Chesapeake Energy Corp

NASDAQ:CHK

Earnings Call Transcript 2019-Q4

[Operator]

Good morning. Welcome to Chesapeake Energy Corp’s fourth quarter and year end 2019 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing star key followed by zero.

After today’s presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touchtone phone. To withdraw your question, please press star then two. Please note that this event is being recorded.

I would now like to turn the conference over to Brad Sylvester. Please go ahead.

[Brad Sylvester, Vice President, Investor Relations]

Thank you Kate. Good morning everyone, and thank you for joining our call today to discuss Chesapeake’s financial and operational results for the 2019 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 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.

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 can be found on our website and in our earnings release.

With me on the call today are Doug Lawler, Nick Dell’Osso, and Frank Patterson. Doug will review our operational and financial results for 2019, and then we will open up the teleconference for questions.

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

[Doug Lawler, President, Chief Executive Officer]

Thank you Brad, and good morning everyone. 2019 was a year of significant change and important progressive accomplishments for Chesapeake Energy. After selling a lower margin asset at the end of 2018, we transformed our asset portfolio through the acquisition of a high margin oil growth asset, where notably we achieved our goal of capturing $250 million in cost savings and revenue synergies in the first year. We continued to identify and deliver cost savings across our multi-basin diversified portfolio and we executed several transactions to reduce the total amount of debt outstanding as well as refinanced portions of our near term maturities.

The second half of the year was marked by rapidly falling commodity prices, particularly for natural gas, a trend which continues today, causing a much softer commodity price outlook in 2020. Despite the challenging macro pricing environment which has further deteriorated in recent weeks with the global reduction in economic activity, we have built on our progress from 2019 to deliver strong execution on our oil weighted capital program and approved cash flow generation relative to our expectations so far this year.

To date, in the face of challenging market conditions, we highlight a plan for 2020 that is built on capital discipline and cash flow maximization, reducing year-over-year capex by approximately 30%. We are targeting flat oil volumes, declining gas production, and a free cash flow to neutral business in 2020. We have $300 million in debt maturing in the second half of this year and we are confident in our ability to generate $300 million to $500 million of proceeds through non-core asset sales to fund these maturities and preserve the liquidity under our revolving credit facility.

Our $3 billion credit facility is supported by a very large proved reserve base, which you will see is valued at $9 billion in our 2019 SEC 10-K filing and valued at approximately $7 billion to $7.5 billion under current bank methodology. Further, while we have a stock price that has fallen to very low levels, we will commence actions to reverse split the number of shares with the filing of the proxy in a few weeks.

Given the quality of our assets, the competitive strength of our operating platform, capital efficiencies, and our track record of balance sheet improvements, we are confident in the stability and future of the company. With improvements to our margins and the changes we made to strengthen our balance sheet and liquidity in the fourth quarter, the previous going concern language will not be present in our 2019 SEC 10-K filing. We will continue to take the necessary steps to improve the financial position of the company and better align the balance sheet with our operating expertise.

With these improvements, we will restore Chesapeake’s ability to create shareholder value in the current market environment. We have stripped massive costs from our system and reduced over $12 billion in debt and liabilities since we began our transformation, all while building and maintaining a standard of operational excellence and execution that is paramount for long term value creation.

We fully demonstrated our operating capabilities through the successful integration and achievement of synergies in our oil weighted Wild Horse acquisition last year. We are confident in our multi-basin operating expertise and we are working towards consolidating additional assets into our portfolio to capture further value, synergies and efficiencies for our shareholders. We firmly believe the industry needs further reduction in development costs and corporate overhead, and we have a proven track record in these areas.

At the onset of 2019, we said we would increase our competitiveness by growing oil production, oil mix, and improving our cost structure, and that is exactly what we did. Despite average NYMEX realized prices before hedges that were 12% lower for oil, 18% lower for gas, and 41% lower for NGLs, we were able to increase our adjusted EBITDAX margin per equivalent barrel by 14%. During the year, we increased our total oil production by 30%, primarily driven by the Wild Horse acquisition, resulting in a massive shift in the composition of our oil and gas revenues from 42% being derived from oil in 2018 to 56% in 2019. We also reduced $336 million in combined GP&T and G&A expenses.

