Good morning, and welcome to the Chesapeake Energy Third Quarter Earnings Conference Call. All participants will be in listen only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Brad Silvester.
Please go ahead.
Good morning and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2019 Q3. 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 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 the earnings release. With me on the call this morning are Doug Lawlor, Nick Dell'Osso and Frank Patterson. Doug will review our operational and financial results, and then we will open up the teleconference up for Q and A. So with that, thank you.
And I'll now turn the teleconference over to Doug.
Thank you, Brad, and good morning, everyone. I'm pleased to share with you today Chesapeake Energy's 3rd quarter performance highlights and to affirm our full year 2019 guidance range for production and capital expenditures as well as share Despite significant commodity price volatility, Chesapeake continues to deliver higher margins and balance sheet improvement, while positioning for sustainable free cash flow generation. In the Q3, we achieved several notable milestones highlighted by record production in the Brazos Valley asset, continued capital efficiency improvements as demonstrated by shorter cycle times, greater productivity and lower CapEx. Cash cost reductions were recognized on an absolute basis across G and A, LOE and GP and T as compared to the Q2. As you will recall, we raised our full year production oil production guidance in the Q2.
And despite a few operational and timing challenges in the 3rd quarter, we remain confident in delivering production and capital expenditures within our full year guidance range due to the balance and strength of our portfolio. Turning to our assets, our progress continues in Brazos Valley, which set a new monthly production record in October of approximately 55,000 barrels of oil equivalent per day, including more than 40,000 barrels of oil per day, despite running 1 less rig than the 2018 program. Our capital efficiency improvements continue to deliver impressive results. The team has turned 13 wells to sales this year with a peak rate above 1,000 barrels of oil per day, while averaging 8.24 barrels of oil per day peak rates in the 3rd quarter. We have also reduced cost per lateral foot by approximately 21% since our acquisition.
Additionally, we have made significant improvement to the fields base decline through our well optimization and workover program. Importantly, as our subsurface understanding evolve, the commercial black oil window of the field continues to expand, further growing our deep inventory of high margin future oil locations. The development program in our legacy South Texas asset continues to deliver as we turned in line the majority of our new drill completions in the latter part of Q3. As a result, our production in the basin has steadily grown since the beginning of Q4, averaging approximately 58,000 barrels of oil per day in October. Further cycle times continued to improve and importantly, even after drilling roughly 3,000 wells in the field, we recognized an 8% improvement in cycle time this quarter.
Additionally, our drilling team set a single well field footage record of 6,800 feet in one day during October. In the Powder River Basin, the company continues to eliminate operating costs in the Turner development program. Year to date, we have reduced cycle times by 25% year over year and recognized per well savings of approximately 10% or $800,000 Our efficiency enhancements have resulted in a recent Turner pad being drilled and completed for approximately $6,000,000 per well. The last 25 wells turned to sales in the Turner have averaged approximately $7,200,000 per well. While we continue to improve our capital and operational efficiency in the Powder, production volumes were below our expectations in the Q3 due to a group of isolated wells located in the northern edge of our Turner acreage, which encountered lesser reservoir quality resulting in lower than expected performance compared to other Chesapeake wells.
Additionally, field production was adversely affected by 3rd party electrical outages that have interrupted our midstream takeaway. We are actively working with our 3rd party utility and midstream partners to mitigate recent power constraints. As we have discussed at length, we remain excited about the stack pay potential of the Powder River Basin. We recently placed on production our first Niobrara well since 2014, achieving record results. With a longer lateral and a modern completion design, the well has quickly become the best performing Niobrara well in the basin, reaching a 24 hour peak rate of 1600 barrels of oil per day, while producing more than 106,000 barrels of oil in its initial 87 days.
We anticipate turning 4 additional Niobrara wells to sales in the Q4 and expect approximately 25% of our 2020 Powder River Basin capital program will be directed towards the Niobrara formation. In the Marcellus Shale, capital efficiency gains continue to result in prolific well performance, highlighted by 9 recent wells reaching peak 24 hour flow rates between 60,000,000 to 85,000,000 cubic feet of gas per day. The quality of our Marcellus acreage and operational efficiencies positions Chesapeake to continue our strategy of maintaining relatively flat operated production to capture the value from seasonal basin congestion and pricing with minimal investment required. We continue to improve our cash cost structure across the company In addition to quarter over quarter reductions in all cash costs categories, we also made meaningful progress in reducing our GP and T and G and A expenses by a total of $109,000,000 compared to the Q3 of 2018. We also restructured several gathering and transportation agreements during the quarter.
