Chesapeake Energy Corp (CHK) 2016 Q2 法說會逐字稿

Good day and welcome to the Chesapeake Energy Corporation Q2 2016 conference call. Today's conference is being recorded. At this time I would like to turn the conference over to Brad Sylvester. Please go ahead, sir.

Good morning, everyone, and thank you for joining us on our call today to discuss Chesapeake's financial and operational results for the 2016 second quarter. Hopefully you have had a chance to review our press release and the updated investor slides that we posted to our 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 and 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 in our earnings release today and in other SEC documents.

Please note 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.

We may also refer to some non-GAAP financial measures which help facilitate comparisons across periods and with peers. For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure may be found on our website and in our earnings release.

With me on the call today are Doug Lawler, our Chief Executive Officer; Nick Dell'Osso, our Chief Financial Officer; and Jason Pigott, our Executive Vice President over the Southern Division.

Doug will begin the call and then turn the call over to Nick for a review of our financial results. And then we will turn the teleconference over for Q&A. So with that, thank you. And now I will turn the teleconference over to Doug.

Thank you, Brad. And good morning. I hope you've had the opportunity to review our press release and presentation from earlier this morning.

We continue to make good progress on multiple fronts, including a meaningful reduction in our debt, stronger production, lower operating cost and optimization of our portfolio. While we still face a challenging commodity price environment, I think it's important to note the significant progress that Chesapeake Energy has made, despite commodity prices.

In the past three years we have reduced our total leverage by approximately 50%. We've reduced our cash costs by roughly 50% and significantly improved our capital efficiency. This year's capital program is roughly 10% of the capital spend in 2012. And importantly, our production today is approximately equivalent to our 2012 production.

We have sharpened our operational capability, technology, geoscience and engineering to drive further value for our shareholders for the long term. We have three major gas assets, each with a significant well inventory of new drilling opportunities that can produce in excess of 30 million cubic feet per day, per well.

I'd like to share a few examples of our continued progress. In the Haynesville we have recognized transformational value improvements this quarter. We continue to lead the industry on long-lateral technology with six 10,000-foot wells drilled to date.

We have recently tested the largest completion in Chesapeake's history with over 30 million pounds of sand being pumped in the well. Results have been very impressive with a restricted initial rate of 38 million cubic feet per day and a flowing pressure of approximately 7,500 PSI. We call this new era in completion technology [proppant]. We have not yet reached the point of diminishing returns in the Haynesville and we plan additional tests up to 50 million pounds in the back half of the year.

We look forward to sharing more results of the proper gain program in the future.

In the Eagle Ford, similar to the Haynesville, we continued to optimize our drilling schedule with longer laterals. We moved from an average lateral length of 6,500 feet in 2015 to an average of 9,300 feet in the second quarter of 2016. We've slashed our cost to drill and complete an Eagle Ford well by more than 50% on a cost per foot basis.

Total cost for wells completed in the second quarter averaged just under $4 million with drill times reduced to 9.7 days, even though we are drilling wells with longer laterals.

The move to longer laterals in all of our fields allows us to accelerate value capture as each rig is developed up to twice the rock volume compared to last year. These are just a few examples of our recent cost and technology improvements, and we believe these improvements, directed at our high-quality assets, provider shareholders with competitive investment opportunities for years to come.

We have an excess of 9,000 well locations across the portfolio that can generate greater than 20% rate of return with $3 gas and $60 oil.

Since June 2015 we have reduced our total debt by over $3 billion, with $1 billion of that reduction being since the beginning of 2016. In addition, we are confident in our ability to completely retire and/or refinance our 2017 maturities.

The complexity of our business is further improved in the second quarter with the repurchase of four volumetric production payment contracts, leaving the Company with only two of the nine VPPs that we had three years ago.

You have also seen that we have increased our production guidance for the full year. This is driven primarily by gas volume increases from the Haynesville and Marcellus assets. Our operating teams have done a fantastic job in generating more value out of our capital program, primarily due to operating efficiencies and lower service costs, resulting in the opportunity for higher activity in the second half of 2016.

For the last six months of the year, we plan to take the following actions, all of which will be completed within our previously estimated CapEx guidance range.

First, we plan to drill 100 more wells, which is roughly twice the number of wells originally planned in 2016. Primarily, this will occur as we keep three rigs running in the Eagle Ford when we had previously expected to release those rigs earlier this summer.

