山脈資源 (RRC) 2015 Q1 法說會逐字稿

Good morning and welcome to the Range Resources first quarter 2015 earnings conference call. This call is being recorded.

(Operator instructions)

Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements.

After the speakers' remarks, there will be a question-and-answer period. At this time, I would like to turn the call over Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator. Good morning and welcome. Range reported results for the first quarter 2015 with record production, a continuing decrease in unit costs and some outstanding well results.

The order of our speakers on the call today are Jeff Ventura, Chairman, President and CEO; Roger Manny, Executive Vice President and Chief Financial Officer; and Ray Walker, Executive Vice President and Chief Operating Officer. Range did file our 10-Q with the SEC yesterday, it should be available on our website under the investors tab, or you can access it using the SEC's Edgar system.

In addition, we've posted on our website supplemental tables, which will guide you in the calculations of the non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliation of reported earnings to our adjusted, non-GAAP earnings that are discussed on the call. Now, let me turn the call over to Jeff.

Thank you, Rodney. I'm going to begin my remarks with some macro comments about our industry, and then focus specifically on Range. Starting with macro, as you all know, US gas supply has increased ahead of demand, causing low gas prices in most of the US and negative basis differentials in the Appalachian basin.

We believe that, over the last year, the US gas market, typically, has been over-supplied by about 2 BCF to 4 BCF per day. However, we see positive things that are happening on both the demand and supply sides of the equation. On the demand side, I believe that most people would agree that additional natural gas demand is coming, and coming in a very meaningful way.

In our presentation on our website on page 19, we have a projection of natural gas demand with time. The good news is that gas demand is expected to increase about 2 BCF per day, this year. This projected 2015 increase in gas demand is driven by the conversion of coal-fired, power-generation to gas, increased industrial demand, planned exports of gas to Mexico and LNG exports from the Gulf Coast, coming online.

For 2016 through 2020, natural gas demand is projected to increase by about 3 BCF to 4 BCF per day, each and every year. It shows about 20 BCF per day, of incremental natural gas demand by 2020.

There are multiple other reports that project natural gas demand with time. And the report we reference is consistent with our internal work, and within the range of other reports that I've seen.

The other side of the equation is the supply side. The supply side can be broken into two pieces. Natural gas associated with oil wells and natural gas from gas wells.

We believe that, prior to the recent oil rig count reduction, there was approximately 16 BCF per day of natural gas being produced, associated with oil production. That's almost the equivalent of the Marcellus and Utica combined.

Of the 16 BCF per day of natural gas production associated with oil, about 8 BCF per day is estimated to be associated with shale oil, or unconventional oil plays. For the first time in a long while, oil is not $90 to $100 per barrel. It's roughly half that.

The industry's response has been to cut their 2015 capital programs to about 40% to 50% of their 2014 budgets. Given these reductions so far, the oil rig count is down about 56%, and appears to be going farther.

Given that moving oil through low-permeability rock is harder than moving gas through low-permeability rock, the first year declines of unconventional resource oil wells are much steeper than gas wells, and typically are in the 70% to 90% range. Given the continuing steep drop in the rig count, and typically steep first-year declines of those oil wells, I believe that we'll see a production response in the second half of this year.

Some are predicting that we will see it before then and they may be correct. Not only with will this help on the gas supply side, but since about 40% of all NGLs are derived from natural gas associated with oil production, it will help with the NGL supply as well.

The other big piece of the supply equation is in Marcellus and Utica. Even in these plays, operators have typically cut the 2015 capital spending plans by about 40% to 50%, versus 2014.

The rig counts for both of these plays are down by about 42% and 44%, respectively. By late summer, some are forecasting that the rig count in the Marcellus and Utica may be down to about half of what it was last year.

Cutting capital spending and cutting the rig count will affect production. In addition, the infrastructure is significantly constrained in the far northeast portion of Pennsylvania. One pushback I get from this argument is that, when the gas rig count plummeted in the second half of 2008 and beyond, the production response was unaffected and it kept going up, and to the right.

I believe that it's different this time, for multiple reasons. Back in 2008 timeframe, there were still vertical rigs drilling for gas. The operators dropped their vertical rigs first, and those rigs were not driving production. It was the horizontal rigs that were doing so.

Today, there are no vertical rigs drilling the Marcellus or Utica. So, decreasing the rig count should have an impact.

The second thing that happened is, the lateral links back in 2008 and early on, were short, maybe 3,000 feet or less. As operators drop horizontal rigs, they drill longer and longer laterals, with some operators now consistently drilling 8,000 foot to 10,000 foot laterals. In addition, the number of frac stages increased, and the spacing between stages decreased, and sand concentrations went up. All of this led to higher production.

I believe that today, operators who have consistently been drilling 8,000 foot to 10,000 foot laterals, with reduced cluster-spacing and high sand concentrations, are in the later innings of the game. Combining the coming, growing natural gas demand with the probable response on the supply side, the outlook for supply and demand coming into balance, and improving natural gas prices, is on the horizon.

In addition, given the significant infrastructure build-out underway in Appalachia, coupled with multiple companies moving their gas out of the basin, and improved demand outlook, we believe the basis differentials in Appalachia should narrow and improve. Therefore, I believe pricing should get better later this year, and on into 2016.

Range is well-positioned for this upcoming event. We have the largest position in the core portion of the Marcellus, Utica and Upper Devonian. This is the area were all three horizons are stacked on top of each other. It's also the area where there's an option to drill either wet or dry acreage.

In total, we have about 1.6 million net acres of stacked pay potential. About 9,000 acres are dry, and about 700,000 net acres are wet. We have some ability to move our drilling between these areas and horizons.

