山脈資源 (RRC) 2014 Q4 法說會逐字稿

Welcome to the Range Resources fourth-quarter and year-end 2014 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 risk 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 to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, Adam. Good morning and welcome. Range reported results for 2014 with record production and reserves and a continuing decrease in unit costs which will set us up our operation for 2015. The order of our speakers on the call today are Jeff Ventura, President and CEO; Ray Walker, Executive Vice President and Chief Operating Officer; Roger Manny, Executive Vice President and Chief Financial Officer.

Range did file our 10-K yesterday with the SEC. It should be available on our website under the Investor 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 calculation 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 today. Now let me turn call over to Jeff.

Thank you, Rodney. In 2014 Range achieved some key milestones that I believe position the Company well for the future. Range recorded record levels of production, reserves, revenue, net income, cash flow, and cash flow per share in 2014. Thanks to continued cost structure improvements and steady production growth despite declining realized prices, our cash flow and cash flow per share have increased.

2015 is setting up to be a challenging year. Fortunately we did several things in 2014 that will help us in 2015. With the redemption of our fixed rate 8% bonds with the proceeds from an equity offering coupled with the cash proceeds we received from our Conger for Nora swap, we ended 2014 with less debt than 2013. Debt per mcfe of proved reserves was $0.30 at year end 2014 compared to the prior year at $0.38. Last fall we restructured and extended our senior bank facility for five years to 2019, and increased our borrowing base from $2 billion to $3 billion. We have no bonds maturing until 2020.

We have continued with our capital and operating efficiencies. In 2014 we improved our operating efficiency by decreasing our unit cost $0.35, or 10% versus the prior year, and expect continued improvement this year. Our capital efficiency improved as we continued to drill longer laterals, pump more frac stages per lateral, and utilize improved targeting of the lateral. We believe this trend will also continue into 2015. We currently have hedged approximately 65% of our projected 2015 natural gas production with a $4 floor, and approximately 77% of our projected oil production with a $90.57 floor.

On the natural gas liquids side, the Mariner East project is still projected to be on time with the start up in the third quarter of this year. When fully operational, even with today's pricing given Range specific contracts and the combined benefits from propane and ethane, this is projected to be approximately a $90 million uplift as compared to selling the ethane as natural gas, net of all transportation and processing fees. In 2014 we grew production 24%, we grew reserves 26%, and we ended 2014 by testing our first Utica well in Washington County at a rate of 59 million cubic feet per day which we believe is a new record for any well in any horizon in the Appalachian basin.

As I previously mentioned we accomplished a lot in 2014 that will help us in 2015. We also have recently taken additional steps to help drive our performance in 2015 and 2016. We cut our 2015 capital budget to $870 million. This is approximately a $700 million reduction from 2014. Given the quality of our assets and team, coupled with continuing improved capital efficiencies, we're targeting 20% growth for 2015 even with the reduced capital. Importantly this growth occurs sequentially throughout the year which sets up Range well for 2016.

We also made a tough decision to close our Oklahoma City office and operate our Midcontinent properties out of Fort Worth. Given that a approximately 97% of our capital is currently targeted to Appalachia, we believe this is the right decision for the Company and it will lead to better capital allocation for Range and improved integration of technology coupled with cost savings. Range has advantage given our core acreage position in the Marcellus. We have approximately 1.5 million net acres of stacked pay potential in southwest and northeast Pennsylvania that is perspective for Marcellus, Utica, and Upper Devonian. Plus our acreage position is further advantaged in that we can selectively drill -- direct drilling capital towards the dry, wet, or super-rich portions of the play.

Coupling this with our processing, pipeline takeaway capacity, and unique NGL marketing agreements, Range is well-positioned for 2015, 2016, and beyond. Gas demand is projected to increase in 2015 from coal plant retirements, gas exports to Mexico, and later this year LNG exports. Given the large capital cuts from a large number of companies in our industry, which is resulting in a rapidly declining recount and deferred completions, we may see a production response in oil, natural gas, and natural gas liquids later this year. The combination of slowing supply growth coupled with increasing demand should help bring the markets closer in balance this year.

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

Thanks, Jeff. While we're focused on the headwinds that we've faced in 2015, when we pause to look back at 2014, 2014 was a record year across many aspects of our operations. We set records in production, reserves, cash flow, and earnings along with significant improvements in cost structure and capital efficiency.

We continued to see great results in well performance in both southwest and northeast Pennsylvania, and like Jeff said we completed our first Washington County Utica well. While it's only a single well, based on the early results and all the previous data, we have approximately 400,000 net acres in what we believe to be the core of the dry Utica, and gives Range another significant growth opportunity to add to our core positions in the Marcellus and Upper Devonian in southwest Pennsylvania.

In 2014 we also put together both halves of the Nora field in Virginia giving us control of operations, and the early results were outstanding. We have the ability to significantly grow that asset in one of the best gas markets on the East Coast in the future. And in the Midcontinent area we saw continued confirmation of the geologic modeling in the Chat play along the Nemaha Ridge leading to some of the best well performance to date in that play.

