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Roan Resources, Inc. (ROAN) Q1 2019 Earnings Call Transcript

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ROAN earnings call for the period ending March 31, 2019.

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Roan Resources, Inc. (ROAN)
Q1 2019 Earnings Call
May 15, 2019, 10:30 a.m. ET


  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Hello and welcome to the First Quarter 2019 Roan Industries Conference Call -- sorry, Roan Resources Earnings Conference Call. All lines have been placed on mute to prevent any background noise and after the speakers' remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press "*1" on your telephone keypad and if you would like to withdraw your question, just press "#".

Thank you. I'd now like to introduce you to Alyson Gilbert, Manager of Investor Relations. You may begin, ma'am.

Alyson Gilbert -- Manager of Investor Relations

Good morning and thank you for joining our First Quarter Earnings Investor Conference Call. We will start today with prepared remarks from Joseph Mills, Executive Chairman, and David Edwards, Chief Financial Officer. Also on the call available for Q&A are Joel Pettit, Executive Vice President of Operations and Marketing, and Greg Condray, Executive Vice President of Geoscience and Business Development.

Today's call will contain forward-looking statements that will describe our beliefs, goals, plans, strategies, expectations, projections, forecasts, and assumptions. Please note that the company's actual results may differ from those anticipated by such forward-looking statements for a variety of reasons, many of which are beyond our control. Additional information concerning certain risk factors relating to our business, prospects, and results are available in the company's filings with the SEC, including the company's annual report on Form 10-K and any other public filings and press releases. Roan does not undertake any obligation to update forward-looking statements made on this call.

Finally, we will refer to certain non-GAAP financial measures. For a reconciliation of these measures to generally accepted accounting principles, please refer to our fourth quarter press release or slide presentation that has been posted to the company's website at

I will now turn the call over to Mr. Mills. Joe?

Joseph Mills -- Executive Chairman of the Board

Thank you, Alyson. Good morning, ladies and gentlemen, and thank you to everyone that has joined us for our First Quarter 2019 Earnings Call. As you are all aware, this is my first quarterly call as Roan's Executive Chairman of the Board. I'm excited to be at the helm of Roan while we search for a permanent CEO replacement. The Board has constituted a search committee and we have engaged Korn Ferry to assist us in a nationwide search for the right person to assume the CEO duties at Roan.

We announced a month ago that Tony Maranto, our Chairman and CEO, had elected to resign. Given Roan's premier acreage position in the core of the basin, the Board has been less than pleased at the company's overall performance over the past year. Management decision to ramp to eight rigs last year was far too aggressive for a company of this scale and at this stage in its lifecycle. With eight rigs running, we could not be as thoughtful about our location selections and, given the state regulatory permit process here in Oklahoma, this resulted in suboptimal locations being drilled based upon available drilling permits rather than optimized development units given the geology and spacing considerations.

Going to four rigs in the first quarter of this year was clearly the right answer to allow us to better balance our activity level, adjust our cost structure more in line with the lower commodity prices, and to optimize our drilling and completion practices based on our learnings from our 2018 drilling program.

I'm very happy to report that our first set of wells drilled and completed in 2019 using our optimized completion design, better spacing assumptions, and pressure management techniques at Mad Play and Victory Slide wells. These appear to be very good wells and indicative of what we expect going forward for the rest of the year on this quality asset. I'll discuss in detail these well results and the 2019 production plan later in this call.

Overall, my focus is to bring capital discipline back to the company and focus on our results while continuing to reduce drilling, operating, and G&A costs and to determine the best strategic path forward for the company. I am now 30 days into my tenure as Executive Chairman and I could not be more impressed with the dedication and talent of our staff here at Roan and the enormous potential the company has. I'm very confident that we have the right people in place to refocus the company and to make the necessary strategic and operation decisions as we move forward.

Roan continues to hold a premier acreage footprint across the Merge play and we intend to continue to exploit this premier position at a more deliberate pace, while still delivering on the promises of continued production growth and the achievement of free cash neutrality by the fourth quarter of this year. I've been asked repeatedly, both internally and externally, if there is a change of strategic direction and the answer to that is no. We remain focused on being the premier Anadarko pure-play operator and to grow our production in a cost-effective and profitable manner.

This leads me to address the recent press releases the company issued two weeks ago regarding strategic alternatives. Following the resignation of Mr. Maranto, the company received numerous inquiries of interest from various participants in and out of the basin, as we described in our April 29 press release. In addition to receiving several inbound inquiries for an outright sale of the company, we also received inbound inquiries from smaller companies seeking an opportunity to engage with us in constructive discussions regarding consolidation of operators in the basin with Roan.