Looking at the economics with strip-pricing on page 17, although the economics for the wet wells are good, currently the dry well economics are better. For 2015, we have moved more of our planned drilling into the dry area.

The other key on the same page is the data in the second row, which speaks to the quality of the acreage. Range's EURs per thousand foot of lateral are best in the southwest portion of the play. And when considering the total Marcellus play, we're second only to Cabot.

It's interesting to note that, Range's and Cabot's lateral lengths are both about 6,000 feet, which is less than most everyone else in the play. Both companies EURs are tops in the play, which speaks to the quality of the rock. One upside for Range is that we only drilled a small number of our potential locations, and as we continue to drill longer laterals with time, our capital and operating efficiency should continue to improve, given that we're in the earlier innings of the game.

The Utica could be another enhancement our capital efficiencies and returns. On slide 14 of our presentation, there are two new bullets that we added to this slide. We, along with multiple other Utica operators, are members of the consortium for the Utica, record our well, and contributed the data to the consortium.

The Utica well we drilled in Washington County, Pennsylvania, was calculated to have the highest gas in place of any of the analyzed consortium wells in Ohio, West Virginia or Pennsylvania. It also has the highest reservoir pressure of any horizontal Utica well drill, and some of the best permeability in the play. This combination of high gas in place, high pressure and high permeability for the Utica, led to Range testing the Claysville Sportsman's Club well at 59 million cubic feet per day, which is a record 24 hour rate for any well in the Utica, or in the Marcellus.

About two weeks prior to Range announcing this test rate, Hart's published a summary of the top 10 shale wells in any play, at any time. If our well had been included in the study, it would have been the number one well.

More importantly, this well has been online at 20 million cubic feet per day, on an interruptible basis, for about 12 weeks, and has produced about 1.2 BCF so far. It's extremely early in its life, but the performance so far is encouraging.

As I mentioned previously, on a stacked pay basis, we have about 900,000 net acres of dry gas potential to drill, and about 700,000 net acres of wet gas potential. I've seen some analysts paint all Appalachian NGLs with the same brush, and value them all the same. Fortunately for Range, that's not true.

There are two key items to consider. The first is the richness of the gas, and the second is the sales contracts the NGLs are sold under.

Because we have the richest gas in the basin, and would appear to be more favorable contracts than others, we receive a significant revenue uplift from our NGLs, as shown on page 18 of our presentation. Our peers might say their ethane should stay in the gas stream. And if their gas is leaner, and if their contracts are not as favorable, maybe they should.

For Range, we continue to build in our portfolio of agreements for all products, which spreads the market risk of our products across multiple pricing structures, multiple outlets, and with multiple counterplays. For 2015, the strategy is serving this well, as more than 80% of Range's ethane is tied to gas- or oil-linked indices, rather than Mont Bellevue.

When Mariner East comes online in the third quarter, Range will be further advantaged as a producer, exporting NGL products outside North America. In addition, our propane will be transported more efficiently on pipe, rather than trucks and rail, adding approximately $50 million to cash flow annually, just on propane transport savings.

Going forward, as we continue to grow in size and scale, we'll have the opportunity to find new markets. And I expect our teams will continue to find innovative ways to maximize cash flow.

I'll now turn the call over to Roger.

Thank you, Jeff. Winter weather usually brings higher oil, natural gas and NGL prices, paired with higher operating costs. Despite a colder than average winter, the first quarter of 2015 did not follow this pattern. Realized price for Mcfe was 28% lower than last year's first quarter.

However 26% higher production and 15% lower unit cost, combined to generate $423 million in first quarter revenue from natural gas, oil and NGL sales, including cash sale derivatives. This top-line figure was only 10% below last year's first quarter, despite the headwind from 28% lower prices.

The operating and administrative expense story, for the first quarter, is an exceptionally good one, effectively bearing the brunt of much of the decline in prices. As I mentioned earlier, the winter weather of each year usually brings higher expenses, as our field professionals cope with the challenges of an often brutally cold operating environment in Appalachia.

This year was even colder than normal, but our operating teams really delivered. Not only did we beat all of our unit cost guidance figures, direct operating expense was lower than last year on an absolute basis as well. The same applies to G&A expense and interest expense during the first quarter, all below unit cost guidance and all below last year, on an absolute-dollar basis.

Cash flow for the first quarter was $207 million, and EBITDAX for the quarter came in at $244 million. Cash flow per fully diluted share was $1.24. These figures were 21%, 20% and 23%, respectively, lower than last year, due to realized prices.

First quarter book net income was $28 million. And earnings, calculated using analyst methodology, was $31 million, generating earnings of $0.19 per fully diluted share.

The non-GAAP measures that I just mentioned, including EBITDAX and analyst earnings, are fully reconciled to the GAAP numbers in various supplemental tables, which may be found on the Range website, under the investors tab. Looking forward to the second quarter, please reference our first quarter 2015 earnings press release for detailed, expense item guidance.

Now turning to the balance sheet, our first quarter, trailing 12-month debt to EBITDAX ratio, was 2.9 times, roughly equal to last year's figure of 2.8 times, and below the 3 times figure from the year before. Despite lower realized prices, our first-quarter leverage is essentially the same as prior years.

Range added additional natural gas, oil and NGL hedges during the first quarter for the remainder of 2015, as well as additional hedge volumes for 2016 and 2017. Details of these additional hedges may be found in the earnings release, the 10-Q and the investors tab on our website.

The first quarter of 2015 reflects the impact of lower year-over-year prices for all of our products. However, the quarter also reflects an appropriate response to this environment, by the Company. Strong production growth, significant reductions in cost, on both the unit and absolute basis, additional hedges and continually improving capital efficiency, driving some of the best well results in our history.