Second, we are projecting to place on production approximately 75 more wells than we originally planned.

Third, in July we took down a small property acquisition in the Haynesville for $87 million. I am very proud of our team's ability to more than overcome the 35,000 barrels of oil equivalent per day sold in 2016 dispositions within the same calendar year.

However, more important is the great momentum this additional activity provides for our 2017 production in cash-generating capability. You will note that we have updated our oil production guidance as the majority of our announced divestiture transactions closed in the second quarter. Full year guidance has (technical difficulty) reduced by 1 million barrels in the Mid-Continent area as a result of the Granite Wash divestiture to [Four Point] and the stack divestiture to Newfield.

To a lesser extent, Mid-Continent oil production for the year was also impacted, due to compliance with water restriction directives established by the state of Oklahoma.

The increased drilling and completion activity in the latter half of 2016, made possible through our efficiency gains, will greatly benefit 2017 oil volumes, offsetting decline and resulting in 2017 oil volumes being relatively flat year-over-year. As a very preliminary look to full-year production guidance for 2017, our total production volumes are projected to be down by a mid single-digit compared to 2016 production levels.

We continue to focus on improving our gathering and transportation costs across the portfolio. We are actively working with Williams and all of our midstream and downstream service providers on win-win solutions in the current pricing environment. We are encouraged with the progress we have made to date and we believe we will be able to announce additional meaningful improvements in the near future.

Following on to my initial comments, we have used this period of reduced activity to perform an in-depth study of the resource position and potential in each one of our operating areas. In short, the oil and gas resource potential of Chesapeake Energy is stunning. Our asset value and portfolio of investment opportunities are being redefined through better operating efficiencies and cost structure improvements and also through the rapid evolution of the technologies we apply.

The result of this work provides the foundation for competitive investment performance with significantly enhanced economics.

We are working hard every day to apply these technologies to our extensive undeveloped acreage position and anticipate that these efforts will translate into incremental shareholder value. As an example and as noted, you can look at the Investor Relations slides posted to our website this morning and you can see the impact that operational efficiencies and technology application are having on the Haynesville asset.

We look forward to sharing more about our value proposition and competitive portfolio in the near future.

On the [AB] front we are increasing our target of gross proceeds from divestiture, either closed or undersigned PSA, to over $2 billion for 2016. One of the select areas that we believe will contribute to the new divestiture target is certain acreage within our large Haynesville footprint. Nick will provide some additional detail regarding our recent [A&D] efforts including the highly accretive acquisition that we closed last week in the Haynesville.

In closing, I am pleased with the significant progress we continue to make in reducing our debt, eliminating complexity, lowering our costs and high-grading our portfolio. We are beginning to see evidence that differential leverage reduction and industry-leading operational capabilities are gaining traction with investors.

However, we are just getting started. We believe the portfolio of high-quality economic opportunities within Chesapeake is unmatched in the unconventional oil and gas business. We are driven to succeed and will continue to work relentlessly to reduce our debt and improve our midstream contracts. And we will continue to share news about our progress on both fronts soon. The breadth and depth of our portfolio will continue to expand from a multiplier effect as we apply our leading-edge technologies to the development of our assets.

This will result in unlocking more and more value. The momentum behind the transformation of Chesapeake is building and, with it, the realization of greater value throughout our portfolio.

I will now pass the call to Nick and then we will open the call for questions.

Thank you, Doug. Good morning, everyone. As Doug has stated, financial discipline across our entire business remains a priority of Chesapeake. It's not only about reducing our operating expenses or capital cost savings, although we have done very well in those areas. Our main focus is the reduction of our total debt and the improvement in our liquidity -- specifically, debt maturity in the next six to 24 months.

While the debt capital markets have been constrained over the past 12 months, we are pleased with the recent increase in the price of our securities and believe our opportunities to enter the market are improving.

As you are aware, in April we reaffirmed the $4 billion borrowing base for our revolving credit facility. And in return we pledged additional properties.

The recent improvements in our cost structure, along with our leverage to gas prices, has yielded a significant uplift in the value to our reserves. Using the same database, same type curves and same reserves but using June 30 strip pricing, our proved reserves increased to approximately $11.1 billion at June 30 compared to approximately $3.1 billion when using the SEC methodology of the average of commodity prices on first day of the month over a trailing 12-month period.