In the fourth quarter, we reported adjusted EBITDAX of $665 million, a 19% increase compared to a year ago, and again in the face of commodity prices that were significantly lower than last year, especially for gas and NGLs. We averaged 126,000 barrels of oil per day, moving our overall oil production mix to 26% of total production, the highest level in company history. Meanwhile, GP&T, G&A and interest expenses were all lower compared to the 2018 fourth quarter. It is on this strong fourth quarter that we have built a foundation to achieve free cash flow neutrality in 2020.

Moving to our operations, the primary driver of our impressive oil growth was the successful integration of Brazos Valley into our portfolio. In February of last year when commodity prices were higher, we believed the asset could be free cash flow positive by year end. While we ultimately realized significantly lower prices during 2019, the asset still achieved positive free cash flow for the first time in the 2019 fourth quarter and, more importantly, is currently projected to generate almost $100 million in free cash flow in 2020, and that’s using last week’s strip prices.

Despite running one less rig in 2019 in Brazos Valley, we placed 81 wells on production and grew oil production 6% year-over-year. This performance was driven by a 40% improvement in Lower Eagle Ford peak rates with 2019 wells averaging approximately 900 barrels of oil per day. Overall, we were able to recognize approximately $250 million in savings and revenue improvements in the 11 months Chesapeake owned the asset. Average completed gross well costs for Lower Eagle Ford wells in 2019 were approximately $909 per lateral foot, a 14% improvement compared to 2018, and we expect 2020 wells costs to decline over 10% further per lateral foot.

Overall, while we intend to focus the vast majority of our 2020 capital on our highest margin opportunities, the breadth and depth of the strong portfolio affords us the flexibility to react to the ever changing market conditions while saying within our proposed $1.3 billion to $1.6 billion capital program. We believe this level of capital optimizes the quality investments we are making in this difficult commodity price environment with the need for capital discipline, debt reduction and cash flow generation.

We are committed to further reducing all cash costs with a specific focus on reducing our production and G&A expenses in 2020. For the year, we are projecting a reduction of over 10% in both LOE and G&A for a total cost reduction of more than $100 million compared to 2019, and accordingly we have moved our 2020 LOE and G&A guidance lower to reflect these projected cost savings. We expect to achieve production expense savings through more efficient workovers, water hauling optimization, treating program adjustments, and greater supply chain synergies across all business units. The G&A savings will be achieved primarily through overhead expense reductions.

On Monday, we reduced our GP&T commitments with buyouts of certain contracts for total consideration comprised of $54 million in cash and $16 million in line fill inventory. These buyouts will remove approximately $169 million of costs associated with future commitments related to these GP&T agreements and will further improve our marketing margin starting in the 2020 first quarter.

Moving to the balance sheet, reducing leverage remains a top priority for the company. In the fourth quarter, we eliminated approximately $900 million in principal debt through exchanges and revised covenants in our credit facility, providing greater flexibility and preserving our liquidity. We also retired the Brazos Valley secured revolving credit facility and debt structure and replaced virtually all of the unrestricted subsidiary debt with a term loan.

Today, we have liquidity of approximately $1.4 billion, which is ample to retire 2020 and 2021 maturities. We continue to aggressively pursue all avenues to further improve our liquidity, including advanced conversations around asset dispositions, capital market transactions, and further cost discipline.

As we manage the commodities price, market volatility, and diligently focus on optimizing cash flow, we have a significant portion of our projected 2020 production volumes hedged. Approximately 76% of our oil is hedged at $59.90 per barrel. Additionally, more than 50% of our gas production is protected with roughly 39% hedged volumes through swaps at $2.76 per Mcf and 24% of April to October forecasted production under put spreads with a floor of $2.06 per Mcf.