I'm also really proud of all of our employees for working all of 2014 without a lost time incident. Safety, environmental protections, and regulatory compliance are our core philosophy at Range, and I want to personally congratulate everyone across the Company for a job well done in 2014. We had a great year, adding reserves at record low drill bit F&D cost while decreasing the PUD percentage, and the startup of Mariner East early propane was another significant step in our liquids marketing strategy in Appalachia further positioning Range with unique and advantaged opportunities.

Recognizing the challenging commodity price environment that Jeff described in his remarks, I know most of you today are primarily focused on our plans for 2015. As we announced previously we've set the capital budget at $870 million, which is 46% lower than our 2014 CapEx, and we've targeted year-over-year production growth of 20%. Nearly 95% of that budget is directed towards the Marcellus, with over 90% of those dollars directed to southwest Pennsylvania. 85% of our total capital is directed to the drill bit for 2015 as we've significantly decreased our planned spending on land exploration and seismic. We're able to make these changes and still target 20% growth for several reasons.

Let me walk you through just a few of them. Number one, we have an experienced team and great leadership with a proven track record of growing production and reserves consistently with one of the lowest cost structures in one of the best plays in the industry. This has been our philosophy at Range for many years.

Number two, most importantly and one of my favorite sayings, the rock rules. And this has proven to be the case throughout history across many plays and through multiple commodity price cycles. It simply means that where you find the best reservoir quality meaning the best rock, the economics are substantially better than non-core acreage. And when a company can maintain a low cost structure in the core of a play that company can sustain its growth at attractive economics across the up-and-down cycles of commodity prices. Range has what we believe is a core position in the Marcellus, Upper Devonian, and Utica allowing us to focus capital in those areas with the best economics, whether they are dry, wet, or super rich, and continue to achieve production growth in 2015 and beyond.

And number three, Range has had a consistent strategy of 20% to 25% growth at a low cost structure for many years. This has allowed us to implement innovative, attractive and a long-term marketing and midstream arrangements that position us well for what we face going forward. It has allowed us to keep our balance sheet strong and maintain liquidity. This strategy has also allowed our operating teams to achieve continued improvements in well performance and operational efficiencies, while at the same time lowering our cost structure, and we expect to continue to see those improvements going forward.

So getting into some details about 2015, let me start with our southern Marcellus Shale division. For 2015 we're planning to turn to sales approximately 101 Marcellus wells -- 35 dry, 40 wet, and 26 super rich, with average completed lateral length of over 6,000 feet with 30 stages. Well timing is expected to be similar to prior years, and therefore our production growth profile is also expected to be similar with sequential growth quarter by quarter throughout the year giving us momentum as we go into 2016. To help investors in forecasting Range's production growth we've updated our presentation for each area in the Marcellus with specific type curves that are representative of the wells planned to be turned to sales rather than the wells planned to be drilled as we've previously shown.

The 2015 type curves that you'll find in our updated presentation on the website correspond to how our wells are planned to be produced and support our expectation of 20% growth for 2015. As we've described many times in the past, it's our practice to focus on optimizing our gathering system based on managing our cost structure to provide the best overall project returns. This results in lower initial rates to sales and flatter declines as the gathering system is built out over time and new processing plants and compressors are installed.

Actual performance as it pertains to the overall project is what matters, and in southwest Pennsylvania in the current environment we believe our well performance and returns are some of the best. Importantly Range's EUR projection in each of the Marcellus areas has increased in 2015 compared to the prior-year estimates while total well costs have come down, again illustrating the quality of our Marcellus acreage and the continued improvements in capital efficiency.

In the past we've made substantial enhancements to our completion designs, such as improved lateral targeting, [RCS], enhanced proppant placement, greener additives, super surfactants, and substantial reservoir modeling, both historical and predictive just to name a few. These enhancements have led to bigger EURs and lower costs year after year. We'll be continuing with that focus on innovation and new technology going forward, and I believe we'll continue to see positive changes in 2015 and beyond. Illustrating a specific example of this, I call your attention to a new slide in our presentation, slide number 35, which follows up on a couple of wells that we talked about several quarters ago.

We drilled two infill wells on an existing Marcellus pad that had been producing for over two years. By applying the new designs and better targeting, the initial sales of those new wells was significantly higher than the existing wells as we previously reported. After almost a year of production, the new wells on average have yielded 53% more than the original wells. We should not forget that on a normalized basis the new wells were $850,000 less per well. This extract -- this example illustrates just one aspect of the capital efficiencies, improved well performance, and resulting economics that we've demonstrated to date and can expect to see in future years.

I'll call your attention to slide 8 and slide 9 in our updated presentation to point out efficiencies that we've achieved over the past several years. Namely in the southwest Pennsylvania area since 2011 as compared to 2015, we've seen a 114% increase in lateral length with a 57% reduction in total well cost per foot of lateral. For 2015 as compared to 2014 we're planning 20% longer laterals with a 37% reduction in total well cost per foot of lateral. Even though our current 2015 plan turns to sales a few less wells as compared to last year, we're actually planning to pump about the same number of frac stages. This illustrates continued efficiency improvements resulting in lower cost, but also results in a consistent activity level allowing us to continue to capture improved service and supply pricing.

