has implemented a number of efficiencies, many of which are right out of our Pinedale playbook. Some of the more meaningful improvements include: 24-hour frac operations; drill-bit optimization; effective winterization of production equipment; artificial lift optimization; and the start-up of a freshwater distribution system.

The freshwater distribution system is worth describing in a little more detail. We decided to convert some equipment that we acquired into a centralized storage and heating facility. This enabled us to keep stored freshwater in a liquid state during the winter using natural gas instead of propane. We were able to distribute that freshwater via pipeline instead of trucks and we were able to reduce frac tank rentals required in each of the well locations. The result was nearly $50,000 of savings per completion.

In addition to efficiencies, we also encountered some challenges in our first few months of operating our new asset. First, we encountered additional downtime on producing wells. Some of the equipment that we acquired was undersized and not fully winterized. Of course, undersized equipment is a good problem to have when it is due to well performance exceeding the original design expectations, but it also required us to curtail wells in the first quarter.

We also have been pursuing improved artificial lift designs. Part of this process is a trial-and-error approach as we tested out some ideas, but we also generated some increased maintenance in curtailment. On occasion we also had to shut in some wells due to full oil tanks. This has largely been mitigated with the addition of 43,000 barrels of incremental oil storage installed on locations of existing and newly drilled wells. We also have established some new cycle time records in our drilling operation, but we have not been able to sustain those on a consistent basis. However, by demonstrating the improved performance on a few wells, we have reset the expectation that those records are achievable, and we fully expect to realize a more consistent and lower cycle time as we progress in 2014.

Our third objective was to advance our understanding of the sub-surface petroleum system. We have run advanced open oil logs on 2 wells, captured 47 rotary cores, analyzed formation water variations; and conducted isolated flow tests on the multiple producing horizons. Our near-term objectives are to refine our geophysical model and to capture useful data to optimize drilling, completions and reservoir management, including the design of our waterflood pilot.

Now turning to well performance. 12 wells brought on line this quarter had been impressive. The average 30-day IP rate of these wells is 156 barrels of oil per day. 8 of the wells have been on line for at least 60 days, and their average 60-day IP is 173 barrels or 11% higher than the IP 30 rate. These wells are on pace to average a payout in under 5 months. Yearly production data indicate that the EUR for these 12 wells brought online in the first quarter range from 250,000 to 450,000 barrels. I will now turn the call over to Mike for closing comments.

Michael D. Watford

Thanks, Brad. Realizing that the first quarter of 2014 is an inflection point for us, let's talk about the remainder of the year for a moment. We spent approximately 22% of our capital budget and produced about 23% of our targeted annual production. Over the next 3 quarters, we will grow total production by 17%, that's fourth quarter over first quarter. The natural gas component grows 13%, with Pinedale growing and Marcellus declining, which will raise our overall price realizations and operating margins, very important.

In crude oil, production will grow by 74%. With this, it looks like our EBITDA approaches $900 million, and we will generate over $200 million of free cash. Reinforcing Mark's comments that debt levels are pretty comfortable now. We will look more aggressively at opportunities set. We have a constructive view of natural gas prices going forward. In particular, western basin supplies, which are less affected by northeast basin supply growth. Demand is growing and will accelerate over the next few years with permanent coal displacement and power generation, industrial growth, significant Mexican export increases and LNG exports. Meanwhile, supplies flattening with growing basis differentials and transport costs associated with the few areas of supply growth. So we are very positive of the direction we are heading.

With that, I'd like to open the call to questions. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] And we'll take our first question from Brian Gamble with Simmons & Company.

Brian D. Gamble - Simmons & Company International, Research Division

Mike, you mentioned a lot of stuff I wanted to hit on -- maybe we can start in the Uinta on the wells during the quarter, the 12 wells seem to have some pretty decent 30-day rates and the 4 that made it to 90-day seemed to have obviously, excellent tracking profiles with the 90-day rate with equivalent, if not better, than those 30 days. Maybe you can talk about not only these 4, but maybe walk back and talk about the 4 that we talked about last quarter as to what your expectations versus the realizations are for those production sets and how those are trending over time.

C. Bradley Johnson

Yes, Brian, this is Brad Johnson. Regarding the well performance and citing the examples that we've provided in the press release, really, those are consistent with what we've experienced since we started looking at the asset. The flat production profiles tend to be 2 to 6 months in duration, sometimes much longer than that. But that's what our type curves are based upon and we continue to see the consistent results as we progress.

Brian D. Gamble - Simmons & Company International, Research Division

And that applies to not only the wells in this quarter, but also the ones we've talked about previously, I guess #1 3A and 3B were relatively early in the curve as of last call. Those are still trending right online as well?

C. Bradley Johnson

Well, they are -- with respect to these rates, and I won't point out the wells we featured last quarter, those 3 or 4 wells, we were doing some high rate testing to understand the deliverability of these wells to help develop our designs for artificial lift.