To close, we are committed to reaching free cash flow in 2020. To get there, we are reducing our capital program to a range of $1.3 billion to $1.6 billion. We plan to make meaningful reductions to certain cash costs without sacrificing our higher margin oil volumes, which we intend to keep relatively flat year-over-year. We expect third quarter oil production will dip slightly due to anticipated maintenance in South Texas; however, we project an uplift to finish the year essentially flat with our 2019 fourth quarter volumes. While our portfolio strength affords us the flexibility to respond to market conditions, we anticipate that our gas production will decline year-over-year with reduced capital investment and as prices dictate. Finally, we expect to achieve meaningful deleveraging from future A&D transactions and look forward to being able to provide more about our progress soon.

With that, we will now turn the call over for a few questions.

[Operator]

[Operator instructions]

Our first question comes from Neal Dingmann from SunTrust. Go ahead.

[Neal Dingmann, SunTrust]

First question centers on your activity, and really what you’re saying, I think it’s about the capital discipline. You were previously pressing activity even in the more, I would call it the liquids area, such as Brazos and PRB, and it looks like pulling back a rig or so in each of those. Really, is this just purely on capital discipline or is there anything we should be reading into just on returns in these plays?

[Doug Lawler, President, Chief Executive Officer]

Good morning, Neal, thanks for the question. The best way to look at it is just as I described, in that we have quality investment opportunities across the portfolio and we are adjusting that capital based on the amount of cash flow generation that we have, maintaining our production volumes as we look forward through 2020 and 2021, so I think it’s a good capital level and I think it reflects the confidence in all the assets that we have. As we’ve shared before, each of our assets is begging for additional funding should we have additional capital there were available, but the cost discipline is coming in with achieving that free cash flow position for the year.

[Neal Dingmann, SunTrust]

Great details. My second question, you mentioned a couple hundred, $200 million to $300 million of potential non-core assets. Are those things that are already in the works or just based on your large portfolio, you just see the potential for this for the year? Thank you.

[Doug Lawler, President, Chief Executive Officer]

Sure. As you are aware, Chesapeake has a very large portfolio. We still have a very significant land position. We have significant portions of assets that are presently not attracting capital funding, and as we think about the opportunities to meet the near-term maturities, we have a very large portfolio of things that we are presently working on and will continue to look at for divestiture this year.

[Neal Dingmann, SunTrust]

Very good, thank you.

[Operator]

Our next question is from David Heikkinen from Heikkinen Energy Advisors. Go ahead.

[David Heikkinen, Heikkinen Energy Advisors]

Thanks for taking the question. Looking at the Marcellus activity without the hedge book, can you just talk through what your current margins and free cash expectations are for the Marcellus this year?

[Doug Lawler, President, Chief Executive Officer]

Yes Dave, we see the Marcellus still as just a phenomenal asset even in the current pricing environment. We expect, as in the presentation you’ll see, to generate really strong production there with a minimal amount of capital, an asset that generates really strong cash flow for us, so the limited amount of capital that we’re spending there we believe to be extremely attractive and still rates as some of the best returns in the portfolio.

[David Heikkinen, Heikkinen Energy Advisors]

What’s your free cash expectation?

[Nick Dell’Osso]

Dave, it’s Nick. I would just add that we don’t look at our capital allocation inclusive of hedges. Hedges are a financial instrument that are separate and they help our corporate results, but we allocate capital based on pre-hedging returns. It’s an unpopular answer, but the reality is the Marcellus generates fantastic returns even at today’s strip. We test it and re-test it, and we look back on our results from last year, and they hold up last year, the year before and the year before that. It is a phenomenal asset and the cash flow that this generates is absolutely justified in our capital allocation.

[Frank Patterson]

David, this is Frank Patterson. I’d point you back to, I think, one or two quarters ago when we put out some kind of guidance on the margins associated or the breakeven price associated with the gas in the Marcellus. I think $150 to $175 is kind of where the wells break out on the Lower Marcellus.

The other thing I would point there is to drive additional efficiency in our system, we’ve been running that field at about 900 pounds of back pressure on the system, so we’re in the middle of dropping our line pressure down using some very cost effective compression, and we’re going to start bringing line pressure to more what the offset operators are producing against, so we’re going to see some really good production volume associated with that at a very, very low capital cost.