Ray, over to you.

Thanks, Roger. At Range, we believe there are three key facts the differentiate us from our peers. Number one, we have a large and high quality position that is low risk and repeatable.

Having stacked pay potential of 1.6 million acres in the core of the highest hydrocarbon in place, in the Appalachian basin, opens many doors for us in the market. And historically, throughout this business, the rock rules. And our results indicate we've captured some of the best rock in North America.

Number two, our team continues to lead the way in innovation, while delivering great well performance and capital efficiency. And we believe our track record over the past several years supports that.

And number three, we have product diversity, with large positions in both liquids rich and dry gas, coupled with our first-mover advantage, low-cost transportation and favorable sales contract, this gives Range a unique and significant competitive advantage.

Execution is the key in 2015 and we're on track with our planned $870 million CapEx budget, and to achieve our targeted annual growth of 20%. Maintaining our low cost structure and continuing to improve well performance is a core focus at Range. And, even though Range is already one of the lowest cost operators, our cost metrics continue to improve.

As Roger pointed out, our cost structure is improving on both an absolute and unit basis. Our operating teams are continuing to find ways of increasing efficiencies, enhancing our well designs and lowering costs, while achieving better and better well performance, all allowing us to get 20% growth from a bigger base, with $700 million less capital than last year.

For the first quarter, our production averaged 1.328 BCF equivalent per day with 33% liquids, and represented 4% growth over the fourth quarter of 2014, and 26% growth compared to the first quarter 2014. Our growth profile for the next three quarters shows production being more heavily weighted to the third and fourth quarters. Just as it has been in the past, and it should set us up well, with momentum going into 2016. Guidance for the second quarter is 1.345 BCF equivalent per day, with approximately 30% liquids.

In Southwest Pennsylvania, on the drilling side, Range is in an excellent position, regarding the terms on our drilling rigs. We're presently on well-to-well contracts on six of our nine rigs.

Of the three rigs that are not well-to-well, all contract terms will expire within the next four months. This has allowed us to capture significant reductions in day rates, and other services, along with providing us flexibility in shifting rigs and capabilities around, to optimize our fleet.

We believe this gives our operating team a huge competitive advantage in driving down cost, introducing new technologies and improving the overall performance of the fleet. On the completion side of our operations, the team pumped over 1,000 stages in the first quarter, averaging over 6.5 stages per day.

That is 84% more stages in the quarter, and 43% more stages per day, than the same quarter last year, with 2 crews, versus 1.6 crews last year. In March, they set a new record of 424 stages for the month, with a new one-day record of 23 stages. I want to offer my congratulations to the team for an outstanding job.

These types of gains promote high utilization rates for our service providers, allowing us to work together with them, to achieve some of the lowest cost and best valued services in the industry. These operational gains also shorten the time between capital being spent, and the realization of production revenues, translating to better use of our capital and quicker returns at the bottom line.

It simply allows us to do more, do it quicker and do it for less cost. And, will allow us to grow more efficiently in 2016, as these improvements continue.

Late in the first quarter, we brought online and new Southwest Pennsylvania dry area pad, with the first well going to sales at 31.3 million a day, with a lateral length of 7,906 feet, with 41 stages. We have been flowing this well now for 20 days, at an average rate of 21.4 million a day. And there still two more wells on the pad to be brought online in the second quarter.

And, just last week, we brought online a new well in our wet area, with an 8,668 foot lateral, completed with 45 stages. And it produced the sales, for 24 hours, at 43.4 million cubic feet equivalent per day.

That is 19 million gas, 520 barrels of condensate and over 3,500 barrels of NGLs. We believe this well has now set the record for the highest 24-hour production rate to sales, in the entire Marcellus play.

As a quick reminder, I want to make three important points. Number one, the production rates that we report, whether they're initial sales, 30-day averages or production reported over any length of time, have been, and will always be reported, at actual conditions as constrained by the production facilities and the gathering system.

Number two, the wells on a pad tend to come online at staggered times. Very rarely are we able to bring more than one or two wells to sales, off the same pad at the same time, as we simply don't design the system to handle those high and short-term initial rates. What we have demonstrated over the years is, this is the most cost-effective way to manage the compression and gathering system for the long-term.

And number three, while these are outstanding and record-setting initial sales rates, they're not appreciably different from what our team forecasted that these wells would produce. In other words, wells like these were built into our model and production forecast. And I believe our team is one of the best out there, in understanding the rock and getting the most out of it.

The initial sales rates only tell part of the story. What is really important is how these wells perform overtime.

Just about a year ago, we announced a record five-well pad in our super-rich area, that came online with a per well average of 28.6 million cubic feet equivalent per day, or 4,773 BOE per day, with 65% liquids and they had an average lateral length of 6,635 feet and 34 stages. The record well on the pad, that we announced a year ago, and still the record liquids-rich well in the basin, meaning wells that have more than 60% liquids, was 38.1 million a day, from a 7,065 foot lateral with 36 stages.

As of the end of March this year, that pad has produced 10.6 BCF equivalent, which is 5.7 BCFs of gas, 223,000 barrels of condensate and 831,400 barrels of NGLs. I believe if you look at that pad, on an absolute or normalized basis, it is among the top performers in the region.

Also, about six months ago, in the Southwest Pennsylvania dry area, we announced a pad with three wells, that had a 30-day average rate of 17.4 million a day, per well, averaging 5,364 foot laterals and 28 stages. As of the end of March, those three wells have produced over 6.1 BCF, with the largest well at 2.6 BCF. Again, in the dry gas area, we believe these wells are clearly among the top performers in Southwest Pennsylvania.