Brian D. Gamble - Simmons & Company International, Research Division

Great. And maybe a follow-up, more macro related. Mike, you talked about the dip on the Marcellus and obviously, you guys are not focused out there at all, and kudos to you for that, as far as getting out of that -- this market for the year. Is it trending as you thought it would when the year started? Any better, any worse? Just any update on your general thoughts on that portion of the market? And how, I guess, your markets are trending, as well as you come west?

Michael D. Watford

For worse or better, I'm going to hesitate on that. I think we're trending directionally is what we thought. On an absolute basis, I think we've missed the exit, the number I think our basis differential in the first quarter is $0.93. And I think we suggested $1, so we're a little off. But I mean, unfortunately, we have the -- I have the scars on my back of being a Rockies producer for 15 years. And a number of years, we're selling gas at 60% of Henry Hub because of too much supply and none of the takeaway capacity and not enough demand. Same thing is happening in the northeast. If we get to Henry Hub gas price of -- it's $5 and you're selling your gas for $3 in the area for several years, you'll be encouraged to add transportation cost and whatnot. And then you'll -- you've been for the next 10 to 15 years, you'll have those dollar transport cost base on your financials. We are a prime example of that with our rec charges now. So we're trying to is not go there again. I'm not debating that there's not good resource up there, but we just have a view that it's more constructive that the West is going to suffer from lower supplies. And so that our Rockies production, which is very low cost, and we have thousands of drillable locations is going to serve us well, so if we can reallocate capital there, we're better off. And I'm going to add -- we're constructive about gas prices. We think the supply is flattening and demand is increasing. And we'll see what happens over the summer with our fill and so we have $4.50 to $5 gas price forecast going out in the future. I can see those that have a $3.50-ish, that's okay. I just don't understand how you have a $3.50 gas price at Henry Hub and you think that you're going to grow northeastern production if you have a $1 basis differentials of transport cost. So that's kind of where we are on the low end of it. So we're going to tend to allocate capital to the West.

Operator

And we'll take our next question from Andrew Coleman with Raymond James.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

If I could step back to the Uinta. At least, Brad mentioned that you were starting to sell some associated gas out there. Should we then factor some of the Uinta into our type curves? And if so, could you maybe give us a sense of what that might look like?

C. Bradley Johnson

Sure. Right now, we're selling about $3 million a day net through that line. Our producing GOR is about 600. And usually, we use about 200 of that in field for fuel to keep things warm. So 600 producing and a 400 GOR from, I would use as a ratio to put a sales forecast out there on the gas side.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay. It sounds good. And then, as you were looking at, I guess, you mentioned that you're looking at a waterflood pilot and an artificial lift, I guess. Could you give a little more color on the timing of the pilot? And I guess kind of what are the options are you looking at some artificial lifts like gas lift? Are you looking at rod pump?

C. Bradley Johnson

Yes, I'm going to -- I'll address you artificial lift and I'll let Doug touch on the waterflood pilot because it has a lot of G&G components to that. On the artificial lift, our base case is rod pump. And that will probably be our solution go forward, but we are in various options within the rod pump space, size of the unit, pump design, pump location, dealing with sand. Those are the types of items we're optimizing on the artificial lift side. And I'll turn it over to Doug for the waterflood side.

Douglas B. Selvius

In terms of timing on the waterflood, it's going to be later this year, probably late third quarter into fourth quarter. And what we're doing to assess that right now is just acquire more technical data on the rocks. We've acquired a good sample of rotary cores throughout the Lower Green River section. And we're also acquiring some advanced logs that will give us more data on the reservoir so we can begin to design and build our models for reservoir continuity and waterflood efficiency.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay. Where do you get the source water from? Is it the water in the reservoir? Will you be buying that?

Douglas B. Selvius

Initially, we'll be using produced water. I mean, right now, we feel that will be sufficient for our pilot.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

All right. And then if I could just ask one more. You mentioned a couple hundred million of potential free cash. I guess, do you think there's a dividend coming back into play as you look to the rest of the year?

Michael D. Watford

Wow, with my stock ownership, that sounds good, Andrew. Here's what I think. I mean, we're very confident with debt position now. I think Mark rattled off some statistics that suggest that we're 2 7 going to 2 2 or so, on a forward-looking basis. And with interest costs continuing to be low, if I said 5% for long-term debt for us now and there's no reason not to utilize that. And we have a kind of an early look page in our corporate presentation where we try to give the most conservative 3-year forecast, which is not the most likely or most probably, but the most conservative. And with that, I mean, I think the low side case there suggests the difference between EBITDA and capital over 3 years at $1.2 billion, $1.3 billion. I think we're going to look constructively at spending that earlier rather than later now. So I think that's what you're going to see from us. So I don't think we're going to do anything different.

