山脈資源 (RRC) 2013 Q4 法說會逐字稿

Welcome to the Range Resources fourth-quarter and full-year 2013 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.

(Operator Instructions)

At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator. Good morning, and welcome. Range reported outstanding results for the fourth quarter and calendar year 2013, with record reserves, record production, and continuing decrease in unit cost. Both earnings and cash flow per share results were greater than first call consensus.

The order of our speakers on the call today are Jeff Ventura, President and Chief Executive Officer; Ray Walker, Executive Vice President and Chief Operating Officer; and Roger Manny, Executive Vice President and Chief Financial Officer. In addition, we have Chad Stephens, our Senior Vice President in charge of marketing, will be available to answer questions after our prepared remarks.

Range did file our 10-K with the SEC today. It should be available on the homepage of our website, or you can access it using the SEC's EDGAR system. In addition, we have posted on our website supplemental tables which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, cash margin, and the reconciliation of reported earnings to our adjusted non-GAAP earnings that are discussed on the call today.

Now, let me turn the call over to Jeff.

Thank you, Rodney. I will begin by looking back on what we accomplished in 2013, and then I will look ahead to what we expect for 2014. Last year, we grew production 25%, with a capital budget of $1.3 billion. Cash flow increased 25% year over year, and cash flow per share debt-adjusted also grew 26% year over year. Our proved reserves grew 26%, to 8.2 Tcfe, which equates to replacing 612% of our production. This was done at an all-in cost of find and developed of $0.61 per mcfe. Reserves per share debt-adjusted increased 25%, while production per share debt-adjusted grew 26%.

As a result of our development activity, we have moved 6.4 Tcfe of unproved resource potential to proved reserves over the past four years. Because of this excellent performance, our total DD&A rate has declined from $2.33 per mcfe in 2009, to $1.44 in 2013, and in the fourth quarter of 2013, was $1.36. Looking at this same time period, our operating expense per mcfe declined from $0.83 to $0.36, and in the fourth quarter of 2013 was $0.36.

The bottom line is that Range is continuing to improve its capital and operating efficiency, and the results are flowing through to the bottom line. Net income for 2013 was $116 million, up from $13 million in 2012. Late last year, the Mariner West project became fully operational, and the ATEX project started line fill in December. Also in December, we reached two new milestones as our gross Marcellus production reached 1 Bcfe per day, and our corporate net production reach 1 Bcfe per day. In summary, 2013 was an excellent year in both operational performance and financial performance.

Looking to 2014, I believe there'll be three key items that will distinguish performance between companies in our industry. The first is owning a sizable acreage position in the core area of one of the key plays, such as the Marcellus. The second is the ability to consistently execute well. And the third is having a strong forward-thinking marketing team.

The first item is critical because the application of the technology of horizontal drilling and multiple-stage hydraulic fracturing has been applied to most of the domestic basins. Therefore, most of the major plays have probably already been identified and leased. The key, then, is to already have a large, concentrated acreage position in the core of one of the key plays. The economics are very different in the core versus non-core portions, due to the differences in rock quality and its impact on productivity of wells.

It's also interesting to note that, in shale plays, the core areas usually represent a small fraction of the play, somewhere around 6% to 17% of the total shale acreage. The non-core, then, totals 83% to 94% of the play. Fortunately, we have a huge position in the core of the Marcellus, which is the best gas play in North America, maybe the world, given the economics of the Marcellus and rest elsewhere.

I also believe the ability to consistently execute at a high level will be key in 2014. In 2013, for instance, simply drilling a horizontal well and announcing a high [AP] rate was sometimes sufficient to increase the Company's stock price. At this point in time, those plays and resource potential are considered [noon], and I believe they're reflected in their stock price. The key now will be to consistently drive up oil and gas production from these plays.

Fortunately, Range has a 10-year track record of consistently meeting or exceeding its targets, a 10-year period with a 20% CAGR. Although past performance is no guarantee of the future, we have created a team and culture that consistently performs and meets or exceeds targets. Time after time, rather than succumbing to events like freezing weather, hurricanes, and significant infrastructure delays, our team finds ways to overcome and achieve its targets.

Third, for 2014 and beyond, having a strong forward-looking marketing team will be vital. Given the renaissance of the US oil and gas business, supply is temporarily ahead of demand, although I firmly believe demand growth is coming. We believe that Range is very well positioned in this category, too. The best evidence for this, again, is our performance.

After discovering the Marcellus in 2004 and bringing the first well online in 2005, we knew the quality of our gas was very high BTU and would not meet pipeline specifications because it contained so much ethane. Early on, some in the industry viewed gas this rich as a negative, and we were approached by some companies who wanted Range to pay a fee to them in order to fix our ethane problem.

Rather than accept this solution, our team was very creative in building a diversified portfolio of three ethane contracts based on three different pricing formulas that would not only ensure that our gas met pipeline quality specifications but would also provide market diversification and enable Range to grow production to greater than 3 Bcfe per day.

Very importantly, rather than these solutions costing us money, our team's solution enhances the value of the project. If all three marketing arrangements were fully operational today, Range's ethane revenue would increase by 25%, compared to leaving ethane in the gas stream. That's net of all transportation and processing cost and including additional propane recovery.

I believe this is the best ethane sales portfolio for any company in the US, and it's a direct result of our team doing the hard work to make a reality of what many people thought could not be done, such as selling ethane to companies in Norway and Canada.

The same is true for our propane marketing. In addition to supplying propane into good markets in the Northeast in the winter, we can now seasonally export propane to Central and South America, and Europe in the summer. Our marketing team is also ahead of the curve in making sure that we can move and market our natural gas.