Looking at pricing across the supply chain, on an apples to apples basis assuming no efficiency improvements, we now have arrangements in place that have reduced our estimated 2015 well cost by 23% to 25% as compared to December 2014 pricing. We've seen reductions in pricing across all services and supplies, and we believe we'll see more improvements if activity continues to decrease across the industry. Let me point out again that we've embedded in our 2015 plan well cost improvements from high grading our program, continued improvements in designs efficiencies in operations, and the reduction in service and supply costs that we currently have in hand.

When you add all these together you achieve the 37% decrease in total well cost per foot of lateral that I described earlier. If we see further reductions in service and supply pricing, our total well cost will decrease further. This of course combined with the diversity of our large core position in southwest Pennsylvania allows us to grow with good economics in 2015 whether it's dry, wet, or super rich.

As a further update on the Utica, we're still planning to drilling two more wells this year. We believe the total well costs for the second well will be around $13 million and will still include some additional science. It's still very early in the program, but I believe as time goes on and we drill more wells we can see the costs come down another 15% to 25% as operational efficiencies and design improvements kick in.

The Claysville 11H, which holds the record IP of 59 million a day, is now producing at our designed constraints of 20 million a day. And albeit very early and with only a few weeks of production, the well is meeting initial expectations. Just like I discussed earlier, current production facilities for these wells are designed to optimize the long-term flow and project economics. The first well will be produced to sales on an interruptible basis until this summer when new infrastructure is completed. The second well is planned to come online about that same time, and the third well is planned to be drilled later in the year.

Now northeast Pennsylvania on slide 9, you can see that the lateral length has increased 100% since 2011 with the corresponding 63% decrease in total well cost per lateral foot. For 2015 as compared to 2014, we are increasing lateral lengths by 18%, with a 20% decrease in total well cost per foot of lateral. The team there had a great year, and we saw a 44% increase in our 90-day rates with a 30% reduction in well cost totally attributable to operational efficiencies and improved well designs that were implemented in 2014. We're planning a one to two rig program this year resulting in about 14 wells to sales. And we expect those improvements that we saw in 2014 will continue.

We've cut the CapEx in the Midcontinent division to approximately $26 million resulting in eight Chat wells, utilizing targets from the geologic model that has been developed over the past couple of years. As Jeff mentioned we've made the difficult decision to close the Oklahoma City divisional office and will now operate the properties, which is approximately 360,000 net acres and 80 million a day of production, with our Fort Worth-based operations team. The field offices across Oklahoma and in the Texas Panhandle will now report to Fort Worth.

In Nora we had the distinct advantages of an asset where we either own the minerals or it's held by production combined with having a very flat decline and receiving some of the best gas prices in the country. Our plan for 2015 is simply to complete our inventory of wells drilled in late 2014 along with minimal maintenance capital resulting in a total spent of about $15 million with about 25 new wells turned to sales.

In only a few short months since taking over the operations, the team has implemented designs and techniques resulting in some of the best results we've seen in that field. And you can see some of those results on slide 45 in the presentation. The 465,000 net acre position has a tremendous inventory of low risk projects combined with exploration potential for the coming years. Again, this is an asset that we believe we can ramp to significant volumes with attractive economics in the future.

In summary our message today is that we have a great team with a proven track record. We have a large and consolidated position in the core of one of the best plays in the world, and history has proven over and over the rock rules. We continually improved our cost structure, setting us up well to continue to deliver economic growth in the current environment. Our plan of growing at 20% to 25% for many years has enabled us to plan and execute innovative and attractive marketing and midstream arrangements that position us well. We have the balance sheet strength and liquidity to support the operational plan. And finally we have a plan for 20% growth in 2015 that creates value by achieving growth consistently and sequentially quarter by quarter at attractive economics, all positioning us for growth into 2016 and forward as commodity prices improve.

Now over to Roger.

Thanks, Ray. The fourth quarter closed out and excellent financial year for Range. Revenue, cash flow, and cash flow per share were all sequentially higher than the third quarter of this year, and also significantly higher than the fourth quarter of last year, while total unit costs were lower. For all of 2014 we set record highs for revenue, EBITDAX, cash flow, and cash flow per share. And while we understand that everyone is keenly focused on current commodity prices and 2015 budgets, we should not overlook these record 2014 results as they properly position Range for a more challenging 2015.

So starting with the income statement, the fourth quarter was much like prior quarters, where we offset lower oil, gas, and NGL prices with higher production volumes and lower costs. Our net realized price per mcfe was 17% lower than the fourth quarter of last year. The production was 26% higher and unit costs were 11% lower. That drove our strong quarterly performance. Reported net income was $284 million for the quarter, benefiting from a $341 million pretax mark-to-market gain on our hedge book. Fourth-quarter earnings calculated using analyst methodology, which eliminates these non-cash mark-to-market entries, was $65 million, or $0.39 per fully diluted share.