Operator

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

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

On Mike, and you just asked one question on the free cash flow, but if you go back to the Uinta for a second, I know when you talked about originally, you had different -- 3 different scenarios with 3 different type curves of 160,000 to 380,000 barrels and it sounds like the wells from the most recent wells looking like 250,000 to 400,000 plus BOEs. Is there anything about the mix in terms of where you're drilling wells? What drives -- were your drilling wells within those different EUR Windows?

C. Bradley Johnson

Yes, this is Brad. I can touch on that. The wells we described included for this quarter, the 350,000 to 450,000, are right in line with the tight curves at those higher end ranges. And where we drill is partly dictated by where we have permits in hand at the moment. And so part of our efforts this quarter is to increase our permitted inventory -- so we can build out some more flexibility about where we place our drilling rigs within the field. I do want to point out the other area we described in the lower type curve of 160,000 barrels, in mid-April, we brought a well online in that area and that well is testing 200 barrels per day. It's testing at early rates more indicative of the higher EUR range, so we're definitely excited about that well and looking forward to getting more data points in that area to help capture some of the upside of the resource that we've been talking about.

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

And related to the field optimization and lift optimization, I'm assuming it's just not just on your new wells. Are you going back to the wells that you acquired as well and making some of those optimizations? And if so, what's the impact then on some of the legacy producing wells? It's almost like found money.

C. Bradley Johnson

Sure. Many of the wells that were legacy, if you will, were the pumps were set pretty high, 4,500 feet or so. So we've been very deliberate going in and lowering those pumps. And the result, as you're moving total fluid out of the well at a higher rate and for a longer period of time as you lower those pumps. And that's been beneficial. We've had some challenges. We've brought sand up along the way as we've lowered those pumps. So while we got a buzz and the volume, we also got sand we had to deal with, and so that contributed to some of the curtailments that I had spoke about earlier. But overall, we see upside in the ability to optimize-- sustain those flat production rates for a long period of time. And yes, it's positive.

Michael D. Watford

Let me add a little more to that with what Brad says, going back and dealing with the legacy wells, the plus/minus 40 wells. Overall, it's very positive to the results, but during the quarter, caused -- it actually caused some production downtime because sand production and repairing. And then also some -- we'd be surprised with the rates and fill up our tanks, and got to shut the well in as we get that marketed and order more tanks. So it was not as consistent a production profile that has -- that we would've planned or that we're going to see going forward.

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

Okay. And on the marketing side, the local refineries versus the rail, what's -- what are the relative pricing differences there? It sounds like at least as you do more via rail that's, I would assume, that's a likely driver behind the low $20 differential to the $18, $19 differential that you talk about in -- earlier in your comments?

Marshall D. Smith

Yes, Ron. We currently have a portfolio in place that ranges from NYMEX less 21 to NYMEX less 18.75. Some of the more recent contracts we have in place on the rail side are at the low end of that. And we continue to build on our relationships and we see that with increased activity on the rail front, we continue to see those differentials come in.

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

Perfect. And then one last one on the gas side. I've felt some of your pain as that Rockies producer. But as you look at the West Coast and end markets there, not -- Midwest and the West Coast, how -- is it getting any better from a hydro standpoint? Or is that also an area that still looks like 2014 can be a surprise for some of your Rockies gas?

Michael D. Watford

Well, I think '14, clearly, will be a surprise, Rockies gas through the drought out in the West Coast. I mean, it's -- they have received some rain. So it's not as beneficial as, perhaps, it was 30 days ago or so, but still it's a win-win for us.

Operator

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

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

Just a couple of things. You were talking about having to add oil storage in the Uinta. And I'm just curious, is that something that -- was that a notion since you took over or just more recently, as you described, it just seems storage fill up faster? And is that within your -- the gathering and facilities budget line in the CapEx?

Marshall D. Smith

Sure. The -- almost immediately, we began installing additional storage and giving that to the stronger wells early in the process. And it's been a steady increase in that storage increase capacity. The second question is, is Kent has done a good job in absorbing that cost in his drill and complete AFEs from a cost standpoint. And so really, we're not seeing any incremental capital pressure as a result of that increase in storage.

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

Great. And can you just refresh my memory? I'm sorry if you mentioned this already. As far as seasonal effects in the Uinta, is there anything like -- I don't know, a spring breakup or anything that would affect second quarter?

Marshall D. Smith

No, no spring breakup. This -- the ambient temperatures in the dead of winter require some costs, some effort to keep things in a liquid form. But no seasonal breakup and our locations are in high ground, so we're good there.

A. Kent Rogers

Yes, I might -- I'm going to -- this is Kent. Let me add one thing. The seasonal increase in temperature, it helps us, okay, not hinders us. And so we're glad to see warmer temperatures. We're a cold weather operator. We have experienced doing this from Pinedale. So the ability to be able to work in Uinta, I understand the impacts of cold weather. We could do it. We do it all the time.