In addition to marketing gas in the Northeast, in 2013, they added 25 new customers in the South, Southeast, Mid-Atlantic, and Midwest; secured firm transportation and firm sales to get the gas to the customers; and hedged price in basis. We have tied the sales price of our gas to approximately nine different indices, creating a strong, diversified natural gas sales portfolio for Range.

We are currently selling our Appalachian gas to customers in Florida; Georgia; Mississippi; Tennessee; Virginia; Louisiana; Texas; Ohio; Pennsylvania; New York; New Jersey; Massachusetts; Delaware; Maryland; Washington, DC; Connecticut; North and South Carolina; Indiana; and Illinois. By 2017, our marketing team is working to have the capability of selling our Appalachian gas to customers as far west as Wisconsin, on a line south to Texas, east to Florida, and north to Maine. We're projecting that we could be able to move 4 to 5 Bcf per day of Appalachian gas to where two-thirds of the current US consumption exists.

For 2014, there will most likely will be intermittent challenges in Appalachian moving gas and in basis differentials for some in the industry. By 2015, we expect that the market improves, as Texas Eastern turns part of their pipeline around to flow gas South, and by late that year, Transco is expected to have in service their partial reversal to move gas out of Appalachia as well. In 2016, we believe we'll see more Transco, Columbia, Gulf, and Texas Eastern capacity going backwards, as compared to the original flows. And, in 2017, it's projected that all of the major pipelines will be bidirectional.

I believe that our marketing team has us as well positioned as anyone in the basin, and better than a lot of the competition. Capacity constraints and basis differentials do not impact all producers equally. The priority of transportation capacity in the markets and pipelines where the production is coming from and moving to are the key differentiators. Range has been and will remain focused on finding creative and effective solutions for marketing our production.

On the financial front, we have a strong, flexible balance sheet to fund our operating strategy. Range continues to build economies of scale, and our cost structure continues to enhance our competitiveness. Range's continued operational success, use of embedded call options on our debt, and the macroeconomic environment with lower interest rates has provided greater access to lower-cost capital.

Overall, for 2014, I believe that we're well positioned. We have a large footprint in the core of the best gas play in the US, a technical and operations team that has demonstrated it can execute well, and a strong marketing team with a demonstrated track record. As always, we'll stay focused on safely executing our plan and being good stewards of the environment.

I'll now turn the call over to Ray to discuss operations.

Thanks, Jeff. 2013 was a great year. We saw improvements in well performance, capital efficiency, infrastructure, and cost control across all divisions. And we expect to see similar improvements in 2014 and beyond, all while working safely. Like Jeff said, we have some really great metrics and reached some important milestones in 2013, but there's just a couple more achievements that I'd really like to point out.

Even with selling our New Mexico assets early in the year, and in spite of the delays in the Mariner West pipeline startup, our teams achieved the high end of our production guidance, at 25% year over year. At the same time, we also saw our direct operating expense decline by 12% for the year. I want to take this opportunity to offer congratulations to all our employees for a job well done in 2013. The innovation and focus on per-share growth, coupled with the core values of cost control, while working safely and maintaining sound environmental protections -- all are translating to the bottom line.

As Jeff described in his remarks, one of the key items that will distinguish companies with an asset base like Range's is execution. Execution is one of our strong points, and getting better at what we do, year after year, is simply what we do here at Range. Let me give you just a few examples based on our last four years.

In 2009, we averaged 57 million cubic feet equivalent per day from the Marcellus, and in 2013, we averaged 719 million per day. That's 1,161% growth over four years. Our direct operating expense per mcfe, corporately, has dropped from $0.75 to $0.36, or a drop of 52% from the fourth quarter of 2010. Three examples from southwestern Pennsylvania for the last four years.

Today, we drill 93% faster, and our cost per foot of lateral drilled has decreased by 24%. Today, we average about 98 frac stages per crew, per month, which is 87% more than we averaged four years ago. And our facilities cost per well is 3% cheaper, while, importantly, cutting construction time in half and deploying design improvements to enhance facility safety, operations, and to exceed emission-reduction requirements.

Needless to say, I can go on and on demonstrating how we've achieved tremendous improvement across many metrics, while always meeting or exceeding our targets. We believe our track record speaks for itself, and, again, the expectation that improvements will continue year after year is supported by that track record. We own the largest net acreage position in the core of the highest hydrocarbon in place within the basin when considering the Utica/Point Pleasant, the Upper Devonian, and the Marcellus. Like Jeff said, having a large acreage position in the core of a top-tier play will be important going forward.

Thirdly, having an effective team to handle the evolving logistics of gas and liquids marketing in the basin is of critical importance. As discussed in our earnings release, and just now by Jeff in his comments, we are well positioned for several years to move all of our gas and liquids. Marcellus and Utica/Point Pleasant volume growth by industry in the region does not affect these plans and commitments.

Range has current firm transportation and/or firm sales in place totaling 1.1 Bcf per day to the key regions previously mentioned, and we have 1.6 Bcf per day lined out through 2016, designed to match our planned volume growth. Keep in mind that we've also built a broad network of strong relationships with primary buyers in these markets, and we'll continue to maximize the opportunity to sell our gas to them under their firm transportation capacity.

Importantly, we are one of the very few companies that kept all of our customers whole during the recent polar vortex storms when others could not, due to the extreme weather conditions. We were able to do this as a result of some really innovative facility designs, coupled with our operations team going 24/7, and so forth. Teaming up with our Midstream partners and led by our marketing group, no Range customer went without product, and that fact is really paying dividends.

