Darrin Henke

Thanks, Danny. We had a solid quarter as the team continues to execute with excellence.
Our wedge production benefited from strong well performance and improving cycle times, while our base production rebounded quickly from the January weather disruptions. The Chord team has enhanced our facility design in recent years and has the equipment and processes in place to mitigate downtime and rebound quickly when there are outages.
Operationally, we continued to be encouraged by the progress we're making on 3-mile laterals, of which we've executed about 80 to date. While it's still early days, on average, performance is meeting or exceeding our expectations, and one can clearly observe contribution from the furthest portions of the lateral.
We're also seeing an uplift compared to the 2-mile analog wells in each prospect area, which is increasing over time. You can find additional details on slide 9 of our updated investor presentation, where we provided performance data on 3-mile wells in Painted Woods that were detailed in the third quarter of last year.
Additionally, we provided incremental details on the anticipated 3-mile production forecast over time and also the expected 40% uplift. It's important to understand that, all else equal, production per lateral foot from 3-mile wells will initially be below 2-mile analogs. This mostly reflects facility constraints and managed flowback, which generally keep volumes in a certain band for the initial productivity period.
However, over time, the 3-mile well production per lateral foot catches up with 2-mile wells, given shallower declines, which ultimately leads to higher recovery. We expect 3-mile wells to deliver approximately 40% more EUR for about 20% more capital. This capital efficiency primarily comes from leveraging the vertical section of the wellbore, as well as locations, roads, and infrastructure, while using similar-sized facilities.
Chord has made significant progress in drilling, completing drilling times declined by roughly 25% over 2023 and is now taking about 10 to 11 days on average to drill a 3-mile well. I should note, in the first quarter, Chord drilled a 3-mile well in 8.7 days spud to rig release, which set a new basin record. On the cleanout side, we have made strong progress and are essentially reaching TD in all our 3-mile wells at this point.
We frequently get asked if there could be upside to our implied 80% productivity assumption for the third mile. We believe this is a likely possibility, especially in light of Chord's progress on cleanouts over the past year. However, given that our 2023 3-mile tills were back-end weighted, it will take until later this year to get sufficient production history to effectively analyze the declines and determine whether we can increase our EUR uplift assumptions.
As I said, we are essentially reaching TD on all our cleanouts and we like what we see for production performance and well pressures. I give credit to the Chord team for embracing our culture of continuous improvement, which has significantly advanced our execution on the 3-mile laterals.
So to sum things up, Bachan is a world class resource with strong economics. And as the premier operator in the basin, we see additional running room to drive further efficiencies and lower breakeven pricing. The combination with Enerplus provides additional levers to advance our capabilities and will allow both Chord and Enerplus to create more value than either company could as a standalone. We expect to lower our supply costs while continuing to reduce our environmental footprint, all the while being good stewards in the communities where we operate.
I'll now turn it back over to Richard.

Richard Robuck

Thanks, Darrin. A quick heads up. My comments regarding guidance will not include pro forma impacts of Internet Plus has will be incorporating a combined look post close in the first quarter, core generated adjusted free cash flow of 204 million. Looking at the puts-and-takes strong volumes, lower operating costs largely offset capital costs that were at the high end of the range, while natural gas realizations were below our February for cash projections, our volumes were strong in the first quarter, 2.6% of our midpoint guidance, while total volumes were about 1% above midpoint guidance. First quarter adjusted CapEx of $254 million, excluded 4 million of CapEx, which will be reimbursed in conjunction with sales of non-operated assets, as Danny mentioned, or program has accelerated a bit from what we have expected in February, which is reflected in our first quarter results and second quarter guidance. On a full-year basis, there were no changes to oil volumes and capital spending guidance that we outlined in February. Oil realizations in the first quarter averaged $1.71, $1.71 below WTI. Slide, the favorable the midpoint guidance as we look through the balance of 2020 for the first quarter, oil differential is expected to be wider than the rest of the year, with Balkan pricing expected to improve as the TMX pipeline begins operating for the full year, we expect crude crude realizations to reflect a modest discount to WTI. Ngl realizations as a percent of WTI were in line with midpoint guidance, while gas realizations fell below our guidance range. As a reminder, certain marketing fixed fees are deducted from our realized gas and NGL prices. This drives higher operating leverage, which hurts realizations for both NGLs and gas at times of weaker price. Because with gas prices trading at low levels, the fees deducted from our price resulted in lower realizations as a percent of the benchmark price. However, physicians should improve quickly in environments where gas prices rise. We have incorporated the current market conditions into our updated 2020 for guidance. Turning to costs, LOE was $10.39 per BOE in the first quarter was better than our original expectations, given strong volumes and lower workover cost. GPT. was $3.30 per BOE, which was towards the higher end of the range. We slightly adjusted our full year LOENGPT. guidance to account for the first quarter before once and our latest forecast. Cash G&A, excluding transaction costs, was $14.5 million in the first quarter and was better than original expectations due to timing of spending. Full year guidance remains unchanged. Production taxes averaged 8.5% of commodity sales in the first quarter, and we really have reiterated our full year guidance. Cord made no cash tax payments in the first quarter. For the second quarter, we expect to pay 1% to 8% of EBITDA, which increases to 8% to 14% of EBITDA in the second half of the year. For the full year 2020 14, we expect to pay 4% to 9% and EBITDA at WTI pricing ranging from 70 to $90 a barrel, which is in line with our initial expectations in 24 and 25. We generally expect cash taxes to be higher in the back half of the year relative to the front half due to timing and projections and other factors. In closing, I'd like to our team for their hard work and dedication to the company contribution shows up in our strong returns, sustainable free cash flow and peer-leading return of capital.
That I'll hand the call back over to Anna for questions.

