Chesapeake Energy Corp (CHK) 2015 Q1 法說會逐字稿

Good day, and welcome to the Chesapeake Energy Corporation Q1 2015 conference call. Today's conference is being recorded. At this time, I'd like to turn the conference over to Mr. Brad Sylvester. Please go ahead, sir.

Good morning everyone, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2015 first quarter. Hopefully, you've had a chance to review our press release, and the updated investor presentation that we posted to the website this morning.

During this morning's call, we will be making forward-looking statements, which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections and future performance, and the assumptions underlying such statements. Please note that there are number of factors that will cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our earnings release today, and in other SEC filings. Please recognize that, except as required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements.

So this morning's teleconference is going to be a little bit different than what we have done in the past. About a year ago, we had an Analyst Day here on campus, and we thought today would be a good opportunity to do another deep dive, like we did last year, into how we're adding value here at Chesapeake. So we're going to use this conference call as sort of a teach-in on the efficiencies and the progress that we're making in all of our operating areas, and the very detailed slides that we will be referencing can be found in the investors section of our website at www.CHK.com.

With me on the call today are Doug Lawler, our Chief Executive Officer, Nick Dell'Osso, our Chief Financial Officer, Chris Doyle, our Executive Vice President of the Northern Division, and Jason Pigott, our Executive Vice President of the Southern Division. Doug will begin the call, and then turn the call over to Jason and Chris for a thorough review of our operations, and then Nick will wrap up the prepared remarks before we turn the teleconference over for Q&A. So with that, thank you, and I now turn the teleconference over to Doug.

Thank you Brad, and good morning. I trust you've seen our release issued earlier this morning, and I hope you've had opportunity to review the slides that will accompany this teleconference today. Before we start, I want to highlight the newest addition to our executive management team, announced earlier this week. Frank Patterson will be joining us as Executive Vice President of Exploration, Land and Subsurface Technology later this month.

As you are aware, Chesapeake has had a strong history of exploration success, which led to early identification and entry into multiple outstanding acreage positions in the US on conventional basins. Frank brings tremendous experience and expertise to Chesapeake, and I believe he will be an excellent addition to our talented exploration, land and technology staff.

I also want to thank John Kapchinske, who served in this position previously, and who has retired from the Company. His service and commitment were outstanding, and we wish Kap and his family the very best in his retirement.

As Brad noted, we're going to do things a little differently on this call, and go into much deeper detail on an asset level, giving you additional information regarding our progress and describing the strategies we are pursuing to grow value for our shareholders. We have made significant progress as a Company the past couple years, executing on a value-driven strategy, with world-class shale assets and extremely talented employees. We continue to drive superior capital efficiency in our operations, and we have achieved industry-leading low cash cost, as measured by production and G&A costs.

Our capital efficiency improvements are recognized through reduced cost and increased recoveries, generating more investment opportunities with greater returns to our shareholders. We still have lots of work to do, but we continue to reduce legacy, financial and legal complexities, while maintaining a disciplined approach to our liquidity. We are delivering on our commitments, and you can expect that our strategy and investments will drive further long-term value for our shareholders.

Moving to our first-quarter performance on slide 4, we generated adjusted earnings on a fully diluted basis of $0.11 per share, with EBITDA of $928 million. Production costs and G&A expenses were down 5% year over year, and down sequentially from the fourth quarter of 2014.

Daily production averaged 686,000 barrels of oil equivalent per day for the first quarter, which is a 14% increase year over year. Daily oil production for the first quarter was up 17% year over year. As a result of the strong quarterly production, we are increasing our 2015 production guidance range to 640,000 to 650,000 barrels of oil equivalent per day.

Our 2015 capital expenditures are on track with recent guidance, as we continue to ramp down activity across our portfolio. I'm excited for Jason and Chris to share further detail with you regarding our operating performance and capital efficiency improvements. We will cover each of our major operating areas, and you will clearly see the strength of our portfolio and operating teams.

Every company is looking to improve capital efficiency, and every company will tell you that they are the best. But I've yet to see any organization post the high level of capital efficiency improvements that are being captured at Chesapeake. High-quality rock and high-quality operations are outstanding attributes of the Company.

Many companies have paid significant acquisition costs to gain entry into high-quality assets. But through our capital efficiency, we are organically increasing our inventory of drillable locations without the acquisition cost. Jason will share with you the best example of this significant value creation in the Eagle Ford, where we're adding 600 to 700 new locations, following successful down spacing tests and continued capital efficiencies.

He'll also share with you some exciting progress in the Haynesville area, where we have recently placed a middle Bossier well online that has been producing over 12 million cubic feet of gas per day, for over a month. The middle Bossier could add an additional 200 to 400 locations, located right in the middle of our Haynesville play, offering significant surface infrastructure synergies. This new opportunity is available today as a result of our outstanding capital efficiency.

Chris will follow Jason, and share the huge value Chesapeake has created in the Utica, and the exciting results we see in the Powder River Basin.

I want to highlight that I'm very proud of what we have done over the past two years to turn Chesapeake into a formidable competitor, with an asset base that is unmatched. For that which we can control, we have performed outstanding and differential to the peer group. We're progressing forward on our path to becoming a top-performing E&P company, with thousands of locations and inventory to develop for many years to come.

I'm very confident in our teams, and what we're going to achieve. Applying high-quality operations to our strong portfolio, and expanding our inventory of competitive investment opportunities. The leadership and talented employees of Chesapeake are excited about the challenges and opportunities that we have today.

I will now pass the call to Jason, Chris will follow, and then Nick with a review of our financial results, and then we will hopefully have time for a few questions.

Thank you, Doug. In the Southern division, we continue to see great results from our efforts to increase our EURs while bringing down well costs. Additionally this quarter, we were able to see the impact of strategic decisions we made last year, such as drilling longer laterals, testing new stimulation techniques, testing new pay horizons, and focusing on our base production. These efforts have paid tremendous dividends, as I would like to highlight today.

On slide 6 of our presentation, I'd like to start off by highlighting some of the successes of our Eagle Ford asset. I'm pleased to announce that our down spacing tests have proved successful, and have added 600 to 700 incremental locations to the development program. These additions represent a material addition of high-value oil wells to our corporate inventory.

Furthermore, the acquisition of these additional locations is essentially zero. The drilling team broke several records in the quarter, having drilled our deepest well, with a total measured depth of just under 21,000 feet, our fastest spud to rig release time of 7.8 days, and our lowest drilling cost well, at $1.1 million.