The progress we made this quarter in improving our future midstream and downstream commitments is significant. First, we were able to restructure our gas gathering and treating agreements in South Texas from a cost of service to a fixed fee structure. 2nd, we negotiated a new Brazos Valley Crude Transportation Agreement via pipeline, which provides access to premium Gulf Coast markets. And finally, we are currently in the RFP process to award additional Brazos Valley wellhead crude gathering business. On the balance sheet, we reduced approximately $733,000,000 of face value of debt and preferred shares in exchange for approximately 319,000,000 common shares, resulting in total debt decreasing to approximately $9,700,000,000 compared to $10,200,000,000 at June 30.
We believe these transactions along with our planned reduction in capital expenditures next year and other efficiency measures will reduce our debt levels and improve the ratios under our revolver. Additionally, we reaffirm the borrowing base for our Chesapeake credit facility with no change. In the Brazos Valley facility redetermination will happen later this year. We continue to evaluate multiple opportunities that can further improve our balance sheet including divestitures, deleveraging acquisitions and capital funding options. Finally, we have a significant portion of our 2020 production volumes hedged with approximately 265,000,000,000 cubic feet of gas and 17,000,000 barrels of oil hedged at $2.76 per Mcf and $59.28 per barrel of oil.
We have a proven track record of capital efficiency and cash cost leadership across our business and we look forward to further improvements in the year ahead. Due to lower commodity prices, we have updated our 2020 forecast to reflect an approximate 30% reduction in our drilling and completion activity. While we will provide full detailed guidance at a later date, we currently anticipate delivering flat oil production while utilizing 10 rigs to 13 rigs and project between $1,300,000,000 to 1,600,000,000 dollars in total capital expenditures. We will continue directing the majority of our capital to our highest margin oil assets and our capital spend will be ultimately be determined by commodity prices in 2020. Additionally, we expect to reduce our production and G and A related expenses by approximately 10%, continuing our track record of cash cost leadership.
We believe this capital program, along with our strong projected finish to 2019 and continued capital efficiency improvements will position us to target free cash flow in 2020. We remain confident in our strategy, asset portfolio and our talented employees and we'll continue to utilize all of our sustainable free cash flow and further delevering our balance sheet to achieve a net debt to EBITDA ratio of 2 times. The volatile commodity price environment has pressured the speed and timing of accomplishing these goals, but we will continue to make incremental progress and improve our competitiveness and profitability. I'd now like to turn the call over for a few questions.
Our first question comes from Devin McDermott with Morgan Stanley.
Good morning.
Good morning, Devin.
My first question is on the indicative directional 2020 guidance. I was just wondering if you could help us bridge in a bit more detail some of the year over year reductions in spending. So what are the key drivers of that reduction? Where are you cutting back activity? And then as we think about how that spending might flex in that $1,300,000,000 to $1,600,000,000 range, where are some of those flex items there to the extent you can provide detail?
Yes, sure. Thank you, Devin, for the question. We actually because of the quality of the portfolio and the strength of the assets see a reduction taking place in activity across most of the assets. While we are not have not finalized exactly where the rig count will be next year, what we do know is that $1,300,000,000 to 1,600,000,000 dollars will be directed across the higher margin oil assets. So you'll see 2 to 3 rigs in the Powder, 2 to 3 in South Texas, 2 to 3 in Brazos Valley and 2 to 3 in the Marcellus asset.
That will vary based on pricing and we have that flexibility in our program that we can make those adjustments. But due to the quality of the assets and the high grading of where we direct the capital, we expect to see reductions across each of the assets and that competitive capital tension that has proven to be so helpful to us in the past.
Got it. That makes sense. And then my second, it's similar, but on the operating costs and G and A side, you're pointing to a 10% reduction in overall costs next year. Similar and what's driving some of those reductions? I guess how much is coming from some of the transport restructuring that you just announced versus cost reductions elsewhere?