[David Heikkinen, Heikkinen Energy Advisors]

Versus the 320 of free cash flow last year, I know I’m harping on this, what do you expect 2020 free cash flow to be? I’m just trying to dial in what that asset’s free cash yield and capacity is.

[Nick Dell’Osso]

Yes, in the Marcellus specifically, I think it will be just a little below that, Dave. I don’t think we’re going to guide to a specific cash flow number for an asset, but it won’t be dramatically different than that number, maybe just a little lower.

[David Heikkinen, Heikkinen Energy Advisors]

Okay, thanks. Then annual free cash flow neutrality, you get free cash neutrality early in the year and then dip down, but through the full year you expect to be neutral as well, is the target?

[Nick Dell’Osso]

That’s correct.

[David Heikkinen, Heikkinen Energy Advisors]

Perfect, thank you.

[Operator]

Our next question is from Arun Jayaram from JP Morgan. Go ahead.

[Arun Jayaram, JP Morgan]

That was close. This is Arun Jayaram, JPM. Nick, I was wondering if you could help preview your thoughts as we enter the spring redetermination season. I think you mentioned or Doug mentioned $1.4 billion in liquidity. I know you’ve probably already started the discussion with the banks, but I was wondering if you could give us some thoughts on potential changes to your liquidity position post the spring redetermination period.

[Nick Dell’Osso]

Sure Arun, thanks for the question. We highlighted in Doug’s notes the value of the collateral that we have available to us under the credit facility today, which is pretty significant relative to the $3 billion borrowing base. It’s $9 billion in our 10-K under SEC rules, and then when you look at it under the bank methodology, which is relatively similar but they’re going to use a lower price deck and they’re going to adjust the way they think about the assets a little bit, there’s some risking on the puds and things, you still end up with a collateral value that’s north of $7 billion.

When we think about what that means from expectations on a borrowing base, we really don’t expect to have any changes whatsoever. The pressure that we have with our bank group is around the multiple of debt to EBITDA. The amount of collateral that’s there is vastly in excess of any traditional metric of what a multiple of the borrowing base should be. I think historically banks have liked to see a borrowing--a pre-reserve or collateral base of 1.5 times the borrowing base. We’re well in advance of that, and in fact we are well in advance of that just on proved developed alone. Proved developed under bank methodology we would estimate to be around $5.5 billion, and this is all using recent bank pricing, so this is all current stuff.

Anything can change, of course, as you approach the next couple of months here leading into borrowing base season, but we feel really good about where we stand from a collateral base standpoint. We have good and open ongoing dialog with our bank group and some in the industry are really thinking hard about how they want to bank the industry going forward, but we do have a facility that doesn’t mature until 2023, and under that facility we’re in pretty good shape. They have great coverage against our loan. They would like to see the debt to EBITDA improve, and so would we, and we talk to them regularly about all of our efforts to do that.

[Arun Jayaram, JP Morgan]

Thanks for that color. A follow-up, maybe for Frank. It looks like in 2020 in terms of your oilier assets, you’re leaning harder on the Eagle Ford and Brazos Valley. We were a bit surprised to see the magnitude of the declines in the Powder River Basin. Frank, I was wondering if you could comment a little bit about your delineation, appraisal efforts in the Powder River, and maybe talk through why you’re cutting activity here more than in the Eagle Ford versus Brazos Valley.

[Frank Patterson]

Sure Arun. In the Powder River, we actually saw a good fourth quarter in the Powder River We talked to you in the third quarter about some wells that were underperforming substantially to our expectations up on the north end of the field. We had to overcome those wells in the fourth quarter and we had a really good fourth quarter outcome associated with that. As we have gone in and kind of dissected what’s going on in the entire basin, not just our acreage but offset operators as well, you’re probably aware that a lot of the operators ran out and talked about four wells per section for the Turner. We said no to three, so we never got to that four well per section point, which I think was a good move on our part.

As we look at it today, what it looks like is that there is actually two zones in our acreage. There is the Turner and then the Frontier underneath that zone. We thought they would act as one. They don’t appear to be acting as one, and so what it looks like is the Turner should be on two wells per section, maybe even in a fractured area one well per section, so we’re having to re-think our development plan on the Turner. They’re still good wells, but you just can’t drill them as close to each other as what people had thought.