We also drilled our first five wells with laterals greater than 10,000 feet, which will help us to continue to drive further efficiencies, as these wells provide an incremental cost reduction of 33% on a cost per foot basis. These accomplishments are significant, and I couldn't be more proud of the team.

However, due to market conditions, we continue to ramp down activity in the area. We reduced our rig count from 20 rigs in January to a current count of 7, with the expectation to get to just 3 rigs by July. Strategically, we're going to take advantage of the ramp-down activity to further enhance our development planning.

The teams are in the process of optimizing our field development, and with the results of these successful test in mind, the top two priorities for the teams are first, focusing on front-loading the rig schedule with 10,000 foot wells. And second, moving forward with planning well locations based upon our recent successful down spacing tests. We understand that our reduced rig count has given us a unique opportunity to optimize our development plan, and we will take full advantage of it.

On slide 7, we are excited to highlight in more detailed the results of our down spacing tests. Last year at our Analyst Day, we identified several tests that we were planning for the year. Our tests at the time showed limited interference, as we went from 1,000 foot spacing to 500 foot spacing. We commented, at that time, that we had observed some interference in the wet gas area, and we can now attribute that largely to differences in rock quality.

The placement map at the bottom of the page that shows the location for the three tests that consisted of 330 foot spacing in our more oil prone areas, and 500 foot spacing in our wet gas area. The graphs on the right of the page are production graphs showing average cumulative oil production from each of these tests, with a data set that includes over 50 wells. The graph highlights that we have no material reduction in performance thus far.

We'll continue to monitor the results, but are moving forward with developing over 700 incremental locations, with these tighter spacing assumptions. These wells represent a material increase in our oil portfolio, with virtually no incremental expense.

The addition of these wells brings our location count up from 3,800 remaining core locations to approximately 4,500, providing us plenty of opportunities to grow this play in the future. Due to the success of these tests, we are now planning some 250 foot spacing tests, and also have plans for upper Eagle Ford tests in the fourth quarter, both of which could help drive further value generation.

On slide 8, I'd like to highlight some equally impressive accomplishments from our drilling team. At the first quarter, the Chesapeake drilling team drilled a record lateral that measured nearly 10,300 feet, in just under 12 days, at a cost of $178 per foot. In addition to this outstanding accomplishment, four additional wells were drilled with laterals exceeding 10,000 feet.

Two of the wells had vertical depths before kicking off of 5,300 feet, which makes them especially challenging. This accomplishment is significant, as it proves up this technique for both our shallow and deep development areas.

The impact of this accomplishment to the Eagle Ford development program is substantial. We expect to increase per well EURs 76%, and reduce costs 33% per completed foot. We will complete these wells in the second quarter of this year, and anxiously anticipate the results.

Along with success, the team is actively moving forward with high-grading the rig schedule to front-load as many of these wells as possible. Currently, we estimate around 600 wells that could be drilled with this lateral length. The Eagle Ford continues to be one of the flagship assets in our portfolio, as we continue pushing the traditional economic limits through our technological and operational competitive advantages.

Similar to the Eagle Ford, our Haynesville team is realizing the benefit of systematic strategies that were put into place over year ago. Slide 9 of our presentation highlights how our focus has not been on making one specific area of the field commercial, but attacking it as a whole. Our top strategic priorities are testing new completion design, drilling longer laterals, and exploiting other pay horizons.

The map on the top right of this slide highlights this fact, as it demonstrates how these tests blanket most of the field. The team has broken the traditional models of development potential, with our first two 7,500 lateral tests coming online at April. Initial flow-back from these wells is averaging over 17 million cubic feet a day.

Successful testing of our enhanced completion design has opened up development in areas that were traditionally written off, in both the Haynesville and the Bossier. The combined result of these breakthroughs is a positive production response, as our production increased 4% this quarter.

Similar to the Eagle Ford, we continue to reduce our activity levels, but the transformative nature of our well economics have opened this area up for partnerships that could allow us to mitigate our minimum volume commitments. At our last conference, we indicated that longer laterals and enhance completion techniques would transform the development of the field.

At the bottom of slide 10, we demonstrate our Haynesville well design evolution. Today, we can drill wells with 7,500 foot laterals, for less cost than we could drill wells with 4,500 foot laterals just a short time ago. There's no other company out there, that I'm aware of, that can boast a 42% improvement on a cost per completed foot basis, while also enhancing well performance in such a short amount of time.

However, the team is not done. We now have our first 10,000 foot wells on the rig schedule, with completions planned for October, and we fully expect to continue this trend.

On slide 11, I'd like to go into a little more detail with respect to changes in our completion designs. Last year, we took a two-pronged approach to well completions - one focused purely on cost reductions, and one on EUR enhancements.

The EUR enhancement techniques utilized reduced per cluster spacing and treated smaller groups of clusters with each stimulation. The cost reduction strategy focused on reducing gel loading and treating more clusters per stage. Early production response was very similar but as time progressed, the EUR enhancement techniques proved to be differentially successful.

On the map at the bottom left corner of this slide, we show the location of our enhanced completion. And on the bottom right, we show the results. The new stimulations have improved our EURs 20% to 30% and have opened up 90,000 acres for development, as we have combined the best of both strategies, which allow us to pump high-intensity jobs at a significantly reduced cost.

On slide 12, we highlight how longer laterals can incrementally enhance performance gains we see from stimulation designs alone. In April, we brought online our first two extended 7,500 foot lateral tests, which also used our enhanced stimulation technique. Both wells came on very strong, one flowing 16.7 million cubic feet a day at 7,700 pounds, and the other flowing 18.5 million cubic feet a day at 8,100 pounds.

After making the plot that we show on this side, we've opened the choke up on both wells. Production rose, the last two days, up to 19.6 million cubic feet a day with 7,200 pounds, and 23 million cubic feet a day and 7,700 pounds, respectively. We believe these wells transform the play as we know it.

If you were to look at a traditional contour map, these wells would be located in the uneconomic 6 to 8 bcf per well contour interval. These wells have shattered the limitations typically placed on Haynesville development.

However, the Haynesville is not the only formation that can add value to our portfolio. On slide 13, we're pleased to highlight the progress being made in the Bossier, as well. We've tested our new completion design on the Bossier and the production plot on the bottom left quadrant of the slide shows the production response from this new technique.

Production is up almost 4 million cubic feet a day, on average, from the two tests. The relatively low historical development in the field leaves this play wide open for development with longer laterals. The map located on the bottom right side of the page shows an early development plan for the Bossier. Contours on this map are an interpretation of recovery on a mcf per foot of lateral basis, with the sticks indicative of lateral length we plan to use in developing the field.