In addition to the quality of the rock, we believe these examples of long-term performance also illustrate the diversity, and highlight our ability to manage long-term sustainable growth at very attractive economics, whether it is dry or liquids-rich gas. As Jeff referred to in his remarks, our first Utica well in Washington County, Pennsylvania, has now been online since late January, constrained at a designed maximum rate of 20 million a day and has produced from 1.2 BCF of gas thus far.

Albeit early, the well is meeting all our original expectations. It's producing on an interruptible basis, meaning it is up and down and not at a constant rate. And before anyone asks, it's still too early to make an EUR prediction.

The second well, which is an opposing lateral on the same pad, is being drilled, and is still on target to be ready for sales this summer, which is about the same time that our permanent facilities will be ready. And the third well is still on schedule to be drilled later this year. Costs for the second well are still targeted to be approximately $13 million gross, which still includes some science. And as we get a few more wells under our belt, we believe those costs could come down another 15% to 25%.

We expect that the Utica will be different from the early years of our Marcellus play, in that it can be drilled in a true development mode, right from the beginning. Most all our Utica wells are expected to be drilled on Marcellus pads, making use of the existing infrastructure. Step-out wells won't be necessary, since we have deeper penetrations, lots of offset wells and 3-D seismic over most of the area.

Essentially, we can drill the wells like a very efficient manufacturing process. The Utica infrastructure will be easy, as it is dry gas. And we have existing right of ways, in which we can lay additional pipes.

Considering that early results indicate we have 400,000 net acres of core, dry-gas Utica potential under our Marcellus position in Southwest Pennsylvania, we believe this play gives us another attractive option for significant growth and value creation going forward. Our team is working on options to begin a Utica drilling program as early as next year, if the market conditions support.

Shifting to Northeast Pennsylvania, our team continues to lower cost and bring online really impressive wells. And we expect to continue the year with one to two drilling rigs. Of note, our most significant well of the quarter had an initial rate to sales of 26.1 million a day, with a 30-day average rate of 21 million a day, and a 60-day rate of 19 million a day.

The well was completed with the 5,514 foot lateral and 28 stages, for a total well cost of approximately $5 million. And we expect an EUR of over 3.3 BCF per 1,000 foot of lateral.

Following up on our top well, in the same area, that we announced about a year ago, the initial 30-day rate to sales on that well was 25.1 million a day and it produced over 4 BCF in 12 months. Again, in this area, we're also seeing significant operational gains, along with up to 25% lower cost. Like the super rich, wet, dry, Upper Devonian and Utica in Southwest Pennsylvania, this area offers yet another highly attractive area for long-term and sustainable growth.

Like Jeff said in his remarks, 2015 is a challenging year for commodity prices. But I'm happy to report that Range is continuing to work safely, improve our operational efficiency, lower our cost structure and, at the same time, continue to improve our well performance.

I also want to note that, we have relayed to all our employees that a tightened budget does not mean cutting corners. In fact, despite current market conditions, we have increased our focus on environmental compliance and safety. Safeguarding the environment and our employees, along with our contractors and the communities where we live and work, is a core philosophy at Range.

When you think about the fact that we had our best operating efficiency gains to date, combined with some of the best well results to date, this quarter, again, demonstrates our ability to grow value at the bottom line more and more efficiently. As I have often said, the rock rules. And we believe we have captured a large position, with stacked pay potential, in the best rock in the basin.

Coupled with an experienced team, we have been able to achieve these results and have a consistent track record of growth, with lower and lower cost. And we believe we're still in the early innings of the ballgame, as we continue to drill longer laterals, implement improved completion designs and improve operational efficiencies. We still have not drilled our best well yet.

Now, back to Jeff.

Operator let's open it up for Q&A.

(Operator instructions)

Doug Leggate, Bank of America Merrill Lynch.

Good morning, everyone. Jeff, clearly I'm going to take Ray at his word, I'm not going to ask you about the EUR in Utica. However, clearly the results are pretty stunning, obviously. So, I guess what I'm trying to understand is, things are pretty well set up, it looks like, to really move very quickly on this program.

What gives, to basically make space for it? In other words, how would you prioritize what you're seeing in the Utica versus, for example, the equivalent opportunities in the Marcellus? And have a couple of follow-ups, please.

Okay. What our plan is, is to -- we got the first well online, 12 weeks, you are right, so far, we are very encouraged. Permanent facilities for that first well, will be there about the middle of the summer. We have spud our second well. And the plans are to put both wells online, in the permanent facilities the summer. And then we'll spud a third well after that.

Obviously, we are doing a lot of pre-planning, for a success case. How would we move the gas? And also, the key then will be, as we get to the end of the year, and we have three wells, and we have longer production history. What do the economics and returns look like versus a Marcellus?

You're correct, it could be a change in capital efficiency or another way for us to grow with better returns or better capital efficiency. To the extent it looks like that at the end of the year, and it could be, then you will see us work the Utica into our 2016/2017 programs, and beyond.

I appreciate that. A related question, then: so, you have obviously now got a very large opportunity, literally under your feet. So, lack of any mention in this quarter of the Mississippian, and it really raises the question of, what do you consider core? Or rather, what do you consider non-core, now? I would ask specifically about Nora and the Mississippian, in terms of whether they are going to be able to compete for capital. And then, I have one final one, if I may.

It's a good point. I'll answer it in this way. If you look at Range historically, since 2004, we have sold roughly $3 billion worth of assets. That has done several things for us. It has allowed us to continue to focus our capital into our highest return, best projects.