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

Great. And just the last one. I didn't quite hear. When you're talking about rail capacity, I think there's a mention of 2,000 barrels a day going to, was it 7,500 or 7,000 a day? And can you just remind me what the time frame is on that?

A. Kent Rogers

Noel, it's 7,500. That's part of the contract, and we can ramp up as we need it.

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

Okay, great. And when is that -- when do you expect to get to that 7,500?

A. Kent Rogers

Well, we -- as part of our overall portfolio, that gives us total capacity of 12,500. We think we'll be moving into that as we exited -- exit the year, approaching 11,000 barrels a day.

Michael D. Watford

I mean, our current production rate on a gross basis is -- what is it, Brad? 6,700 barrels a day right now?

C. Bradley Johnson

6,900.

Michael D. Watford

6,900, so we're moving there.

Operator

And we'll take our next question from John Nelson with Citigroup.

John C. Nelson - Citigroup Inc, Research Division

I just wanted to follow up on an earlier question with respect to Uinta EURs. And paraphrasing a little here, but were you trying to say that the 250 to 450 EUR is in line with the top end of the, I guess, 345 to 380 band around the type curve you guys would naturally see and you're just doing the logical thing in going to the best areas in the field first? Or are you trying to say that results, thus far, have exceeded expectations and while we're still pretty early, if this continues it could ultimately cause positive revisions to your type curve? I just wanted to see which way I should read that.

C. Bradley Johnson

I think it's more of the latter in the sense that the early performance, we're very pleased with it. And it continues to indicate that these wells are very profitable and very economic. I think, for us, the most encouraging thing is when you look at the table and look at IP 30, 60, 90, it's staying flat, if not improving. We're really happy about that.

Michael D. Watford

I think we're drilling wells where we have permits now. So it's not like we're cherry-picking the locations. We may get to cherry-pick later because we've got 6-month inventory permits now that we didn't have 6 days ago. And I'm going to get Brad to talk about this a little bit -- the EURs, I mean, we're -- these wells will pan out in 4 or 5 months, so it's fantastic. The issue is whether it's a 250,000-barrel EUR or a 400,000-barrel EUR. It's really about longer-term decline rate. There's nothing of about -- nothing to do about profitability well or return of the well. And we just need to see more production history. Brad?

C. Bradley Johnson

And our type curve is based upon analogues in the basin. And we know that the rock that we have here is pretty special and much better than much of the data we have in the basin that we have built that analog type curve from to develop the shape of the curve. And so the flat profile, probably with some decline later, will dictate ultimately what those EURs are going to be. But when we pay out 5 months and it's 150-, 200-barrel a day flat, you might imagine we're pretty excited about it.

Michael D. Watford

Yes. And then where it ends up being 300,000-barrel type curve or 400,000-barrel, which as just an issue, 10, 12 years from now, production rates.

C. Bradley Johnson

And we maintain that range on the early data because the early data is flat. So there's...

Michael D. Watford

[indiscernible]

C. Bradley Johnson

But range is based upon judgment about when it might turn over and at what rate it declines and reduce using that as a range for now. That gives it an appropriate range until we learn more. But man, we hit the payout curve in 5 months, pretty pleased with that.

John C. Nelson - Citigroup Inc, Research Division

That's definitely fair. And then I also just wanted to circle back to the comments with regards to your opportunity set and being more comfortable with the debt leverage profile. There have been a few transactions in your neighborhood at prices that are well below where your equity trades. I was wondering if you could also just comment for us on your pecking order with regards to higher activity levels versus potentially acquisitions. And at what debt thresholds do you become more active or the timing around that comfort? Any thought would be great.

Michael D. Watford

I think we're at a debt threshold, where we become more active. I'm more and more comfortable with 3x forward EBITDA, honestly, with less than 5% interest cost, closer to 4%. It's not the same cost the organization -- plus, again, we have constructive view of natural gas. A couple of M&A transaction have occurred in our backyard. The first one was all non-operated, small, working interest across the field. So no ability to control development or pace of development or anything else. So it should be at a lower value. And then the other one, the larger one, is Kennesale [ph], the private equity group is -- it's 75%, 80% per EPEs. It's all about getting an uplift in the PDPs to, I think, to turn it into an MLP, is what I think. So it's not -- there's not a lot of developmental opportunities there. So it doesn't fit with where we are primarily in the Pinedale, where we're 35% developed at that. And Brad is shaking his head. No we're not that far along. So we still have a huge development wedge and we have not been able to drill the best upfront in the field because of regulatory issues. We're told we're to drill more often than not. So -- and as we continue to bring down the well costs, we're only improving our returns on economics, much different assets, so -- but back to the -- how do we use our $1.2 billion, $1.4 billion of EBITDA over CapEx for the next 3 years from our most conservative 3-year plan we have out there? We're not ready to find that yet, but we're certainly comfortable with -- more comfortable with acquisitions now that we've done 1 here recently. It's worked out very well. But we won't be buying Marcellus gas. So it would I be interested in the Western basin and gas? Sure. Because we think there's more upside there and we're more about, I guess, we'd say buying gas than accelerating development of gas at this time, because we still want to maintain this kind of flat supply domestically. I think that's the right answer. And then in realities of acceleration on the gas side or anywhere now is rigs. I think Brad said that we ordered our 2 rigs last June. It was a 6- to 9-month delivery. Now we're told that if we want to order more rigs, it's a 12-month delivery. So if we said, "Go," tomorrow, beginning of May, you wouldn't have additional rigs til May, June of next year operating. So actually, that's good, I think, because it will tend to return the growth in natural gas.