The bar graph on the top of the map shows a breakdown of lateral lengths and well count against the interpretation of deliverability. As shown, we have the ability to develop both 7,500 foot and 10,000 foot laterals. As demonstrated by our Haynesville results, we have high performance expectations for the Bossier as we move forward. The Eastern Gulf team has been very aggressive with their strategy over the last year, and it's great to see the fruit of their work transforming the asset.

I'd like to move on now, and highlight our Miss Lime and greater Mid-Continent asset, starting on slide 14. I strongly believe that our Mississippian Lime position is one of the most undervalued assets in our portfolio. Despite perception, the Miss Lime continues to be a steady out-performer in the portfolio, as indicated by our 11% sequential production growth for the quarter.

Key strategies for this asset are to expand both laterally, the limits of the field, and vertically, as we begin to test new formation across the entire Mid-Continent area. With respect to expanding vertically, we've brought online multiple wells in new formations this quarter, with three Oswego wells, our best well making 630 barrels of oil per day, and a test in the Hoxbar, which came on at 715 of barrels of oil per day. We believe the stack nature of these plays, and our massive acreage position will provide significant new development potential in the future. Focus on the base is also a top priority, with nearly one-half our operated well count is in the Mid-Continent area.

On slide 15, it's really powerful, as it shows how we continue to improve results every year. The graph located on the top left shows production performance by year. In short, it highlights that wells are coming on stronger, with shallower declines.

There are several key drivers that lead to consistently improving performance. We have completed our drilling program to hold leases, balance our exploitation and development drilling program, by increasing focus on the development in the core. The benefit of these changes is clear, as our EURs have improved 20% over the last two years, to 335,000 barrels per well. In addition to the solid performance increases, the team continues to work the investment side as well.

Slide 16 highlights our continued improvements in well cost. The bar graph at the bottom left portion of the page shows how capital costs continue to come down in the play, as we take advantage of supply chain savings and continue to generate efficiency gains. I could not be more pleased with the team's performance; as well costs have been cut nearly in one-half over the last few years.

These cost reductions and EUR enhancements have driven our rate of return up to 39%, as shown on the graph in the bottom right corner of the slide. We currently estimate that there are over 560 locations remaining in the developable core, with an additional 400 locations that offset the current core.

As mentioned previously, we have nearly half of our operated wells in the greater Mid-Continent area. As part of the Chesapeake transformation, we've set up dedicated production teams focused strictly on enhancing base performance. The graph on the bottom of slide 17 highlights gross base production on our northern Mid-Continent area. Through the implementation of a proactive artificial lift program, reducing downtime and maintaining a healthy work-over and recompletion program, we were able to improve our base decline rate from 2013 to 2014 by 20%, taking it to 28%.

The teams developed a work-over and recompletion post-appraisal system in 2014, which is paying huge dividends, as we were able to learn from our historical decisions and high-grade our activity throughout the year. As a result, our base optimization programs delivered a rate of return over 100% for 2014. We plan to continue building on this success in 2015, and have already started to see some additional reductions in our base decline rate.

In summary, every key driver for the successful development of an asset is clearly demonstrated with our Mid-Continent development program. Like all other assets, this team has a continuous improvement culture, which is continually delivering more value to the asset. Additionally, we have some exciting new tests from other productive horizons that will supplement the asset for years to come.

I'd like to speak more generally about an emerging base decline mitigation program. Talk about refrack potential in the industry has been on the rise. On slide 18, I give you a very high level overview of our progress.

Within our retained portfolio, Chesapeake has drilled 6,750 horizontal wells since 2004. Of these wells, nearly 4,600 were drilled prior to 2012, we consider these wells understimulated, compared to our current designs, and based on their vintage.

The Barnett, as one of the first major shale plays, has the most easily identifiable concentrations of understimulated wells, and was our first asset to focus on for our initial restimulation test. To date, we've tested nine wells in the play, with two different techniques.

In the plot on the bottom right, we highlight aggregate results from these tests, which resulted in a production increase of nearly 10 million cubic feet per day. These results are promising, but are challenged by this price environment. However, we continue to high-grade the opportunity set, because the prize is significant.

Additionally, we have seen production responses in the Haynesville that indicate our refrack program should be successful in achieving incremental production. The graph on the bottom right shows the production response to our parent wells before and after we have offset them with new drills. To date, 100% of our parent wells have seen an enhancement from offset drilling, with increases in both pressure and rate. Right now, we're looking at all our base wells, and working through the best way to recover the incremental reserves, be it an offset drilling program or refracks.

Overall, we have some great highlights for you today. We're attacking every asset strategically and now we are seeing the results from those programs that were implemented over a year ago. Even with the great progress we're highlighting today, the teams are driving forward, with new completion designs, longer laterals and more ways to offset base decline. It's a very exciting time for us in the Southern division.

I will now turn the teleconference over to Chris Doyle, to discuss the Northern division results.

Thank you Jason, and good morning. I'll walk through the tremendous progress that we continue to see in the Utica, the Powder River Basin and the Marcellus. We spoke a lot last year at the Analyst Day about building a culture of continuous improvement. Like Jason, I will point you to tangible examples this morning, in each of those areas, of exactly that. I'll also provide an update on our supply chain efforts through the first quarter.

Let me start on slide 20, with the Utica, where we reported 10% sequential growth on the backs of outstanding operational and technical performance, currently running five drilling rigs, 4 1/2 frack crews. By middle of the third quarter, we plan to reduce that to 2 drilling rigs and 2 1/2 frack crews. That will closely approximate the level of activity needed to maintain our lease position.

Our strategic focus for 2015 in the Utica is to continue leveraging our industry-leading operations, driving further capital efficiency into this asset. With our forecasted completions activity, particularly in the first half of 2015, we will reduce our drilled not completed well inventory by 40% by the end of the year.

You will also see us continue to expand our core position with further testing, and I'll share an exciting example from our recent efforts in doing exactly that. Importantly, 2015 is going to be a year that is focused on base optimization. That was one of the keys to our first-quarter out-performance in the Utica.

Turning to slide 21, I've said all along that our drilling team has provided Chesapeake a competitive advantage force in the Utica. On this slide, you see a recent comparison from IHS for our drilling performance against four of our closest competitors. Based on their third-party view, they judged Chesapeake to be 40% more efficient than the next closest driller. That's in terms of drilling cycle times and penetration rate.