And what's the timeline for that 10% being realized full year average over average? Are we going to enter the year at a run rate that's 10% lower? How should we think about the cadence?
I think the best way to look at that is we continue as I was trying to highlight there in my comments to make quarter over quarter improvements. So I think you can expect to see that continue across the year. Specific targets for LOE, excuse me, and G and A as we attack all parts of the cost structure in G and A and LOE. We see continued efficiencies in synergies either through technology or through more efficient ways to do our business. We really project that to be across the year and more reduction on an absolute basis compared to 2019.
The way I look at that is that historically the company has continued to make improvements in those areas to find better ways to do things, to find better and more efficient ways to operate. And that continued reduction is really just a reflection of the operating philosophy that we've had over the past several years.
Got it. Makes sense. Thank you very much.
Thanks, Tim.
Our next question comes from Subash Chandra with Guggenheim.
Yes. Hi, Doug. It seems like you've achieved what a lot of E and Ps would like to do, which is shed legacy GP and T costs. Just curious if you give us magnitude of this reduction? And I think the Eagle Ford, if I recall correctly, was your most expensive GP and T contract in the past.
So any more color there?
Yes. Hey, Subash, it's Nick. So what we did in the Eagle Ford is we went from the cost of service contract structure to a fixed fee structure. The primary benefit of doing this is the clarity it gives us on our development program going forward. Year over year, we won't actually see an immediate decrease in the rate paid.
And what we get again is the clarity in the development program going forward and a better long term rate of return as we think about the embedded cost of that cost of service over time. So it's a big win for us to have that clarity, to understand the long term economics of the field and not have the uncertainty of the cost of service contract. And then when you marry that with what we were able to do on the long haul takeaway side where we took out transportation, gosh, almost 10 years ago for much higher delivery of oil volumes. We have great access to the Gulf Coast markets. We were able to work with our midstream partners to get access to the Gulf Coast markets now for our new Brazos Valley asset and better utilize that transportation that we pay for out of South Texas across the board.
We think there's a lot of potential for future economic benefit here. The immediate impact is greater clarity.
Got you. Thanks, Nick. And a follow-up, any sort of the nontraditional assets in the portfolio that you can monetize, whether it be water assets or royalty assets?
Yes. Subash, we have a number of opportunities like that, whether it be nontraditional assets in our portfolio, whether it be opportunities for non core areas across the acreage, across the country, or as we look to evaluate and in the current market opportunities to divest of a larger asset. So I think that that's a space to continue to watch. We are seeing interest in different things, some of the nontraditional, some of the non core and we'll continue to focus on that as a primary and principal way of further delevering.
Got it. And if I could ask one final one, please. Any way to hazard a guess on what the oil ratio might be in 2020 for total volumes?
Sure. As we forecasted because of the reduced capital spend on the gas side next year and maintaining the oil production, it will likely maintain that 25% to 30% on the ratio as we exit 2020.
Great. Thank you.
Yes. Thanks, Subash.
Our next question comes from Arun Jayaram with JPMorgan.
Yes, good morning. Nick, I wanted to start with you. There's some language in the 10 Q around the leverage ratio covenant and the credit facilities. Wondering if you could comment on your revised thoughts on 2020 and your confidence of staying in compliant with that covenant.
Sure. Absolutely, Arun. So I think most of you may be familiar with the way this disclosure comes about. And it's based on our projections over the next 12 months and the ability to keep up with the covenants in the credit facility. I'll remind you that in our credit facility, we have a decrease in covenant around debt to EBITDA throughout 2020.
So it's a reflection as much of the covenant structure that was put in place over a year ago at much higher prices than it is our underlying business and how we are progressing with our debt reduction. As you're aware and as we've talked about at length, we've been keenly focused on absolute debt reduction and we've made great strides. We expect to continue to make strides using all the same levers that we have, cost discipline in all aspects of our business, asset sales, hedging prices as they rise, capital markets transactions and of course, working very closely with our bank group, which we do on a regular basis. We could go out and seek a waiver at any time from our bank group, but at the moment, we're continuing to be focused on the strategic levers that result in permanent debt reduction.
Got it. Got it. And shifting gears a little bit, I wanted to see if you could talk about maybe some implications to the gas macro from your initial outlook comments on 2020. What would that imply if your oil production stays relatively flat for natural gas volumes next year?