John C. Nelson - Citigroup Inc, Research Division

That's very helpful. And then just one quick housekeeping one for me and then I'll jump off. The comment on the Pinedale production ramp to 530 a day. I just want to be clear. Was that a 4Q average or an exit rate target?

C. Bradley Johnson

That's an exit rate.

Operator

We'll take our next question from Jon Wolff with ISI Group.

Jonathan D. Wolff - ISI Group Inc., Research Division

Michael, I'm just curious, could you talk a little bit about Western demand dynamics and sort of the balance between Rockies supply, and California and other West Coast? And then also, can you tell me if any Rockies gas, Northern Rockies gas is going east or if there is any significant amount?

Michael D. Watford

I'm going to have Mark help, but I'll start. During the winter, because we do have the Rex transport and we can use it profitably from time to time, we were able to wheel gas from West Coast markets or Midwest markets to take advantage of better prices. So I think that helped us achieve probably better-than-expected natural gas price realizations for the quarter, so that was very helpful. Most of the -- of our Rockies gas does go West other than peak times. The supply issue is we usually we have all the major basins in the West, and the Canadian basins are all in decline. The only group in the U.S. is in the Northeast and that gas can't get to the West Coast. That doesn't happen. Won't happen. And so -- and with the -- I don't have the exact demand-supply numbers in front of me, but traditionally, the California and the West Coast markets have been supplied by Rockies gas, which is our area, San Juan Basin over the West Texas gas with El Paso, delivering gas out there, and Canadian gas. While all those areas are in decline, one might argue that West Texas is flat with the associate gas, but -- so we're, I guess, our issue is we have more of a declining supply with flat to increasing demand now, and particularly with the waning hydropower this year.

Jonathan D. Wolff - ISI Group Inc., Research Division

And so related to that, you have the best dry gas asset in Northern Rockies, there's very little activity in Peonce [ph]. Mexico is going to get gas from the Mid-Con. Doesn't it -- does it make sense to sort of try that, a rig or 2, and take a chance on drilling into potential strength?

Michael D. Watford

It may, John. We're waiting to see that. We think 2015, the futures curve is underpriced. And we think it's going to continue to climb over the course of this summer and we want to see a higher gas pressure '15 before we commit to something like that.

Jonathan D. Wolff - ISI Group Inc., Research Division

So maybe you're saying you like to be able to lock it in the hedge curve?

Michael D. Watford

Yes, sir.

Marshall D. Smith

And John, just going back into Mike's comment, not only the location but with the transportation flexibility that we have associated with our asset base. When we see price dislocations, we're able to take advantage of it, we saw that this winter and you saw the effects of that in the first quarter. So we can sell our gas, Mike's point, not only on the West Coast, but all the way back to the Mid-Continent and take advantage of the transportation abilities we have and see the uplift we saw in the first quarter.

Operator

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

Brian Singer - Goldman Sachs Group Inc., Research Division

The first question follows up on John's question, which is, you mentioned the lead time to get new rigs if you want them. Does that mean if you want to increase your activity in Pinedale in 2015, that decision needs to be made now? Or do you think you could make that decision in 3 months or 4 months as you see futures prices and have that rig available at the beginning of next year?

Michael D. Watford

Yes, Kent found out yesterday that it was...

A. Kent Rogers

It was more -- it was -- Brian, it's Kent. I -- we -- I talked to a gentleman who's in the industry representing a rig contractor. And you told me that if we ordered 1 today, it will be 12 months out, April next year. So I assume if we delayed 3 or 4 months, that delay would carry on. This particular contractor is sold out for the year. So I don't think there's any way we could have one for the start of 2015, Brian, is that what you're suggesting?