It keeps us focused. It's driven down our cost structure. It's driven up our returns. It's been a source of funds. So clearly, when we see that other people value those assets higher than we value them, we will do what we think is the right thing for the shareholders.

In the mid-continent area, we have roughly, I don't remember exactly. I'm going to say 75 million per day and about 360,000 net acres. We have a big footprint, a lot of production. And we will do what we think is the right thing there, ultimately, for shareholders.

And then, we have what, 170 million per day and 460,000 net acres, basically in the southern Appalachian division, basically in Virginia. So yes, we always look at those things. And we look at how it would compete for capital, and what is the best way to manage those assets, going forward.

Is it an active process underway at this point, Jeff?

We're always active. We're always looking at the opportunities and considering how to best maximize the value of the assets for the Company.

Okay. My second one, hopefully, is quick. So, OpEx and CapEx cuts the prospect of our gas price recovery. If you're growing at 20%, having already cut your capital $700 million, what do you do with incremental cash flow? Whether it comes with CapEx reductions, or better gas prices? And I will leave it there.

Thanks.

I think in the short-term, if you're looking into 2015, to the extent we get service cost reductions, or other things happen, I don't think -- we're not going to change our guidance for 2015. It is 20%. CapEx will be the same. To the extent we're more efficient, it might help us better set up 2016.

Plus, I think the other thing to remember, that maybe helps to distinguish Range from its peers, or one of several things, is our production profile is backend loaded. And it has been that way every year for the last five years. So we see relatively, a little bit of growth in the second quarter. But the big growth in third and fourth. What that does then, is really help set up 2016.

And then, with the portfolio we have, looking at 2016 and beyond, then it's a matter of -- we're in a fortunate position that we're in the core of the Marcellus Upper Devonian and Utica. We have 900,000 acres of dry and 700,000 of wet. We can drill up and down that section, and back and forth. So we will be able to -- we will maximize returns as best we can, going forward from there.

Thanks for taking my questions, Jeff. I appreciate it.

Thank you.

Bob Brackett, Bernstein.

Hi, good morning. You all replaced your debt to EBITDAX covenant with an EBITDAX to interest expense covenant. Can you talk about how easy or hard that discussion conversation was? And what the new covenant lets you do?

Sure, Bob, this is Roger. It's a good question. It was actually a pretty easy conversation, as evident by the fact that all 29 banks unanimously approved the change. It only required a 51% vote, no bank chose to be carried. They all stepped up and did the right thing. And we're very pleased and proud of them for doing that.

The reason is that, the covenant really no longer fits. We redid our bank facility in the fourth quarter last year. And, in that process, we went to an annual borrowing base determination. A lot of folks really didn't pick up on that, but it was a pretty big change. It saves us a lot of money. It helps us manage our affairs better, over the long-term.

But, when the banks do the borrowing base determination, they basically take all your cash flow until your next review date, and toss it out. So in our case, when you went to a fully one-year re-determination, they took, essentially, over a year of our cash flow out, through April of the next year, which encompasses a lot of our hedges and everything.

So you can see, with the $3 billion plus borrowing base that they approved, we're real pleased that that ratified our liquidity and our position. The borrowing base is, that's their primary tool to manage leverage.

And the reason is pretty simple, it's a forward-looking test. It's basically a PV noncoverage test. So, the best way to work your growth, is to be looking out the windshield, and working the break and throttle, accordingly. And that's why the banks rely on that test, first and foremost.

The debt to EBITDAX covenant, that's a rearview mirror test. So, it's really not as applicable to managing leverage over time. In our case, the covenant was a no harm, no foul covenant. We're never anywhere close to that ratio, never intend to be anywhere close to that ratio.

But looking at it after getting through the restructuring process, we just decided that an interest coverage test was more appropriate. We rely on the annual borrowing base determination to work with our banks, to keep leverage where it needs to be. And that rearview mirror test just didn't make sense for us anymore.

And, the banks agreed with us, and we made the swap. And it just removes a source of potential concern from investors, that may not have an in-depth knowledge of the process.

Great. That's great color.

Quick follow-up. You talked about your rig contract roll off, and the strategy there. Can you talk about your completions contracts, and the strategy for keeping them busy? Do those contracts roll, or are they longer term?

Bob, this is Ray.

We really don't have any long-term frac contracts. We have what we more commonly referred to inside the Company, as relationships. We've had, for instance, Frac Tech doing the majority of our completion work in Southwest PA, really for, almost since 2007.

And so, that long-term relationship allows us to work with them on key performance indicators, that help us work more efficiently. And then we're able to arrive at pricing based on the market, and utilization that allows us to do things that a lot of our competitors can't do. That consistent strategy over the years has allowed us to innovate with a lot of things like new manifolds that our teams designed, and new liner systems to protect the pads. And, all those sort of things that have allowed us to go forward.

So we don't really, technically, have any long-term frac contracts. That was one of the things that allowed us, like on the drilling rig side, to take advantage of what we we're seeing happening, back in December and January, work with our supply-side vendors and suppliers to create prices where, they could still work, and we could still continue on with some pretty significant savings. And I think that was way in advance of what a lot of our competitors were able to do.

Great. I appreciate it. Thanks.

Brian Singer, Goldman Sachs.

Thank you, good morning.

Your lateral length in the two Southwest Pennsylvania Marcellus wells, you highlighted today, was in the 8,000 foot to 9,000 foot range, which is well above your average.

Could you just update us on how significant your ability to drill wells of this lateral length in your Southwest dry and wet gas acreages, from a contiguous perspective, whether you see these types of results as repeatable? And maybe I'll ask an EUR question on this, what the impact on EUR and well cost per thousand feet of lateral is versus your base case said, slide 17 assumptions?

