Rodney L. Waller - Senior Vice President and Assistant Secretary Jeffrey L. Ventura - Chief Executive Officer, President and Director Ray N. Walker - Chief Operating Officer and Executive Vice President Roger S. Manny - Chief Financial Officer and Executive Vice President Chad L. Stephens - Senior Vice President of Corporate Development Alan W. Farquharson - Senior Vice President of Reservoir Engineering and Economics

David W. Kistler - Simmons & Company International, Research Division Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Welcome to the Range Resources First Quarter 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 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. Rodney L. Waller: Thank you, operator. Good morning, and welcome. Range reported outstanding results for the first quarter, with record production and continuing decrease in unit costs over the prior year. The order of our speakers on the call today are: Jeff Ventura, President and Chief Executive Officer; Ray Walker, Executive Vice President, Chief Operating Officer; and Roger Manny, Executive Vice President, Chief Financial Officer. In addition, 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-Q with the SEC yesterday. It should be available on the homepage of our website, 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. Now let me turn the call over to Jeff. Jeffrey L. Ventura: Thank you, Rodney. Range is continuing to successfully execute its plan and we're currently on track to grow our production volumes at 20% to 25% for this year and beyond. For the first quarter, production grew 21% over the prior year quarter. Cash flow reached $262 million, which is an increase of 20%. Unit costs decreased 6% compared to the prior year quarter, and net income was $33 million. On the operations side, it's fun to announce that we drilled our best Marcellus well ever, in what we believe is the best Marcellus well ever drilled by the industry in the southwest portion of the play. The well tested at a 24-hour rate of 6,357 Boes per day, or 38.1 million cubic feet equivalent per day from a 7,065 foot lateral with 36 stages in the Marcellus. Our team continues to demonstrate its ability to consistently improve and raise the bar. This speaks both to the quality of our acreage and also to the quality of our team. The Midcontinent team also set a new record by drilling our highest oil-rate Mississippian Chat well to date. This well came online at a rate of 1,263 BOEs per day. Of this total, the oil-only rate was 1,062 barrels per day. As I discussed in detail on our last call, I believe that there are 3 key items this year that will distinguish performance between companies in our industry: one -- the first one is owning a sizable acreage position in the core area of the key -- of a key play such as the Marcellus; the second is the ability to consistently execute well; and the third is having a strong forward-thinking marketing team. In regards to item one, we have a huge position in the quarter to Marcellus, which is the best gas play in North America, maybe the world, given the economics of the Marcellus and the risks elsewhere. In terms of being able to consistently execute well, Range has a 10-year track record of consistently meeting or exceeding its targets, a 10-year period with a 20% production CAGR. Over the last 5 years, our Marcellus CAGR is 96%. Given our strong portfolio of natural gas and liquids contracts from customers, I believe we have a strong forward-thinking marketing team with a demonstrated track record. One comment that I hear is that the Range story is well-understood and that people have confidence in our ability to grow production by 20% to 25% for many years. The question that I get following that comment is, what does the market not understand about Range? I think there are several things, particularly for those that model the value of Range. Since we discovered the Marcellus in 2004, the quality of oil wells has improved in terms of production rates and reserves each and every year. We've shown our historical improvements in terms of 0 time plots year after year. In addition, you can see this improvement, and that every year since then, we've had positive proved reserve revisions reviewed by our independent reserve auditors, which further confirms the strong performance. For those of you who model Range's future in the Marcellus, I believe that we can continue to see these kinds of performance improvements over time. In our view, the capital efficiency improvements are not over and should be considered in any evaluation of Range. We've also seen efficiency improvements year after year on the cost side. LOEs per mcfe has significantly decreased since the discovery. G&A per mcfe has also crested over and has been declining. We believe there's still room for both to continuing to decrease on a per mcfe basis as production goes up. Interest expense has been declining on a per mcfe basis as well, and absent significant changes in the macroeconomic environment, I believe that this, too, will continue. Therefore, we believe these future cost efficiencies should be considered in evaluation calculations as well. If you have a high-quality technical team and a huge footprint in the core of a high-quality play with thousands of wells to drill, that's the type of performance that should occur, and that's what we're witnessing. In addition, as we continue to develop the resource and get better and better with time, the recovery factor of the hydrocarbon in place should increase. In my opinion, in the core of a high-quality natural gas play, the recovery should approach and may likely exceed 50% of the in-place volumes. As we continue to develop this resource and acquire more data and more history, the probability of success of this project should continue to increase, thereby increasing the value of our company. In addition, as we go forward, I believe that gas markets will improve given the move to increase gas usage and power generation and in the petrochemical sectors, along with the rise of manufacturing. LNG exports will also be a driver, and slowly but surely, transportation fueled by natural gas is increasing. Each successive year, we projected the value of Range should increase. Given our expectation that will drive up production 20% to 25% per year, each successive year the starting point for our production in the model will be higher, the capital and cost efficiency should get better, and ultimately we believe that the gas price will move higher. We believe we have the potential to significantly drive up shareholder value. Another significant upside that