Question and Answer Session

Operator

(Operator Instructions) Neal Dingmann, Truist Securities.

Neal Dingmann

Hi morning, guys. Nice quarter on, Danny. My first question is maybe on your post plus D and C plans. I note which maybe just what you can talk around this specifically. I believe courts been running around two to three rigs in there plus two. And I'm just wondering, you mentioned something on your prepared remarks that it seemed like you suggested that guidance would stay relatively the same given the orders. You didn't want to raise guidance that gives you a commitment to staying relatively flat. And I'm just wondering, with that said, it's fair to assume that potential downside, that CapEx if these operational efficiencies that you and Darren team are continuing to see if you're able to continue to do that.
I think that's a case of the question, Neil. Yes, I think that's I think that's fair. What we we've got that we're doing really well as an organization. The efficiencies are coming through cycle times are improving down and what were not interest. We're not interested in chasing production higher and higher. We think that sort of a flat plus program that we've talked about many times is kind of the right way to run the organization, and that's how our thoughts on that hasn't changed. And so as we see these efficiencies move through, as we're able to pull more capital out of the system, instead of filing that into more activity will probably keep our activity about the similar what it would have been otherwise. And just to let more free cash flow closer to system love to see that.
Okay. And then just secondly, on future LOEs specifically, I just wondered, you've recently cut some workover rigs that you've done a nice job just on that workover program. I'm just wondering outside of whether or not what I would call something that's doable. What do you envision deserted sort of a typical workover play? And maybe I'll start with or without adverse our at a plus on what do you assume, you know, on a kind of work over plan? I'm trying to get an idea of the plan will be about where it is today, which you rent a backup for you to how should we think about that workover rework plan go into?
All right. Thank you. Yes. I'll ask Darren to provide some some commentary here in a moment, but maybe just give my thoughts 1st year. I think what you should expect the Neal is we've got that we've got a significant workover rig program. There's probably some seasonality in it. So some quarters it may be a little higher than others. We've been working really, really hard to trying to optimize our cost. And this we recognize it's a big portion of our LOE. in that as we can get more efficiencies through the system and do that work better, we should be the beneficiaries of sort of lower cost and that structure. So that certainly a focus for us that could include reducing the number of rigs, move, more power rates for more efficient operations and lots of different things. But from an enterprise perspective, they have I'd say there are workover program is sort of comparable to ours on on a flowing barrel are well basis. And so we don't anticipate huge amount of changes other than our focus on continuous improvement. But I'll ask Darren to provide his thoughts on.
Yes, they'll We've since Q3 of last year, we've been able to reduce our workover costs on our on our ROE repair jobs by about 15%, just really focusing on how we conduct our operations and being the most efficient operator possible. We've also been able to improve our are run times so that we actually don't need as many rigs is maybe we did historically. So when you look at in or plus relative to Cord, the run times at quarter are slightly longer than what enter plus has been experiencing. And so I think when we put the two companies together will be able to glean some additional efficiencies increase in runtimes as well as a decrease in the overall workover program.
Very helpful. Thanks, guys.

Operator

David Deckelbaum, Cowen.