Yes, Brian, good questions.

Like Jeff said in his opening remarks, we have only touched a small, small number of the total potential locations that we've got left to drill. We don't have -- while we do have a lot of units formed, we don't really have a lot of limits on the lateral length that we can do, going forward. So, we do expect to continue to significantly increase lateral lengths, by year, going forward.

And I think eventually you will see our average up there, in the 8,000 foot to 9,000 foot range. Of course, every area will have a different optimal lateral length, depending on liquids and reservoir pressures and all the different things. Because remember, we have a huge position there in Southwest Pennsylvania. So the Marcellus is not the Marcellus all -- it's not the same all across that property.

We have super rich, wet, dry. We have thicker areas, higher pressure areas, a little bit deeper areas. So, all of those wells will be designed differently. But, we do expect to get significantly longer each year.

Those longer wells that we talked about in the remarks today, they were in the plan. That's part of what makes our average go longer this year. And, our team is continually able to push those wells out. We have, in fact, drilled wells that are much longer than those. So technically, mechanically, from a land standpoint, there's really no limits of what we can do.

What I would like to point out is, look at some of those wells, for instance, in that 8,000 foot to 9,000 foot range. And, compare them to some of the offsets in the flank areas, that are not as good of rock. And I think you'll start to see what we get excited about, talking about the longer laterals, and how much more capital efficiency and well improvements we're going see, going forward.

From your standpoint of --

And totally to clarify that, I know that what Ray means. When he's saying flank areas, he's saying our acreage is core. You can look at other operators who have drilled outside of what we feel are core areas, who have already drilled longer laterals like that, and then compare them on a rate basis, or EUR per thousand foot, or per space. Sorry to interrupt, Ray. But for our listeners, I wanted to make sure that was crystal clear.

Good point-out. And then, on your point on well cost, again, those were also forecasted in to our model, and our plan this year. But, if you'll look on page 8 in our presentation. For 2015, in Southwest PA, we give you a cost per foot for those wells. That is for the average well that will turn to sales this year.

And if you were to think about it from the standpoint, longer is certainly better, because economies of scale kick in, and so forth. So, longer laterals do get cheaper on a per foot basis. And, we have seen well performance hold rock steady.

In fact, I think these two wells will probably end up having some of the highest performance on a per 1,000 foot basis of any of the wells in the area. So, we do see good improvements going forward.

And the third point I want to make is, we really (inaudible) forecast. Our team is getting really good at understanding this rock. And I think our track record supports that. But they were forecasting rates pretty close to these, in our model.

So that is part of what was a significant point in allowing us to reach 20% growth this year, with $700 million less capital. It's what we have been saying for many years is, our capital efficiency is going to flow through as we drill longer laterals, and our team gets better at getting more out of the rock. And like I have said, you probably get sick of me saying it, but I'm going to keep saying it. The rock rules. And we think we have got a core position, where all of this is possible. And we're in the very early innings of the ballgame, because we have got thousands and thousands more of these wells that we can do, as we get better and better.

And, I'll just add again, a little bit to what Ray said. I totally agree with what he's saying, the rock rules. But you want to have the high-quality rock and the core in an area of good infrastructure, with favorable takeaway, and contracts to external markets. And I'm sure Chad, at some point, will hit on some of those.

That's helpful. My follow-up is, you highlighted in your opening comments, the unique attractiveness of your NGLs contracts. Beyond the start up of ethane exports later this year, can you talk to what you see as differentiating your ethane and propane net backs, versus others? And, whether you see a situation in the market, whether to maintain pipeline spec, portions of your ethane or propane production would, at least temporarily, be a drag to cash flow?

I would like Chad to answer that question. But Chad, if you would, could you also talk about some of the gas contracts for the second half of the year? Because it's really all three products. Natural gas and NGLs and condensate.

Yes, right. This is Chad, Brian.

As Jeff mentioned in his notes earlier in the call, 80% of our ethane is tied to either oil or gas indexes. So, that is already reflected in the prices we show in our financials.

Once Mariner East starts up, 20,000 additional barrels of ethane will be going to market, so it can go into international markets, priced at a NAFTA, Brent-crude sliding scale formula, which will, again, improve our cash flow. We focus more on improving our cash flow than we do our per unit metrics. So that is an important point we try to make in our slides on 37, 38 and 39 in our slide deck.

Once Mariner East is in service and flowing later this year, we -- going forward, our LRP forecast, we don't need any more ethane projects to meet spec. We can grow our production under the LRP, up to as much as 3 BCF a day. So, we don't need any more projects. Mariner East will also help in propane service, because we can flow 20,000 barrels a day, and load ships at a very high rate, once that is in service.

Jeff referenced our gas contracts. As reflected in our slide deck, we show what our firm transport capacity projects are. And later this year, we have our Spectra Uniontown to Gas City project coming online, which takes 200,000 a day up from capacity, over to the Midwest, where we can get much better pricing. The indices over there are very stable. And then later, in 2016 and 2017, we have other firm transport capacity projects coming online, which again will take our gas away from the Appalachian basin, to more stable of indexes and help improve our cash flow.

Thank you.

Dave Kistler, Simmons & Company.

Good morning. Real quickly, looking at the CapEx this quarter, down 45% quarter over quarter, and keeping your full-year CapEx guidance, which would imply that it continues to step down, similar to what you outlined with rigs falling off contract, et cetera. Can you break down for us how that CapEx decline, both this quarter and going forward, is split between lower activity, lower service cost and better efficiency gains?

Dave, this is Roger.