This has led our Board to create a transactions committee to evaluate all potential opportunities to enhance and to maximize our shareholder value. The company is in the final stages of engaging one or more investment banks to assist the Board in evaluating the multiple opportunities and to help determine the best course of action for Roan. Currently, all strategic opportunities are on the table, including in-facing consolidation, divesting non-core acres that could be credit-enhancing and provide a more accurate value marker on our premier acreage, or an outright sale of the company. The transaction committee is committed to making the best informed decisions for all the shareholders and the company. This will be an ongoing process that may result in multiple strategic transactions. We do not intend to provide routine updates to the market but will do so when legally required or when it makes sense to do so.

There have also been a few other concerns or rumors that I would like to briefly address. The S-1 amendments that have been filed this year are in response to comments received from the Securities and Exchange Commission. The original S-1 was filed in the fall of 2018 pursuant to the Registration Rights Agreement entered in connection with the reorganization of the company last summer. You may continue to see S-1 amendments filed until the SEC's review is complete and our S-1 is declared effective. No shares can be sold under the S-1 until it is declared effective. The Board of Directors and their affiliates own approximately 75% of the outstanding shares and remain fully committed to Roan and very supportive of our current strategic direction.

Now, let's turn to our first quarter results. Production for the quarter was approximately 49 thousand Boe/day, with 26% being oil, 30% being NGLs, and 44% gas, which is an increase in production of over 30% as compared to our first quarter of 2018 results.

As we discussed during our March 2019 earnings call, first quarter production was down as compared to fourth quarter 2018 due to our previously announced frac holiday, where we elected to suspend our operated completion activity in late 2018 due to the significant fall in commodity prices and to allow for the resetting of service costs due to decreased in-basin activity levels while simultaneously observing the results of our most recent completions.

The delay in completion activity resulted in no new wells being turned to first sales for over 80-plus days, which was effectively the majority of the first quarter. Once we resumed our completion activity in late January, we were able to turn to sales 15 wells during the quarter. However, 12 of the 15 were turned online in very late March, causing basically minimal new production to be accounted for during the quarter.

In addition to the delayed completion activity, the company also was electing to reject ethane for the month of January, which resulted in less NGL recoveries, and this is also reflected in our reduced production for the quarter. I will note, right now, that we are back in ethane rejection for the month of May and this has the impact of reducing our overall liquids production for the second quarter as well. I'll address this in more detail in a minute.

First quarter capex totaled $172.8 million, which was approximately $44 million lower than the fourth quarter of 2018 and below Street consensus. It is important to note that, for the first quarter, our plan was to have our highest capex spend rate for the entire year while production was at its lowest. We forecast capex to continue to trend down sequentially throughout the remainder of the year while production will trend meaningfully higher sequentially, quarter-to-quarter.

EBITDAX for the quarter was $72.8 million, which was down from the fourth quarter but primarily due to lower volumes and to lower overall commodity prices. Dave Edwards, our CFO, will go into more detail on the financials and discuss our plans to address our liquidity here in a few minutes.

During the first quarter, the company drilled 19 gross wells and turned 15 gross wells online. We started the year with eight rigs but dropped to four rigs by the end of January and have held flat at that level since that time. We maintained an average of two frac crews during the first quarter and we still have two frac crews running today.

Completion costs per foot came down by over 40% during the quarter as compared to similar completion costs during the fourth quarter of 2018, all due to service cost reductions as well as optimizing our frac design.

We are disappointed with the overall performance results of many of our first quarter completions. The majority of the first quarter completions were ducks from our 2018 program and it is now evident from the early performance that many of these wells have been spaced too tightly and have underperformed our expectations. Given the scale and quality of our acreage position, there was no reason to have them so aggressive on spacing at this stage in the development of this emerging play. We understand how to optimize the asset but we fell short on implementing the necessary changes fast enough to ensure best execution that would highlight the premier quality of this play.

As noted at the beginning of this call, we have adjusted our program for the remainder of this year and our first optimally spaced and completed wells have started to come online and we are excited about the early production results. Focusing on today, production is recovering and currently is at over 53 thousand Boe/day, with 28% of that being oil after normalizing for ethane rejection during the month of May.

Electing to reject ethane is an economic decision that has the effect of lowering our daily production by approximately 3,300 barrels of oil equivalent per day. In addition, we have approximately 2,800 barrels of oil equivalent per day that is shut in due to our ongoing completion activity on offset wells, or sometimes referred to in the industry as frac hits. So, if we normalize for the ethane rejection and shut-in production due to our frac hits, we'd be producing over 56 thousand Boe/day.

Our optimized drilling activity for the balance of 2019 is focused in two distinct areas: the western portion of the Merge play, which is closer to Cimarex's Lone Rock acreage, which we are simply calling the "West Merge," and further east in the oiler parts of the Merge and the SCOOP plays. We remain very excited about our entire position across the Merge play but we believe we have demonstrated the appropriate pattern design and completion recipe for these two areas, and the balance of our 2019 development activity will be focused on these two areas.