we have, that perhaps is not well understood by the market, is the Utica potential beneath our Washington County acreage. Based on our mapping and seismic, we believe that make we may have the dry core of the Utica play in that area. That's based on well control and seismic control, not only in Ohio and West Virginia, but in Washington County, Pennsylvania. Typically, in any play, the dry core is the area with the most prolific wells. While we've not yet included the Utica in our published resource potential figures, we have spudded our test well and we expect to have some results to talk about before year end. Our portfolio at Range essentially consists of 3 areas: about 1 million net acres in Pennsylvania; about 325,000 net acres in the Southern Appalachia basin; and about 360,000 net acres in the Midcontinent. These areas all have the same attributes that we really like at Range: great stacked pay potential; a rich hydrocarbon charge; good infrastructure; and great technical, marketing and operating teams focused on creating shareholder value with the assets. I'll now turn the call over to Ray to discuss operations. Ray N. Walker: Thanks, Jeff. I'll focus my remarks this morning on operational results, production guidance and marketing, and as always, there's specific detail in our earnings release and in our updated presentation and we can certainly cover any of that in the Q&A. I'll start with our southern Marcellus division in Southwest Pennsylvania with an example of improving capital efficiency, combined with improving well performance. We recently drilled 2 new wells on an existing Marcellus pad in our wet area. That pad had 5 existing wells that had been producing for a little over 2 years. One is the new well with a 700 foot spaced well and the other one was a 900 foot spaced well. That new wells averaged 3,776 foot laterals and 19 stages as compared against 2,500 feet and 9 stages on the 5 existing wells. And the new wells utilized our newer targeting technology, reduced cluster spacing, or what we call RCS completions, and our newer frac-ing science. These new wells point out some very important and significant value adds going forward. First, these 2 new wells, on average, cost approximately $850,000 less per well than like-kind wells drilled on a newly constructed pad today. In other words, an apples-to-apples comparison with today's cost and processes. The reason for the significant savings is the already existing infrastructure, in essence, the pad, road, water and some of the production facilities were already paid for, along with the gathering infrastructure. Secondly, the average initial production rate, or IP, of these 2 wells was $18.9 million a day each, as compared to $4.9 million a day each for the existing wells completed over 2 years ago. That's nearly 4x better. This is a tangible example of improving completion designs and technologies combined with reservoir modeling, and this example confirms our belief that there's opportunity to recover additional reserves at better metrics as we add wells on existing pads throughout the field. Third, even though the new wells were 50% longer laterals with more than twice as many stages, the new wells still cost 6% less than the original wells on an absolute basis. And we're almost 4x better performers based on the IPs. And lastly, but equally impactful, these wells came online approximately 9 to 12 months earlier than normal due to much of the permitting procedure being satisfied by the existing pad and related infrastructure. We believe we're still in the early innings of the ballgame in driving real step changes in value and capital efficiency going forward as illustrated by this example. 10% of the wells we're drilling in 2014 will be wells that we've gone back onto existing producing pads like this example, and we expect that percentage should increase in the years ahead. The second example from Southwest PA involves a new 5-well pad in the super-rich area. The 5 new wells were all completed with our latest RCS designs, having an average lateral length of 6,635 feet and 34 stages. Again, these laterals are significantly longer than our historical average. The 5 wells had an average IP of 28.6 million cubic feet equivalent per day each, or 4,773 Boe per day, of which 65% is liquids and is now our highest per well average IP from any pad yet in Southwest Pennsylvania. One of these wells IP-ed at 38.1 million cubic feet equivalent per day or 6,357 Boe per day with a 7,065 foot lateral and 36 stages, and is now the highest liquids-rich well IP, again, with greater than 60% liquids in the basin. In fact, we believe it's the highest IP rate reported in the southwest portion of the basin or any Marcellus well, either dry or wet. When you consider this fixed offset pad to this new super-rich pad, which hold 28 wells, having an average IP of 9.9 million a day with 3,650 foot laterals and 18 stages, these 5 new wells, on an absolute basis, have a 189% higher IP, and on a normalized lateral length basis, have a 60% better IP, again, illustrating that our team is getting better and better at understanding the reservoir and recovering more of the hydrocarbon in place. We get a lot of questions concerning how to compare well results with variable lateral lengths against the standard type curve. Considering the variability of lateral lengths actually being completed, we've now updated the presentation with a slide that normalizes our 2013 actual well data on a lateral length basis for our super-rich area. What you'll see is that with a year's worth of data, the 2013 wells on a normalized basis continue to produce about 50% above the 2013 normalized type curve. This clearly supports the upgrade of our type curves at the last earnings release. Going a step further, albeit very early, the 4 super-rich wells that we've turned to sales thus far in 2014, which averaged 5,933 feet with 30 stages are slightly outperforming the 2014 type curve. While recognizing they have less than 30 days of production history, we're cautiously optimistic this performance will hold up. And once we get more wells and more production history on the 2014 wells, we'll update and normalize the 2014 type curves accordingly. A third example of improving well performance is a new pad we just brought online in our dry gas area of Southwest Pennsylvania. This pad had 3 wells averaging 4,768 foot laterals with 25 stage completions. This is a brand-new pad and we're still cleaning these wells up, but all of these wells appear capable of well over 20 million a day and are exhibiting really strong wellhead pressures. In fact, one of the wells