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And the second question is, there's a lot of talk on well performance in the Uinta. But I just wanted to make sure we're clear on the production trajectory from here. I think production for the quarter into the Uinta was about 4,500, so a little bit more BOE a day, up about 500 from when you announced the acquisition. And I think the growth rate of 6,900 was a little bit less than what you talked about on the fourth quarter call. Just trying to look at the annual guidance for the year, which would have -- seem to imply about 1,500 BOE a day of growth per quarter. Can you just add some color on the achievability of that trajectory? And why some of the completion-related shut-ins that you talked about as having negatively impacted first quarter production would not apply to future quarters?

C. Bradley Johnson

Sure. Yes, the first quarter was down a bit with the curtailments that we experienced. Some of that was operational, some of that was self-imposed, as we were testing our artificial lift. The weather in the winter had a factor as we were getting equipment winterized. So the weather factor is going to be behind us as we go out through the rest of the year. And then operationally, we're just going to get better and smarter on operating asset. So yes, first quarter, we're down just slightly a bit from what we thought it was going to be. I think those issues are behind us and the exit rates, as we leave 2014 of 11,000 gross and 9 net is very achievable. I think right here going forward, it'll be fairly steady, pretty steady pace of growth as you look at our quarter-to-quarter model.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And did you say -- you may have said this, what the weather-related impact was in terms of barrels a day impact on gross or net production?

C. Bradley Johnson

It was one of several factors, Brian, I didn't -- I don't have -- I didn't quantify the weather alone. It is one of several factors we experienced in the first quarter.

Operator

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

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

I was hoping you could give us a little bit more color on Marcellus diffs. It looks like you guys are talking about $1.50 in the second quarter in terms of what you expect. Just kind of any color on what may you have seen here in the month of April? Are you seeing the $1.50 now? Do you think that's going to widen throughout the quarter? I'm just trying to get my arms around the $1.50.

Marshall D. Smith

From March, we saw about -- March, we saw about $0.97. We're seeing in the range of $1 now. And we see it widening as we go through the year.

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

Okay, that's helpful. And I guess just in terms of activity in the Marcellus. You guys talked about, I think, 5 other completions this summer. Is there any joint activity by your partners or is it just reducing backlog of previously drilled wells?

A. Kent Rogers

The drilling activity, we expect to go on through the rest of the year will be all in the Shell AMI. Of course, we would like them to stop. But 3 or 4 months ago, they're planning 35 wells for the year. They have reduced that to 23 as of this morning. We have only elected to participate in 5 of those. Of course, we haven't received all of those AFEs. And we may modify that some going through the year, but the activity levels are dropping. They're going to take the rig out of the AMI for 3 months to drill some Utica wells directly offsetting our leasehold, which is a good thing, in our mind. We'd like to learn something about that resource additional. So activity is going to be modest for the rest of year and our participation level is going to be a fraction of what Shell actually drills out there.

Michael D. Watford

So it's -- I think it's important to note on our -- whatever it is, 250,000, 260,000 net acres. The 100,000 acres that Anadarko operates, no activity this year, no activity next year. Probably none for '15. On our 60,000 acres, no activity in the last few years, none for '15. That's correct. And Shell has slowly reduced theirs, but they are even suggesting 35%, 40% less activity now than what they were telling us in December for this year. So I -- and I think theirs is a quarter-to-quarter effort, so they could pull that rig anytime.

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

Okay, that's helpful. And I guess, obviously, you talked about long lead times for rigs in Pinedale. I wanted to kind of hear your thoughts on Uinta. It sounds like the well performance has been very good. Will that be a shorter lead time, given that's a smaller rig? And where are you guys in terms of thinking about getting a second rig there in Uinta?

C. Bradley Johnson

Yes, definitely shorter lead times in Uinta. Shallow wells, so a lot more opportunity to get a rig there. We are planning for a second rig. We're going through those plans right now. We've talked about doing that in 2015 and we're working hard to do it sooner than that. Permit count is a major factor in that, and we've made a lot of success or had a lot of success this quarter in increasing our permit inventory. We're going to continue that and our plan is to get a second rig in the near future.

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

That's helpful. Any update on what's going on with the Rex pipeline? There's kind of chatter on partial, reversal and things like that.

Michael D. Watford

We have firm contracts that go through another 4.5 years and we pay them $80 million per year on that. We'd be glad to stop it tomorrow. But until that outflow stops, I don't see how it gets reversed. So I think you can count on reversal, maybe in 2020.

Operator

And we'll take our next question from Marshall Carver with Heikkinen Energy.

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Yes, you talked about having below $20-oil differentials in Uinta for the remainder of the year. Where do you think that could go longer-term, I mean, for 2015 and beyond?

Marshall D. Smith

Marshall, we're focused on 2014 at this point in time. And we think that with the increased rail capacity out of the area that there's potential for it to tighten up beyond that. But the numbers that we cited were really focused on 2014.

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Okay. And in terms of winter downtime, do you have a way to quantify what that was for Q1? And what sort of winter downtime do you factor in for Q4 of '14 and '15 -- or 1Q of '15 in Uinta?