IHS reports our average cycle times at 13 days in this report, and we continue to see and set efficiency records, with our fastest spud to rig release coming in at 7.8 days, and drilling multiple sub-10-day wells this quarter, despite drilling longer laterals. In fact, we received a note this morning that our last well that we released set new records, for the highest footage drilled per day, at 1,900 feet, and a lowest-cost, the first well ever released at under $100 per foot.

Simply put, the best drilling organization in the basin is only getting better. And that competitive advantage is allowing us to redeploy those savings into our completions, and that's driving our type curves higher.

Slide 22; let's take a look at all the enhanced completions that we're seeing in the Utica. If you compare our type curves today, looking at the bottom right curve look versus what we rolled out an Analyst Day, we're seeing 20% higher EURs, and that's driven primarily from these enhanced completions.

Our drilling targets are deliberate and we're drilling longer laterals, increasing the number of stages and tailoring our cluster spacing, all depending on where we are in the field. And all of this based on our deep understanding of the Utica. Check out the graph in the upper right-hand side of this slide.

Think about how different a Utica well delivered today looks from just a few years ago. Lateral lengths have gone from under 5,000 feet to almost 8,000 feet this year, or a 25% increase from 2014. And we're pumping two to three times more stages, and delivering more value for our Company.

The key here is that we're also delivering those results faster and cheaper. As I mentioned on previous calls, our completions team continues to outdistance the competition. Last week, our four frack crews averaged eight stages a day, per crew. Each of our frack crews, from two different service companies, have exceeded 10 stages a day, with the max coming in at 12 stages a day, indicating that additional efficiencies are still available, and we're not going to rest on our laurels. We will continue to seek and find these efficiencies.

Slide 23 is an awesome example of how we are expanding our core position in the Utica. Let me share with you some of the results that we're seeing in Columbiana County. This is, as you can see on the map, on the bottom right, a county that is outside what most would view as our core position. The graph just above the map tells a completely different story. Early well performance, based on the first nine wells in this lean area, outperformed the type curve. But interestingly and remarkably, recent wells, those three in green, have out-paced those tests by 50%.

The main driver here is not necessarily just completions, but it's also our optimized targeting, based on our seismic and geologic interpretation, that has continued to evolve and sharpen over the past year. And here is a concrete example of a G&G team driving value, and proving an outside area from our traditional core position to a 25% rate of return, based on $3.25 and $65.

Finally, on slide 24, I mentioned our focus on optimizing base production. This slide shows exactly that. The graph on the right shows the 2015 base well set, held static beginning in January. The green line depicts our initial base forecast. And as you can see, the wells have blown that away, leading to a new forecast in red. In fact, you can see that these wells, these base wells, are actually inclining over the past couple months.

During the first quarter, thanks to better winter preparedness, the team reduced downtime by 60%, another key factor in our first-quarter out-performance. Just as impressive, though, are the team's tireless efforts, throughout the quarter, to limit midstream disruptions, lower line pressure, drive pressure maintenance and choke management programs.

Final processing, we spoke to, last year, expansion at Leesville in November, in combination with compression expansions in December and again this quarter, have allowed us to increase production from these existing wells, and reduce our base decline significantly. The wedge between the green line and the red line is a sustainable improvement in our operations and our value delivery.

Our industry-leading Utica team obviously extends well beyond our drilling and completions teams, includes our G&G, reservoir, land, marketing, production teams. But most importantly, it includes the strongest field organization in the basin. At today's strip prices, that team has pushed our Utica NAB to approximately $7 billion, up sharply year over year.

Now turning to the Powder River Basin, on slide 25, we also reported 10% sequential growth. Consistent with previous calls, the resource potential in this basin is huge, and continues to expand with successful tests up and down the strat column. Multiples stack plays push our gross resource potential to over two billion barrels equivalent and 3,000 potential locations. That's up huge from last year's Analyst Day.

With the pullback in commodity prices, our established federal units have allowed this team to dramatically reduce activity, prudently dropping down to one drilling rig and one frack crew, to maintain our core position. Our limited 2015 activity is going to focus on driving additional capital efficiencies, mainly in our Niobrara development, while also continuing to test this prolific basin with significant focus on progress being made in Sussex.

Slide 26, some new information for you guys. We've shared with you previous tests; we've never shown you a type curve. Let me start by highlighting the most recent Sussex test that clocked in at approximately 2,000 equivalent barrels per day, 65% of that oil. In the first quarter, we set multiple drilling records. This is new information from Chesapeake. Most recent being a spud-to-rig release record at 14.1 days that delivered $1 million in savings.

Like other areas, we continue to push our laterals longer. You see that we've got a 9,000 foot, or nearly 9,000 foot lateral completed, with 30 stages. We're continuing to outperform our high expectations, however, and that's what I want to focus in on. Look at the type curve at the bottom right hand side of the slide.

We were expecting, going into this year, an 800 mboe Sussex type well. That's the blue line. The black line is our actual performance, based on over a year's worth of production. That historical performance was fully 100% over our type curve, and increases our expected Sussex rate of returns from 20% at the type to 50%, at $3.25 and $65.

In order to get a 10% rate of turn, the breakeven oil price on this Sussex, is $42.50. Huge, huge performance in the Powder River Basin.

Let me turn to the Niobrara, where we currently project about 20% higher type curves, compared to what we discussed at last year's Analyst Day. While we continue to optimize completions and drill longer laterals, the team is using the pullback to continue testing core extension, not only laterally, going back to areas with our new efficiency, but also vertically. And we're looking at our first stacked laterals that we mentioned on previous calls. Those should be on production this quarter.

Finally, turning our attention to the Marcellus in Northeast Pennsylvania. As we shared on our previous call, we began curtailing about $250 million a day gross late last year, in late December, due to weak in-basin gas pricing. We continue to maintain the production levels from that time. And you see our sequential growth is pretty well flat, and we're now curtailing about $500 million a day gross. Given that ability to rapidly respond to potential market strength, we quickly and prudently reduced activity to one drilling rig and one frack crew, to maintain our lease position.

We plan to maintain production at that reduced activity, but stand ready to respond to what the market tells us, regardless of production impacts. As in previous years, our focus in 2015 is driving the most value for the Marcellus, as efficiently as possible. Armed with our new and demonstrated operational efficiency in the basin, the team is rethinking, re-examining and going back to test limits of our lower Marcellus position as well as testing the upper Marcellus. While some of this activity has been deferred in 2015 we have ample tests coming our way to validate what this asset will deliver in the coming decades, even with minimal capital investment.