Well, as you'd expect, if we're not investing a significant amount of capital, you'll see our gas production decline. In the Marcellus, we anticipate to be relatively flat, Arun, for the year, running 2 to 3 rigs up there. And the capital efficiency and the quality of the asset, the rock that we have in the Marcellus is just outstanding. You made a comment about the greater macro environment and I think that that's an interesting comment because when you see a company like Chesapeake with the strength and quality of our gas portfolio reducing capital, I think it should be a good indication of directionally where others should be reducing activity as well. We have that gas lever available to us in our portfolio.
At present, we don't want to invest there because of the higher margin, greater returns we can get from our oil assets. And I think that from a macro level, you'll see others reduce or pull back spending because if a company like Chesapeake is investing with the quality of our inventory, it ought to be an indicator that others shouldn't be either.
Great. Thanks a lot, Doug.
Thank you.
Our next question comes from Brian Singer with Goldman Sachs.
Thank you. Good morning.
Hey, Brian.
With the slower growth path in 20 20 to get to the flat oil production year on year, can you just talk about how you see trajectory for oil, particularly at the end of the year? And then how you see the implications on 2021? And if you could just touch on the impact on decline rate at the end of next year as well as a result of the slower path that would be helpful?
Hey, Brian, this is Brent Patterson. It's a good question. We're still working the 2020 plan as far as exactly where we're going to put all the capital to drive the best performance. As you probably have figured out, we're going to enter the year at a relatively high rate and we'll go into somewhat of a decline. The 2021 program has not been fleshed out at all.
I think we have an opportunity to move capital around and drive a better 2021 outcome than people might be guessing. But definitely, we're going to see some decline from the beginning of the year towards the end of the year. We'll work very, very hard for 2021 to create an inflection moving up into 2021 to keep that relatively flat. If the price of oil stays where it is, I think you probably need to be thinking kind of flattish in 2021. And that would be something that we would strive for.
I might just add on that, Brian, that pardon me just for a second there that really the culmination of all the work that's taking place in Chesapeake, the capital efficiency improvements, the cash cost structure that we recognized over the past several years is what positions us in this volatile period to be able to reduce the capital and maintain that relatively flat oil production. So we are ever mindful of what those impacts are to future cash flows with the reduced capital program. But because of that capital efficiency, the quality of our assets, the allocation of capital across the portfolio, we have confidence in a reduced program to the tune of 30% that doesn't compromise those later years. Now indeed, if you're not investing with the given decline rate and nature of the shale production profile, you're going to see a need to fight that decline. But that's really what we're trying to communicate is that the capital efficiency and at that spin level will be roughly in that flat type of range as Frank highlighted.
And what oil price are you now assuming versus with the second quarter as an example when you were talking more preliminarily about next year?
We've actually we're assuming current market prices actually. It's what we've been modeling is something a little less than current strips. So I think we're in pretty good shape as we forecast how that's going to turn out in the year. Great.
And then my follow-up is on the Powder River Basin. Can you talk to why GP and T costs have fallen in the area and any implications for further reduction into 2020? And then you highlighted some of the negative results and it seems like you think that is a one off. Can you just add some color on whether this represents an inventory reduction or just an attempt to push out the limits of the field?
Brian, it's Nick. I'll answer the GP and T. So a couple of things happening there. 1, just the sheer increase in volumes in the field drives some economies of scale, which are attractive. The second is that earlier this year, we moved from trucking our oil from the wellhead a sales point to an oil gathering system at a very attractive rate.
So that's starting to show up. We expect to see some continued reductions as economies of scale drive more efficiencies on the gas side. There's going to be a step down at some point in the future. We had a restructuring of the gas gathering agreement here at the end of 2016. And there's an opportunity for us once we achieve certain volumes to have a step down in rate.
That will happen at some point in the relatively near future. So I would expect the GP and T in the powder to continue to decline.
Hey, Ryan,
this is Frank. So we're calling out some wells in the Turner on the very north end of our field, kind of at the furthest northern extent of our acreage position. Those wells are underperforming our expectations. We put a slide in the deck to kind of give you some color on that. If you look at those wells, they kind of perform at the basin average, but not to our expectations.