As we continue to grow our wet-gas volumes, we work closely with our Midstream partner, MarkWest, to assure that we have adequate gathering, processing, and fractionation capacity. Our inventory of wells waiting on infrastructure continues to be one of the lowest in the basin. As Jeff discussed, our marketing team has been extremely innovative, as demonstrated by our three ethane projects, which again, when all three projects are fully served, Range's ethane revenue would increase by over 25% as compared to leaving the ethane in the gas stream and selling it as BTUs.

For 2014, our CapEx budget will be $1.52 billion, with 87% of that directed to the Marcellus. There's a detailed breakdown of that allocation in our earnings release and in our investor presentation on the website. Most importantly, with this CapEx budget, we've elected to drill our Marcellus wells with significantly longer laterals and more stages than previously announced. This will drive greater EURs and better capital efficiencies that will primarily flow through in 2015. And we expect those lateral lengths to get even longer as we further and continue to optimize our plans.

Production guidance for the first quarter should be right at 1.05 Bcf equivalent per day, with approximately 30% to 35% of that being liquids. While able to supply all our customers during the winter storms, we did not go completely unscathed when it comes to production growth. There were times when we simply had to shut down frac operations due to the extreme cold over the last couple of months, and we did experience some production downtime.

That downtime will impact first-quarter growth and volumes, as has been the case historically. This is nothing new and was forecasted in our growth trajectory, just as we've done in the past. For the year, our production guidance remains 20% to 25% year over year, as we've previously stated.

Going to the Southern Marcellus division, we've updated the production from the super-rich wells in 2013 in our investor presentation. We now have a zero time plot of all the wells, as compared to the 2013 type curve. The takeaway is that the super-rich area of wells are performing above our expectations and getting better as we go.

I should also point out that we furnished the zero time plot because the six-month production data provided by the state only shows wellhead gas and condensate, and some people continue to miss that distinction. This is really important. For example, in the super-rich area, you would miss as much as 1.2 million or more barrels of NGLs that are really valuable and often represent half or more of the total EUR of the well.

In 2013, in the super-rich area, we had an average lateral length of 3,850 feet with 20 stages. In 2014, we expect to drill wells with average lateral lengths 38% longer, at 5,300 feet with 26 stage completions, resulting in an average EUR of 2.05 million boe per well. For 2015, the lateral lengths in our current plan average 5,600 feet with 28 stages, and an average EUR of 2.23 million boe.

In the wet area in 2013, our average lateral was 3,200 feet with 16 stages. And for 2014, we are planning on 4,200 feet with 21 stages, resulting in an expected average EUR of 12.3 Bcf equivalent. For 2015, the lateral lengths in our current plan average 4,800 feet with 24 stages, and an expected average EUR of 14 Bcf equivalent.

In the dry-gas area of the Marcellus, in southwest Pennsylvania, for 2014, we're planning 5,200-foot laterals with 26 stage completions, resulting in an average expected EUR of 13.4 Bcf. This is up significantly from 2013, which averaged 2,950 feet with 14 stages. And for 2015, the lateral lengths are today identical to 2014.

All of the EURs, lateral lengths, and number of stages are updated in our investor presentation, and we've updated the type curves and the economics to reflect our current plans for 2014, based on recent well performance in each of these areas. Again, I want to point out that we do expect that these lateral lengths will get longer, thereby resulting in higher EURs and higher returns as we continue to optimize those plans.

We've talked about improving capital efficiencies in the past, and I'd like to point out a tangible example of that occurring this year. In southwest Pennsylvania, our plan is to go back on to 5 producing pads and drill approximately 14 more wells. Just in pad construction alone, and not counting all the other already-present infrastructure, such as compression, gathering, water, and roads -- for the wells planned on those pads, we estimate that we'll save over $200,000 per well just in pad construction alone.

Even more importantly, the real efficiency comes from the savings in time. We essentially save 9 to 12 months in preparation and permitting, thus bringing significant production volumes from these 14 wells online 9 to 12 months earlier. As we do this more and more over the coming years, the increase in capital efficiencies will be significant, and this is a tangible example of just one of those improvements.

There are many more factors that should also significantly improve our capital efficiency and value going forward. Just a few examples would be: improved recoveries of hydrocarbon in place; better completion designs; longer laterals; closer-spaced laterals; development of multiple horizons from the same pad; and the list goes on and on -- again, making that inventory of resource potential more and more valuable with time.

Also of note, we're planning to drill a Point Pleasant well in what we believe is the core of the play underneath our Marcellus position in Washington County. The well should spud this spring, and the current plan would yield us a production test prior to year end.

Based on our extensive high-quality 3D and Trenton Black River test in the immediate area, we already know a lot about the rock. The Point Pleasant is expected to be approximately 130 foot thick with around 10% porosity.

Gas in place is expected to be as high as 140 Bcf or more per square mile, and we expect around 1,000 nanodarcy perm, which is exceptionally good. We have strong indications that the reservoir pressure could be extremely high, thereby resulting in really high gas in place and really high productivity. And the TBV will be about 11,500 foot, which is very workable.

The plan is to drill a long lateral and complete it with an RCS-style completion. We have all the ingredients for a highly productive well, including thickness, the right maturity, very high gas in place, exceptional rock quality, high pressure, a 3D survey, and it's at a very reasonable and workable depth.