Slide 29 is all about the drilling organization in the Marcellus, part of the team that absolutely redefined this asset last year. This was a team that was stuck in the 25, 26 day cycle time quagmire. And we used last year to attack every single segment of the drilling operation, whether it was the vertical section drilled on air, the curve, lateral, every flat time in the well path. The end result is a cycle time reduction of over 50% since 2012. But more impressively, and just a huge indicator of a culture of continuous improvement, the team further reduced cycle times this quarter by 30%, compared to last year.

We drilled two back-to-back sub-10-day wells, as well, setting records. Our rigs today are 150% more efficient, costs are 40% lower compared to just a few years ago, and to think about accomplishing this in the sixth year of development, is just simply staggering. It was a true team effort, a focused drilling organization working with the business unit and supported by our operations support center, to get it done.

Slide 30, as we've touched on most of these assets, we used those drilling savings, redeployed them to drill longer laterals, to optimize completions, and the end result is higher EURs by about 20%. The table on the bottom right lays out an extremely compelling story. And we show you what we were telling you back in 2011 and 2013, and what we're telling you today in 2015.

Every year, IPs are going up, EURs going up, thanks to longer lateral lengths and stage counts going up as well. All the while, capital has trended down significantly. The end result is the graph that you see just above the table - a completely redefined investment thesis, as I've said in the past year. What that means is, a 30% rate of return could be delivered back in 2011. Assuming a $3 realized gas price, that's cut in half this year, $1.50.

How do you explain such a rapid enhancement and asset performance so many years into development? The same way you explain 40% to 65% capital efficiency gains in every single area in which we deployed capital last year. The answer, obviously, is the strength of our technical teams in each of those areas, along with such industry-leading support organizations as our operations support center, or OSC, that I mentioned previously.

The OSC is manned by 100 industry experts, drilling superintendents, geo-steerers, geologists, engineers, lease operators, analysts; OSC is Chesapeake's Central Command Center. It's like NORAD in Oklahoma City. But more than just monitoring and supporting, the OSC links our teams executing out on the field with real-time data analytics, industrial analytics and tactical performance-enhancing adjustments. The OSC opened its doors back in 2013, but the full extent of its value proposition wasn't fully realized or demonstrated, honestly, until last year in the northern Marcellus.

What happened? By identifying optimal drilling parameters based on historical drilling data, every single well had a well plan based on what it took to drill the fastest, best, most competitive well. And any and all trouble time was analyzed, evaluated, all events in the past. And so the OSC was able to forewarn our drilling organization, including the drillers on the rig floor, when they were either outside the optimal drilling window, or they were headed for a potential issue.

The result was optimized drilling performance and elimination of downtime events. That's how you reduce cycle times from 26 days to 12 days, in the sixth year of development.

Beyond minimizing trouble time and ensuring optimal drilling conditions, the OSC helps our asset teams maintain geologic target integrity, push lateral lengths further than ever before, all to deliver the most capital-efficient well possible. And that's demonstrated in each of our business areas.

Building on this success, we continue to expand the OSC service to all of our assets, and to all aspects of our operations, including completions, reductions and fluid logistics. I'm confident that the OSC will help our teams reduce waste and optimize our base production, yielding more efficient growth and maximum value for Chesapeake.

Finally, let me provide an update on our supply chain efforts. As discussed in our last call, we've been busy aggressively targeting significant reductions in service cost that better align with the current view on commodity prices. This quarter, the teams have already captured 15% savings, compared to 2014.

The graphic on the right shows pricing adjustments that range anywhere from 8% up to nearly 40%, depending on the category. And also, on the expense side, we haven't talked about it a whole lot, but we captured about 5% savings, or $0.10 of boe and we anticipate that those savings will begin rolling in through actuals this quarter.

My next message is this: we're not done. We continue to target all categories, to ensure any and all supply chain savings are realized for Chesapeake. We continue to focus, however, on more than just price. As we've said in the past, it's all about service delivery. We realize that our industry-leading efficiencies are only possible working hand-in-hand with the very best service providers.

Finally, let me be absolutely clear. These savings are solely from supply chain efforts. They do not include design changes. They do not include efficiency gains that should enhance capital efficiency by a further 5% to 10% by the end of the year. Both Jason and I have spent the last 30 minutes showing you tons of examples where the teams are already exceeding that expectation.

Let me now turn the call over to Nick Dell'Osso to further discuss the quarter and update guidance.

Thank you, Chris. I'm very proud of how we're executing our business plan. As Doug mentioned, our first quarter demonstrated strong production and cash cost moving lower. The first quarter also showed our capital spending was in line with what we forecasted, while basis differentials, particularly in the Northeast, were better than we had expected.

As we continue to deliver gains in capital efficiency, current commodity prices are dictating to the industry that we must also be flexible, with regard to our capital spending levels. As shown on slide 33, our Q1 capital spending was right in line with our quarterly guidance, and we're reducing our activity in capital spending rate for the remainder of the year, as previously forecast.

We started 2015 with around 70 rigs running, including a few spudder rigs, an average 54 rigs during the first quarter. Today, we're running 26 rigs in total, and we're forecasting to drop to 14 rigs during the third quarter.

As a result, we are already seeing dramatic reduction in our capital spending rate. Our capital spending on drilling and completions alone in January was approximately $490 million. By the time we get to June, we're projecting around $200 million in D&C capital. So while we are doing amazing things in the field with our assets, as shown today, we still believe the prudent approach, in the near-term, is to reduce activity and preserve liquidity and flexibility in the current price environment.

Our balance sheet and liquidity remain very strong, with $2.9 billion in cash, and an undrawn credit facility, with capacity at $4 billion and a net debt to total capitalization ratio of 37%, or 35% when excluding the non-cash ceiling test write-down in the first quarter.

Just as our CapEx was significantly higher in the first quarter than it will be in the remaining quarters of the year, as we execute our planned activity reduction, we saw the largest cash spending levels this quarter that we expect to see in 2015, as well. We remain on track to meet or beat our revised budget targets we laid out a few weeks ago, and continue to aggressively defend our liquidity position, which we see as a valuable tool in the current commodity price environment.

I'd like to turn your attention now to slide 34, which lays out our gas differentials from 2014 through a 2016 sensitivity. We put this together to address the sensitivity seen from low capital development levels, and the cost of service agreements we have through our gas gathering contracts. As you can see, the gathering and transportation component of gas differentials isn't all that sensitive to movements and development in the short-term, and may decrease, through production mix and growth, in certain areas.