Let me answer the first half of your question, and then I'll pitch it over to Ray, to talk more about where the capital is going, later in the year. Just one thing I wanted to highlight. There was a big working capital swing in the first quarter. So, over $100 million of the incremental debt and spending was due to working capital.

So, there's a Delta between the cost incurred schedule and the cash flow. So, please go through the Q or give our guys a call, and they can walk you through that. So the CapEx increase, depending on how you measure it, is not as large as it first may appear. But I will tell Ray tell you exactly where the money is going.

Yes, Dave, when we put together the CapEx plan for 2015, we did plan in there some service cost reductions. And I talked a lot about that on the first call. If you looked at our well in Southwest Pennsylvania where the lion's share of our CapEx is going, and you looked at a well in February, compared to December, on apples to apples basis, we're seeing 23% to 25% less total well cost, as a result of service cost reductions.

Those numbers were built into our plan this year. But it's also important to realize that, all those savings did not kick in on January 1. They really kick in towards the end of the first quarter, and then they start flowing through the rest of the year. So, I think you'll see, the CapEx will come down, quarter over quarter.

Because we tend to have more rigs running at the first part of the year than we will at the last part of the year. And that is pretty much the same that it has been every year. So, I don't see that as a whole lot different. But, hopefully, that is a little more color on how that comes together.

Yes. And then, just to reemphasize, we still feel comfortable, and are confident with the 20% growth, at $870 million.

Great, I appreciate that clarification. And then, maybe switching a little bit to some of your slides where, I know you put some of this out last quarter as well. But, you highlighted the benefit of the optimized completions and the down spacing in the Marcellus. And then, in the optimized completions in the Nora area. Obviously, nice step up, uplift in production, associated with those.

Does that maybe, argue for going back to existing wells and doing optimized completions, or refracks, on those existing wells? Just given that they would be even lower cost, and probably generate with 50% uplift at production, versus what you had done before? Maybe even a better rate of return, than drilling original wells?

Yes, Dave. I mean, we did talk about that example that we put in there last conference call, on page 36. And that was an exact case that you just described, where we went into a well, a pad that had five wells on it that were two years old, had been online for two years. And we put three new wells sort of in between the laterals. And there were really, three things we wanted to test.

We wanted to test how much less would the wells cost, drilling them on a -- since all the existing infrastructure: roads, paths, water, gathering system and all that sort of thing was already there. Number two, did the new wells interfere with the older wells? And then number three, how much better would the new wells be, with the newer completion technology?

And number one, the wells were $850,000 apiece cheaper. And we think that number could even be higher, as we began to do more of this as we go forward. Number two, there was no impact to the older wells, which I think is very significant. And, I think that you have read a lot about our competitors that are in non-core areas, they have not been able to do that, where they have seen big hits on their other offsetting wells.

And then the third thing, the wells produced 53% more production in the first year, as compared to the older wells. I think early on, the IPs were four times higher. So clearly, we see that as unbelievable upside going forward, because we clearly have a lot of those pads already out there, some of them as much as eight or nine or ten years old, almost.

So, I think that going forward, you're going to see us, probably in about 2017 or 2018, as we get into our further plans down the road, where a bigger and bigger percentage of our wells each year, will be going back on to those existing pads. And we see that is a huge step change, in both well costs, efficiencies and well performance. And also in gathering system costs, because your gathering system is already there, already been mostly paid for. So essentially, those wells will produce at a much lower gathering fee.

So, we see that as big potential going forward. There's not really any of those wells planned this year, as we're still trying to really optimize our program, to try to get the wells -- the final HBP work done that we need to get done. The infrastructure buildouts that we're still doing over this year and next year. And I think that is big potential that we see, going forward.

Okay, I appreciate that. But maybe one, just clarification. Other than drilling in a tighter spacing, would you look at going back to an existing well, and refracking it?

We're hearing about recompletions from other folk that are seeing that as a positive, and obviously, from some of the service companies commenting on that. How do you think about that in your inventory? Or, is it really, we're going to finish HBP, and then we'll consider those things?

Well our team, I think, is probably, technically, one of the most gifted teams in the industry. They are continually coming up with innovations and new ideas and concepts and sort of things.

We have studied and talked about refracks for some time. I, personally, have a lot of experience with refracks, most of which was not that good. So, we don't really see the refracks as big potential, going forward. It's certainly not anything we're counting on. But we will clearly study it, as we go forward.

And my overall statement for refracks is, if you really messed something up the first time, then there is potential that you could do something if you went back in there. But, we don't see that as big potential, and it's certainly not anything were counting on going forward.

Great. I really appreciate the clarification. Thanks so much.

Thank you.

Neal Dingmann, SunTrust.

Good morning, gentlemen.

Just to follow-up on the slide 36, someone was asking about the down spacing. Just a question now. Have you looked at that, as far as, in the entire southern Marcellus and the northern Marcellus area? And, are you confident now that that is going to work in most of the area? Or, is that still isolated to core areas of each of those respective regions?

Yes, Neal, this is Alan Farquharson. I think that, what we have seen so far is, we've done a fair amount of activity in the wet and super rich area. Our plans are to do some additional testing in the dry. We're also looking at what some of our competitors have done as well. Obviously, we don't have to spend all the R&D work.

But, we believe fairly comfortable, that you will be seeing a significantly tighter spacing in the wet and super rich. We also believe, but we don't have yet, the data, to really feel comfortable yet. That we'll probably see some of that happen in the dry areas, as well.

We think some of it has to do with, just the quality of the rock that we have at the end of the day, compared to what our other competitors have.