David Deckelbaum

Thanks, steady local or the Triton team. I wanted to ask a follow-up just on guidance for this year. So obviously, you lift the full year unchanged since just given the historical bias to producing more in the back half of the year. I was surprised that the implication is that more or less be flattish from the second quarter. I know that there's obviously some pretty even kills throughout the first half and the back half of the year. But still if we think about the summer seasonality that uptick there, it would seem that you guys should have increased production in the back half of the year, unless I'm thinking about that incorrectly. I know that you guys talked about managing the program to sit within the capital budget, but is there something else that would be impacting the production side that would otherwise keep those volumes flat?
Yes. Thanks for the question, David. I think it will actually and we anticipate having and a half of the year as we window out a frac crew and a drilling rigs or activity actually, we anticipate will fall as we move into the third quarter. And so as a result of that, that till balance is going to be slightly tilted toward front half of the year, not the back half of the year. And so what that's going to do is provide incentives sort of a more cyclical production profile. It should provide a more stable production profile quarter on quarter. And I think that's the impact you're going to see. So we see as we continue to see strong strong performance, you note again, we're not we're not really looking to chase activity higher as we go faster. We'll just slow. The activity is down a little bit and let more free cash flow flow through. I appreciate that some that maybe you can revisit some of the commentary around potentially doing better on some of the synergies with enter a plus of though it's probably too early to talk about some of those, but I know a lot of a certain trade developed the potential that could have free permit some of their locations in the three mile laterals or the go forward basis.
And you've obviously had some increased success on your own program has a time line and how you guys think about achieving that changed as you look at integrating some of these assets? Or is it something that's still likely not impactful until 2026?
Well, I think from a development program standpoint, so for new wells that we're doing, we're probably we're likely see really the impact of that 2025, not in 2026. And so that we've been working as separate organizations as as is appropriate until close, we won't really get to a full new integrated development plan foot to gathering to post close. And so internally, we've been we used the phrase coiling the spring. So we're calling this spring here, getting ready to wear a jump on this as soon as we close, we've done as much integration planning as we can. Until that point, once we close, we'll put a full integrated development plans together, which I anticipate will go largely into effect in 2025. So I think you'll see really those those benefits, at least from a practice standpoint, move through 2025. So a lot of those synergy captures and 20 and 2025. Now with respect to reap permitting and replanning, that process obviously takes a little longer. And so we'll need to put the acreage together, play there, geometry gains of of of replanning out. So maybe the impact of moving from currently planned two-mile laterals to future plans. Three-mile laterals may be a little later in the process. But from a from an activity standpoint, we should see that synergy savings roll through in, I'd say, early early 20, 25, maybe the opportunity for replanning into three mile laterals and moving some of that development plan over maybe later and later in the year.
Thanks, Derek.

Operator

John Guinee, Stifel.

John Guinee

Hey, good morning, guys, and thanks for taking my questions. For my first one, staying on the synergies under plus has been active on the CMO, correct front. And if I'm not mistaken, that's one area called it hasn't really leaned into yet. Can you provide your thoughts on incorporating simul-frac development program and the potential cost savings associated with it?
Sure Thing happy to do that. So you're exactly right in our Plus has done a great job implementing simul-fracs as well as they recycle more produced water in their frac operations than we do. And so those are some learnings that we we intend to implement immediately, really a mid mid year this year going forward. And so the savings when you combine the recycling, the water along with simul-frac is probably going to work out plus or minus $100,000 per well savings from other things that are plusses done really well as the use of more vapor recovery units. And as far as capturing gas off of their facilities. And that's something that you'll see core to implement as well to help with our gas capture going forward.
Makes sense. And a quick clarification or those savings are ready included in the 150 million synergy target? The of the savings I've talked about are in those numbers. Makes sense for my follow up. With the four mile laterals planned for later this year. Can you offer any preliminary expectations regarding potential cost savings and ultimate you are either from the subsurface work you have done or analogs across the basin?
So I think from a four mile lateral standpoint, obviously, it's sort of early days for us and that we would anticipate that similar to as we underwrite of four mile lateral program will obviously be looking at some some incremental degradation on the Ford mile delivery, just like we've looked at incremental degradation in addition of a three mile delivery as opposed to two mile.
And so I think we're encouraged that maybe we've been a little too conservative on that from a two to three mile standpoint. Again, we'll provide some more clarity on that as we get a little more data and as we get toward the end of the year. But as we increase our learnings through the three-month process will plow that into Fourmile.
I'd say that the from a drilling perspective, we're very confident that the now that the four miles shouldn't provide too much of a technical challenge for us from a plot out profit placement standpoint, we feel confident we can place our profit appropriately out the four mile. I think the clean out is probably the technical challenge that we have most just with existing coiled. Certainly coil tubing clean out will be a big challenge for us in a lateral that's long and probably will require some stick pipe. But we do anticipate sort of similar to move from two and three miles.
You can think about there's still huge advantages and leveraging the vertical section of the well, the facilities that you've got, the roads that bringing to the pad, et cetera. And so if you can imagine, going from a two-mile from a two-mile development program 0.214 mile development program that provides a real opportunity. And so I'm not sure how much we're envisioning for miles replacing three miles, but where we got geometry that doesn't lend itself to three-mile development, but really is lending itself to two-mile development. Certainly a formal well instead of a two mile, well could be a big uplift for us. And so that's what we're that's really what we're excited about.
And John, just to add to that a little bit, the three-mile on a cord standalone, we've been talking about 60% of our inventory is in that three mile category, which means that 40% is open to being able to continue to extend on a combined basis were about 40% in the three-mile identified category. So the four mile lateral will just give us more opportunities, as Dana mentioned, that have more more shapes, if you will, to get a larger portion of that inventory into either three or four mile, thus increasing the capital efficiency across the program. So there's there's a lot of opportunity left in the program and and we think the format will just add to that.
Great color. Thanks again for taking my questions.