What we think we saw out there was probably some lower reservoir quality. It's also in an area where there's quite a bit of congestion and offset operator drilled 4 wells per section, which is something that we don't think is the right answer. We actually had an opportunity to join those wells and sold out. We drilled and we spaced off and drilled those wells at 2 to 3 wells per section, which is the right answer we believe from our work to the south. The rock is just not performing as expected in that isolated area.
If you look at the rest of the Turner program, what you can see is that, the remainder of our wells inclusive of those 9, we're actually outperforming the basin by about 40%, we think is good. We want more. So we're pushing for better completions, better well design and better spacing solutions. So we just wanted to call that out because it's important. It represented about 2,000 barrels a day of under delivery in the powder.
We have to admit that in the Q3, but we're going to make that up through the rest of the program. So just wanted to highlight, there is some variability. We understand that variability. We don't have to drill wells up in that area any further.
Great. Thank you.
Our next question comes from David Heikkinen with Heikkinen Energy Advisors.
Good morning, guys, and thanks for taking my question. I had one operating question first and then one financial question. On the operating side, as you think about your improved cycle times and really the reduction in rig count, how does that impact like your ratio of rigs to frac fleets by region? Can you maintain a similar and stable frac fleet or do you have to flex that up and down with rigs just as you've improved your drilling time?
Yes, David, this is Frank. That is very important to us. The operational efficiency is imperative. We're working through that. We do believe a 2 to 3 rig program in most basins will keep 1 frac crew, if not a frac crew and a half busy.
Our goal will be to align as much as possible the rigs with the frac crews. And that's what we're going through right now, Dave. We're also negotiating contracts with our vendors, suppliers to get the best possible price going into 2020. So that's all a work in progress, but we are keeping that kind of alignment between drilling crews and frac crews very much on the front burner, making sure we get that done. Right now, it looks like we'll probably be able to keep 1 frac crew fully busy in all of our basins with the exception of maybe powder.
If we move to more and more Niobrara in the powder, that will allow us to expand that frac crew into more time because those frac jobs take quite a bit longer than the Turner wells.
Okay. That's helpful. Just on the efficiency side going next year. And then as you think about the transition to free cash flow in 2020 and the cuts, which is a necessary move, how do you guys think about the criticality of your 2 free cash flowing gas assets in the Marcellus and Haynesville relative to your covenant and long term free cash flow
plan? Yes.
No, it's a good question. The gas steel assets are still a very important and critical part of our portfolio that give us balance and diversity that we really, really like. The quality of Marcellus is simply outstanding and the cash flow projection and profile there that we expect over the next several years is quite significant and quite meaningful to us. The reduced activity in the Haynesville, as you would expect and how we model our cash flows there, We fully incorporate that profile, that decline that we'll experience until we start redirecting capital that direction again. And that's all been considered and weighed into the covenant situation and the projected cash flow and returns and free cash flow neutrality and the sustainable free cash flow that we seek to deliver in the coming years.
So it's the way I'd look at that and answer the question is that the gas assets are very important and critical to Chesapeake. They're a tremendous lever and we evaluate the capital program and the cash flows very closely with respect to our financial performance and future profitability of the company.
And any exit would have to be at a premium to your covenant multiples, I'd assume?
I think that's David, I think that's a safe way to think about it. But I think we'd be cautious to guide you to expect that there's a big exit of a large gas asset at a price that isn't something that we would find attractive to shareholders across the board. So I don't think we would be driven just by that one metric.
Okay. Thank you all.
This concludes our question and answer session. I would like to turn the conference back over to Doug Lawlor for any closing remarks.
Yes. Thank you for joining us today. And just to reiterate, our confidence in our program and execution of our strategy remains very high. Our oil production will continue to ramp in the last few months of the year, growing over 10% in the Q4 as compared to the Q3, and we're on track to meet our 2019 production and capital guidance. Looking forward to the year ahead, we'll reduce our capital spend by approximately 30% as I shared on delivering flat oil production and maximizing our cash flow.
Our capital efficiency improvements combined with the proposed development plan positions the company to target free cash flow in 2020. And we'll continue to build a business which is resilient to the fluctuation of the commodity market. This concludes our conference call. And if you have any further questions, please do not hesitate to reach out to us. We're happy to address any questions.
Thank you.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.