Got it. And then, obviously you have had two monster wells in the southern Marcellus, between this recent Washington County well, the 43.4 million a day test rate. And then obviously, on the heels of this one in December. A couple of questions around that.

First, on that, I noticed both, or you mentioned in here, that your Utica is flowing around 20 million a day. Could you just talk about how you see, given these monster IP test rates that you have, how you think about the sales, or the choke program that you have, once you see these huge test rates?

Well, that's a good question, Neal. And, one thing I want to correct you on, those are not just monster wells, they're monster pads. Because they both our multi-well pads, and we just simply hadn't been able to turn the other wells on yet. But, we expect actually, pretty similar results from the other wells on the pads.

Part of our long-term goal that the team works on, sometimes three, five and seven years in advance is, looking at the gathering system. And, we have very intricate models of the gathering system, working with MarkWest on deliverability at any given point, compressor station upgrades, processing plants, and so forth.

So, all of this has been built into that plan. And we don't have a choke management program, as a gimmick or a fad or anything like that, to manage the wells. Were simply trying to produce those wells at what we believe is the optimum performance that will generate the best economics for the project at the end of the day. It is a long-term look that we take at it.

Initial production rates are great, they're fun to talk about. It is kind of a yardstick to compare wells. And in a case like these two monster pads, you had a lot of facilities there for maybe three wells, or five wells, depending on how many wells were on each pad. What you end up doing is bring one of the well on, and just let it produce through the facilities that all five wells might use, to see what it is capable of.

In actuality, we'll probably choke that well back and then start opening up the other wells, and try to get them online. They'll all be produced or constrained conditions for quite a while, in that case. But that's the way we designed it, going forward.

And we think that keeps our cost structure down. It is better planning with MarkWest, which allows them to keep their cost structure down, which in turn gets us lower gathering fees. And again, we're really focused on the years ahead, and watching that gathering fee falloff, as we go back in and fill in on these areas.

We think that is the most efficient way to develop this project, long-term. Because again, we have only touched a very small portion of the total number of locations that we can drill going forward, just in the Marcellus. On the Utica and places like that, the other stack pay potential, we've a long ways to go on that also.

As far as the Utica well, when we get the permanent facilities online in the middle of the summer, those wells will be put online and they will be uninterruptible. In other words, we'll be able to hold them at a constant rate. And the production facilities are designed to limit those wells at 20 million a day. And again that's not necessarily for any sort of choke management, or anything that we're worried about on that end of it, as much as it is trying to optimize the cost for those facilities, and that gathering system that we're putting in place.

And Ray, if I could ask one last one.

I know it's not just Washington County. Obviously, that's where these huge pads were for this Marcellus and Utica. But, in this surrounding area, near-term, do you have -- when you have the take away for each of the -- all this Utica production on top of the existing Marcellus production you have there.

What do you have near-term? Could you flow it in the same line? I guess you could, but you really don't want to. Maybe you could just talk about take away, if you would start with Washington County that generally given these huge pads, take away from both the Utica and Marcellus, in this specific area?

Well, I'll start and then let Chad jump in. But again, like Jeff brought up earlier, there's really three keys to a big, successful play like this. One is, you have got to have the rock, and we have clearly done that. Number two, you got to have the infrastructure, and we were blessed.

That 75 years plus of infrastructure was built right through this area. And we were able to tap into all of that, we were first movers in the play. And working with MarkWest, we have been able to put a huge system of interleaks in place there for the wet gas. I think what a lot of people forget is that, there's clearly also, a lot of dry gas lines in that system. There is a lot of residue gas that comes off the plant, a lot of meter taps into the different pipelines: Tennessee and Columbia and line in and so forth. So we have all of that together, growing over time.

And then the third piece, the third cornerstone of it, is the markets, and having actual customers on the other end to use the product. And that has also been a core philosophy of ours for years, is to cultivate not only the firm transportation and the actual infrastructure to get there, but also the consumers on the other end to use that.

So, in part of our plan that the team is currently working on today, to put an effective Utica development program together, which could begin as early as next year, depending on market conditions. All three of those pieces have to be in place. And I will let Chad refer to how we might expand, going forward.

Yes, to expand on that a little bit, because of all the existing infrastructure, we're currently working on a short-term solution to be in service mid-to-late 2016 for what we're calling a header system, which is some pipe that would run through this particular area of Utica development, to get the gas to our existing capacity, that we have to take it to market. And then long-term, that header system, we're going to be able to expand it to whatever direction the Utica and dry gas development takes us.

So having the existing infrastructure allows the optionality to be able to quickly, as the drilling teams come up with these new monster pads, as you described them, we have the opportunity to build out the infrastructure, and we will do so. So we've short-term projects that we're working on for mid 2016. And much bigger projects beyond that, in later years, to help to get the gas out of there.

That's great detail, thanks.

At good economics, at good prices.

Good. Thank you all.

Thank you. Ladies and gentlemen that is all the time we have for questions. I would like to turn the call back over to Mr. Ventura for his concluding remarks.

2015 is a challenging year for our industry. With our current plan to spend approximately $700 million less in 2015 than 2014, and still target 20% growth, we believe that we'll be one of the most capital efficient companies in our industry.

These capital efficiencies, coupled with our large footprint in the core of the Marcellus, Utica and Upper Devonian, and the optionality of being able to drill dry, wet and super rich acreage, as well as the shape of our 20% growth profile for 2015, which is backend loaded, have us well positioned for 2015, 2016 and beyond. Thanks for participating on the call. If you have additional questions, please follow up with our IR team.

Thank you. Ladies and gentlemen, thanks for participation in today's conference. You may disconnect your lines at this time and have a wonderful day.