C. Bradley Johnson

In the first quarter, our downtime ranged between 5% and 10%. And we're striving to get that down to 5%. But it bounces between 5% and 10%. And part of the issue wasn't necessarily only weather or winter or ambient temperature. We have wells shut-in because the tanks were full. So we addressed the storage issue. We had to get some winterization out there. We've got some equipment that's undersized. We'd like to have a little bit better equipment on our wells. So that's going to be a part of the process going forward.

Michael D. Watford

I mean, the previous operator didn't have the equipment winterized is the bottom line. So we took over the middle of December and we had to do it on the fly, so that's -- we had more problems than what we would forecast in the future because of that. Because we're -- as Kent said, we're used to operating in the cold environments in Pinedale, Wyoming. So we have that -- we'll have that taken care of by the time we get to fourth quarter of '14.

Operator

And we'll take our next question from David Tameron with Wells Fargo.

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

Mike, I've been toggling back and forth. So the 530 is that a -- that you mentioned, is that a year end accelerated in Pinedale? Is that what I heard?

Michael D. Watford

Yes.

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

Okay. And then you guys put out that '15, '16 guidance...

Michael D. Watford

No, we didn't put out '15, '16 guidance. We put out the most conservative '15, '16 early look we could have. Not the most probable, not the most likely, but the most conservative. So if anyone's using that as a plan going forward, they're way low.

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

You just cut to the chase and got my answer. So I'm just trying to think about -- obviously, the Street is way low for '15, '16 on both, particularly on the oil side. And I'm trying to figure out, are there hurdles -- and Brian asked this question, Singer, but any permit hurdles? And what would be the hurdles? And what do you need -- or maybe better way to phrase it is what do you need to execute on? Do you need more permits for '15, '16 to get to those numbers on the oil side, particularly in the Uinta? And should we think about -- as you said in your conservative early look ahead is -- should we think about gas, being kept fairly flat if gas stays at current levels? And then with the growth coming from the Uinta or can you just -- can you give us any more framework around that?

Michael D. Watford

I'm going to let Brad talk about the Uinta permitting, ability to accelerate and what not.

C. Bradley Johnson

Sure. Obviously, permits are important in Uinta. We've increased our permit inventory in just 4 months. That pace to submit and receive is pretty predictable. And it's just a matter of getting the resources assigned to that effort and to get it going, and we're pleased with what we've accomplished so far. So I don't think permits by themselves are going to be a significant hurdle for the growth that we've outlined.

Michael D. Watford

And let's -- on the gas side, I mean, from '13 to '16 on our early look ahead slide, we're showing flat gas, 3% growth over the 3 years. But it's -- we're just changing the location of the production. We're going to have the Marcellus asset decline and the Wyoming asset increase. So it's really the -- our relatively modest conservative 3-year growth plan, overall, 21% all on the oil side, almost 600% growth over 3 years in oil.

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

Okay. No, that's helpful. And then just back to the Uinta, just for some clarifications. Any -- I mean, are there any concerns around -- air pollution has always been an issue up there. Anything else as far as stipulations? As far as that little creature that [indiscernible] or anything random up there like that, that we need to keep our eyes on?

C. Bradley Johnson

Those items are all present in the Uinta Basin, air, animals, water. But those are all a lot -- the same items that we've dealt with in Pinedale. So we have a good handle of those items and we know how to address those. And we'll continue to engage the stakeholders and work through that, be a responsible steward in the Uinta Basin.

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

Okay. And then Mike, it just -- I know you won't like this question, Mike, but the Rex pipeline, they announced yesterday that binding open season for East to West capacity, is it -- it's my understanding there'll still be -- even if that goes through to, there'll still be options for West to East? Mike, can you just talk about -- can you just say more color on that?

Michael D. Watford

But -- I mean, it's one piece of pipe and they have all these firm shippers that are paying them money for firm demand charges through 2019. I mean, they may be able to do some incremental things, but that's all they can do until they let the firm shippers out of the contracts till 2019. And it's all there is. I mean, they like to talk about this and it's the only -- they've got a lot of debt on that pipeline, which is all backed, by the credit worthiness of the firm shippers. So they just have to figure out some way to deal with that or else, it's not -- it's a 2020 event. And I can't say anymore simple and straight from that. I don't understand how they could suggest something otherwise. And again, point of fact, they have never talked to us.

Operator

And we'll take our next question from Brian Kuzma [ph] with Bitcom [ph].

Unknown Analyst

My only real follow-up was when you look at the shape of the curves, the the cum plots that you guys originally put on out in the Uinta, it looked to me like the wells that you were expecting the lower cums on were also -- they didn't just start out at a lower rate. They also looked like they started rolling over sooner. So there was, I guess, there was pressure behind them or something that. And I wanted to get some kind of feel for what's driving your thoughts on the EUR range on this set of wells, relative to not just the rate, but the underlying pressures behind it?

