May 6, 2015
Executives
Bradley D. Sylvester - Vice President-Investor Relations & Communications Robert D.
Lawler - President, Chief Executive Officer & Director Mikell J. Pigott - Executive Vice President-Operations, Southern Division M.
Christopher Doyle - Executive Vice President-Operations, Northern Division Domenic J. Dell'Osso, Jr.
- Executive Vice President and Chief Financial Officer
Analysts
Brian A. Singer - Goldman Sachs & Co.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
David M. Heikkinen - Heikkinen Energy Advisors Arun Jayaram - Credit Suisse Securities (USA) LLC (Broker) Scott Hanold - RBC Capital Markets LLC
Operator
Please stand by. We're about to begin.
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.
Bradley D. Sylvester - Vice President-Investor Relations & Communications
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 a 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've 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 are adding value here at Chesapeake. So we're going to use this conference 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 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.
Robert D. Lawler - President, Chief Executive Officer & Director
Thank you, Brad, and good morning. I trust you've seen our release issued earlier this morning, and I hope you've had the 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 entering into multiple outstanding acreage positions in the U.S. unconventional basins.
Frank brings tremendous experience and expertise to Chesapeake, and I believe he'll 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's 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 are 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've 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 costs as measured by production and G&A cost.
Our capital efficiency improvements are recognized through reduced costs 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're delivering on our commitments and you can expect that our strategy in investments will drive further long-term value for our shareholders. Moving to our first quarter performance on slide four, we generated adjusted earnings on a fully diluted basis of $0.11 per share, with EBITDA of $928 million.
Production cost 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'll 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 have yet to see any organization post the high level of capital efficiency improvements that are being captured at Chesapeake. High-quality rock combined with high-quality operations are outstanding attributes of the company.
Many companies have paid significant acquisition cost 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 are 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's 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 are 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'll now pass the call to Jason; Chris will follow; and then Nick with a review of our financial results.
And then we'll hopefully have time for a few questions.
Mikell J. Pigott - Executive Vice President-Operations, Southern Division
Thank you, Doug. In the Southern Division, we continue to see great results from our efforts to increase our EURs by bringing down well cost.
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 productions. These efforts have paid tremendous dividends as I would like to highlight today.
On slide six 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 seven with the expectation to get to just three rigs by July. Strategically, we are going to take advantage of this ramp down in 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 tests 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 test. 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 seven, we're excited to highlight in more detail the results of our down-spacing test. 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'd observed some interference in the wet gas area.
But we can now attribute that largely to differences in rock quality. We placed a 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 graphs highlight that we have no material reduction in performance thus far.
We will continue to monitor 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 eight, I'd like to highlight some equally impressive accomplishments from our drilling team. At 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 make 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 as 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 this success, the team is actively moving forward with high grading the rig schedule to frontload 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 a year ago. Slide nine 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 foot lateral tests coming online in April. Initial flow back from these wells is averaging over 17 million cubic feet a day.
Successful testing of our enhanced completion designs have 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 open this area for partnerships that could allow us to mitigate our minimum volume commitments. At our last conference, we indicated that longer laterals and enhanced 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-prong approach to well completions. One focused purely on cost reductions, and one on EUR enhancement.
The EUR enhancement techniques utilized reduced perf cluster spacing and treating smaller groups of cluster 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 on the bottom left of the corner – left corner of this slide, we show the location of our enhanced completions; 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 on line 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 slide, we've opened the choke up on both wells. Production rose the last two days up to19.6 million cubic feet a day with 7,200 pounds and 23 million cubic feet a day and 7,700 pounds respectfully (sic) [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 are 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 slot 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 an 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 length 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 assets.
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 outperformer 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 brought online multiple wells and 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 barrels of oil per day. We believe the stacked 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 as 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 our production performance by year. In short, it highlights that our wells are coming on stronger with shallower declines.
There are several key efforts 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 developing 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 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 our 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's transformation, we set up dedicated production teams focused strictly on enhancing base performance. The graph on the bottom of slide 17 highlights gross base production in our northern Mid-Continent area.
Through the implementation of a proactive artificial lift program, reducing downtime and maintaining a healthy workover and completion 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. Now, I'd like to speak more generally about an emerging base decline mitigation program.
