Chesapeake Energy Corp (CHK) 2016 Q4 法說會逐字稿

Good day, everyone, and welcome to the Chesapeake Energy Corporation fourth-quarter 2016 conference call.

Today's conference is being recorded.

At this time, I would like to turn the call to Mr. Brad Sylvester.

Please go ahead, sir.

Good morning, everyone, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2016 fourth quarter and full year.

Hopefully you've had a chance to review our press release and the updated investor presentation 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, 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.

We also may 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, Nick Dell'Osso, Frank Patterson, and Jason Pigott.

Doug will begin the call and then turn the call over to Nick for a review of our financial results before we turn the teleconference over for Q&A.

So with that, thank you, and I will now turn the teleconference over to Doug.

Thank you, Brad, and good morning.

2016 was a year of significant progress and substantial achievements for Chesapeake Energy.

We are stronger today than any other time in our history.

Looking back across this challenging period of low commodity prices, we've successfully delivered on our strategy to delever, derisk, and simplify our balance sheet while driving improved capital and operating efficiencies and also driving industry-leading low production costs.

The Company is positioned to differentially perform through further debt reduction and development of our high-quality asset portfolio in the coming years.

The most significant accomplishment for 2016 included successful liability management initiatives that resulted in reduced debt, refinanced near-term maturities, and restoring a reasonable cost of capital.

Other major accomplishments included: one, divesting the Barnett asset, eliminating an annual negative impact of $200 million to $300 million in EBITDA, principally due to NBC payments and burdensome gathering and firm transportation agreements associated with the asset; two, renegotiating midstream contracts including new gathering agreements in the Powder River Basin and Mid-Continent assets; three, divesting of more than $2 billion in non-core, non-operated, and/or low EBITDA-generating assets; four, significantly improving capital efficiency with new technology, better engineering, and greater recoveries resulting in higher quality, more efficient well economics; and five, reassessing our entire portfolio and confirming the long-term economic strength of our asset.

We have previously shared the strength of our portfolio consisting of 11.3 billion barrels of net recoverable resources, 5,600 locations with an internal rate of return of greater than 40%, and a projected growth rate of 5% to 15% annually through 2020 at normalized flat pricing of $3 per MCF and $60 per barrel Of oil.

We crushed our cash costs in 2016.

We reduced our total production expenses by approximately $336 million, or 28% per barrel of oil equivalent of production, compared to 2015.

We also reduced our total GP&T expenses by approximately $264 million, or 7% per BOE of production, compared to 2015.

These improvements total $600 million of annual savings and we are not done.

Our total production in 2016 averaged over 635,000 barrels of oil equivalent per day, down just 0.3% after adjusting for asset sales, while we reduced our total capital expenditures by approximately 53%.

This excludes approved property acquisitions and the repurchase of volumetric production payment transactions.

These accomplishments reflect the power, strength, and resiliency of our portfolio and the focus of our talented employees.

Last week we released capital and production guidance for 2017.

We are committed to improving upon our 2016 performance, continuing the transformation of our balance sheet, and increasing our productivity and capital efficiency.

We include this service cost escalation in our capital guidance, but we will utilize our operating strength and purchasing power to minimize any potential cost increases.

We will be working to accelerate at our stated debt reduction target of $2 billion to $3 billion over the next few years through additional asset sales.

Our capital program is designed to achieve cash flow neutrality in 2018 as we progress toward our targeted net debt to EBITDA multiple of 2 times.

After planning for a lower turn and line count in 2017 in the first quarter, our production volumes are projected to return to growth in the second quarter of this year.

We believe this strong growth trajectory will be driven by our oil assets, most notably the Eagle Ford, the Mid-Continent, and some exciting progress coming from the Powder River Basin.

Meanwhile, we expect our gas volumes will be primarily driven by the Haynesville and Marcellus.

We are moving to more pad drilling in all of our operating areas which we anticipate will generate a strong production ramp in the second half of the year.

Our production guidance for 2017 is projected to deliver an exit-to-exit increase in total production from the fourth quarter of 2016 to the fourth quarter of 2017 of approximately 7%, of which oil is projected to have an exit-to-exit increase of 10%.

We expect this oil growth to accelerate even more in 2018, with oil production projected to increase from the fourth quarter of 2017 to the fourth quarter of 2018 by more than 20%.

Our portfolio across six major basins is getting stronger due to growing use of longer laterals, more aggressive fracture stimulations, and the shortening of our reinvestment cycle, all leading to greater productivity and higher cash flows for Chesapeake.

To reiterate, total production growth through 2020 is expected to range between 5% and 15% per year.