If I were listening to this conversation, I would say within your location count it’s going to go down in the Turner, and that’s correct - our location count will go down, but we’ll add back some Frontier on a wine racking system to offset that. Then the thing we really want to get to and we’ve started now is Niobrara, and Niobrara, the wells that we’ve put on in the last quarter are beating the basin type curve pretty dramatically, so we won’t don’t want to rush the Niobrara because it is relatively--we need to understand the spacing there. It’s probably going to be more like three wells per section, maybe two in some real fractured instances.

We’re working through a redevelopment plan there and pretty pleased with where we are on costs, pretty pleased on where we are on operations. It’s just we have to cut back in some assets, and that asset has the best potential to cut back because we hold big acreage on units.

[Arun Jayaram, JP Morgan]

Great, thanks a lot, Frank.

[Operator]

Our next question is from Doug Leggate from Bank of America. Go ahead.

[John Abbott, Bank of America]

Good morning, this is John Abbott. Hello?

[Doug Lawler, President, Chief Executive Officer]

Morning John, we’ve got you.

[John Abbott, Bank of America]

Yes, it appears that Doug is on the other line here. This is John Abbott for Doug Leggate. Just several questions for us. First, what are your thoughts on maintaining free cash flow heading on into 2021?

[Doug Lawler, President, Chief Executive Officer]

Well as we’ve stated, that is a goal of the company and a priority for us, and we have the portfolio and the asset capital investment flexibility to adjust. I think that in 2021 and beyond, it requires what does the pricing environment look like, John. I mean, it’s going to be largely dictated activity levels and capital based on pricing, but we are pleased with the portfolio, we are pleased with the transactions we expect to execute upon this year, and confident in the cash flow generating profile that we’re getting from our assets. It’s not a one-year goal. It’s never been intended to be a one-year goal, so our projection at this point in time would be to continue to build upon a free cash flow neutral or positive business from this point forward.

[John Abbott, Bank of America]

Then the second question for us is what are your thoughts about paying the preferred dividend going forward, just given commodity volatility?

[Nick Dell’Osso]

Hey John, good question. It’s something we look at all the time, and we are very protective of our cash flow and will remain very protective of our cash flow, so I think all I would tell you at this point is that we look very, very closely at that analysis each time.

[John Abbott, Bank of America]

All right, thank you very much.

[Operator]

Our next question is from Charles Meade from Johnson Rice. Go ahead.

[Charles Meade, Johnson Rice]

Good morning, Doug, to you and your whole team there. In your prepared comments, I felt like you heard you allude at least twice to the industry M&A environment, and I think one comment was about the need for more consolidation. Can you elaborate on what you see, either as the opportunity set or what needs to happen in the industry, and what role you see Chesapeake playing in that?

[Doug Lawler, President, Chief Executive Officer]

Sure Charles, and it’s a great question. I think we all agree and know that there is continued opportunities for companies with top quartile operating expertise to further consolidate and to capture further cost savings, whether it be in a capital program with just experience and expertise or further supply chain synergies that can be accomplished. But there’s also a significant need to further reduce the overall corporate overhead and we believe, as we have proven with the Wild Horse acquisition, that we have that strength and capability to execute and to conduct our operations in a way to capture further value for our shareholders.

As we look at the portfolio, we know there are several things that we can execute upon to meet our near-term maturities and further improve our balance sheet and reduce debt, but we’re also mindful of what is the strength of this company and that’s the operating platform that we have, and we’ll continue to use all these levers and all these weapons that we have available, and we believe the market requires it and we intend to be a part of it.

[Charles Meade, Johnson Rice]

Got it. Thanks for that elaboration, Doug. That’s it for me.

[Doug Lawler, President, Chief Executive Officer]

Thanks Charles.

[Operator]

Our next question is from Kashy Harrison from Simmons Energy. Go ahead.