Cash flow for the fourth quarter was $273 million, 8% higher than last year, and cash flow per fully diluted share was $1.64. EBITDAX for the fourth quarter came in at $310 million, 5% higher than last year. Cash flow and cash flow per share for the full year 2014 was just over $1 billion, or $6.33 a share. EBITDAX for the full year was $1.2 billion, and 2014 was the first year that cash flow topped the $1 billion mark.

As Rodney mentioned earlier, please reference the various reconciliation tables found on the Range website and earnings release for full reconciliations of these non-GAAP measures to GAAP. On the expense side, all of our fourth-quarter expense items came in at or below guidance, reflecting heightened focus upon cost as oil, gas, and NGL prices waned during the quarter.

A special mention is the continued decline in our DD&A rate. Our DD&A rate for the fourth quarter was $1.25 per mcfe, down from $1.36 per mcfe last year and $1.46 per mcfe the year before that. The fourth quarter DD&A rate represents a 48% decline during the past five years from the peak rate of $2.41 in mcfe back in 2009. We expect the DD&A rate to continue falling as we high grade our asset base and become even more capital efficient. While there are several non-material positive and negative nonrecurring items passing through the income statement in the fourth quarter, there is one item that is highly nonrecurring.

This item relates to the closing of our Oklahoma City office that Ray and Jeff mentioned, and the resulting $8 million accrual for severance costs. The office closing will reduce our total company-wide headcount by approximately 8%. There are other overhead costs associated with the office closing besides severance, and the first-quarter results will likely include an additional accrual of approximately $8 million to account for these costs. When the closure is completed we expect an annual G&A reduction of approximately $15 million to $18 million, or $0.04 per mcfe, with these savings layered in beginning in the second quarter of 2015.

Flipping over to the balance sheet, the first number you may notice is that we ended the year 2014 with less debt than the end of 2013. Aggregate debt and leverage are both down from last year, even though we added 2.1 TCF of proved reserves and grew production by 26%. The steps taken mid-year in 2014 to reduce leverage and interest carry by calling our highest cost notes has positioned us well for the current more challenging environment.

Looking forward, our revised $870 million capital budget results in a very modest cash flow over spend, which is easily funded by our recently renewed bank facility. At year end 2014 we had over $1 billion in liquidity available under our $2 billion commitment, and over $2 billion in available liquidity under our $3 billion borrowing base.

Another balance sheet number that you may notice is our retained earnings topping the $1 billion mark for the first time. Considering that for six consecutive years we have seen our realized price per mcfe come down, while cash flow and cash flow per share for the past six consecutive years has gone up, we view retained earnings growth as yet another indicator of our improving capital productivity, the quality of our assets, and our relentless focus on growth at low cost. Please reference our fourth-quarter earnings release for detailed expense item guidance for the first quarter of 2015.

The earnings release also contains summary details of our hedge positions on both commodities and basis for 2015, 2016, and 2017. Additionally detailed hedge volumes and price information may be found on our website. To summarize, 2014 brought record high revenue, operating income, cash flow, and cash flow per share with record low cash unit costs. The progress we made in 2014 places us on firm ground as we enter 2015. With additional capital efficiencies and cost reduction still to come, we are confident in our ability to continue to deliver consistent growth for many years.

Jeff, back over to you.

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

(Operator Instructions)

Ron Mills, Johnson Rice.

Ray, you talked about slides 8 and 9 and it shows that cost improvement particularly adjusted for lateral length. There's a big decrease as expected, a much bigger decrease is expected in 2015 versus 2014.

Can you talk about how much of that is related to the lower overall service cost environment versus ongoing efficiencies? I'm just looking at the last bar and the well cost per lateral length, and the pace of the decline is much greater in 2015.

Yes, good morning, Ron. Good question.

The difference -- when you look at those charts on page -- slides number 8 and 9, what you've seen from 2011 to 2014 has pretty much been a factor of well design improvements, longer laterals, operational efficiencies and the capital efficiency that we've seen during that timeframe. From 2011 through 2014 we really have never seen service and supply chain cost reductions.

So the difference in the slope of that line, if you want to look at it that way, going from 2014 to 2015, is the service -- or the supply chain side of the -- the pricing reductions that we're seeing. We're seeing discounts across all of the sectors, across -- from drilling rigs all the way through, every piece of it.

I think the jury is still out on how much more of that we'll see during the year, but I think it will depend on the activity across the industry. But certainly with all of the capital reductions that we've seen across all the different plays, we're taking advantage of those every opportunity we get.

But that's the big difference so that what I quoted in my remarks, the 37% reduction that we're seeing from 2014 for the plan to average in 2015 is really a combination of well design improvements, operational efficiencies like we've seen in the past. And we'll continue with all of those innovations. And then the other is the new thing this year is really the difference in well cost from the supply chain side of things.

Okay, great. Later in the presentation you show each of the areas and you have the 2014 actual production versus the unrestricted type curves. Can you give just a little bit more color on what the restrictions are? And is it just the build out of gathering and right sizing the gathering for long term as opposed to flowing unrestricted? And I assume your guidance is based off of how you're actually flowing them as opposed to the unrestricted type curves?