Talk about re-frac potential in the industry has been on the rise. On slide 18, if I could 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, and we consider these wells under-stimulated compared to our current designs and based on their vintage.
The Barnett is one of the first major shale plays, has the most easily identifiable concentrations of under-stimulated wells, and was our first asset to focus on for our initial re-stimulation 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 a re-frac 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 are looking at all our base wells and working through the best way to recover the incremental reserves, be it an offset drilling program or with re-fracs. Overall, we have some great highlights for you today.
We are attacking every asset strategically, and today, we see the results from those programs that were implemented over a year ago. Even with the great progress we are 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.
M. Christopher Doyle - Executive Vice President-Operations, Northern Division
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 the 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, 4.5 frac crews. By the middle of the third quarter, we plan to reduce that to two drilling rigs and 2.5 frac 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'll reduce our drilled, not completed well inventory by 40% by the end of the year. You 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's focused on base optimization. That was one of the keys to our first quarter outperformance in the Utica.
Turning to slide 21, I said all along that our drilling team has provided Chesapeake a competitive advantage for us 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 time to 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 food.
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 versus what we rolled out at Analyst Day, we're seeing 20% higher EURs, and that's driven primarily from these enhanced completions.
Our drilling targets are deliberate. We're drilling longer laterals, increasing the number of stages and tailoring our cluster spacing, all depending on where we are on the field, and all of this is based on our deep understanding of the Utica.
Check out the graph in the upper right-hand side of the 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, a 25% increase from 2014, and we're pumping 2 to 3 times more stages and delivering more value for our company. The key here is 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 frac crews averaged 8 stages a day per crew.
Each of our frac 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'll continue to seek and find those efficiencies. Slide 23 is an awesome example of how we're 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 our type curve, but interestingly and remarkably, the recent wells, those three in green, have outpaced those tests by 50%.
Main driver here is not necessarily just completions, but it's also our optimized targeting based on our seismic and geologic interpretation that's continued to evolve and sharpen over the past year. And here is a concrete example of a G&G team driving value, improving an outside area from our traditional core position to a 25% rate of return based on $3.25 [gas] and $65 [oil].
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 outperformance. 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 you 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. It includes our G&G, reservoir, land, marketing, production teams, but most importantly includes the strongest field organization in the basin.
At today's strip prices, that team has pushed our Utica NAV 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. Multiple stack plays push our gross resource potential to over 2 billion barrels equivalent and 3,000 potential locations.
That's up huge from last year's Analyst Day. And 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 frac 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, 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 are expected Sussex rate of returns from 20% at the type to 50% at $3.25 [gas] and $65 [oil].
In order to get a 10% rate of return, 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 [cubic feet of gas] 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 frac crew to maintain our lease position. We plan to maintain production with – at that reduced activity but stand ready to respond to what the market tells us regardless of production impacts.
And 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.
I'm 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 or the curve, the lateral, every flat time in the well path.
My 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.
And 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 you think about accomplishing this in the sixth year of development is just simply staggering.
It's a true team effort, focused drilling organization working with the business unit and supported by our Operations Support Center to get it done. Slide 30 is we've touched on most of these assets.
We use those drilling savings, redeploy 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, in 2013, and what we're telling you today in 2015.
Every year, IPs are going up, EUR is 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. The completely redefined investment thesis as I've said in the past.
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. So, how do you explain such a rapid enhancement in 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, geosteerers, geologists, engineers, lease operators and 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 in 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. Now 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 costs 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 have ranged 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 capture about 5% savings or $0.10 a boe.
And we'll 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 said in the past, it's all about service delivery. We realize that in 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.
Domenic J. Dell'Osso, Jr. - Executive Vice President and Chief Financial Officer
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 much 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 are 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 spud rig, and averaged 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 are projecting around $200 million in D&C capital. So while we are doing amazing things in the fields 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 of $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 in 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 continue 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 a strong first quarter performance and otherwise reiterating our outlook.
We are 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 are 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 teams' efforts in the areas of recompletions and more efficient workovers are great examples of ways we are 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 am 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
At this time, we will start the question-and-answer session. And we'll take our first question from Brian Singer with Goldman Sachs.
Brian A. Singer - Goldman Sachs & Co.
Thank you. Good morning.