Shifting to the Northern Marcellus, the team continues to maintain our position while drilling some really impressive dry-gas wells, as listed in our earnings release. For 2014, the divisional average lateral length is 4,600 foot and 23 frac stages. The team recently brought online three new wells on a pad that, together [cumed] a little over 4 Bcf at 90 days.

One of those wells had a lateral length of 6,353 feet with 32 stages. Its first 30 days' productions to sales averaged over 22 million a day, and it has a projected EUR of right at 18 Bcf. We have a 100% working interest and an NRI of 86% in that well. Again, we believe our position in Lycoming County is a prime dry-gas area that is essentially HBP'd and ready for us to ramp up when the time is right.

In the Mid-Continent division, we remain focused on delineating and testing our Mississippian Chat acreage on the Nemaha Ridge, along with developing our St. Louis production in the Texas Panhandle. For the Chat play, we're continuing with our larger stimulation designs, and those are updated in our investor presentation. While it's still early, these results are encouraging. As we analyze our recent 3D data in the Oklahoma portion of the play, we expect to make good progress in developing our understanding of the reservoir and its delineation throughout 2014.

For the Southern Appalachian division, the horizontal Huron Shale wells drilled in 2013 were our best ever. The CBM wells continue to improve, resulting in positive revisions. The vertical-type gas sands wells continue to outperform their forecast, with two of those wells being the best we've drilled to date. The team continues to hold production on a minimal decline, with very limited capital, essentially holding production flat.

In closing, 2013 was a great year, and we have a plan that'll make 2014 and many years into the future also great. Range has about 1 million net acres in one of the best plays out there, with a lot of that positioned in the core of the highest hydrocarbon in place in the Appalachian Basin. We believe we can execute as well as anyone, and we have the people and the track record to support that belief. And we have a marketing and logistics team that's been innovative and class leading, while positioning us to remain confident in our ability to consistently grow production 20% to 25% year over year and deliver shareholder growth for many years into the future.

Now, over to Roger.

Thank you, Ray. Top-line revenue from natural gas, oil, and NGL sales for the fourth quarter, including cash-settled derivatives, was $446 million, 7% higher than last year on 20% higher production volume. Cash margin for the quarter, at $2.68 per mcfe, decreased slightly from the fourth quarter of last year, due to much higher NGL realizations in the fourth quarter of last year and lower realized prices for both gas and NGLs this year.

Cash flow for the fourth quarter was $252 million, 2% higher than 2012, driven by higher production and continued expense control. Cash flow per fully diluted share was $1.56, slightly above last year's fourth-quarter figure. And fourth-quarter EBITDAX totaled $295 million, 2% higher than last year.

Cash flow for all of 2013 totaled $943 million, a year-over-year increase of 25%. Cash flow per fully diluted share for the year was $5.84, a 24% increase from last year. EBITDAX for the whole year was $1.1 billion, 22% higher than 2012, and the first year our EBITDAX has broken through the $1-billion mark. GAAP net income for the fourth quarter was $28 million, while earnings calculated using analyst methodology, which excludes asset sales, derivative mark-to-market (inaudible), and various nonrecurring items, was $68 million, or $0.42 per fully diluted share. As Rodney mentioned, both cash flow and per-share earnings per share for the quarter exceeded consensus estimates.

GAAP net income for all of 2013 totaled $116 million, a nine-fold increase from the 2012 net income figure of $13 million. All of our non-GAAP measures are fully reconciled to GAAP on the various supplemental tables posted to the Investor Relations section of our website. As is evident in our 2013 financial performance, whether one uses GAAP or non-GAAP measures as income and cash flow, improvements in our capital and cost efficiency are clearly flowing through to the Range bottom line.

One of the most visible indicators of improving capital efficiency is our DD&A rate for mcfe. The DD&A is the most significant cost item flowing through the income statement, and in the fourth quarter of each year, we reset our DD&A rate following completion of our year-end proved reserves report. The DD&A rate for the fourth quarter of 2013 was $1.36 per mcfe, down 7% from $1.46 in the fourth quarter of last year. And, as Ray and Jeff mentioned, the DD&A rate is down 38% from 2009, not from ceiling test write-downs, but from real improvements in capital efficiency.

Unproved property impairment for the quarter, at $6 million, was unusually light, reflecting a year-end true-up. However, we do expect this expense to be significantly lower in 2014 than prior years, with first-quarter unproved property expense coming in between $12 million and $14 million as we continue to block up and high grade our acreage positions. Likewise, cash exploration expense for the fourth quarter, of $13 million, came in significantly below guidance, as we experienced fewer dry holes and less (inaudible) rental expense than planned. The first quarter of 2014, reflecting a reloaded 2014 seismic budget, should see exploration expense return to the $17 million to $19 million range.

All other quarterly expense items came in at or below guidance, although I should mention that unlike prior quarters, direct operating expense guidance is going to be flat to slightly higher in the first quarter of 2014, at $0.37 to $0.39 per mcfe. This pause in the quarterly reduction of unit operating expense is due primarily to the 24/7 shift coverage by our lease operators during the freezing weather conditions that Ray mentioned.

We expect direct operating expense to resume its gradual drift downward after we get through the first quarter. Please reference our year-end 2013 press release for additional first-quarter 2014 expense item guidance.

Our balance sheet at year end was right on plan, with our trailing four-quarter debt-to-EBITDAX ratio at 2.8 times. That's down from the 3.2 times figure at year-end 2012. Leverage continues to decline as our cash flow growth outpaces our growth in leverage. And, with $500 million in bank debt outstanding, we ended the year with approximately $1.2 billion in unused committed availability under our $1.75-billion bank facility. Fourth quarter was another active quarter for hedging, with Range adding natural gas, NGL, and oil hedges for 2014, 2015, and, for the first time, 2016. The Range website and press release tables contain detailed hedge volumes and prices, by product, that investors may use in preparing their updated forecast.