When we speak of optimized locations, we're referring to wells spaced more optimally at 5-8 wells per unit and completions for a 2-mile well with 30-45 stages per well, 1,500-2,500 pounds of proppant per foot, and 8-16 clusters per stage. Given Roan's large-scale footprint and with these revised spacing assumptions, we believe we have over 10-plus years of premier acreage available to drill and develop.

Several wells have recently come online that should more accurately represent the remaining completions for the year, which include our Mad Play unit and the Mayes wells in our Earl unit, both located in Canadian County, plus we just brought on our Victory Slide wells that just came online over the weekend.

The Mad Play is a 4-well unit with 2 Mayes wells and 2 Woodford wells, with 500 feet of horizontal separation and 200 feet of vertical separation between well bores, located in the West Merge. The average per well 15-day IP rates for the Mad Play wells is 1,818 barrels of oil equivalent per day, which was made up of 45% oil, 21% NGLs, and 34% gas, from a normalized 10,000-foot lateral. The actual average lateral length of these wells was about 6,780 feet. We are projecting well costs to be under $7 million per well, so we're feeling pretty good about these results and the cost structure.

The Earl unit is a 6-well unit with 3 Mayes wells and 3 Woodford wells, with about 500 feet to 800 feet of horizontal separation and 100-150 feet of vertical separation between well bores, which is now located in the Eastern Merge. The average per well 15-day IP rates for all six Earl wells was 932 barrels of oil equivalent per day, which was made up of 45% oil, 23% NGLs, and 32% gas, from a normalized 10,000-foot lateral, which these had an actual average lateral length of over 10,165 feet. The average per well 15-day IP rate for the three Mayes wells was over 1,688 barrels of oil equivalent per day and that was made up of 42% oil, 25% NGLs, and 33% gas. The Mayes wells were optimally spaced and representative of the remaining 2019-focused activity while, unfortunately, the Woodford wells were not optimally spaced for this unit. We are projecting well costs to be approximately $7 million per well from this pad.

Over the past weekend, we turned to sales our two Victory Slide wells, which are located in Grady County, and we're very encouraged by the early production flow-back results. The average daily rate on the two Mayes wells was over 1,444 barrels of oil equivalent per day, with that being made up of 78% and 86% total liquids, which was normalized over a 10,000-foot lateral. The average lateral length of these wells was about 9,900 feet. The third well is a Woodford well and it is still cleaning up as we speak. Early cost projections are indicating these well costs will be approximately $7 million or less per well.

We'll provide more details on all of these wells next quarter but, again, wanted to highlight what type of wells will be coming online, we hope, for the remainder of this year.

Focusing now on our pressure management program, looking back at our wells from the fourth quarter of 2018, the 16 optimized wells that had at least 120 days of production from the fourth quarter continued to demonstrate lowered decline rates and are in line with our expectations for pressure managed wells.

As a refresher, this data set of wells had an average 90-day rate of over 1,059 barrels of oil equivalent per day, with 50% oil, 20% NGLs, and 30% gas, all being normalized to a 10,000-foot lateral. That same set of wells, at 120 days, had an average rate of 1,006 barrels of oil equivalent per day, with oil being 48%, NGLs constituting 21%, and gas at 31%. At 150 days, those same wells had an average rate of 999 barrels of oil equivalent per day, with oil constituting 47%, NGLs 22%, and gas was 31%.

These wells are continuing to showcase lower decline rates, both on a total Boe basis and, more specifically, the oil decline, which is very supportive of our assessment of using pressure management techniques. We will continue to apply pressure management to our new wells in 2019.

We project production to be approximately 50 thousand Boe/day for the second quarter with our capex to be about $155 million. We are projecting to turn 19 gross operated wells to first sales during this quarter, with 15 already online and the remaining four to come online in late June, while we continue to run an average of two frac crews.

This takes us to an updated look for 2019. Given our completion delays to our program in the first quarter and our less than optimal results during the first quarter, we are revising our production guidance slightly downwards for 2019. We are lowering our overall production guidance down approximately 7% at the midpoint as compared to our previous guidance of 56-59 thousand Boe/day in 2019. We now expect full-year production to range between 51,500 barrels and 55,500 Boe/day, with 26% to 28% being oil and 26% to 32% being NGLs. This still reflects total production growth of approximately 20% to 25% year-over-year at the midpoint and oil growth of approximately 18% year-over-year.

Our expected fourth quarter production is expected to average between 60,000-62,500 Boe/day, reflecting approximately 35 wells to be turned online in the back half of the year. We remain focused and still forecast to be cash flow positive in the fourth quarter of 2019.