Our corporate strategies and financial discipline, profitable and efficient growth from captured resources, business development, and exploration remain unchanged.

2017 is an important year for Chesapeake, a year where we pivot from defense to offense.

As noted, we are committed to removing an additional $2 billion to $3 billion of debt from our balance sheet and our plan to execute upon this reduction sooner rather than later.

We are focused on expanding our margins and, thereby, our EBITDA through greater oil production and our unrelenting drive to lower all of our cash costs.

I will now pass the call to Nick to share some additional financial information.

Thank you, Doug, and good morning, everyone.

We are very pleased with our 2016 results and the significant improvements in our capital efficiency, asset performance, cost structure, and liquidity that Doug highlighted in his comments.

Starting with our liquidity position; as a reminder, we have effectively taken over $4 billion of leverage in preferred stock out of our capital structure over the last 16 months.

That's $2.6 billion of debt, inclusive of our December 2015 debt exchange, and $1.4 billion liquidation value of our preferred shares for common shares.

Importantly, through these transactions and several incremental refinancings completed in 2016, we removed or refinanced approximately $2.7 billion of near-term debt that was maturing or could be put to us in 2017 and 2018 primarily through refinancing, with only $77 million remaining do or putable in that period.

Today we have liquidity of approximately $3.4 billion including a projected $300 million of cash on hand at the end of February, with no borrowings outstanding on our revolving credit facility.

We are pleased with this liquidity position, but our goal is to reduce our debt even further and as Doug mentioned, we remain prudently impatient in working toward removing another $2 billion to $3 billion of debt off our books.

We continue to achieve significant progress in lowering our production expenses and expect these to decline even further in 2017 on a BOE of production basis.

However, our G&A ticked up slightly year over year and will continue to increase in 2017, primarily as a result of costs moving from LOE to G&A following our significant asset sales.

We continue to see opportunities to improve efficiency around our reduced operating footprint, having sold nearly 10,000 operated wells in the last year and with that having removed the maintenance of over 30 field offices, significant IT and communications equipment, invoices to process, and decreasing the burden on several other administrative functions.

Given the movement between G&A and LOE, we believe the best way to measure the improvement is to note that our combined LOE and G&A per BOE of production decreased by 8% year over year.

We also continue to see our GP&T expenses improve, decreasing by approximately 7% on a BOE-of-production basis in 2016 and forecasted to decrease by approximately 10% in 2017.

With our exit from the Barnett Shale, the restructuring of our Mid-Continent and Powder River Basin gathering agreements, and amendments to certain firm transportation agreements in the Haynesville and Eagle Ford operating areas, we have seen a reduction, a $5.5 billion reduction in our future GP&T commitments since the end of 2014 and a $2.9 billion reduction since the end of 2015.

We have additional commitments that will step down going into 2018 as well as expected synergies associated with volume growth in our key basins, and so we anticipate continuing the trend of decreasing GP&T costs on a per-unit basis beyond this year.

This work continues in 2017 with our buy-down of certain crude oil and natural gas transportation commitments this quarter for roughly $390 million in cash.

The buy-down of these contracts will remove approximately $560 million from our future transportation commitments, further optimizes our long-haul transportation plans, and significantly improves the margin in our marketing group over time.

We have provided a slide on this earlier today, projecting how these buy-downs have improved our GP&T commitments in the coming periods.

We also continued to improve our netbacks for our liquids production in various basins by accessing new markets for our hydrocarbons and optimizing our point-of-sale further downstream in several cases versus at the wellhead.

Our marketing team continues to have success in improving our realized pricing for our productions and we look forward to further success.

On the A&D front, with the closing of our two Haynesville asset packages this quarter, we have received approximately $2.2 billion in net proceeds from asset sales that were signed during 2016.

Like we have said before, we expect to continue to optimize our portfolio in 2017 and use asset sales proceeds for further debt reduction.

Finally for 2017, we currently have approximately 71% of our projected gas production hedged at $3.07 per MCF and approximately 68% of our projected oil production hedged at approximately $50.19 per barrel, using midpoints of our production guidance.

With these hedges in place, our cash flow is not materially impacted by the recent decline we have seen in natural gas prices.

We have also hedged a meaningful portion of our 2018 gas production at a little over $3 per MCF.

We have stated before that our 2016 achievements have allowed us to focus on our operations instead of our obligations.

Our return to production growth during 2017 sets Chesapeake up for an even stronger year in 2018.

This production growth and the associated growth in cash flow accrues much more directly to our equity holders than in the past, given our significantly decreased total leverage and improved capital structure.

We look forward to executing on these plans to deliver these enhanced returns to our shareholders.

That concludes my comments.