Given we are well ahead of having a budget for 2016, and the intent of this exercise is to test the impact of low development, we ran this 2016 sensitivity assuming the low level of fourth-quarter 2015 capital expenditures continued throughout 2016. We show overall differentials improving in 2016, primarily due to improvements in the forward curve for basis at our sales points. We work closely with Williams on mutually beneficial opportunities to improve our gathering costs, and are pleased with their commercial approach since taking over complete ownership of the business.

The recent operating strength of our assets, the expansion of our core areas, the identification of additional economic zones, and the potential for future additional business with Williams, all contribute to potential opportunities for improvements in our rates.

Lastly, on slide 35, we are truing up our production guidance for our strong first-quarter performance, and otherwise reiterating our outlook. We're extremely pleased with the performance this indicates for Chesapeake during this low commodity price environment, but are pushing hard for further improvements across the board. Production, differentials, capital and operating costs, as you heard throughout our call today.

We're committed to generating additional EBITDA as a Company, and we are working hard to expand our margins, both on the cost side and the revenue side of our business. Our team's efforts in the areas of recompletions and more efficient work-overs are great examples of ways we're doing this, with limited capital investment, in the current environment.

We will continue to focus on reducing our leverage, both financial and operating, through additional sales of non-core assets, and through working to improve the non-basis side of our business, particularly in gas. Overall, I'm very confident in our ability to deliver greater value for our shareholders, and I'm looking forward to that as 2015 unfolds. That concludes my comments; I will now turn the call over to the operator for questions.

(Operator Instructions)

Brian Singer, Goldman Sachs.

Thank you, good morning.

Good morning, Brian.

You've highlighted on the call the opportunity set in the portfolio and the cost efficiencies you are seeing. And slide 33, which you went through, talks to the quarterly CapEx reduction, as activity comes down. Can you clarify, of the reduction that you see in coming quarters to CapEx, how much is related to activity reduction, versus supply chain cost deflation, versus the operational efficiencies and improvements?

Or in other words, are all the cost reductions that you talk to in this presentation assumed in the going-forward CapEx program, and in your revised production guidance? Or is there an element of upside?

Thanks for the question, Brian. The principal reduction in the capital program is related to activity. But as you'd expect, with these types of efficiency gains that we are recognizing, we also expect our capital to improve going forward, because of those efficiencies. And as Chris noted, and he will like to comment here, the supply chain continues to be something that we further optimize, and are gaining significant ground on, as we work with our high-quality vendors and contractors.

Yes, the only thing I would add, Brian, is one; I'm very proud of what our asset teams and supply chain delivered in the first quarter. But I'm going to sit here in three months, and six months, and tell you how much more proud I am of additional supply chain savings that they will capture. None of that is built into the forward forecast.

Efficiency gain, cycle time improvements that we continue to deliver every single quarter, not built into that forecast. And so I think what you will see is the same thing you've seen from this company, over the past couple of years, is just continuous improvement quarter over quarter. But we're not going to reflect that in the forecast. And so I would say yes, there is some upside there.

Got it. Thanks. And then separately, and this question may be a little bit unfair. But as you've gone through areas like the Haynesville or the Barnett or the Utica, the Eagle Ford, and found some of these efficiencies, what would you say is proprietary to Chesapeake versus what you think we should expect out of the rest of industry? And I wonder a little bit, because that dovetails into whether consolidation opportunities make sense? And where you stand on that, too, bringing some of these efficiencies to other assets?

Thanks, Brian. I don't consider it an unfair question at all. I think it's a great question. When we see what's taking place out there, I would first point to the quality of the rock in these assets, and then point to the innovation and creativity of our employees. And as with the rest of the industry, and the improvements we see at some point in time, all of the creative ideas bleed over into other assets.

But the quality and strength of our portfolio is the quality of the rock, and the technical expertise. And the way we are driving synergies and value from these assets is something that you can continue to expect from Chesapeake. So whether the rest of the industry adopts it, I'm not really concerned about, because we are leading it, and we will continue to lead it.

I guess, does that create an M&A opportunity that you see? Or is the valuations, and then your own balance sheet's funding gap, just too prohibitive right now?

Sure, it absolutely does. And we're doing things that others can't. And because of that leadership on the operations and capital efficiency side, that creates a lot of opportunity. And we have the teams that can execute that.

The one thing I would add, just specific to the Utica is, as we said last year, we been there longer than everybody else. But guys, we are not just six months out. This is years into the development. The thing that is proprietary is our track record of continuous improvement. And companies can talk about how they're going to deliver what we have been delivering, and that's great. We have delivered it, pure and simple. Now, on the acquisition front, I think coring up a position in the Utica would make some sense. But those companies, many of them are valued as if they will have Chesapeake operating them tomorrow. And we have yet to see that in many cases.

Thank you.

Neal Dingmann, SunTrust Robinson Humphrey.

Good morning, Doug. Say, again, a lot on your slides, you guys talked about a lot of these enhancements you were doing. The longer laterals, just the improvements on the completions in general. My question is around that, for you or Chris or Jason and the guys. Is this now focusing on more proppant overall? Are you doing the proppant with the different mix? Maybe if you could just talk about the enhanced completions a little bit? I know it's a little bit on Brian's call. But what you all are doing? And how different is that, like you were doing in the Eagle Ford versus some of these other basins?

Sure, Neal. The first I will say is that around the completions, Chesapeake is an industry leader in interventionless completions and that we are working closely with all the suppliers, we're trying new things, testing new things. And I'm very excited about it. I think there's a ton of potential yet further. And I'll just ask Chris and Jason to weigh in on that, because it really is an advantage that we continue to pursue, and see as very competitive.

This is Jason. And just to echo what Doug said, one of the things that's our competitive advantage is our people, and the efficiency they are able to achieve on our wells because they look at every hour that we spend on location, and how to optimize it. Completion strategies, in general, we're testing tighter perf clusters for Haynesville, for example. We've reduced all the way down to 20 foot between perf clusters. So they are tight, and I think that's one of the key things that gets that lower quality rock to help.

There are some other things they are doing there. Also sand, increasing our sand per foot. But the thing that's also an advantage for us is, we don't ever get satisfied with what we do. So we've tested sand limits up until the point where it's a diminishing point of return, and then we dial it back to the sweet spot. That was part of our EUR enhancement discussions that I talked about.

We're testing new things in every field, as well. In the Eagle Ford, they're going to start testing some of the designs that we've got going in the Haynesville, this month, in fact. Also, tried a new completion design this week that they just finished. That's a 90 stage job on the Eagle Ford. So I think part of it is not being satisfied with where you are today, and just continuing to press the limits in every single field that we operate.