Another great question. We've done a couple of things in our presentation this time. One is in 2014 we were showing you an unrestricted, unconstrained, however you want to say it, type curve that was based on the wells that we planned to drill that year. Going forward we're showing you our predicted forecast for the wells based on all of the systems that we have out there, the timing and so forth.

And we're basing the mix on the wells that we're actually going to put to sales. So it will actually help the investors more correctly model our production forecast going forward. And that's the big difference in the curves.

Ron, this is Alan Farquharson. With that I think Ray covered a couple of those things that really talked about we're trying to make the forecast easier for people to model, one.

Two, I think at the end of the day what it looks -- what you're seeing is well EURs on a per normalized basis are exactly the same as what they were before. Overall they're going to be -- we're going to have higher EURs because in fact we'll be drilling longer laterals, and we're also realizing the benefit of lower well cost.

With that, this is the constrained situation if you want to call it, or restricted, is really the result of success of the drilling programs that we've had over the last several years. It's traditionally you design systems to maximize the overall value of the whole project as opposed to individual well economics.

So with that we've modeled everything from that standpoint. That's not to say we're not going to -- we're going to stop to not find improvements.

We still think that they are going to be able to realize some improvements going forward in terms of looping lines, additional compression. We have a plant coming on, scheduled to come on in 2016. We're also looking at improving the pipeline hydraulics that are out there.

So we think with that there are also going to be some improvements that hopefully we'll be able to see over the coming -- in 2015, 2016 and beyond. But with that we believe this is a great model to be able to get to the 20% growth that we have.

Great. And then into the optimized versus original curves on slide 35, is it fair to assume that the plan is to really do the 700-foot spacing going forward? Or is it -- are you still -- is still early days?

Well you'll also see, Ron, in our presentation that the slide before that on slide 34 is an update of the 500-foot space test that we had talked about several quarters ago. Probably over a year ago. We're updating that.

We now have basically five years of production on those tests, and our original projections of about 80% of the 1,000 foot example is still holding very true. What slide 35, what the example I called out in my remarks does is show you not only a version of that, but it also shows you the improvement in well designs and operational efficiencies and just better targeting, all of those impacts basically showing the two new wells on a normalized per foot of lateral basis produced 53% more production over a year's timeframe than the original wells, which were only two years prior.

I think going forward we have a mix of both of those cases. Now whether the spacing is 500 foot or 700 foot or 900 feet or what the ultimate space is going to be, I think when you look at our core position there in southwest Pennsylvania it's very large and it's very diverse.

We go from super rich all the way to dry, and I think as we develop over time you're going to see some areas in the liquids I would think where we probably ended up wells closer together there and maybe not as close in the dry area. But I don't think at this point in time we can say it's going to all be 500s because I don't think that's going to be the case.

But it's certainly going to be a lot more infill well drilling, and when we go back on those existing pads it's really important to point out the improvement in well performance that we are seeing. But also you can't forget the decrease in well cost.

When you're looking at $850,000 less per well, those economics are going to be outstanding going forward as we go back in and redevelop those areas to fill in the gathering system as we get more room. Gathering costs will come down in those areas. That's going to be some real upside for us going forward.

Great, thank you.

Just to summarize that a little bit. That slide 34 all those wells were drilled at the same time, so that you had a pilot of 500-foot wells versus opposed to 1,000 all drilled with old technology of five years ago and infill looks very attractive.

However, when the wells are wider spaced initially and then we've gone back years later and infilled, rather than that infill well getting 80% of the original well, it actually is better because the longer laterals, RCFs, better landing, all the things that Ray said. So the infill wells rather than being a fraction of the original well are actually better.

Thanks again.

Doug Leggate, Bank of America.

Hi, this is John Abbott speaking for Doug Leggate. We just had a couple questions, apologize if they had already been asked.

With regards to the Mississippi line, is that even considered core anymore and something that you would potentially consider divesting? And considering -- if so, when you look at the Nora, is there a possibility -- what would you need to see in order to pick up activity?

And then our follow-up question is it looks like based on your new program your 2015 budget, there is the possibility that you may generate free cash flow. If so where would you allocate the cash? Thank you.

This is Jeff. Let me start and I would imagine you'll hear from two or three more other than me. I think what you've seen us do it focus our capital on the Marcellus where we have very strong returns, the ability to drill dry, wet, and super rich and we get strong returns, we get good growth. Its also an area where there's infrastructure, ability to grow it. There's contracts in place. We have to hold acreage. There's a lot of different factors that blend into that decision to focus in the Marcellus. And I think if you step back and look at it I would argue there are returns in the Marcellus that are as good as any play really in the US today. So strong returns and yes, it's an area we need to drill to continue to hold acreage which we'll do. When you look at Nora it's a totally different decision. It's all HBP, in fact its better than that and we own the minerals under the bulk of it. So ahead strong returns, strong economics, and good gas markets, but that scenario we have the ability to ramp up when we're ready to do that. And great asset. I think we created a lot of value by putting it together. Again, its all the strengths that Ray said. We put the two pieces together that creates value. We tried new technology. There's some great slides in the book that show what those new wells look like in the appendix. And we still get a premium to NYMEX there and we have the ability to grow and ramp that in probably one of the best if not the best gas market in the US. In the Midcontinent the decision to slow down there was given the returns that we have in the other areas, we were putting like I said in my notes, approximately whatever the number was, 97% or so plus or minus of our capital in Appalachia. So we thought the most efficient thing to do is to really operate those properties out of Fort Worth. There are significant G&A savings that Roger mentioned, several million dollars a year in savings. We still think the properties have potential. Its a big footprint, stacked pay, a lot of that's controlled. Let me switch gears a little bit and just talk in the abstract. You talked about -- you look at asset sales clearly over the last several years we've sold almost $3 billion worth of properties So if we ever get to the point where we think those assets are worth more to somebody else than us, and clearly we've done that multiple times. To be honest with you its early in the morning and I don't remember all the other questions. I'll turn it over to Ray or Roger. (laughter)