I will now turn the call over to the operator for questions.

(Operator Instructions) Neal Dingmann, SunTrust.

Morning, gentlemen.

Two questions: first, Doug, for you or Nick, just something was reported on this expects -- on the material weakness internal controls.

Anything you can just suggest, anything you are worried about to that come up on the 10-K?

Happy to answer that, Neal.

This was an oil basis pricing differential calculation in one region for a discrete period of time.

It has nothing to do with our reserve engineering and is isolated to that one regional oil price calculation.

The impact to our financial statements was not material and is laid out in the table in the 8-K.

Okay, perfect.

Thanks, Nick.

Great to hear on that.

Then, Doug, looking at the analyst day, how you laid out the rig scenario for this year and then just on the most recent slides, looks like everything is pretty close to the same.

I'm just wondering maybe in two areas.

One, Mid-Con you talk about four currently running and I think during the analyst day you talked about potentially one to two in Oswego and three to 10 in the Miss and the Wedge.

And then over in the Marcellus I noticed you currently don't have any running and I think at the time you were mentioning potentially zero to two there.

So maybe if you could just address those two areas.

Sure, Neal.

I'll comment and then Frank may want to chime in as well.

Basically, as we look at the year and the capital expenditure program that we have laid out, there is a significant amount of flexibility that we've built in based on taking advantage of either pricing, opportunistically looking at where we are testing new things, where we can drive the greatest value.

There's not anything significant to take from that.

It's just a normal shifting around of the program to optimize the best economics at the current time.

Frank, do you want to share anything else with that?

Sure.

Neal, if you'll recall, we talked about in the Marcellus and the Utica we've combined that into one business unit and the driver there was not to make a massive business unit, but to allow a lot better rig sharing.

So when you look at the Marcellus and the Utica you need to look at it as a combined venture, as far as drilling and completion.

We are moving rigs back and forth between those, depending on what wells we need to drill and what wells we need to complete, and it really creates a lot of efficiency for us in a regional area.

In the Mid-Con, what we are looking at is we have two rigs running in the Oswego right now.

The cycle times are really impressive there; the wells are performing great.

The Wedge play, it is evolving, and as we get more and more data we will start to look at do we ramp up, how do we manage that program forward.

So where we are today on the slide, you will see in the deck is kind of a static position and as we get more data, we will make that call.

Very good.

Congrats, Doug.

Great turnaround.

Brian Singer, Goldman Sachs.

Thank you, good morning.

One of the areas you highlighted at the analyst meeting for focus was the Powder River Basin and I wanted to just see if you could give us an update there and the acceleration and how that translates into production and knowledge on the play.

Brian, this is Frank Patterson.

Since the time of the analyst meeting, we talked about putting a rig in play in November; we've done that.

As we started to review our opportunity set and the potential in the Powder, we made the election before the end of the year to move in a second rig that is just going to be basically Sussex-focused.

So where we are in the basin today is we are completing and actually drilling out our first Turner test now, so that will be online in the near future.

We've drilled a Parkman test on the same pad; it will be online in the near future.

We have gone in with the completion crew and begun completing ducts, so our production volumes are turning around now.

And then the Sussex rig, the second rig, was in the field and spud on the first Sussex pad the first week of February.

Great, thanks.

My follow-up is on natural gas prices.

Given the whipsaw that we've seen and the, at least for now, warm recent weather, I just wanted to get a sense as to how the natural gas price environment impacts your capital allocation and capital plans, if at all, for the year.

Brian, as Nick noted, the hedging position we have for the year is quite good at approximately 71% at $3.07 per MCF, so it doesn't material impact the program for 2017, the volatility that we are presently seeing.

Keep in mind though that the flexibility of the Company today is much improved and where we sit as we look forward to that capital deployment and the long-term pricing forecast, we can make adjustments in the program based on that volatility, if we deem it appropriate and in the best interest of our shareholders to do so.

So I think that if you see continuing weakening and pricing we will adjust our capital program and redirect it at other opportunities in the portfolio.

The great thing about the Company is the strength and resiliency of the portfolio.

We could shift rigs around and drive greater value from other areas if the pricing conditions dictate.

Thanks.

On a follow-up to that, what gas price would you have to believe in for 2018 to either increase or decrease activity in the Haynesville Shale relative to where you're at right now?

We haven't set an exact price.

As we've shared in the past, we have excellent breakeven economics in the Haynesville and they continue to get better with the improved capital efficiencies that we have recognized.

I think basically in the $2.50 to $3.50 range is where we anticipate gas to move with the seasonality.

If you saw it dip below $2.50 for an extended period of time, we would probably start making adjustments, but we are -- we haven't really said at a specific price we would move or adjust at.