And Neal, this is Chris. I think you mentioned what -- is it sand, is it something else? I think anybody can go out and pump 3,000 pounds a foot, and get a better well. We've seen that in most of our areas. But our focus really is, as Jason highlighted, how do you optimally stimulate a two-mile long lateral? And so what you've seen, as laterals have pushed out, what you've also seen is the stage count per foot has increased significantly, as we're -- when we talk about the cluster spacing.

As we are continuing to work in the lab, and out in the field, making sure that we're optimally stimulating the entire length of that lateral, and not just putting it away in a stage here, or a stage there, but throughout the length of the casing.

Another thing, Neal, I think it's important to note that there is a lot of non-technical popular misconception around that everybody can just do the same thing. But the inherent technical rock properties, petrophysical properties, that make a high-quality asset, create a differential for value creation.

And what you are seeing is, as Chris noted, others can go mimic and copy Chesapeake. That kind of stuff has taken place for years. And you can go do that, but it doesn't necessarily mean you're going to get the same type of results. And it has to be a combination of the operations, the technology and the quality of the asset. And those were many of the things that we were really trying to highlight for the investment community today.

Obviously, the proof is in the pudding. It's not just about completions; it's also about the other aspects of our business, and the other teams, as we highlighted in Columbiana County. This has to start showing up in our results, as you've noted in the Utica, it is. And as you've seen in other areas of the Company, you are starting to see that. So I'm excited not only how far we have come in the two years, but I'm excited to see what happens for the rest of this year.

Great details, guys. Two more quick ones. Doug, just your thoughts on M&A here, either international, or just anything you are seeing around the basins?

Yes, I still think there's a lot of opportunity. And the Company is still focused and looking for either bolt-on or strategic opportunities Neal. And we will be continuing to look at that, and accretive opportunities that we can apply this horsepower and skill to new assets. I think one of the things we really are trying to demonstrate for everyone is that it doesn't matter what asset that Chesapeake is focused on. We're going to drive value from it.

And we definitely have some issues that we are working on, that are reminiscent of the past but if we focus on the strengths of this Company, and acquire some additional assets, you can expect similar type of performance. I'd also like to highlight that I think it's really important, many companies have paid billions of dollars for an acquisition into oil in the United States and we organically, today, are making it public about some of this technology and improvements that we see in our assets - adding 600 to 700 locations in the Eagle Ford, adding locations in other areas, because of our capital efficiencies, seeing the improvements in the Powder River - these are dynamite things, guys, dynamite things. And you can go out and pay $2 billion, $4 billion to try to pick up that type of inventory location. But the strength of the capital efficiency is driving great value, and will continue to drive great value for our shareholders. I just think it's a great opportunity.

And then just lastly, Doug -- or for you, for the guys -- just on takeaway contracts. I know in the past, you have mentioned, in the Haynesville, what that extra cost you on what you are required to take away. Anything Appalachian-wise, or anything else? Are some of those now going away? Or where do you guys sit, on some of these takeaway contracts that you once had?

Thanks for asking, Neal, and Nick and I will both comment on it. It's something we continue to work on. And as you all know, we are partnered with Williams and we are pursuing win-win solutions that involve not only efficiencies of the new opportunities that we are looking at, such as the Bossier and the improvements in the rates from the Haynesville wells that we're seeing We're also looking at base optimization opportunities, looking at where we can extend contracts potentially. And we're very pleased with the commercial approach that Williams has in looking for opportunities for win-win solutions - Nick, do want to add any additional color?

You asked about, has any of our takeaway gone away in the Northeast and so just to answer the question directly, you'll see in our Q, in our commitments footnote, a decrease in takeaway. The big driver of that is a transfer of a portion of our ATEX line to southwestern, associated with the southern Marcellus transaction. So in addition to that, we look for opportunities for valuable takeaway from the Northeast part of the Marcellus, where we are currently curtailing production.

Those opportunities haven't proven yet to be actionable, in a way that we see value-added so we look at our portfolio of takeaway all the time and as Doug noted, we work with Williams on improving our gathering contract cost, but we also look for accretive ways to better market our gas, and get better pricing for it. I think we have a good portfolio takeaway in the Northeast. We think it gives us a competitive advantage for our long haul out of the basin and if opportunities present themselves to add to that, we would do so. Recently, there have not been any that have been value accretive.

Great details. Thanks, guys.

Thanks, Neal.

David Heikkinen, Heikkinen Energy Advisors.

Good morning, guys - just had a quick question, first on they, Sussex. How do you ramp activity levels there or is that really a possibility, just given the surface constraints?

Sure, David, this is Chris. It's absolutely a possibility. I think the team focus right now is understanding that we're early in the development in the Sussex. We only have a handful of wells but my gosh, they are performing phenomenally well.

So as we are closely watching the performance there, we've got some new longer laterals coming up. We have some spacing tests in the Sussex. We're going to test those. We will be ready to ramp up, given some market strength. But as I indicated, breakeven price of $42.50 is pretty strong, based on what we have seen over the past year. So the team is actively working and getting prepared. Remember, we were planning to run 7 to 9 rigs this year. So we've got some permits, and we'll continue to prepared to ramp up when the time is right.

Why isn't the right time, with that rate of return and the permits for 7 to 9 rigs, may be the better way to ask that?

I think when we look at, that's more of a corporate portfolio discussion. Again, we're early into the Sussex, as we try to get to cash flow neutrality as quickly as possible. That was one area that, just based a couple months ago, wasn't garnering more capital. It could very well do so between now and the end of the year.

And then on slide 33 -- that is helpful, Nick. As you think about your fourth-quarter cash flow, CapEx, and just the implied trajectory for both into 2016, can you give us a snapshot into how you are thinking about things? Either Doug or Nick?

We obviously haven't put anything out, David, on 2016. But what we're seeing is greater productivity on a per-well basis. Why we are slowing down our activity, in the latter part of 2015, I hope that everyone recognizes one of our core strengths and attributes is the speed in with which we can ramp back up and the confidence that we can with greater pricing, further accelerate our programs.

I also think that it's good to note that, if you hear -- you are driving down the road and you hear that song, all about that bass, you ought to think about Chesapeake. We have a huge, huge base optimization program, and we're focused on that. That's going to add incremental volumes, and we see good opportunities there. So looking forward to 2016, we will continue to execute on our capital efficiency, which drives greater productivity on a per-well basis. We've got the base coming in, and we see the ability to ramp back up accordingly, with the speed and strength that Chesapeake is historically known for.

Is there any update to your Howard Weil presentation on quarterly progression of production?