Using June 30 strip pricing and a 9% discount rate, similar to how our bank group values our reserves, the value increased to approximately $11.9 billion. We have ample reserves backing our liquidity position of approximately $3.1 billion at June 30. With this liquidity we are well-positioned to fully retire or refinance our ending 2017 debt maturities.

On the expense side, our cash costs continue to decline and we have moved our production expense guidance lower to two additional cost savings. During the quarter our G&A picked up a bit due to additional legal expenses related to the settlements of legacy lawsuits and some bad debt expense that we wrote off impacting our EPS by about $0.01.

Overall, however, we expect our G&A to remain within our current guidance range at this time.

On the A&D front we have closed on the announced sales to Four Point and Newfield. We've also stated that we intend to put a select portion of our Haynesville assets on the market.

These are widely developed properties that we will not likely further develop for some time, given the depth of our Haynesville drilling inventory.

After the acquisition we completed in July, we currently have approximately 430,000 net acres in the Haynesville and are looking to sell approximately 150,000 net acres of that position. While we know there is substantial value to be created with evolution towards longer laterals, higher frac density completions and cost efficiencies going forward, we will retain a position where we have hundreds of locations remaining to be drilled by Chesapeake after the planned disposition.

The acreage we are looking to sell includes approximately 95 million cubic feet a day of production.

In July, we were approximately 70,000 net acres in the Haynesville, primarily within our already existing operating units, for approximately $87 million, pursuant to a pref right we had on the properties. Through the acquisition we increased our average working interest in the area to approximately 83%, along with adding daily net production of approximately 60 million cubic feet a day of gas.

The midstream contacts on the asset are the same as Chesapeake's and the rates on those have decreased since our renegotiations with Williams last year and some of the downstream transport this year. Additionally, our operational efficiencies are allowing us to better utilize our transportation, which brings even more improvement to those contracts. Most importantly, we exercise our pref right on the purchase because we felt were getting assets for a fraction of the alue using current pricing.

Using June 30 strip pricing, we internally valued this incremental asset ultimately $200 million or more than double the cost. Additionally, the PV-10 of the PDP line was higher than the purchase price. We are huge believers in the Haynesville, and with gas prices lifting and the current completion techniques being employed, we are very pleased to have increased our working interest in the play at an attractive price.

We have been adding to our hedge position for the remainder of 2016 and 2017 to help de-risk our cash flow. For the remainder of 2016 we are hedged at ultimately 75% of our project production with approximately 373 BCF of our remaining 2016 gas production hedged at $2.77 per MCF and approximately 12.1 million barrels of our 2016 oil production hedged at approximately $46.60 per barrel.

We have also started to add some 2017 hedges. For 2017 we currently have 290 BCF hedged at $3 per MCF and 7.7 million barrels hedged at approximately $47.79 per barrel.

In closing, we are making meaningful strides in our debt reduction efforts and look to do more in this area. Our production remains strong and we have been able to beat estimates and guidance without increasing our capital spending range. We expect more success in the A&D market and look forward to being able to talk more about these transactions later this year.

That concludes my comments. I will now turn the call over to the operator for questions.

(Operator Instructions) Matt Portillo, GPH.

Just a quick question on the Haynesville -- I was curious if you can update us on your thoughts around capital activity in the play heading into 2017, given the soft guidance. And specifically around that, just trying to get a better sense of where the breakeven economics are in the basin today and how that competes for capital versus the Eagle Ford, which has historically been another area that has been a call on capital.

Again, we are going through the budget process at the Company right now and we would expect to keep three rigs flat, but running some sensitivities on that as we speak. So the Haynesville again, with these new completion technique -- that there really transformed the asset [bore]. It's just as competitive as the Eagle Ford is.

One of the challenges that we've got is all the teams are doing very similar things and they are fighting each other every day for every dollar -- in a good way. But they all have rate of returns that are in 40% to as high as 60% in every single play that we operate.

So, it has been an exciting time for us as our economics today are better than they were when we had $80 oil prices, and we continue to optimize each of these plays. So, the longer laterals -- when you look at Chesapeake's history, we have really -- we went in lease capture mode where we had one well per 640 acres. So for us we see an advantage. And we are one of the few companies that can go to these 10,000-foot wells in nearly every play that we operate.