John, this is Roger. Your free cash flow question. I think your modeling is correct.

It's a very, very modest overspend by projection, the lowest overspend we've had since I can remember. The interesting thing about it is it's not contingent on some asset sale, so there's no asset sale risk in that number.

It's not contingent on some capital market transaction, so there's no market risk in that number. And you're right, more cost savings and/or higher prices could easily flip us to cash flow positive. And if we find ourselves in that position we've got lots of places to put the capital and we'll make that decision at that point in time.

I appreciate it. Thank you.

By the way a little color, we're sitting here looking out the window in Fort Worth and it's an intense snowfall. It's extremely rare for those of you that don't know Fort Worth, but very beautiful. Next question.

Holly Stewart, Howard Weil.

Hello?

I'm sorry. Phillips Johnston, Capital One.

Hey, guys, thanks. In your prepared remarks you referenced sequential production growth throughout this year, and I'm wondering how the quarterly progression of that growth is expected to look like in the second, third and fourth quarters?

Is it expected to be fairly smooth at close to a 5% sequential per quarter growth rate? Or would you expect some lumpiness in the progression?

Phillips, it's a great question and I think it's -- we still feel very comfortable with the 20% growth for the capital that we said. Now we've given you the first quarter guidance, so by definition its kind of back-end loaded.

I think if you look at the Company historically it's looked that way for the last decade. So I would just look at the last few years and model it that way.

Okay. Then as we look into next year it sounds like, Jeff, you're pretty confident that you can maintain that 20% growth rate. Obviously drilling efficiencies are a tailwind for your growth rate, and you have some mix shift from the Midcon to Appalachia, but can you give us some comfort as to how you can continue to grow at that level despite the fact that your planned well count this year is down more than 25% year over year?

Yes, well I think it speaks to -- when you look at the wells, the quality of the wells has gotten better year after year, and we've talked about that a lot. It's longer laterals.

This year we're targeting 6,000 foot on average roughly, and I think you'll see the laterals progress with time to longer laterals, better technology, better landing, better capital efficiencies. If the pricing, strip pricing holds in there with us and I think we'll be in pretty good shape.

I think the other things are probably like a lot of other companies for 2015 our production curve will progress throughout the year towards back-end loaded. So it gives us a good start on 2016. So I think that coupled with capital efficiencies puts us in a position where if you asked today we still feel that our getting 20% growth is very reasonable.

Okay. Thanks, Jeff.

Holly Stewart, Howard Weil.

All right, let's try this again. Can you hear me?

Yes.

Okay, great. Maybe just switching gears to NGL realizations, because you talked about in your presentation how in the second half of year there will be a higher percentage based off of natural gas.

And obviously the fourth quarter NGL realizations were a lot better I think than everyone was expecting. So could you just maybe walk us through how to think about that in 2015 and beyond?

Yes, hi, Holly this is Chad. There's probably three things that affected or influenced fourth quarter NGL realizations or improvements.

One, you got to realize or remember that Range has a POP processing arrangement with MarkWest. So as prices come down the fee we're paying MarkWest comes down which improves our realizations.

October, November, the market saw a bit colder temperatures, so demand for propane, heating demand for propane increased. So propane prices improved a little bit.

And approximately half our NGL barrel is ethane, and 80% of our ethane is currently tied to natural gas index as we sell on our Mariner West project, all of the ethane is sold on a gas equivalent and some of the ethane on ATEX is sold at a gas equivalent price. That's why you saw the realizations improve in fourth quarter.

Okay, that helps. And then maybe just a bigger picture question for Jeff.

You've laid out in the slide deck you're going from 1.4 I think it is to 2.5 bcf a day of transportation agreements between 2015 and 2018. So maybe strategically can you reconcile that growth and ST capacity to the growth in expected production should prices remain weak?

I think one thing we've had for a number of years now is a long-range plan. So we have a very integrated process where we look at the production profile that we expect and will integrate it with Chad and the marketing team in terms of the amount of firm transportation that we need to hit those targets.

And it's not just on the gas side, but on the liquids side as well. We do have -- so we have a good plan, capital efficiencies like we said will continue to improve.

I think you'll see us move out to longer laterals, more frac stages, all those types of technologies that help on that side. So our capital efficiency should improve.