C. Bradley Johnson

Sure. No, I think your observation is fair. There are a handful of wells. They start out at a lower rate and their flat profile don't last as long. So those are the wells that -- there's -- I'll kind of narrate through the 160 EUR type curve, where we represent those wells coming on around 100 barrels a day and only having a flat production profile for a couple of months. If you go to the other side, 400-barrel -- 400,000-barrel wells or 350,000. They come on at 200 a day and those stay flat for 6 months or greater. And that boils down to really -- it's really pH and net pay and the quality of the rock in the column. Recall that we're completing these wells and producing them from a sequence of producing horizons. And so we have variability and the net pay and the rock in each location. And we're trying to bracket that and describe that for you. And we also -- we're spending effort trying to understand that much more advanced state, so we can be better predictive and we can high grade and optimize the asset.

Unknown Analyst

Right, so on this well that you guys drilled or just brought online it was in that 160 area, where you had some old wells that were 160, was there any anomaly from a pH perspective there? Or do you just expect maybe that well to roll over and not maintain as high a rate for as long as the other well?

C. Bradley Johnson

I don't know that we can answer all of these questions precisely yet. And there was no anomaly from a pH standpoint, from a pay statement standpoint. What we are seeing and what we're observing as we drill wells across the field is there is variability in the lithology or the composition of the rock. There's quite a bit of variability in limestone and silica content, or calcite, and silica content as we move around the field. And this one particular area seems to have a higher percentage of limestone. That may be what's affecting some of the production performance in that part of the field. We don't know yet. We're just early on trying to learn these things now, but that's what's driving some of the sub-surface resource assessment that Brad was talking about earlier. And then we start to figure these things out if there's a big win for us. We are applying one completion design all across the field right now. We started trying to understand these rocks better and we start to tailor our completion designs to specific areas. It could make a huge difference. And it might turn some of these 160,000 EUR wells into 360,000. We don't know. That's what we're trying to figure out right now.

Unknown Analyst

I got you. Okay. And then what drives the upward bound of when you look at the volumetrics that you're dealing with out here? Is 450 possible to put in these wells on 40-acre spacing?

C. Bradley Johnson

Yes, certainly. We will do our resource assessment and did our ULIP [ph] well in place calculations. Initially, we assigned a primary recovery of, I think, it was 7% or 8%, if I remember correctly from the analysis. And so we definitely can put that amount of oil back in the ground and have a conservative recovery factor. Of course, we're also looking a hit for water flow and then we want to double that with waterflood. Double the recovery factor, that is, so that we can recover more.

Unknown Analyst

Great. And just a point of clarification, that 7% to 8% is -- was based on the 2 -- just the 8% number? Or the -- which type curve was that based on?

C. Bradley Johnson

Well, that's being applied across the resource on our recovery factor. And as pH drops off and as the value metric cank [ph], if you will, falls off, that's what dictates the lower EUR. So the recovery factor for now is constant and that's being applied to a variable pH, SG, that whole 7 to 7.5, 8 [ph] BOI in that calculation.

Operator

And we'll take our last question from Mark Hanson with Morningstar.

Mark P. Hanson - Morningstar Inc., Research Division

I know there's been less of an emphasis on the Marcellus as of late. Just curious, as you look from first quarter of '14 back to Q4 of '13, kind of surprising that volumes were able to be held flat, which just 1 well brought online. Maybe just some color there on what either you or the out-partners were able to do to kind of keep that flat? Kind of read through there for maybe the rest of the year?

C. Bradley Johnson

Sure. The 1 component of that is just taking care of the base production and looking for ways to optimize it, plunger list and de-foamers -- excuse me, foamers to help the de-liquification of those wells. Compression has been a factor and -- but also, just a flat decline. We observe these wells with declines getting flatter and flatter over time, and we've lifted our EURs on these wells over time as they've flattened out. So we've seen that since the early days with these wells turnover and we have considered a much flatter profile than some of the early curves we're suggesting. And that's across-the-board in the dry gas area of north-central PA, across all our assets.

Mark P. Hanson - Morningstar Inc., Research Division

And then just one other question here, as you start to think about the next few years, given the comfort with the balance sheet, some of the free cash flow generation, I assume that the New Ventures group is still very active behind the scenes. Is this still your preference here, if you did come across something that were bite sized to have a more of a flowing developed characteristic, as opposed to kind of virgin property?

Michael D. Watford

Yes, that would be our preference.

Operator

And it appears we have no further questions at this time, so I would like to turn the program back over to Mr. Mike Watford for any closing remarks.

Michael D. Watford

Thank you. We appreciate everyone's participation today. If you have additional questions, please contact the Investor Relations group, and we hope you enjoy the rest of your day. Goodbye.

Operator

And this does conclude today's program, and you may disconnect at any time.

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