Operator

(Operator Instructions) Sean McGowan, Daniel Energy Partners.

Sean McGowan

Good morning, guys. Thanks for taking my question. You guys had impressive improvement on an oil-linked terrestrial time is a shell for sorry about that drill times year over year. Is this improvement around more of the size of the hammer are well designed in the form of drilling fluids, drilling, mud, et cetera?
That's a great question. The team has done a fabulous job driving down our cycle times on the drilling front. And it's a combination of working with the vendors on pit design and advancing our bit design on that. You hit the nail on the head with respect to the drilling that we're using, the properties of that mode and how we're able to to drill the well bores really quickly, but also keep laterals claim what we're doing that and of course, having good laterals that we can get to get the pipe to bottom with no problem and cemented in place. So it's not really any one individual area. It's just it's cords commitment to continuous improvement. We're never going to rest with what we done historically. We have set the record for the fastest three were three mile well in the basin. But that doesn't mean we're going to step back and be comfortable with those results will continue to focus and look for additional wins to drive down those cycle times. Got it. Maybe a follow-up just on several of your competitors or peers are talking about refracs and the Bakken and the Eagleford. How do you guys think about the refrac market? Do you think about it? I think enter plus does some, but any color on that would be helpful. Yes, I think where we're open to re-fracs. We think we've got some opportunity within our program to do those. We candidly, the greenfield development program we have right now is really compelling data. But as we have opportunities to the refracs, particularly in areas where we see development in the area. So we've already got wells shut in in the area with already got wells fracked protected in the area. Those areas are doing refracs at that moment is that it would be difficult for the refrac itself to justify going back into areas like that to shut wells and frac protect them because there's expense and cost associated with all of that. And so I think you'll see us focus on refracs and that manner as a standalone program for us, we are observing we are observing others. We're learning from our own practices and and we'll move forward. one of the one of the in that one of the reasons you go in and do a refrac program is really the original wells were mainly under stimulated, at least relative to modern expectations in the first place. And we've got a few areas in the field that are that are like that, that generally speaking, I think that legacy organizations and there's been a pretty good job upfront. And so maybe there's not as much of meat on the bone is or maybe for some others. But that's still an interesting program that we're looking at. Yes.
Okay. Thanks for taking my questions.

Operator

Thank you. There are no further questions at this time. I will now hand the call back to Mr. Danny Brown, CEO, for closing remarks.

Daniel Brown

Thank you, and I will close out. We appreciate everyone's time today and interest in our company. Also want to thank our employees for their continued commitment and dedication because they really are the backbone to our success. We pride ourselves on being strong capital allocators and doing the right thing for shareholders. We remain more excited than ever about the merits of the combination with into plus, which will accelerate cords, beneficial rate of change as it relates to improving returns and value creation and look forward to updating the market on our progress as we move through that process. And with that, thanks to everyone for joining our call. This concludes today's call.