In summary, 2013 reflected another year of improving unit cost and capital efficiency, holds a strong double-digit production and reserve growth. 2014 looks to be similar and off to a really good start, with higher natural gas prices and two of our long-term NGL offtake contracts up and running smoothly. Also, unit costs continue to decrease, while we project another year of steady production growth of between 20% and 25%.

Jeff, over to you.

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

(Operator Instructions)

Gil Yang, DISCERN.

Thanks for all the details in the call. Jeff, growth clearly on track. Cash flow growing. Could you talk about what your expectations are for CapEx versus cash flow trends over the next several years?

Yes. We really feel comfortable with that 20% to 25% line-of-sight growth for many years. We have a big inventory. It's largely de-risked. You can look on the slide that talks about the percent of the wells we have drilled. Upside in many different ways, either through incremental recovery, other horizons, things like that. So we feel comfortable we can grow at 20%, 25% for many years.

We talked about in the early years, like we are now, we're getting the 20% to 25% growth with the cash flow outspend, depending on where commodity prices are, of between $250 million and $350 million. If you project forward a couple of years, depending on where prices are, we will be getting 20% to 25% growth within cash flow. So I think we're well positioned, continue to grow consistently in one of the highest rate of return, lowest cost plays out there, with a really strong Team that has a great track record of delivering quarter in and quarter out, year in year out.

Great. If you just look at the strip, when would you get to that cash flow-CapEx breakeven?

It's hard to say. It may be in a couple of years or something like that. It depends where prices will ultimately be. I really think, if you look forward, we're in a great position with where the strip is. But I think the good news, there's a lot of upside in terms of gas. There's different studies out there by different companies, and I'll quote a few of them. I'm not picking any one company, but Goldman Sachs is saying 20 Bcf of reserve growth by 2018. Goldman Sachs -- or, excuse me, Citi has 20 Bcf by 2020. There's other people out there.

So I think natural gas will do great in this current price environment where the strip is, but I think there's actually good upside to that because natural gas really is a superior fuel. A lot of things are happening. A lot of people are spending money on everything from converting more gas for power generation, LNG for export, gas for transportation, gas for manufacturing, gas for petrochemical business. So a lot of upside out there.

Great. And then a follow-up in that context. With that 20% to 25% growth rate, you mentioned you could drill your Northeast gas at the right time. So within the context of the pricing expectations and the 20% to 25% growth, what is the right time for that gas drilling to accelerate?

We're doing some of it right now. Ray mentioned some outstanding wells. One of them was an 18-Bcf well from a reasonable length lateral, 6,000 plus feet a little bit. So I think we have good returns on that drilling now. The good news is we have a great inventory of dry projects, wet projects, and super-rich projects. We have a portfolio within a portfolio, and we can allocate capital for what we think we can get the best returns as we go forward.

Do you need a specific price, though, to start accelerating versus what the liquids are doing right now?

I think it comes back to, 20% to 25% growth we think is strong, particularly for a company our size. Every three to four years, we will be doubling at 20% to 25%. So if we can double in three to four years and then double again for a company our size with the returns we have, we think that's great. We are currently drilling some dry gas wells now both in the Northeast and in the Southwest. It will just become part of our portfolio.

Okay. Great. Thanks a lot.

Neil Dingmann, SunTrust.

Jeff, you've obviously put on a lot of solid contracts with Mariner West and some of the -- ATEX and some of these others who just tried coming on. Are there number of additional ones that you are considering at this time? What's your thoughts as far of putting more those on going forward?

I think we are in great shape. The Marketing Team, led by Chad and Greg and others, has done a great job. Again, I think our portfolio on the ethane side is as good as any company I am aware of in the business, really, for any size. So what that does for us, that plus all the firm takeaway, the 25 new customers and bringing gas really all over to the South, Southeast, mid-Atlantic, West, Northeast, coupled with the ability to sell propane in the good markets or export in the summer when you could bring it to better markets, that's really cleared the path for us to get the greater than 3 Bcf per day. So we are in a great position. We don't have to do anything to take our production to greater than 3 Bs per day net and beyond. Our gas will be on spec. We've got great contracts, great prices. To the extent there's things that make sense, we clearly will continue to look at those things.

Okay. And then detail, you and Ray detailed, great detail about the longer laterals and how you come up with higher EURs. Just wonder your thoughts. I know there's some peers out there that are doing somewhere around your Southwest PA, some of these monster laterals closer to 9,000 or even further. Your thoughts about going out and stepping out and trying some of those? Or are you going to still consider more around that 5,200-foot average?

Well, you hit on it there in your last comment. The 5,200-foot is an average. So for all those numbers that we're quoting you and that we show you in the investor presentation, is an average of literally 100 plus or minus wells that come online. So we have drilled some longer laterals, and we do plan to reach out and drill longer laterals when it's appropriate. But again, we're really focused on optimizing the recovery of hydrocarbon in place, and a lot of that we focus on is EUR per thousand foot. Are we targeting the most optimum place in the zone? Are we pumping the right size frac job, the right spacing between the perf clusters?