We are not as overdeveloped. We are not focused on having to go to down spacing and increased density to add well count. We are adding these longer-lateral wells across every field that we operate today and we are not forced to down space in order to add inventory.

Great. And then just a follow-up question in regards to the increase for guidance this year. Was just curious how much of the enhanced completions you are baking in across your asset base, i.e., is that guidance increase already assuming the higher-intensity completions in the Haynesville and potentially some of the changes you are making in other basins?

Yes. We are expecting to switch all of our Haynesville completions to this new design, which is baked into the forecasts and it is driving our increasing guidance.

Thank you.

Neal Dingmann, SunTrust.

Doug, just maybe a little more color, if you could, on the asset sales. Besides, obviously, what you've closed, wondering what others you already have PSAs on. And when you look at regions that you consider non-core, if you could talk about that?

It's a good question. The extensive portfolio that we have and the significant acreage position gives us a lot of flexibility as we look at our go-forward capital plans, the cash-generating capability of the Company and how we might accelerate value from some of these assets.

The acreage positions are large, as you know. And as we look at the core positions, what may not be the primary core to Chesapeake could be outstanding core acreage for another company, which drives that interest.

And that's what we wanted to highlight for you today in the Haynesville is we have literally hundreds of locations, a significant multiyear inventory of high-quality acreage for us to develop. But we also believe that, given the quality of the acreage and opportunity there, that we can accelerate some value.

So we know there is what we will call select areas that, whether it be inside of core or non-core, that we can accelerate value. And as we look across the portfolio I'm not prepared to give you any further guidance other than the Haynesville. But there are several other areas that we are looking at and we feel very good about achieving that divestiture target.

Got it. And just lastly, just looking at that slide 8 that shows that huge portfolio, you mentioned with your rigs today -- I noticed there was not a rig yet in the Barnett. Either for you or Jason, just how you see -- I think on that slide 8 it shows about 65,000 a day -- how you think about the Barnett as far as activity or just maybe production.

Well, the Barnett is a great asset. It has been a fantastic asset inside our portfolio. When you look at the potential we have with the longer laterals and with economics that we are getting out of the other place, the Barnett is not getting a lot of capital in the near term. So it's still a very strong, high-quality asset. We don't see direct in capital there this year or in the near term.

Appreciate it. Thanks, Doug.

David Heikkinen, Heikkinen Energy Advisors.

Just a question on the working interests and your expectations of the regions for the additional spuds and pops this year, the 100 wells you will drill. Where will those be? And the 75 wells that you're going to put on production?

I can answer that. Most of them will be in Eagle Ford. We were planning to shut that program down earlier in the year. We decided with -- well, once we've seen the cost savings that have been able to achieve -- again, they taken their well costs down to $4 million for wells that are 9,000 feet long. So that's an amazing transformation for them. Also savings in areas like the Haynesville have allowed us to just that program going. So we are reinvesting there.

So that's the biggest increase in our drilled spuds. It's going to be in the Eagle Ford. We've gone to -- I think we had 25 was our original plans and we are now up to 100.

So, a lot of incremental spuds in the Eagle Ford. Those translate -- really are going to show up more in 2017 because their acceleration on the schedule until the [tills] don't start to really come in until 2017. So that's when you will see those.

We do have about 15 or so incremental tills in the Eagle Ford this year. MidCon saw a big jump in the till count as well. We had some of the curtailment issues that impacted us early in the year. We had shut down our Miss Lime completion program. We have been able to work through the water issues by re-completing in the different disposal zones, which will open up our water capacity later in the year.

So we will be tilling a lot of misaligned inventory, which -- we don't talk a lot about that. But those are -- they're making some fantastic wells in the Miss Lime that are very competitive in our portfolio as well.

And along those lines, with the oil volumes flat year-over-year, just trying to make sure I'm getting with the right benchmark for 2016. Doesn't that -- your updated millions of barrels guidance, basically just think that 2017 will be flat with updated guidance for 2016? Or is that like an exit great for fourth quarter? I'm just trying to make sure I get the right benchmark for that soft guide.

Its total production for the year is anticipated to be flat, Dave.

Awesome. And then you all hit --

David, let me just jump in on that. If you think about what that means, given the trajectory this year, that means that in during what is really happening during 2017 order to be flat year-over-year is a ramp during the year.

Yes; you started high in the first quarter, then declined --

That's right.