was flowing at over 30 million a day over the weekend. Takeaway of the pad is limited to approximately 50 million, and again, this is another example of applying our new completion designs in the dry area with some longer laterals and delivering outstanding results. Combining what we've seen from the first example of going back onto an existing pad with much improved capital efficiency and achieving much better well performance, coupled with the much improved and record-setting performance of the super-rich area and the dry gas area examples, our high-quality inventory becomes even more valuable. Being in a core position like we are, we believe the high-quality rock can continue to yield better and better results. And again, as I've said many times in the past and we just proved once again, we haven't drilled our best well yet. We expect our EURs to continue to improve on an absolute and normalized basis, while at the same time becoming more capital efficient. This is very impactful as we have a large footprint in the core of the Marcellus in Southwest PA and have only drilled a small portion of our inventory to date. And we have almost a 10-year track record in the Marcellus to support that we are getting better and better. Shifting to the Utica test. We've spud the well, and albeit very early in the project, we're on track to have test results by the fourth quarter. We're planning for a 6,500 foot lateral targeted in the Point Pleasant interval to be completed with approximately 32 stages, utilizing our latest RCS designs. There've been a lot of questions concerning what our expectations might be. While I'm not going to predict the test rate, what I can say is we're a little deeper, we believe we have a thicker formation with comparable permeability and porosity, and we believe we have comparable and potentially higher pressures than the key offsets to our West and South. Again, we could have the core of the highest gas in place in the Utica right underneath our core Marcellus and Upper Devonian position in Washington County, PA, and this well should tell us a lot about the potential value of that resource. In northeast Pennsylvania, we're continuing with our program, averaging one rig throughout the year while fulfilling our lease commitments and holding our production volumes approximately flat. As a follow-up to our last call, where I announced the 18 Bcf well in Lycoming County, that particular well, for the first 150 days, averaged 16.9 million a day. Again, it was a 6,353 foot lateral with 32 stages. The average of the 4 wells on that pad was 11.8 million a day each for the first 150 days, and the 4 wells had an average lateral length of 5,406 feet with 22 stages. The great news is that we have the ability and capacity to add as many as 25 more wells that will exceed 5,000 feet of lateral length in that immediate area in Lycoming County to significantly ramp up volumes when the time is right. In the Midcontinent 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 we just completed a new well that IP-ed at 1,263 Boe per day with 92% liquids, including 1,062 barrels of oil per day. This well has just yielded our highest oil rate to date in the play. As our team is applying the new stimulations, while it's still early, the results are encouraging. I want to reemphasize that our expectation for EURs remains in the range of 485 to 600 Mboe as we stated in the past. As you know, during the first quarter, we had a much colder winter in Appalachia than average, and it certainly exceeded what we had forecasted as normal winter downtime in our volumes. While we were successful in supplying all our customers during the extreme conditions, we did experience significant shut-ins affecting our production for the quarter. Despite those challenges, we exceeded our first quarter production guidance. And my congratulations to the operating teams across the company for all their great planning and execution during the extreme weather condition. Production for the first quarter was 1.056 Bcf equivalent per day with 35% liquids. Moving to the second quarter. In Southwest Pennsylvania, MarkWest just completed a planned turnaround of its Houston and Majorsville plant complexes that will significantly affect our second quarter volumes. This is a very positive event for Range, and despite the downtime, we are still on track for quarter-to-quarter growth and to grow our 2014 volumes 20% to 25% over 2013. It's important to point out that this turnaround completely took down all of our wet and super-rich production in Southwest Pennsylvania for 7 days. This turnaround was the first since the Houston site began operations in the fall of 2008 and involved major upgrades to various systems at both processing complexes. These upgrades set us up for an increase in process and capacity for Range by 200 million and should significantly enhance plant operations and provide better reliability and efficiencies, allowing for Range's wet gas and liquids growth over the coming years. We applaud MarkWest for their exceptional planning and execution of these upgrades, and we see this as a very positive event for Range. Inclusive of the turnaround, our second quarter guidance will be in the range of 1.06 to 1.075 Bcf equivalent per day with 30% to 35% liquids. The turnaround was significant and results in an impact of approximately 50 million cubic feet equivalent per day in our second quarter volumes. However, the turnaround also now gives us greater confidence in our remaining plans for 2014. Quarter 3 guidance will be approximately 1.16 to 1.210 Bcf equivalent per day, and quarter 4 should be approximately 1.28 to 1.34 Bcf equivalent per day, both with a range of 30% to 35% liquids. As we continue to emphasize, and as pointed out in the press release, Range's marketing strategy is to continually diversify and expand the company's markets with customer base in those markets and the indexes to which we sell. We continue to do this through the acquisition of firm transportation capacity that dovetails with our growing production volume. As part of this strategy, we've focused on projects that involve the expansion of existing infrastructure, thereby resulting in relatively lower transportation rates. And we continue to focus on projects with in-service dates that fit the company's projected volume growth. We're able to do this because our acreage is located in Southwest Pennsylvania where the existing infrastructure is already expansive and in close proximity to our operations. Slide 21 of our presentation provides a detailed breakout of the regions of the country where we're sending our gas, the