So we will continue to do like we've done for the last several years, and we'll update these curves as we go along. I think you will see us continue to get longer and longer, but we don't want to get so long that we really cause our optimal recoveries of hydrocarbon in place to suffer. So we're going to really proceed along that line, just specifically database, not out run our technical understanding of the play. I think right now, or in Southwest PA, for sure, our recoveries per thousand foot of lateral are class leading. I'm real proud of what the Team has done there. The Marcellus is great rock. It's just getting better and better.

All of the improvements that we are making, the adjustments that we make year over year are getting us higher recoveries, and I expect those to continue to go up for some time. I still think we are in the early innings of the ballgame in being able to optimize that. And I think that's completely different than we've seen in a lot of other shale plays, mainly the Barnett and some of the other ones that have a lot more history. We seem like we got through the ball game pretty quick in a lot of those, and it was simply stacking laterals closer together. I think we've got a lot of efficiencies and improvements to do going forward, and I think a lot of that has to do with the fact that we are in the very core of the sweet spot in Southwest PA. And then, of course, when you stack the Upper Devonian and Utica, up on top and below that, we've got even more efficiencies that we can get over the years to come.

Having a large footprint in the core of the best play out there with a really strong technical Team, I totally agree with Ray that we ought to be able to continue to improve with time.

Ray, Jeff, just one follow-on to that, if I could. You mentioned about the stacked pay, and obviously your gas-in-place maps really show that you have a lot of Utica potential. Just the cautious approach by maybe not drilling the first there until spring, is that more a result of just how good your current Marcellus results there? Or why not, obviously, just ramp that up quicker on the Utica side, certainly if those gas-in-place maps are as good as they're showing?

Well, again, we HBP everything as when we drill the Marcellus. So it's been a really a matter of focus on the Marcellus. We're making really good project economics there. We are seeing improvements year over year. We've known the Utica is there for some time. I think there's been wells drilled closer to us. We've got a lot more 3D together. And over the years, it's always been there. People tend to forget, we actually drilled the very first horizontal Utica well ever drilled back in 2009, so we've been working on it longer than anybody. It's just that we've been focused on the Marcellus.

And with the data we have today, I think the timing is right. I think the Team has put together some really good technical work. We're really excited about this project. I don't know if you could tell that are not when we were reading about it. But it's going to be, I think, a great well. We've taken our time; we've gotten prepared for it. We actually believe we can bring this well online pretty quickly after we test it. That's critically important. We don't like to have wells sitting around waiting on infrastructure. So we're really excited about it, and we think it has the potential to be hugely economic and a great play that we can really ramp in and develop in as the years go forward. But again, it's going to be HBP'd, and as it fits into our plan, you are going to see us do more and more of it as the years go forward.

All great points. Thanks, Jeff.

Holly Stewart, Howard Weil.

Hoping to dig a little bit more into the NGL marketing side, given your expectations for increased volumes. Two of the three-prong NGL marketing strategies have begun operations. So can we maybe use January and February as an example of how the realizations are changing? And then maybe a little color on your outlook and how you view them thus far.

Holly, thanks. This is Chad. I'll try to give you a little bit of color on that. So in January, beginning of January this year, we were flowing 15,000 barrels a day of ethane on MarkWest and approximately 10,000 -- Mariner West, and that's gross. And about 10,000 barrels a day gross on ATEX. The MarkWest pricing is tied more to Appalachia index price, and ATEX is more of a true Mont Belvieu price, less the transportation cost. So if Mont Belvieu prices in January were -- they had a little jump up or increase in price, so they were around $0.40, $0.39 or $0.40. We see that going forward later into the year, and in 2015, coming back down to a more historical average price of around $0.30 a gallon. That's the Mont Belvieu index price before index, I mean, before transportation deduct.

But, really, what you need to look at is going into 2015, once all three projects are in service we're delivering 15,000 barrels to MarkWest, NOVA, 10,000 barrels a day to ATEX, to Mont Belvieu, and then 10,000 barrels a day on Mariner East, which has a more European [Napa]-based index price. All three of those gives you that 25% uplift, and we get a deeper cut. The more ethane we take out of the gas, we get a deeper cut of propane, which again, gives us a little bit more uplift in our overall NGL realization. So you really need to look at it that way. Current prices, January and February, for ethane are up because gas prices have moved up, and ethane will follow that full price of gas. But going forward, you need to look at the 2015 portfolio of all three projects in service.

Perfect. That's helpful. And then maybe on the basis, looks like $0.22 during the quarter, but then Appalachian prices have moved up in the first quarter, so can you just give us a sense of how this is evolving, maybe in the first quarter compared to 4Q, and then your expectation throughout the year?

Yes. What I really like to do, is address -- I know there's a lot of people on the call that probably have -- want to know what our thoughts are and want us to give color on basis differentials, so I will try to address that more generally. As Jeff mentioned in his prepared remarks, the basis differentials don't impact all producers equally, especially that's true in the Appalachian basis, that notably vary depending on which pipes you are delivering into or which markets or producers you have access to. So, if you look at our supplemental tables, it shows corporate gas prices third quarter of 2013 differentials of 17 (inaudible). Fourth-quarter 2013 was minus $0.22 per mcf.

If you drill down a little bit, and to give a little color on that, if you look at a subset of that corporate differential and just look at our Marcellus differentials, it improves quite a bit. For example, in third quarter 2013, our Marcellus gas price differentials to NYMEX was minus $0.06, and in fourth quarter 2013, it was minus $0.11. So that should give a little bit of context going forward of what we are doing with our Marcellus gas and how these firm transportation arrangements out of the basins are really helping us.