-- Through this year and then V up the next year with those tails, particularly.

That's right. So the momentum there is really strong.

Yes. The cost per rig line now in the Eagle Ford and the Haynesville has come down a lot. You are doing things faster, and you talk about lower well costs. Can you just update us on, on an annual cost per year, what a rig line costs in your four major operating areas -- Eagle Ford, Haynesville, MidCon and Utica?

I don't have it on a per rig line basis. I'll just do that Eagle Ford. We till -- we are getting to 2 to 2 1/2 wells per month. They are $4 million gross per well. And then we are drilling 30-ish wells per year in the Eagle Ford at $4 million a pop on a gross basis. We are averaging about one well per month in the Haynesville, even with the longer laterals. So they are on the pace of 12 per month.

If we go to these enhanced completion techniques, which we are planning to, costs will be $9 million to $10 million. So you are talking $120 million on a gross basis per rig line there, all in. And what was the other area?

MidCon is the other main area.

MidCon will be hard to do. We've got a great story in MidCon that we are not telling you today because the acreage capture out there is very competitive. We've got 15 different formations that the team has been mapping since the divestiture. We have replaced all of the inventory that we sold to Newfield with prospects in new plays. This is an area where our core lab has given us a great advantage as we are taking cores in some of these new formations and we are able to analyze them faster than anybody else in the play.

But because it's such a mixed bag of wells that we are drilling in order to test these 15 different formations, it's hard to put a dollar-per-rig-line together on this.

We can get -- if you get with Brad, we can try to get you some numbers there. But it's a very different portfolio that we will be drilling in the future in MidCon.

Just a completion in that Miss Lime now, since you are tilling some wells there? What do they cost? I haven't thought about that in a bit.

I think they are $400,000 total well costs. For a Miss Lime well is about $2.3 million.

Perfect. Thanks, guys.

Doug Leggate, Bank of America Merrill Lynch.

Doug, real interesting commentary around the potential to resolve some of the transportation issues. I realize that some of these things are confidential and so on. But as an order of magnitude, can you provide some idea as to what you might think the endgame could be as -- [why we have] impact on your cost races?

Let me make sure I understand your question. It was cut out just a little bit, Doug. To understand the cost on -- did you say transformation or transportation?

Sorry, I apologize. I'm not quite sure why my line is choppy this morning. So basically the potential to continue to improve your transportation agreements in terms of the cost obligations. I'm just wondering if you could quantify think the order of magnitude could ultimately be on the improvement?

The way that I would look at that, Doug, is in calling out the progress that we've made over the past couple of years, the message in our call today is we've got huge opportunity all over this Company. And I couldn't be more excited about it. And we are going to share more detail in the coming months about those improvements. So I'm going to hold off on quantifying it for you exactly at this point. But what you can expect is the cost structure improvements, the portfolio, enhancement, the technologies, improvements to our debt. These things are all just part of the plan that is leading Chesapeake to a much more competitive, much more valuable company.

And I just will address your question by saying that we expect to see continued improvements in those transportation costs and continuing to work with Williams

and other midstream service providers, and I am excited about it. So it's -- good things are coming.

I appreciate (inaudible) it was worth a try, Doug, I guess. Maybe my follow-up, very quickly, is no capital really going to the Barnett. There's obviously -- I apologize; there might have been -- someone asked this earlier because there's a couple calls going on this morning. But the Barnett has been mentioned in this [part] as a potential disposable candidate. Could you comment on your view as to whether you see that as a core asset at this point? And I'll leave it there. Thanks.

The Barnett has been a great asset for Chesapeake. It's a high-quality asset. As the investment community knows, it has not attracted capital in the near-term. And based on the quality of a few of the other assets, we have a hard time directing capital there in the next few years. So, that given, we will continue to look at the portfolio, our acreage position of developed and undeveloped properties. And if there's opportunities to accelerate value and enhance the economics, enhance the EBITDA or cash flow of the Company, we will absolutely capture that. So that not only applies to Barnett, it applies to the entire portfolio.

Congratulations on your efforts to date, Doug. Thanks a lot.

Okay, operator. Thank you for the call. Everyone, today, we appreciate your time. If there are additional questions regarding our operating or financial performance, please contact Brad Sylvester. And we look forward to sharing more with you in the coming months. Thank you.

That concludes today's call. Thank you for your participation. You may now disconnect.