No, there's really no update there. We upped our guidance to reflect the strong first quarter production, and that's going to have its tail effect through the year so the full year comes up, as a result of that. The general trajectory there is the same. It will be muted a bit towards the end of the year there, on how we were showing that, quarter over quarter, to the positive there, Dave. But overall, just by that little bit, is all we would say at this point.

Okay, thanks, guys.

Arun Jayaram, Credit Suisse.

Good morning, gentlemen. Doug, I do like your taste in music, unfortunately. Real quickly, on the Williams comments that you made. I was just wondering if you could maybe elaborate on potential win-win scenarios to reduce some MVCs? And you also talked about maybe bringing in some partners in the Haynesville? But just wanted to see is, your thoughts. Are you talking to Williams today and maybe some opportunities to reduce those liabilities, over time?

Yes, we know that this has been obviously a focal point for Chesapeake, as we want to try to further improve our competitiveness. And I would highlight, again, that everything that we are looking at doing is to find win-win opportunities with Williams and the contracts that we have. We do know that bringing in additional parties on those systems can be helpful.

Our capital efficiency, as I noted earlier, is helping generate more volumes and as we look for recompletions, refracks, all of those kind of things, it will be very helpful in that respect. And whether it be through contract extensions or other opportunities, we are making progress in that respect. While we don't have the specifics to share today, we are encouraged with the commercial approach, and think we will find ways to help improve the competitiveness there.

Okay. And Doug, just some thoughts -- or Nick, on how -- what were differentials in the first quarter? And how do you expect that to shake out, for the rest of the year, on the gas side? I know you've given guidance of $1.80, at the midpoint, in terms of diffs.

Yes, the differentials were strong in the first quarter. And again, the difference relative to our guidance, or relative to our expectations, was really in the Northeast. So we feel good about where that sits in the first quarter, headed towards the full-year within our range. The basis for the summer remains pretty questionable. We've had some of that. But, as a result of that, we really haven't wanted to change our guidance.

But first quarter was ahead of our internal expectations around basis. We feel good about that. Overall for the year, again, we always focus on trying to find the best outlets for our hydrocarbons, and particularly gas. We feel good about where we're headed. We continue to try to look for opportunities to hedge better basis prices when we can. We've done a little bit of that. So optimistic there.

Okay. Just final question, in terms of your year-end rig count outlook, a pretty wide range of 9 to 19. Doug, what would push you towards the upper end of that range versus the lower end of the range?

The capital efficiencies are continuing to be really outstanding so I think that the range is still good, but right in the middle of that is probably where we will be - in the 14, 15 range and just depending on what we see, in terms of pricing, and the competitiveness of the projects we are investing in, we will adjust that and provide more information on it, as the year goes on. But I think it's a good estimate right now just to assume that we'd be in the middle of that range.

Okay, thank you very much.

Scott Hanold, RBC Capital Markets.

Thanks, good morning guys.

Good morning, Scott.

If I could go to slide 38, where you have got your activity levels, again, throughout the year and at the end of the year, just looking at the allocation of rigs by play, could you give us a sense of how you step back and do corporate capital allocation? Because when you look at this, and you see some of the returns that you've got in the Eagle Ford, the Utica, comparatively to the Mississippian Lime, there's a bottle-neck. The returns you're showing on the Marcellus, at current prices, are just up the charts. Yet you are reducing activity there. How do you allocate that appropriately, in your view?

Yes, so the capital allocation process is very detailed, and we spend a lot of time with that. Keep in mind that as we're optimizing our liquidity and activity, that we are also very focused on improving the competitiveness of each of these plays. Each have specific inherent things that we are trying to accomplish. Your reference to the Marcellus, obviously, is its fantastic and an unbelievable position up there but you also have takeaway issues that are in the basin there.

So with the ability to deliver more volume in the Marcellus, we'd absolutely put more rigs there. The things that we are testing and improving in the Mississippian Lime give us a lot of confidence and we're going to continue to drive down our costs, and make that play more competitive, which make it very attractive to us. Haynesville, same thing. Haynesville has got a lot of questions from the investment community, is why we went back there? This is over a year ago, when we first went back into the play.

And we've just crushed the cost there, and made it extremely competitive, and continue to see further improvement so it's really more of a balance portfolio approach. These are all really strong assets that have different specifics requiring optimization, either through technology or efficiencies that we're looking to try to achieve, for the long-term value. So if we just want to focus on one area, and not pay attention to how we develop the whole portfolio for the long-term, then you could potentially say just put the rigs all in one area.

But that's not what we're doing. And I think the information shared here, on the asset level, of all the different technical things, capital efficiencies, synergy, supply chain. All of those things are pointing to why this high-quality portfolio is undervalued.

Okay, and I appreciate that. And the thing that really stands out would be, for example, the Mississippian play. Where I wonder, is it was more of a near-term capital efficiency versus, say, a better, longer-term return that gets a little bit more activity, relative to the long-term returns in that play today?

It's just a function of how we're managing the whole portfolio, I think Scott is the best way to describe it. And we started the year with a higher number of rigs there. We can put more back. And it's really a function of managing our liquidity, and managing the portfolio for the long haul.

Okay, thanks. And one real quick one. Obviously, you made a great acquisition with Frank coming over to the team. Obviously, his experience has got a lot of international offshore bias to it. Should I read into that any way? Or is it just a strong recruit?

It's -- I think that Frank Patterson is world-class, and I think you can read into it basically whatever you would like to. We're going to continue to optimize, and look to grow organically, our domestic portfolio. And as I've stated earlier, if we see opportunities elsewhere in the world, we'll look at those. What's great is that Frank has that experience and expertise. But I wouldn't read in it that we are looking to go jump off into international, at any point in time. We have a great portfolio. We're seeing good growth from it, with our capital efficiency. And we have many opportunities that our exploration teams are working on at present, that are domestic. And we will continue to look for opportunities to expand and grow the Company elsewhere.

Thanks for that. I appreciate it.

All right. Thanks a lot

All right, I think we're out of time anyway, operator. So if you don't mind, I will just go ahead and call the call to a close. We spent a lot of time today talking about our continued progress in the Company, and I'm hopeful that this additional information will help improve your modeling and performance expectations of Chesapeake, as we continue to improve.

I think that resonating throughout this presentation is the continued value on the things that we can control, we're executing in an outstanding fashion. And also highlight that we are not done. My confidence in our ability to execute is very high and I just would encourage, if you have subsequent questions about our performance on any of the assets, or anything else regarding the Company and our plans for 2015, please reach out to Brad. Thank you all, and have a great day.

And this concludes today's conference. Thank you for your participation. You may now disconnect.