We have a majority of our acreage in production is in the Southwest portion of PA, near large and already existing pipelines, such as TETCO and Columbia. We have great relationships with them. It gives us access to multiple markets. As Jeff and Ray have both reported, we currently have 1.1 Bcf of either firm transportation or firm sales in place. Going out into 2016, we have 1.6 Bcf of firm transport or firm sales. These arrangements allow us to supply as much as 50% to 60% of our gas to multiple consumer regions outside the basin.

And Jeff talked about some of those regions. The Gulf Coast, we have great arrangements on TETCO and Columbia to get our gas to the Gulf Coast and Southeast. Midwest, the Ohio Valley where there's lots of -- we have great relationships with power and utility users, so that's a key area for us. And as well as the mid-Atlantic area. And this percentage could increase in future years with a lot of the flexibility we have on our firm transport. And also, Ray mentioned we worked hard to add 25 new customers and create strong relationships with these power and industrial users outside the Appalachia basin, and we've been successful in doing that.

There's no question that likely there will be challenges due to the volatility in the market between now and probably late 2016 with demand. We see demand increasing, but we'll continue to use this strategy that we've used in the past to diversify our pricing and expand our capacity markets and number of customers, using our portfolio of firm transportation in these relationships that we have.

So, really, back to your question. What do we think the basis is going forward? We understand the importance of that. Range doesn't typically give guidance on any specific commodity pricing, particularly basis, really because of the high volatility. You've seen that of late. In addition, the current dynamics and going forward, the volatility of the gas markets is constantly changing, so it's difficult to give any specific guidance on a particular basis or pricing. But what I can tell you and the shareholders is that we are diversifying our risk. Our Team has done a great job and are continuing to do a great job out there, and we are well prepared from a gas marketing standpoint. Thanks.

Perfect. Thanks, gentlemen.

Ron Mills, Johnson Rice.

A couple real quick questions. Should we view, as you move to both longer laterals and drilling more wells off of existing pads, including currently producing pads, is 2014 more of a transition year in terms of the cycle times pushing some of the growth more to the second, third, and fourth quarters, so later in the year? But then 2015 and beyond, is it something that we can start looking at as more moving into acceleration mode? Is that a fair way to look at your plans?

Well, Ron, this is Ray. Part of it, I could say, is every year, we've consistently drilled a little bit longer laterals. We've done more and more things like going back to existing pads and testing 500-foot space laterals and RCS completions. So every year, I think we've made steady improvements. I think the recent couple years, certainly, we've seen more of those have larger impacts, and I think that will continue, at least for a few more years.

As far as acceleration, we are going to grow 20% to 25% per year for as far as we can see out there, and that, essentially, seems pretty aggressive to me, and that's doubling every three years. So as an operations guy, that growth year over year, a couple years out is huge. So that's certainly accelerating from where we're at today, if you want to look at it that way. So I think that's going to happen.

Now, as far as production seeming to always be backend loaded, there's a simple fact in Appalachia that we can't mess with mother nature. If we could figure out how to warm her up in January and February, we wouldn't have these six-week periods that we have consistently every year where it's just simply hard to frac, period. When it's negative degree, when it's negative 15, negative 20 degrees, even 10-pound salt water freezes solid, so you just can't complete wells during that time. There are control lines on compressors that will freeze up. There's things like that that will always happen when it gets that cold.

As much planning as we do -- and my hat's off to our Operations Teams. They have absolutely done better every year that goes along. But I don't think we are ever going to get to a point where we can sail right through. The really cold weather in January and February is a blessing, and we certainly are very appreciative this year that we had cold weather and polar vortex storms and all that, especially since I don't have to live in Pittsburgh anymore. It's really great. But the fact that it is cold is hard to have operations going consistently through January and February, and it's going to be that way forever.

So I think you're always are going to see the first quarter down. We forecast that in our numbers. We've done that for as far back as I remember, and it's going to always be that way, so that's just part of it. But did I tell you about those super-rich wells that we've been drilling lately? (laughter) They're doing really well. (multiple speakers)

And then when you talk about going back to existing producing pads, one to just make sure I understood. When you go back to 5 currently producing pads this year and drilling 14 more wells, I'm assuming the 14 is an aggregate number, is number one? And then number two, the excitement or the description of why you are so excited about the Utica on your acreage came through loud and clear, but do any of -- are you also doing any other stacked pay test, i.e., are you continuing to test Upper Devonian in some of these areas, and/or is that part of what you're going to do on some of these producing pads you go back into?

Well, the 14 wells is an aggregate number. That's across all five pads, so three, four, five wells pad thing. The Utica is, we are very excited about it. We just have the one well this year. Of course, we want to drill it. We want to test it, put it on production, analyze it, optimize our plans from that point, and so it's going to take us a while to see that.

The Upper Devonian, we've got figured out. We've drilled enough wells. Every time we drill a Marcellus well, we go through it, so we've got hundreds and hundreds of wells worth of information about it. There are now enough Upper Devonian tests all around our acreage, not even including ours, that certainly have delineated and really de-risked that. To us, it's more simply a fact of focus on the Marcellus, and let's continue to optimize that.

I do believe at some point, we'll start putting Upper Devonian wells on the same pad as we get into that -- if you want to refer to it as a manufacturing mode. When we, more or less, drill all the wells on a pad, whether that's 10, 20, 30 wells, whatever that is. Eventually, going forward, I think you will see that more and more starting to occur over the next several years.

Great. Thank you for the information.

Jack Aydin, KeyBanc.

I know you've been talking about uplift. If you had all the ethane project on a plays, and you're talking about 25% uplift in revenue, could you put a circle around what could mean that to the cash flow potential? I'm sure you modeled it.