associated volumes and transport costs. You will note on the slide that our current firm transport cost is approximately $0.25 per mcf, and by 2016, is projected to be $0.21. Not reflected on this slide is a recent arrangement Range has entered into as anchor shipper on a pipeline expansion project. This firm transportation agreement provides Range with an additional 200 million per day of capacity from Southwest Pennsylvania to the Gulf Coast, with a projected in-service date of June 1, 2017. We also picked up 25 million per day of released capacity effective April 1, 2014, to East Coast markets with some of the strongest basis to NYMEX. Also in our press release is a schedule that provides detail of our corporate differential to NYMEX over the last 5 quarters. This schedule also provides detail of our Marcellus-only basis to NYMEX. First quarter 2014 corporate basis before the effects of basis hedges was a plus $0.66, and after basis hedges was a minus $0.24 as it's very similar to the pricing we saw in the third and fourth quarter. The bottom line is that our marketing team is doing a great job accessing the best indexes to sell our gas. We like to stress that 85% to 95% of our gas is sold under more favorable indices, and by 2017, we'll be selling on approximately 20 different indexes, 15 of which are outside the Appalachian basin. Turning to our NGL marketing. Our 2 new ethane pipeline projects are working well, with Nova taking its full contracted volume on Mariner West, and the ATEX pipeline to Mont Belvieu is receiving its full amount as well. Mariner East is expected to be in service in 2015. Again, when all 3 ethane projects are up and running, we'll receive a 25% uplift on our ethane revenue versus leaving the ethane in the gas stream net of all fees. We have been and are continuing to take advantage of Sunoco's market export terminal in Philadelphia to access international propane markets on a seasonal basis. We're also in discussions to sell our butane volumes to international markets, all of this being tangible examples of the good work our marketing team is doing in the basin. In closing, Range has some great acreage positions across the company, and we have tangible and current examples unlocking improvements in both well performance and capital efficiency across all our divisions. And we have a great marketing team that continues to deliver, all of which continue to drive up shareholder value and gives us confidence in our expectations for meeting our goals going forward. Now over to Roger. Roger S. Manny: Thank you, Ray. Building upon the strength of our 2013 results, the first quarter of 2014 saw strong production-driven top line revenue growth, building significantly higher earnings and cash flow than last year. First quarter revenue from natural gas, oil and NGL sales, including cash-settled derivatives, was $467 million, 17% higher than last year. Cash margin for the quarter was $2.73 per mcfe, roughly the same as last year's $2.75 figure, but higher sequentially than the $2.68 per mcfe figure from the fourth quarter. Cash flow for the first quarter was $262 million, which was 20% higher than cash flow from a year ago. Cash flow per fully diluted share was $1.62, 19% higher than last year. EBITDAX for the first quarter was $305 million, 18% higher than last year. Net income for the first quarter came in at $33 million compared to a net loss last year of $76 million. Earnings derived from methods used by most analysts, which excludes asset sales, derivative mark-to-market entries and various nonrecurring items, was $74 million or $0.46 per fully diluted share. As Rodney mentioned, please remember that all our non-GAAP measures are fully reconciled to GAAP on the various supplemental tables found on the Range website. Moving down the income statement to the expense categories and keeping with our current practice of only commenting on expense items that were significantly different from guidance, most of the unit costs came in as expected or better. Cash direct operating expense for the first quarter at $0.41 per mcfe was $0.02 over guidance due to nonrecurring workover expense and higher field-level overhead expense, mainly due to costs associated with managing production to a record cold Marcellus winter and higher water disposal costs. We expect second quarter cash operating expense to return to trend at $0.36 to $0.38 per mcfe. Cash transportation, gathering and compression expense per mcfe was $0.78 for the quarter, also $0.02 over guidance, primarily due to maintenance and capacity expansion ahead of our volume growth. We added additional firm takeaway capacity at the start of the second quarter, which will not be fully utilized until future periods. And these capacity additions, while prudent to support expected production growth, are expected to cause an increase in transportation, gathering and compression expense in the second quarter this year to between $0.86 and $0.88. As we get past the impact of the processing turnaround and production builds in the second half of this year, we should see this rate come back down into the high $0.70 range. Exploration expense and unproved property impairment expense were both below the low end of guidance by a combined $5 million due to the timing of seismic expenditures and fewer lease explorations. Please reference our first quarter 2014 press -- earnings press release for additional detailed expense item guidance for the second quarter. Aside from higher book equity from a solidly profitable first quarter and cash flow continuing to grow faster than debt, things were pretty quiet on the balance sheet. The trailing 4-quarter debt-to-EBITDAX ratio rounds up to 2.8x, down from the 3x figure at the end of last year's first quarter. And in April, our bank group unanimously reaffirmed our $2 billion borrowing base, and we ended the first quarter with just over $1 billion committed liquidity. Range continued to orderly layer in additional 2014, 2015 and 2016 hedges during the first quarter. And the best place to obtain detailed hedge volumes and prices by product is the Investor Relations section of the Range website. Investors may also find summary hedge information in the press release tables. To close the finance remarks, Range is off to an excellent start in 2014, with production up 21% and cash flow up 20% from the first quarter of last year. Our cost structure and capital efficiency continue to improve while production increases and cash flow builds, trends that we anticipate will continue into the rest of 2014. Jeff, back over to you. Jeffrey L. Ventura: Operator, let's open it up for Q&A.