[Kashy Harrison, Simmons Energy]

Good morning all, and thank you for taking my questions. Doug, in the prepared remarks, please correct me if I’m wrong, it sounded like you said oil production volumes declined through Q3 and then grew into Q4 to keep the Q4 rate flat year-on-year. One, wanted to get confirmation of that; and then two, should we think about the maintenance capital to hold 2020 oil volumes flat into 2021 as pretty much what you’re spending this year in the oil-levered regions? Is that how to think about maintenance capex to hold oil flat?

[Doug Lawler, President, Chief Executive Officer]

Yes, it is. The answer to that second question, Kashy, the maintenance capex is approximately what we will be investing this year and to maintain those relatively flat oil volumes going forward. To your first question on the quarterly production, we know there will be some maintenance work in the South Texas area in the third quarter. We also--the timing of our till results in a little bit of a dip, not significant - I mean, we’re talking about a couple percent or so in the third quarter.

When you look at the profile of the oil production over the year, it’s relatively flat, but we just called it out to note that there is a little bit of a dip in the third quarter and we’ll be working to minimize any of that maintenance and also be working our till timing to keep all those volumes flat. But there isn’t anything concerning regarding the production profile or the amount of capital that we’ll be investing there.

[Kashy Harrison, Simmons Energy]

Got it, that’s helpful on both fronts. As my follow-up, Doug, you also talked about the softening economic environment. You’re also really well hedged for 2020, so it was just trying to understand what’s that breakeven point for you where you say, we need to pull back, we need to reduce activity in 2020. Is it 45, 42?

I think you touched on this a little bit earlier, but in 2021 should we just think about the overarching goal regardless of wherever the strip is as free cash flow neutrality?

[Doug Lawler, President, Chief Executive Officer]

Absolutely, that’s exactly the way we want you to think about it, Kashy. Then in addition to that, our focus on further reducing debt is top priority of the company. When we look forward, we’re very comfortable with our hedge position in 2020 and as we look at all the levers we have available, looking forward to 2021. Obviously the pricing environment will play a heavy role in those future capital programs, but the key to note with the company is I think it’s often that this is not a single basin company. We have multiple levers that we can pull. We can execute upon diversity in geography, diversity in product, and excellent outstanding operations in each of the areas that we operate, so we’ll continue to build and improve on that strength and look to gain further momentum as we go into 2021, regardless of what the pricing environment looks like.

[Kashy Harrison, Simmons Energy]

Got it, and the pricing threshold for 2020 would be somewhere in the 40s? Is that the right way to think about it?

[Doug Lawler, President, Chief Executive Officer]

You know, I want to make sure that it’s very, very clear that the capital allocation is not based on, well, we’re at 50 so we’ll maintain our capital program. We constantly are evaluating and thinking about the profile, the capital investment level and what we’re returning, so it’s an ongoing process even with the hedge pricing that we have secured for the year.

Definitely as we think about a sub-$50 oil price and a sub-$2 gas price, we are rigorously evaluating the capital program, and I think the best way to answer that question is that anything less than $50, and really in even better prices we continue to evaluate and make sure that that’s a prudent investment as we look for what we’re trying to deliver in 2020 and also in those later years. So it isn’t so much a price as much as an operating philosophy and capital discipline, that we will continue to evaluate that capital spend, and obviously as prices decline we’ll be even more prudent and quick to pull back if it deteriorates below $50.

[Kashy Harrison, Simmons Energy]

Got it. Thanks for all the color, really appreciate it.

[Doug Lawler, President, Chief Executive Officer]

Okay, I thank everyone for joining us today. Sorry Operator, just a few closing remarks.

I just want to reiterate as we look toward the year ahead that I’m confident and can assure you that achieving free cash flow is not just a goal but a mandate for Chesapeake. Our employees are focused and addressing all parts of our profitability with great energy and focus, and I’m very pleased with that energy and the direction that we’re heading, given all the circumstances that the industry is under and some of the internal challenges.

Our oil production will remain strong in 2020 and we’ll continue reducing our cash costs and continue to improve upon our capital efficiencies. We are absolutely determined and focused on strengthening our balance sheet and we intend to move quickly, as quickly as possible using future A&D and capital markets transactions to expedite and improve the balance sheet.

This concludes the call for us today and I encourage you to follow up with us if you have additional questions.

[Operator]

The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.