Well, one, I'll turn it over to Roger and Chad in a minute. This is Jeff. One thing is, one of those things that are online, again, to Jack's point, extracting the ethane, once all three projects are up, there's a 25% uplift relative to leaving it in the gas stream. So for the analysts and investors that run NAV models or whatever, clearly, you're going to add significant NAV when you model that in for a particular year. The other thing I will say, too, I think we did a great job in 2013. We said we'd grow 20% to 25%, and we did. Almost every metric you look at, including cash flow or cash flow per share debt-adjusted, reserves, production all grew in that range. In fact, we hit the high end of the range. Let me turn it over to Roger or Chad for additional color you want to add.

Jack, I think when you look at our cash flow growth, it really has twinned our production reserve growth fairly well. This has been a pretty good year last year in terms of comparison. While NGL prices were down fairly significantly, gas prices and oil will pretty much offset each other. So you saw, really, 25% cash flow growth in 2013 with relatively flat to down prices. So as you start pulling ethane, and particularly when, as Chad mentioned, the 2015 enhancements come into play on Mariner East, I think you'll continue to see cash flow grow in somewhat parallel fashion with our production and reserves.

If you look out there far enough, and depending on what prices do, it could even grow in excess of that if you go out a few years, which is pretty exciting.

Thanks. Second question for you is basically on your budget. You allocated about $210 million for leasehold and renewals. Could you break it down, or second, are you, in a state of drilling to hold leases on production, now you are renewing it, paying the money, is that what you are doing? Could you explain it a little bit?

Jack, it's a good question. The majority of that is driven, of course, by the Marcellus. We have a million net acres plus or minus there, and a lot of that is still in the progress of HBPing. So it's what I would call normal blocking and tackling. It's filling in holes; it's bolting on things to units. It's renewals; it's all of those things that you just mentioned.

So we'll see that taper off in the future. There's no question about that. We're getting closer and closer. Our at-risk acreage is becoming a very, very low number. We show that in our investor presentation. And so we're doing a much -- we've made great strides, I would put it that way, in holding as many as four units worth of acreage from one surface location. It gives us a lot of -- not only a lot of operational and capital efficiencies, but it's very efficient at HBPing land. So we are feeling really good about that.

But I think we have a very large acreage position, and just normal blocking and tackling, it's going to be that way. But the good news is, there's at least one good leading indicator that we are seeing in the 10-K. We'd look at expiration expense. You are seeing that crest over and come down. So I think that's an excellent leading indicator, and that shows us that we are about to get to that point where it comes over. Southwest PA has a lot of small tracks, and it's just simply going to take us some time to fill in all of the little puzzle pieces, but we are feeling really good about that.

Thank you very much.

We are nearing the end of today's conference. We will go to Phillips Johnston of Capital One for our final question.

Just on the first Utica/Point Pleasant well, I'm wondering if you can say what the AFE might be and what cost for science that might include? And given the depth and the pressure, what average well cost would you expect in full development and pad drilling mode? And just as a follow-up to the earlier questions that Ray answered, if you like what you see there, how many wells do think you could feasibly drill looking out into next year?

Well, the first set of questions on all the details is no, no, no, no, and no. (Laughter) The first well, you can't really talk about the first well. You build a lot of insurance in there. You do a lot of things. From a science standpoint, it is our very first well. The way we tend to look at things like that is on a project basis. It's just like any exploration project. Let's go drill the first well; let's look at it. The question is, in a development mode, if it all tests out, will it make sense? And all our numbers, what I can say is it looks really, really good.

With the high pressure, high gas, it's at a very workable depth. We've got a large position. We know we're in the core from a lot of -- we have actual Trenton Black River test with well logs, a lot of modern, scientific-type logs right in the area. We have infrastructure on the surface where we can put some of these wells online early on. So it's a pretty exciting project. It's something, again, we've been working on since, literally, back in 2008, 2009.

So I think this first well will (inaudible) a lot. It's a little early to say, would we drill another one in 2015 or 2016, when would it be? If we get a good test by the end of the year and things look good, I could definitely see us drilling a second or maybe third well in 2015, but certainly in 2016. From that point forward, I think it's just a matter of when it makes sense to ramp that up, and it gives us another great option. Again, we control our own destiny. We don't have a lot of JV partners. We've got great marketing and commercial logistics for the area. We've got a lot of takeaway capacity, and we think it's got huge potential for us going forward.

The wells drilled off it will be drilled off an existing Marcellus pad, and there's room for additional wells. So it'll be -- it could really be great upside for us.

I was going to say, plus it's really easy to build volumes quickly with dry gas, and so with big wells like that, it gives us a lot of good options in the future.

And then just as a follow up to Ron's question earlier, are there any Upper Devonian wells that are planned in this year's capital budget?

No. We currently don't have any planned right now in the schedule.

Okay. Thanks, guys.

Thank you.

Thank you. This concludes today's question-and-answer session. I'd like to turn the call back over to Mr. Ventura for closing comments.

Range had a great year in 2013, and we expect another great year in 2014. Given our approximately 1-million-acre position in Pennsylvania, focused in the Southwest portion of the state where there's great stacked pay potential, and because we have a great portfolio of dry, wet, and super-rich wells, we believe we can continue to grow at 20% to 25% for many years. Thanks for participating on the call. I know there were several other people teed up that we didn't get to for time. If you would, please follow-up with our IR Team. Thank you.

Thank you for your participation in today's conference. You may disconnect at this time.