Robert D. Lawler - President, Chief Executive Officer & Director
Good morning.
Domenic J. Dell'Osso, Jr. - Executive Vice President and Chief Financial Officer
Morning, Brian.
Brian A. Singer - Goldman Sachs & Co.
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 talked to in this presentation assumed in the going-forward CapEx program and in your revised production guidance, or is there an element of upside?
Robert D. Lawler - President, Chief Executive Officer & Director
Thanks for the question, Brian. The principal reduction in the capital program is related to activity.
But as you'd expect, with this type of efficiency gains that we're recognizing, we also expect our capital to improve going forward because of those efficiencies. And as Chris noted and 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.
M. Christopher Doyle - Executive Vice President-Operations, Northern Division
Yeah, the thing I'd 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'll capture.
None of that is built into the forward forecast. Efficiency gains, cycle time improvements that we continue to deliver every single quarter, not built into that forecast.
And so I think what you'll 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.
Brian A. Singer - Goldman Sachs & Co.
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? I wonder a little bit because that dovetails into whether consolidation opportunities make sense and where you stand on that to bring some of these efficiencies to other assets.
Robert D. Lawler - President, Chief Executive Officer & Director
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 tell you that the first point to the quality of the rock in these assets, and then point to the innovation and the 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 strength of our portfolio is the quality of the rock, and the technical expertise and the way we're 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're leading it and we'll continue to lead it.
Brian A. Singer - Goldman Sachs & Co.
I guess does that create an M&A opportunity that you see or is the valuations and then your own balance sheet funding gap just too prohibitive right now?
Robert D. Lawler - President, Chief Executive Officer & Director
Sure. It absolutely does.
And we're doing things that others can't. And because of that leadership on the operations and capital efficiencies side, that creates a lot of opportunity and we have the teams that can execute that.
M. Christopher Doyle - Executive Vice President-Operations, Northern Division
The one thing I would add, just specific to the Utica is as we said last year, we've 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.
Brian A. Singer - Goldman Sachs & Co.
Thank you.
Operator
And we'll take our next question from Neal Dingmann with SunTrust.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Morning, Doug. Say...
Robert D. Lawler - President, Chief Executive Officer & Director
Hey, Neal.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Again, a lot – on your slides, you guys talked about a lot of these enhancements you're doing, I mean, the longer lateral, just the improvements on the completions in general. My questions are around that, I guess, for you or Chris or Jason and the guys.
Is this now focusing on more proppant overall? I mean, are you doing the proppant with the – just 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 just kind of, what you all are doing and how different is that, like you're doing in the Eagle Ford versus some of these other basins?
Robert D. Lawler - President, Chief Executive Officer & Director
Sure, Neal. Well, the first I'll say is that around the completions, the Chesapeake is an industry leader in interventionless completions.
And we are working closely with all the suppliers. We are 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's a – it really is an advantage that we continue to pursue and see as very competitive.
Mikell J. Pigott - Executive Vice President-Operations, Southern Division
This is Jason. And just to echo what Doug said.
I mean, one of the things that's our competitive advantage is our people and the efficiency that they're 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're tight. And I think that's one of the key things that gets that lower quality rock to help.
There's some other things they're doing there. Also sand, increasing our sand per foot, but we – the thing that we – is 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'll dial it back to the sweet spot. That was part of our EUR enhancements discussions that I talked about.
We're testing new things in every field as well, in 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, we've tried a new completion design this week that they just finished. It'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.
M. Christopher Doyle - Executive Vice President-Operations, Northern Division
Hey, Neal, this is Chris. I think you mentioned 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 talked about the cluster spacing. As we're 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.
Robert D. Lawler - President, Chief Executive Officer & Director
Another thing, Neal, I think is kind of important to note that there is a lot of non-technical popular misconception around that everybody can just do the same thing, but the technical – inherent technical rock properties, petrophysical properties that make a high quality asset create a differential for value creation. And what you're seeing is, as Chris noted, others can go mimic and copy Chesapeake.
I mean that kind of stuff's 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.
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.
M. Christopher Doyle - Executive Vice President-Operations, Northern Division
Obviously, the proof is in the pudding. It's not just about completion.
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 you've seen in other areas of the company, you're starting to see that.