The key is, as you know, we are focused on driving the greatest value where we can capture the greatest returns and we will make those changes immediately as we deem appropriate that we can drive value for another area.

Thank you very much.

Jacob Gomolinski, Morgan Stanley.

Good morning, guys.

Just had a question on the -- it looked like there was $205 million of cash spent on acquisitions in the quarter, which included capitalized interest of $56 million.

So just curious if you had any additional details on the $149 million of acquisitions in the fourth quarter.

Yes, so during the fourth quarter we exited our Devonian shale position and associated with that exit, we repurchased a VPP.

That ends up getting booked as an acquisition to repurchase the VPP; those assets then move off with the acquisition.

We had noted at the time that we said we were going to divest of the acquisition that it would be a nominal net amount of proceeds to the Company, and that's where it came out.

We had a nominal amount of proceeds that came in after repurchasing the VPP.

Okay, got it.

Then, I don't know if you had any color on the outlook for that -- for acquisitions in 2017.

No specific plans for acquisitions in 2017.

As I'm sure everyone is aware, there are a ton of opportunities out there to look at.

And we have a very active and well-functioning business development team that works with our business units to look at opportunities in areas where we think we have good operating synergies, we have good geologic knowledge, and we have an ability to add value to things that we would purchase.

That's always put through a lens of the purchase price and the opportunity relative to the set we have in front of us today, which is a significant drilling inventory at a high rate of return, as we have highlighted for everyone before.

So we are very active in looking at things that come across and we are pretty tough judges of what meets the bar that we would consider moving on and we will continue to do that.

If we move on something, know that it would be something that we really felt was impactful to our portfolio and we thought we could generate great returns on.

We have got so much in front of us today that that is a very high bar.

Got it.

Just a follow-up, if I may, in terms of the flipside of that question I guess.

You mentioned in the release additional asset divestitures and just wanted see if you might be able to provide any additional details around size and scale or perhaps which specific assets might qualify.

We've stayed away from giving any specific color for the calendar year 2017, other than to note that it's important to the Company to make progress towards our goal of debt reduction.

It's important to the Company to make progress towards rightsizing our oil and gas portfolio, and we will make progress on that this year.

Exactly how much, when, what assets, we're going to stay away from as it's market-dependent on so many fronts.

We're working a number of things today and you can expect that we will continue to progress that.

But in terms of a specific point of guidance, we are going to continue to just point to the multiyear goal of $2 billion to $3 billion of debt reduction.

Got it, thanks very much.

Biju Perincheril, Susquehanna.

Good morning.

Just a couple of quick questions on the Powder River Basin.

I was wondering; at the analyst day you highlighted one well, I think it was the Barton well, and I was wondering the well that you recently brought online, how similar the completions where to that Barton well.

Biju, this is Frank Patterson.

Two things.

One, the Barton well was a longer lateral -- it was the longest Niobrara lateral we had drilled and it was the largest completion.

We had several Niobrara ducts available to us and so when we went back into the field, the completions team took a look at the completion design on that Nio well that was the Barton, which is basically the best Nio well in the country from a cumulative basis.

The new wells have received the larger frac.

They are not extended lateral so they didn't perform quite as well as the Barton, but the initial well that we brought on is still making about 1,230 barrels of oil a day -- BOE a day.

60% of that is oil after almost 30 days online, so we are seeing a response that is very positive.

Now we're going to move; as we go into a new Nio program down the road, we will be putting longer laterals and larger fracs on those Nio wells and expect to have good success.

Then that recent well looks like it's sort of within your gas condensate window there.

Given that was 60%, 70% oil, does your view of what the gas condensate window is, does that change at all or --?

That well actually it's performing on a cut basis, as far as oil, pretty much as expected.

What it did do is it also validated the spacing assumptions that we are going with now.

With a little bit further spacing between wells gives you a lot higher sustained pressure and lot higher deliverability at the wellbore.

So everything we told to analyst day seems to be playing out pretty well.

We will have a lot more data as we move down the road.

The completions team and the drilling team are really focused on this and I think we're going to do a really good job and deliver what we said at analyst day.

Great, thank you.

That does conclude our question-and-answer session.

At this time, I would like to turn the call back over to you, Mr. Lawler, for any additional or concluding remarks.

Great, thank you.

We appreciate everyone joining us today.

2016 was a great year for Chesapeake and we look forward to building upon that.

What you can expect is continued improved performance across all aspects of our business.

We look forward to sharing that with you in the coming months and we appreciate again you joining us for the call.

Thank you.

Again, that does conclude today's conference.

Thank you for your participation.

You may now disconnect.