[Operator Instructions] The first question comes from the line of Dave Kistler with Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: I appreciate the breakout of the corporate differentials historically, and it looks like, obviously, in this quarter, due to favorable pricing up in the Northeast and kind of unfettered access to those markets is what drove that 88% -- or excuse me, $0.88 premium in the Marcellus. Can you guys talk about, I know you've got hedges in place, but what your expectations are for kind of expected run rate, both short term and long term, on those basis differentials at this juncture? Chad L. Stephens: Yes, Dave, this is Chad. Thanks for the question. First off, if you look in our earnings press release on Page 5, there's a table that talks about the corporate basis differentials and the breakout of our Marcellus, which was the specific Marcellus was $0.88 positive. But we also -- there's a little paragraph there that talks about going forward with our existing basis hedges, the impact of them are and they're relatively immaterial going forward. But to give you a little bit more color, let's briefly review some of the main points that we talked about in our last earnings call and then I'll talk a little bit more specific about new information that we have released since then. First, one of the most important factors regarding our differentials is determining what pipelines a producer has access to, and we talked about in Southwest PA, the multiple pipelines we have access to. When we began accumulating our Marcellus acreage position in 2006, not only did we want the best location based on gas in place and we have some gas in place maps in our presentations, as evidenced by the maps, we also wanted the best location based on accessible infrastructure. The bulk of our Marcellus acreage is located in Southwest PA near several large existing pipelines that give us access to multiple markets and pricing points. This diversity reduces the risk associated with all the recent basis volatility in the Appalachia indices that we've seen over the past 4 or 5 months. One of Range's unique qualities is our disciplined approach of finding multiple options. So you can see this in our selection of stacked pay acreage positions, the multiple NGL marketing ranges we have with our ethane, extensive customer base that we talked about and we're expanding on that, and specific to your question, really, is the pricing indices. The more good options we have, obviously, the better decisions we're able to make. Last month, we provided that we have 9 different pricing indices on which our Marcellus gas is currently priced and also showed our expectations to add a few more by 2016, and we continue to do that. I did not know of another producer in Appalachia that has the same level of pricing diversity. Our corporate differential during the first quarter, as we've shown, was minus $0.24, which is similar to what we've been reporting in the prior quarters. Although we don't guide for any type of specific pricing going forward, we do expect natural gas realizations to continue reflecting the general price movements of the multiple indices on which we sell our gas, and we talk about 85% to 95% of our gas is sold on premium or better indices. Only about 10% to 15% of our gas is exposed to either M2 or Leidy, which are the -- 2 of the more negative indices in the Appalachia basin. In the summary, this generally will result in slightly weaker basis relative than our mix, while in the winter, we'll have some more exposure to premium prices like we showed in the first quarter of 2014 during this winter vortex. I hope that gives you a little color about our perspective on pricing. David W. Kistler - Simmons & Company International, Research Division: It does, but I'm just trying to get a little bit more specific. When I look at kind of Q1 and Q4, as you highlight, it's sort of a corporate level of about a minus $0.24 -- $0.23, $0.24. Is that something we should run going forward in our economic models? Or do you think that, over time, you're going to be able to generate even higher returns, kind of similar to what we saw Q1, Q2 in 2013? Chad L. Stephens: Again, it was -- the first quarter was this unforeseen winter vortex and prices, all of the indices really spiked. And that was really what drove the loss in the basis hedges. We used all of our tools available to us. We accessed multiple indices through the multiple firm transportation pipe projects that we have, but we also use other tools such as basis hedging. As we entered this particular winter back in late summer and early fall, we were anticipating these basis blowouts, which were occurring as we entered the winter, and we were hedging to protect against continued blowouts. And unfortunately, this winter vortex hit, the basis narrowed. And we caught -- we got caught with these basis hedges. But we're going to always continue to use all of the tools at our disposal to protect against this basis risk going forward. So I hope that gave you some perspective of how we approach. I think going forward, relative to fourth quarter 2013 and first quarter 2014, when you look at where the indices were and where our corporate differential resulted, I think you can pretty much project similar differentials going forward, absent a winter vortex. David W. Kistler - Simmons & Company International, Research Division: Okay, I appreciate that color. And then just one other question. As you guys highlighted, you'll be moving from 6 horizontal rigs down to 3 horizontal rigs in Southwest PA through the balance of this year. Obviously, it highlights tremendous drilling efficiency and completion efficiency gains, but it didn't look like there's any change to forward CapEx. So with that in mind, does that mean that more capital is going to the individual wells, specifically through more stage completions, the tighter frac clusters, et cetera? Or is there potential that your full year CapEx actually could come in below expectation? Ray N. Walker: Well, that's a great question, Dave. Our CapEx budget is still going to remain at the $1.52 billion and we're not going to change that. We are -- you hit on a couple of points. We are definitely becoming more and more efficient. We're also drilling longer laterals. We have an extra rig in there for the, of course, the Utica test. It's really just a matter of timing and everything else that is the reason, the fluctuation of rig count, but it's really what we're seeing is capital efficiency, more RCS completions, longer laterals and it's just all a matter of fact of the timing. But our CapEx budget will remain at the $1.52 billion. David W. Kistler - Simmons & Company International, Research Division: Okay. Last question, at 3 horizontal rigs at year end, is that where you plan to be running in 2015? Or do you need to ramp that back up to kind of maintain similar wells drilled as you did in '14? Just trying to get a handle on how that's swinging up and down. Ray N. Walker: Yes, it will swing up and down throughout the year, but definitely there will probably be on average more rigs running in '15 than there is in '14 just simply because we're going to keep our production growth guidance in the 20% to 25% range. So of course, 20% to 25% of '14's volume is a lot bigger than 20% to 25% of '13's volumes were.

Our next question comes from the line of Jeffrey Campbell with Tuohy Brothers Investment Research. Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.: I've got -- I've sort of several kind of quick answer-type questions. The first one is the Utica test that you're currently drilling, is that being drilled on an existing production pad? Or is that a stand-alone well? Ray N. Walker: Yes, that is being drilled on an existing producing Marcellus pad. And we're actually offsetting one of the Trenton-Black River tests that was done years ago, have a high-quality 3D seismic that we shot across the position for the Marcellus, which also enables us to image the Point Pleasant interval in the Utica. And then we've got the ability to actually put this well into sales fairly quickly towards the end of the year. So we're pretty excited about the test. Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.: Okay. I noticed that the NGL production had a pretty significant uptick quarter-over-quarter. Is there any special color to that? Jeffrey L. Ventura: Yes, let me address that one. What you saw, as we have, as we mentioned in the press release, both of our ethane projects, Mariner West and ATEX, up and running. Next year, we'll add the third one that we have, Mariner East. And as we mentioned in the release and Ray did as well, once all 3 are up, it's actually a 25% uplift of taking the ethane out, that's net of all fees versus leaving it in the gas. To put a little more color, on an annual basis, that will be about a $45 million to $50 million increase in cash flow. Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.: Okay, great. And the last question that I'll ask today is, when do you plan to start to -- now that you've got the Utica going, when do you plan to start undertaking some liquids-rich exploration or development, whatever you want to call it, for the Pennsylvania Upper Devonian? Ray N. Walker: Well, we've, in the past, have drilled, I think, 4 or 5 Upper Devonian tests, and every time we drill a Marcellus well, we get a good look at the Upper Devonian. So we've mapped it out. There's now enough industry tests that have been done around our position in Southwest PA, as well as all across the play, actually. And we've got a few slides in our presentation that refer to that. I think Slide #24. So -- and when you look at all that data, that, to us, is something that's been unlocked. We had a really, really great well, the last well we tested. So we're basically holding that right now, focusing on the Marcellus. As we drill the Marcellus, we hold rights to all of the formations from surface to the center of the earth. So it's really a matter of focus for us today. And we have, as I talked about, really good examples of going back on the existing producing pads and wells that are a whole lot cheaper and a whole lot better performers. And we believe there's lots of potential to figure out the Marcellus. And I think you'll see the Upper Devonian layer into that plan as the years come forward.