So, I'm excited not only how far we've come in the two years, but I'm excited to see what happens for the rest of this year.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
That's great details, guys. Two more quick ones if I could.
Doug, just your thoughts on M&A here, either international or just anything you're seeing around the basins.
Robert D. Lawler - President, Chief Executive Officer & Director
Yeah. 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're working on that are a remnant 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 also would 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 efficiency, 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.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
And then, just lastly, Doug, or for you, for the guys, just on takeaway contracts. I know in the past you've mentioned I know in the Haynesville kind of what that extra costs you on what you all 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?
Robert D. Lawler - President, Chief Executive Officer & Director
Yeah, 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 the efficiencies or the new opportunities that we're 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 that 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. And Nick, do you want to add any additional color?
Domenic J. Dell'Osso, Jr. - Executive Vice President and Chief Financial Officer
You asked about has any of our takeaway gone away in the Northeast. And so just to answer that question directly, you'll see in our Q, in our commitments footnote a decrease in takeaway, and part of that is, or 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're currently curtailing production. So 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 of 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.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Great details. Thanks, guys.
Robert D. Lawler - President, Chief Executive Officer & Director
Thanks, Neal.
Operator
And we'll take our next question from David Heikkinen with Heikkinen Energy Advisors.
David M. Heikkinen - Heikkinen Energy Advisors
Good morning, guys. Just had a quick question first on the Sussex of kind of how do you ramp activity levels there, or is that really a possibility, just given the surface constraints?
M. Christopher Doyle - Executive Vice President-Operations, Northern Division
Sure, David. This is Chris.
It's absolutely a possibility. I think the team focus right now is understanding as we're early in the development of the Sussex.
We only have a handful of wells, but my gosh, they're performing phenomenally well. So, as we're 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'll 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've seen over the past year.
So the team is actively working and getting prepared. Remember, we were planning to run seven to nine rigs this year, so we've got some permits and we'll continue to prepare to ramp up when the time is right.
David M. Heikkinen - Heikkinen Energy Advisors
I'm trying to – what is the – why isn't the right time with that rate of return and permits for seven to nine rigs may be the better way to ask that.
M. Christopher Doyle - Executive Vice President-Operations, Northern Division
Well I think when we look at, that's more of a corporate portfolio discussion. Again, we're kind of 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.
David M. Heikkinen - Heikkinen Energy Advisors
And then on slide 33, that is helpful, Nick. As you think about your fourth quarter cash flow, CapEx and just kind of the implied trajectory for both into 2016, can you kind of give us a snapshot into how you're thinking about things, either Doug or Nick.
Robert D. Lawler - President, Chief Executive Officer & Director
Yeah. So we're 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 which that we can ramp back up and the confidence that we can, with greater pricing, we can further accelerate our programs. I also think that it's good to note that if you hear – you're driving down a road and you hear that song, "All About That Bass," you ought to think about Chesapeake.
We've got a huge, huge base optimization program and we are focused on that. That's going to add incremental volumes and we see good opportunities there.
So there's – looking forward in 2016, we'll 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's historically known for.
David M. Heikkinen - Heikkinen Energy Advisors
I guess is there any update to your Howard Weil presentation on quarterly progression of production?
Domenic J. Dell'Osso, Jr. - Executive Vice President and Chief Financial Officer
No. There's really no update there.
I mean we upped our guidance to reflect the strong first quarter production. That's going to have its tail effect through the year.
And so the full year comes up as a result of that. The general trajectory there is the same.
It'll 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 a little bit is all we would say at this point.
David M. Heikkinen - Heikkinen Energy Advisors
Okay. Thanks, guys.
Operator
And we'll take our next question from Arun Jayaram with Credit Suisse.
Arun Jayaram - Credit Suisse Securities (USA) LLC (Broker)
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 NDCs. 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 then maybe some opportunities to reduce those liabilities over time?
Robert D. Lawler - President, Chief Executive Officer & Director
Yeah. It's a – we know that this has been a – this is obviously a focal point for Chesapeake as we want to try to further improve our competitiveness.
And just would highlight again that everything that we're 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, re-fracs, all those kind of things, it will be very helpful in that respect.
And we will continue to look for, whether it'd be through contract extensions or other opportunities, we are making progress in that respect. And while we don't have the specifics to share today, we're encouraged with the commercial approach and think that we'll find ways to help improve the competitiveness there.