I think another key thing to think about too is we really think natural gas demand is going to improve with time as well. And I mentioned it in my notes early on with the mass retirements on power plants kicking in in the spring of this year, increased exports to Mexico, and LNG starting up later this year, we think demand will be up one to two Bs this year.

And then we think for every year thereafter demand increases three to four bcf per year. And there's a slide in our book that points that out.

Peeking at where we think incremental gas demand could be 20 bcf by 2020. So we think there's going to be a lot of gas demand and gas is going to be a good place to be, and we're in the highest quality -- in the core of the highest quality best gas play out there with the ability to drill wet, dry, and super rich as well as Marcellus, Utica, and Upper Devonian.

Thank you, gentlemen.

Brian Singer, Goldman Sachs.

Thank you, good morning. Just one question on how you're thinking about longer-term Marcellus production relative to your takeaway capacity.

What scenarios do you see relative to the very large takeaway you have lined up to get gas out of the basin for you to be producing above that number versus below that number? And how are you thinking about scenarios and what to do with in terms of contracting additional takeaway capacity, if your plans are to produce above that in 2018, or what you will do with any excess takeaway capacity if you're producing below that?

I think if you look at us now we're basically fully covered and well integrated for the plan that we have. And right now there's a benefit to having all that firm transportation.

There is value to that portfolio, and yet I think we have a very forward-thinking team that's been able to line up pieces. And let me flip it over to Chad to talk about that a little bit more.

Yes, thanks. So getting to where we are today, the firm transport capacity we have through 2018 has been a very thoughtful methodical process, getting with our drilling teams and understanding what our volumes are going to be up through 2018 and beyond.

When you look at slide 37 in our presentation it shows regionally where that firm transportation is and what we deem as relatively cheap firm transportation costs. That dovetails or fits real well with our projected volumes.

Going forward we think that there's release capacity markets we've already been involved in and getting again relatively cheap or inexpensive firm transport to layer in to the areas we want to get our markets to. Obviously slide 37 shows our main objective is to try to get as much of our volume out of Appalachia into other areas Midwest, Gulf Coast, and southeast. And in the future we want to try to do that as well.

We think that with rig rates coming down, CapEx budgets being cut, projected volumes will be coming down, and those companies that committed to firm transportation volumes will not be using all of that capacity. So we're going to take advantage of that and get into the release capacity markets, and when needed speak up for some of that released capacity. We're also in discussions with some of the midstream companies about adding and layering in additional strategic firm transportation projects that would fit our volumes and our needs, again getting the volumes out of the Appalachia basin to other areas of the country where the basis is not been quite as volatile and we don't think it will be in the future.

Got it, thanks. Then with regards to the cost reductions that you seem to be showing here at least on a per 1,000 foot of lateral basis in the super rich and southwest wet Marcellus plays, can you talk to how much of those lower costs or what the split is in terms of what you would call cyclical service cost reduction that maybe in a higher oil and gas environment would go away versus what you would consider secular?

Sure, Brian, this is Ray. In my remarks I tried to do that as best we could, but one of the things I said was that on an apples-to-apples basis if you look at the contracts, I'll call them arrangements, if you look at the arrangements we have in place today with all our folks, our partners on the supply chain side of things and you look at apples to apples compared to December of 2014 to today which is what we have in hand again, our well costs are down 23% to 25%.

The operational efficiencies, design improvements, the new technologies all those things that we've done over the past four years are going to continue going into 2015. So when you add those together that's where you achieve that big changes that you're seeing from 2014 to 2015, which is a bigger decrease than the slope of that line had been previously.

Adding those two together gets you a 37% decrease on a per foot basis. We haven't put that in a total well cost basis just because all the lateral links are different and it's just too difficult to talk about from that standpoint. But again, the service price reductions and supply side of things reductions, those add up to about 23% to 25% on an apples-to-apples basis compared to December of 2014.

I think if you look on slides 8 and 9 there's a lot of detail, and you can see like Ray mentioned earlier there wasn't much of a change in service industry costs from 2011 through 2014.

If anything it went up.

So those are pure operational efficiencies.

Great, thank you.

Sameer Uplenchwar, GMP Securities.

Thanks for squeezing me in. And congrats on another great quarter.

My first question is related to slide 17. If I look at the IRRs now I understand they are coming down for the super rich and wet gas window driven by the oil pricing, but how does this change the plan, longer-term plan for Range going forward with gas competing well with the super rich and rich window? Then I have a follow up.

Let me start and Alan might have a follow up. But one of the advantages that we have is we do have a big acreage position in dry, wet, and super rich.

And again across those three things as well as up and down through the various horizons, Marcellus, Utica, and Upper Devonian. So we have some ability to shift capital back and fourth to try to drive further capital efficiency and better returns.

That's an advantage of the portfolio and the size of the footprint that we have. And we'll do that with time.

Obviously as prices swing, as oil swings high to lower, gas swings higher to lower NGLs, it's going to affect the economics and we'll do our best to capture the most optimum returns that we can. Alan, do you want to add to that?