Our next question comes from the line of Ron Mills with Johnson Rice & Company. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Ray, on the super-rich wells that you -- the 5 well pads you talked about in the longer laterals, those are 20-plus percent longer than what you expect for the average this year. Are you still sticking to the 5,300 foot lateral average for the year? What drove the longer laterals? And was there anything special or different about where you drilled that pad to result in that kind of deliverability? Ray N. Walker: Well, that is a great question, Ron. We -- the pad was actually not a special pick geographically per se as much as it was fitting into an area that we needed to HBP some acreage and also fill in the infrastructure. So it was probably more governed by that and was probably a location that was planned 2 or 3 years ago when we picked that location. So I think what you're seeing is a couple of things. We are producing or completing wells significantly differently than we did 2 or 3 years ago. We're using better frac designs, RCS completions, different profit mixes and all sorts of things that the completion team, the technical team up there are doing. They're also working a lot on targeting the laterals and figuring out exactly how to place these things in the Marcellus and it's making a huge difference, as you can tell, by this monster pad -- monster well that's on the pad. So this has been a really impressive pad for us. As far as lateral lengths, we're always trying to drill the longest lateral that we potentially can on a site. When we put out the average lateral lengths planned for the year at the last call, those were basically based on our plans at that time. Our hope is that we will basically get to drill a little bit longer when we actually get the rig on that pad because we'll be able to add leases at the last minute and things like that, that go forward. So all of those things being said, I think our average lateral length will probably end up being a little bit longer. But again, it is, on average, over 100-and-some odd wells. Some of those will be pretty long. Some of them are over 7,000 feet, and some, of course, will be shorter. So hopefully, we'll always be able to push that lateral length a little bit further as time goes on. Jeffrey L. Ventura: Let me add a little color, Ron, before you add your second question. And top of what Ray said, if you look at Slide 19, we show in the Southwest, dry, wet and super-rich, and importantly, that second line is EURs per thousand foot of lateral. And with the exception of what Cabot has up in the northeast, I think our EURs per thousand foot of lateral were probably second highest of anyone there. Really, what it speaks to is the quality of the lot. Now what you're seeing is we're taking high-quality rock and we're drilling longer laterals. So we drill a 7,000 foot lateral and we got a well that's 38.1 million per day. It speaks to longer laterals and more stages and all those efficiency Ray said can do, that was in the super-rich. In the dry, we went back and drilled some wells with little bit longer laterals and the wells are constrained, and just opening one up and it's still constrained, it was 30 million per day. So it shows when you got high-quality rock in the core of the play, and as we continually optimize completions, it speaks to, as we continue to migrate longer, what those wells might look like. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Great. And then, I guess, somewhat as a follow-up to Dave's question earlier. If you look at the success here in the super-rich and the 3 dry gas wells, you talked Marcellus, as well as you talked about in -- or earlier on the call, plus the Utica. When you think about capital allocation over 2015 and beyond, and also with the rig count that you talk about, how do you full strength your plays given the strong results in each of these plays, albeit with the Utica still drilling the first well? Jeffrey L. Ventura: Well, I think the key is on that same Slide 19. I just talked about EURs per thousand foot of lateral. If you look on the same slide, it looks at the rates of return. And you can see the rates of return, whether they're dry, wet or super-rich, are really strong in all 3 areas. So we intend to develop that entire position. And again, remembering that position is about 530,000 net acres on the slide before it. On 80 acre spacing just in the Marcellus, there's over 6,000 locations to drill. And as Ray mentioned, it looks like we can go tighter, we have hole pilots in some of these new wells that he referred to -- were really exciting because it shows going back in earlier, jumping back to last summer, so when you infill, we thought maybe those infill wells might be 80% of the offset. Now with some of these other tighter spaced wells going in with newer completions in older areas, it shows, hey, maybe we can do a lot better than that. So we've got the Marcellus to develop on top of it. The Upper Devonian looks derisked and a great opportunity and we'll find out. And hopefully, on our call in October, we'll be able to talk about the results in the Utica and we have high hopes for that. Again, we're offsetting old Trenton-Black River wells. So we've already seen the formation and seen what it can do and it correlates really well to the high-rate wells that are marching eastward towards us. In fact, one of them is within a mile of the edge of our acreage. So we plan to develop all of it. So really, what we think we're going to end up with is a cube of Upper Devonian, Marcellus and Point Pleasant below us with stacked pay potential and then you're going to have dry, wet and super-rich and really that whole thing looks good, which gives us the confidence to say that we think we can grow at 20% to 25% for many years with improving capital efficiencies as we go forward into a better gas pricing environment. Ray N. Walker: Ron, I was just going to add a little color to that. I don't know if I told you about these 2 wet wells we drilled. One of them, just to illustrate Jeff's point with a tangible current example, is we went back on this pad that has 5 existing producing wells that we completed a little over 2 years ago. So they've been on sales for 2 years and one of these new wells was placed between laterals that were 1,400 feet apart, so it's a 700 foot infill well instead of maybe a 500 foot, but that's pretty close. And the other well was between 1,800 foot, 2 laterals that were existing 1,800 feet apart so we put one in that's 900 feet spaced, in other words. Those 2 wells IP-ed at almost 20 million a day as compared to 5 million a day from the original wells. And what's more important than all of that, they're $850,000 cheaper per well on an apples-to-apples comparison. When we look at those kind of economics, what we show you on Page 19 doesn't even get close to what potential we could see going forward. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Which gets to the last point in terms of capital efficiency. I mean, obviously, significantly higher EURs at even the lower cost. You've made a lot of changes as you can -- as that highlights just on the 2 years on that 1 pad. How close are we getting in terms of getting to -- not maximum, but where do you think you are in the continuum of increasing capital efficiency, given the amount of changes that you made just over the past 2 years? Because I don't think they're driving potential significant value growth in -- when you look at your future inventory. Ray N. Walker: Yes, that's a great question, and I think we still got a long ways to go and it's an impact of several things or an effect of several things. One, we've got a really top-notch technical team that's doing tons of PVT analysis and reservoir modeling and analysis of targeting and all of these different things that they're doing. And we're in the core position in the play, which has better perm, better porosity, more hydrocarbon in place. And when you combine all of those things, I really think, as fast as things are changing, that we're still only in the third inning, maybe the top of the fourth of a baseball game trying to figure out what the potential could be going forward. We're only several hundred wells into what, like Jeff referred to earlier, could be 6,000-plus wells going -- when it's all said and done. So when you get a team that's that sharp, that's got the kind of track record that we've got and kind of improvements that we've seen just in the last few years, I think the potential is really, really big for what we're going to see in improvements going forward.

Our next question comes from the line of Bob Brackett with Bernstein. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Yes, a couple of quick ones, please, if I could. On that Utica test well, are you drilling a vertical pilot hole? And has that already been TD-ed? Ray N. Walker: We have not TD-ed the pilot hole yet. We will drill down and actually get some logs and so forth and then we'll kick it off and drill a horizontal in it. So I could -- you could say a pilot hole from the standpoint of just getting some logs and so forth, but we have an offset well fairly close but we will confirm that and actually match it up to our seismic and all of that going forward. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Okay. And then the other, back to the Marcellus, on these new RCS wells you've been talking about, especially the infills, what do you think the effective frac half-widths of these things are? Ray N. Walker: That is the age-old question. And if you ask 20 different engineers, you'll probably get 20 different responses. There's -- to me, as a guy that's done a lot of frac jobs over the years, it depends. When you talk about effective fracture length, if we're talking about where we effectively place the proppant in the fracture, that could be quite long, in some cases, maybe 500, 600, 700 feet half-lengths. But I think what we now understand in today's world is that these fractures are very, very complicated and very complex near the wellbore. And actually, what we're learning is we want more of that to take place near the wellbore. So I would tell you today that in an effective -- from an effective production standpoint, that you're probably 100 to 150 feet away from a wellbore at the best because all of the really good production that we're seeing is coming from pretty near wellbore. When you do history matching of pressures and different things over the years, you're going to see that, that -- that's what's happening. And you've seen that evidence in some of the fields that have a lot of history like the Barnett, where they've actually been able to put laterals as close as 125 feet in some cases. But clearly, they did it at 250 feet in a lot of areas in the sweet spot. Now will this go that far? It's way too early to tell that at this point. But we clearly, as the examples we've talked about this morning, clearly believe we can get to 500 foot spacing in the wet and super-rich area. I think there will be areas where you can go closer than that in some instances. I think the Upper Devonian may act the same way, but again, remember, the Marcellus is not the Marcellus everywhere. We're talking about a huge position in Southwest PA, 530,000 net acres, and the way we treat a well in the super-rich area is a completely different design of what we're doing in the dry area. Even though we may use the same techniques and processes and engineering principles that taught us what we know in the super-rich and we apply some of those things in the dry area, it's a different design that we're pumping in the dry area, and we're seeing that, that is actually working. When our reservoir -- we showed you super-rich, we showed you wet and we showed you dry in a presentation. When our engineers work on it, they're working on 20 to 30 different map areas just in the wet and super-rich area, for instance. So they're looking at a lot of different areas to try to design specifically for that instance. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: And on those 150 sort of wells stimulated, what does that tell you about the recovery factor of those rocks that close to the wellbore? Is it 80%? Is it... Ray N. Walker: Well, I think, when we look at all our numbers today, we think we're in the high 30s of recovery of gas in place. Now as time goes on, we'll probably be able to calculate that there's more gas in place than we thought there was, but we'll also get better at frac jobs. We'll also get better at initiation of fractures near the wellbore in making more complexity, and there may be stress shadowing and different things like that, that we can do to help create that complexity. But there's no doubt we will drive recovery of hydrocarbons in place up as time goes on. But today, I think we're still pretty solid in the 35%, 40%. Alan Farquharson can talk a little bit more about that. Alan W. Farquharson: Yes, Bob, we're still in that range in terms of where we think we're going to be. And as Jeff said a little bit earlier, we think we're going to be able to drive it up to over 50%. As you look at each individual layer, I think it gets very complex to try to say in the first 100 feet, we're going to be x percent and then we're going to get y after that. So I think, really, of all the numbers we continue to provide you is on what the resource opportunity is looking at specifically, our acreage block [indiscernible] over the years. In those numbers, there is variability depending upon where the acreage is and the hydrocarbon in place in those numbers. So obviously, in the cores, maybe a little bit higher than that. But in the aggregate, we're thinking that we're in the 35% to 40% type recovery range and that we think we should be able to exceed up to 50%, depending upon what spacing is going to be at end of the day, commodity pricing, et cetera. That is what's going to continue to drive recovery factors higher. Jeffrey L. Ventura: Yes, if I can just add on, if you go back to Slide 13, we have a gas in place now for the Marcellus Shale, and of course, behind that, the other horizons. And I really believe, and I think we believe as a team, where you're going to get the high recoveries, by high recoveries I mean maybe exceeding 50%, is in the core of the play. And there's clearly 2 cores, one in the Northeast, one in the Southwest. If you're in non-core, the recoveries are going to be lower, the stuff may never be drilled. So it's where your acreage is located. And again, going back to those original infills that we released last summer, we've shown that you can drill as tight as 500 foot between wells successfully. So how tight that ultimately gets, we'll see. But I think driving the recovery factors up will be a combination of tighter spacing, which may be the 500 foot, coupled with more efficient completions.