Arun Jayaram - Credit Suisse Securities (USA) LLC (Broker)
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 for $1.80 at the midpoint in terms of this.
Domenic J. Dell'Osso, Jr. - Executive Vice President and Chief Financial Officer
Yeah, so 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 hedged some of that. But so 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 hydrocarbons and particularly in 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.
Arun Jayaram - Credit Suisse Securities (USA) LLC (Broker)
Okay. Just final question.
In terms of your year-end rig count outlook, 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?
Robert D. Lawler - President, Chief Executive Officer & Director
Well, the capital efficiencies are continuing to be really outstanding. And so I think that the range is still good.
But right in the middle of that is probably where we'll be and in the 14-15 range. And just depending on what we see in terms of pricing and the competitiveness of the projects we're investing in, we'll 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.
Arun Jayaram - Credit Suisse Securities (USA) LLC (Broker)
Okay, thank you very much.
Robert D. Lawler - President, Chief Executive Officer & Director
Okay. Thanks.
Operator
And we'll take our next question from Scott Hanold with RBC Capital Markets.
Scott Hanold - RBC Capital Markets LLC
Thanks. Good morning, guys.
Robert D. Lawler - President, Chief Executive Officer & Director
Morning, Scott.
Scott Hanold - RBC Capital Markets LLC
If I could ask, go to slide 38 where you've got your activity levels again throughout the year and at the end of the year and just looking at the allocation of rigs by play, can 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 little disconnect.
And especially when you look at the Marcellus, the returns you're showing on the Marcellus at current prices are just off the charts, yet you're reducing activity there. How do you allocate that appropriately in your view?
Robert D. Lawler - President, Chief Executive Officer & Director
Yeah. So, the capital allocation process is very detailed and we spend a lot of time with that.
Keep in mind that as we are optimizing our liquidity and activity, that we're also very focused on how we are improving the competitiveness of each of these plays and each have specific inherent things that we're trying to accomplish. Your reference to the Marcellus obviously is it's fantastic and in unbelievable position up there, but you also have takeaway issues that are in the basin there.
And so, we're – with the ability to deliver more volume in the Marcellus, we'd absolutely put more rigs there. The things that we're testing and improving upon in the Mississippian Lime give us a lot of confidence and we're going to continue to drive down our cost 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 as to why we went back there.
This, over a year ago when we first went back into the play and we're just crushed the costs there and made it extremely competitive and continue to see further improvements. So, it's really more of a balanced portfolio approach.
These are all really strong assets that have different specifics that require optimization either through technology or efficiencies that we're looking to try to achieve for a long-term value. So, 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, well we 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 efficiency, synergy, supply chain, all those things are pointing to why this high quality portfolio is undervalued.
Scott Hanold - RBC Capital Markets LLC
Okay. And I appreciate that.
And then I guess the thing that really stands out would be for example, the Mississippian play where I kind of wonder that 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.
Robert D. Lawler - President, Chief Executive Officer & Director
Well, it's just a function of how we're managing the whole portfolio, I think, Scott, is the best way to describe it. It's – and we have yet – 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.
Scott Hanold - RBC Capital Markets LLC
Okay, okay. Thanks.
And one real quick one, obviously you made a great acquisition with Frank coming over to the team. Obviously, his experiences have got a lot of international offshore bias to it.
Should I read into that any way, or is it just a strong recruit?
Robert D. Lawler - President, Chief Executive Officer & Director
It's a – 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 Frank has that experience and expertise. But I wouldn't read in it that we're 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.
Scott Hanold - RBC Capital Markets LLC
Thanks for that. Appreciate it.
Robert D. Lawler - President, Chief Executive Officer & Director
All right. Thanks a lot.
Operator
And we'll take out next question from David Tameron with Wells Fargo Securities. Caller, your line is open.
Please check your mute function. Caller, your line is open.
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Robert D. Lawler - President, Chief Executive Officer & Director
All right. Well, I think we're out of time anyway, operator.
So if you don't mind, I'll 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 perform to expectations at Chesapeake as we continue to improve. I think that resonating throughout this presentation is that 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 that 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.
Operator
And this concludes today's conference. Thank you for your participation.
You may now disconnect.