Yes, really I think it comes down to, and onto what Jeff said, we had the opportunity to be able to drill in any one of the three areas, number one. Number two you saw that in 2014 as well, that we had a balanced portfolio.

We talk about that early in the year last year and so you saw a mix of wells that are going to be in there. I think it still comes down to well performance is still really strong.

Recoveries are still on a normalized basis, still the same but overall URs are going up. Costs are coming down, so as we continue to work through that process we're going to continue to put the capital in there that's going to give us the best return that we can realize.

But I think you see those two things really coming at the end of the day. And it just allows us more enhancement to the portfolio.

That's an advantage of having a really large footprint in the core of the play with high-quality rock with a strong team through multiple years that you can make those kind of continued improvements.

The follow up is, Roger, middle of last year that was there was a plan to get to investment grade by middle of 2016, maybe late 2016. How has that plan changed with the commodity coming down now?

Hi, Sameer this is Roger. I don't believe we ever put a date on which we desired to be investment grade. The agencies tend to take a dim view of their customers telling them that.

So there was never a firm date, but you're exactly right. We were on a trajectory and still are to become investment grade in the future.

With the lowering of the tide affecting all companies it appears that it's going to take a little longer than it otherwise would have for us to be there. When you look at our core metrics and the fact that where our bonds trade, every one of our bonds even though the coupons are like 5%, all of our bonds are trading over 100 cents on the dollar.

Our spread to treasuries and our longest notes are about $2.98. So our bonds are trading right at the crossover mark, so I think the people that really understand credit liquidity are voting with the market and we're still on that trajectory. But again, we're not going to project when that might occur in the future.

Perfect. Thanks.

Thank you. We are nearing the end of today's conference. Drew Venker, Morgan Stanley for our final question.

Good morning, everyone. Jeff, if you could put a little bit more color on the Utica program?

You mentioned building on some infrastructure. Are you expecting to produce that well at a higher rate once the infrastructure is in place?

Good question. We're excited about the Utica, the first well, it's only been online a few weeks. We purposely designed the production facilities to basically limit that well at 20 million a day because again we tend to focus at Range on the long-term project economics and not initial production rates or anything like that.

Because the projects at the end of the day are what's most important. For the first half of this year that first well is actually producing on an interruptible basis as we have room to cram it in, so to speak.

We are currently building a new pipeline segment that will take it directly to a big pipe essentially. That will be finished sometime this summer, and that is also corresponding with about the time we believe -- and all of this is plus or minus a month at this point.

But that's going to correspond with about the same time that the second well is ready for initial production. We will design those facilities for that second well to also limit it to about 20 million a day, but we do expect for the last half of the years that both those wells will be able to produce at their full rate, which is going to again be limited to 20 million a day each.

But we think they'll come online this summer time and produce the rest of the year on an uninterruptible basis. The third well we'll drill later in the year.

At this point it's too early to tell, we're kind of in the planning process and permitting process to know if it will actually produce this year or not. But it will be somewhere around the end of the year or beginning of next year when the third well is ready.

Second well we think we can do at about $13 million. It still got some science in it and again, I am fully expectant and I think our team is pretty pumped about what we see so far.

And they think that we believe that as we go into that program that we can lower those costs another 15% to 25% as we kick in well designs and different things that we learned going through these first couple of wells. And I will also point out that third well, it will be in that same area but it will actually be on a different pad, is the current plan.

Okay. Understood. It's obviously very early, how much production history or well control would you want before moving the Utica into development mode or before you're let's say allocating a significant amount of capital to the play?

We have a lot of information about the Utica. We had as we talked about in quarters past a lot of old Trenton Black River tests and a lot of port test wells that were done back in the very early days before the Marcellus even.

So we have a lot of log data. Industry has certainly drilled a lot of Utica wells all around us at this point.

There's enough production history now to prove up some of the things on pressure and the reservoir parameters that we were looking at. So the Utica is a lot different than the Marcellus.

We won't have to be stepping out and delineating acreage like we did in the early days of the Marcellus. This is going to be more of a manufacturing type process.

We'll actually be able to just to put pads on existing pads with existing infrastructure and start layering those wells in over time. We generally like to see and we will update you quarter by quarter as we see the production from these wells, just like we did in the early days of the Marcellus.

And I think once we've seen three to six to nine months of production on these various wells we'll be pretty comfortable with what we have going forward. At that point I think it's going to be a factor of the economics.

It's going to be pretty easy to grow with those kind of wells. It's going to be -- the economics are going to be very competitive.

I think that we'll have to look at what the market is telling us at that point, 2016 and beyond as we develop these plants as what we do next. But it's another really strong option for us and that's what we like.

Thanks for the color.

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

2014 was a record year for Range. Cash flow was over $1 billion for the first time in the Company's history.

Reserves reached a new record level of 10.3 pcfe. With the Conger/Nora swap we now have operational control over essentially all of our properties.

We ended the year with lower debt and approved bank facility with plenty of liquidity and no bond maturities until 2020. 2014 was also a challenging and difficult year, with falling commodity prices that have continued into 2015.

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 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.

Ladies and gentlemen, thank you for your participation in today's conference. You may now disconnect your lines at this time.