We are nearing the end of today's conference. We will go to Doug Leggate of Bank of America Merrill Lynch for our final question. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Can I ask a question about your -- you said that the limitations on how much further you can go with the lateral lengths on the wells that you drilled to date. I guess, what I'm really trying to get at is you're sticking with the 5,300 feet but -- and I think the expression you used in the press release is you continue to experiment. But are there any limitations as to why you couldn't move to the longer length as a more standard well design? And I've got a quick follow-up, please. Jeffrey L. Ventura: Yes. No, there's no limitations to our lease position or anything like that. I mean, so what -- I think what's really important, if you go to Slide 18, the fact that just -- we're just now -- we have roughly 1 million net acres in Pennsylvania, the biggest position, I think, in Pennsylvania than any company, and importantly, with big parts of that in the core, in the stacked pay areas where the infrastructure is and all that type of thing. But if you go to 18, even on 1,000 foot between wells, we've drilled 8% of our wells to date. And I think, ultimately, we'll be drilling on 500 foot in that core area. So you could argue we've drilled 4% of them. No, there's no limitation and what you've seen us do is progressively go longer. I mean, if you go back every single year, we're progressively -- we've gone longer, and you're seeing us now step out and try some 7,000 foot wells and all and, hey, with great results, 38.1 million a day, the best well ever by any company in the whole southwest part of the play in the Marcellus. In fact, if you look at liquids-rich, it's better than any of the Utica wells, if you want to look at it that way. So no, there's no limitation. So I think as good as the results have been, we can, like Ray said, we're probably bottom of the third, top of the fourth. We can continue to go longer. If we haven't optimized the first 4% to 8% of our wells, we'll get better on the remaining 90%, so we're working on it. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Okay. My follow-up, Jeff, I guess, nobody has really asked about the mix on the call. I just wanted to get your updated thoughts on that. And what's behind my question is, if you look at the well results, the most recent well results, I guess, after you changed your well design last year, you changed back again to, I guess, the longer laterals you're doing again now. But it seems that the well results are coming in a little lighter in terms of volumes, the 30-day volumes, compared to what you were getting in the wells last year. So I'm just wondering, what was your updated level of enthusiasm, I guess, in the overall quality of the play and in terms of how you think about future capital commitment and so on? I'll leave it there. Ray N. Walker: Yes, Doug, that's a good question. And I think in the last earnings release, we reported some 30-day rates on a group of these newer design completions, and that 30-day rate is a little bit higher than the 7-day rate we reported in this release. That's not unusual. These wells tend to start out and they don't, a lot of times, don't reach their maximum production rates for a week or 2, sometimes a little longer out. So I would expect that -- I wouldn't put too much weight in the 30 day versus 7. I mean, we certainly don't. I mean, we look a lot more at 30 days, we just don't happen to have 30 days on those wells yet. So we're still cautiously optimistic about it. We're very pleased of what the team's doing. They, as evidenced by, they just hit a record well. It's our biggest oil rate from any well to date. So I think we're doing much better at delineating the acreage and learning from our 3D seismic that we're getting in. We're -- the bigger stimulations, we're still tweaking some things in that. And I really think by the end of the year, we'll have a much better picture of how those wells are going to hold up. It's simply -- we simply need to see 6 to 9 months of production out of some of these wells and it's going to unfortunately take 6 to 9 months to see that. So we can't speed it up. So once we've got that data towards the end of this year, I think we'll be able to get a lot more color on how we see that play emerging from this point.

Thank you. This concludes today's question-and-answer session. I would like to turn the call back over to Mr. Ventura for his concluding remarks. Jeffrey L. Ventura: Yes, I'd like to start by saying I think there's roughly 10 more people that were in the queue for questions, so please -- I apologize we don't have more time. Please follow up with the IR team, and we hope to answer all your questions. But the concluding comments, we're on track to grow production 20% to 25% in 2014. I think cash flow will grow in line with that or perhaps better, we'll see. But given our approximately 1 million net acre position in Pennsylvania, focused in the southwest portion of the state where there's good historical infrastructure and where there's great stacked pay potential and because we have a great portfolio of dry, wet and super-rich wells, coupled with our approximately 325,000 acre footprint in the southern Appalachia basin and our 360,000 acre net footprint in the Midcontinent, we believe we can grow 20% to 25% for many years. As always, we'll stay focused on safely executing our plan and being good stewards of the environment. Thanks for participating on the call.

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