Along with an update to production, we're also lowering our anticipated total capex spend for the year. We are now projecting total capex will be between $515 million and $555 million, which is down $15 million from the top end of our original capital guidance. This is primarily a reflection of completion optimization, improving capital discipline, and lower non-DNC costs. Both LOE and cash G&A are going to be higher on a Boe basis with the lower production output. LOE is up approximately 6% on a total cost basis while G&A is flat on a total cost basis. I assure you I am focusing on our LOE and G&A and intend to drive them down this year.

For a full look at our updated 2019 guidance, please turn to Slide 7 in the investor presentation.

So, with that, I'll now turn the call over to our CFO, Mr. David Edwards.

David Edwards -- Chief Financial Officer

Thank you, Joe, and thank you to everyone that is on the call today. Let me start with a recap of the first quarter results. As Joe mentioned, production came in at 48.9 thousand barrels of oil equivalent per day, 30% higher than the first quarter of 2018. Oil volumes were at 12.7 thousand barrels per day for 26% of total production. NGL volumes were 14.8 thousand barrels per day, or 30% of total production, and up 52% year-over-year. As Joe mentioned, NGL and natural gas pricing dynamics led the company to electing to ethane rejection for the month of January, which impacted Boe volumes in the month by approximately 33 thousand Boe/day.

Oil prices average $53.18 per barrel for the quarter, approximately $1.60 below its index price. Realized gas prices averaged $1.87 per Mcf as compared to a weighted average Henry Hub price of $3.17 per MMBtu, which includes deducts of approximately $0.67 for regional pricing and approximately $0.63 for gathering, processing, and transportation. Finally, realized NGL prices were $12.18 per barrel or approximately 22% of WTI.

Lease operating expenses for the quarter were $14.8 million or $3.37 per Boe. As previously noted, we expect our water service contract with Blue Mountain to reduce operating expense, which became effective at the beginning of the second quarter. Production taxes were in line with projections at $5 million or $1.14 per Boe.

For the quarter, G&A was $11.2 million, or $2.55 per Boe, after excluding equity compensation of $3.1 million and bad debt expense of $1.5 million. Incorporating these components, adjusted EBITDAX for the quarter totaled $72.8 million.

Total capex for the quarter amounted to $172.8 million, which represents a $44 million reduction as compared to the fourth quarter spend. Capex for the quarter includes 19 gross and 13.1 net spuds and 15 gross and 12 net completions.

We ended the quarter with $2.2 million of cash on hand and long-term debt of $602 million on the revolver for a net debt position of just over $600 million. Our next determination will be in June.

As we have stated previously, we are working to enhance our liquidity by position by terming out or otherwise refinancing a portion of these borrowings on the credit facility. While we believe traditional sources of capital are available, such as second lien borrowing, we are mindful to properly consider adjustments to our capital structure in the context of the various strategic alternatives we are currently evaluating.

We continue to maintain an active hedge program for 2019 and 2020. Based on our 2019 guidance midpoint, we are nearly fully hedged on our oil production for the balance of 2019 at an average price of approximately $60 per barrel and approximately 80% hedged on anticipated gas production at $2.91 per Mcf and 17% hedged on NGL production at $32.25 per barrel for the same period. Additionally, approximately three-quarters of our natural gas losses are hedged with basis swaps.

As Joe previously mentioned, we expect second quarter production to be approximately 50 MBoe/day and we've updated full-year 2019 guidance to 51.5-55.5 MBoe/day. Importantly, our guidance for future periods incorporates the assumption that we will be in ethane recovery, which is approximately 3.5 thousand Boe/day increase as compared to forecasting volumes in ethane rejection. Thus far in the year, we've been in ethane rejection in January and May and elected into ethane recovery in other prior months.

Our second quarter capital spend is anticipated to be $155 million, highlighting the continued reduction in capital intensity. We are also updating our full-year 2019 capex to a midpoint of $535 million, a $10 million reduction from our prior projection.

I will now turn the call back over to Joe for closing remarks before we start the Q&A session.

Joseph Mills -- Executive Chairman of the Board

Thank you, David. I'd like to end the call by reiterating that the second half of 2019 is going to be a different year for Roan. In 2018, the company was an early leader in the Merge play and was focused on growing its production aggressively while trying to better understand the spacing requirements of this region. Unfortunately, the overspend on capital was due, in part, to early stage de-risking and operational optimization but some of the overspend was due to operational mistakes and unforced errors that we have now corrected.

Most importantly, we have learned a lot from our 2018 drilling program and the go-forward 2019 plan will demonstrate a much higher level of capital efficiency with substantially lower risk. We'll be able to show that the Merge will compete favorably with the best plays in the lower 48. Notwithstanding some of these self-inflicted wounds, we are still focused on growing our overall production by 20% to 25% in 2019 as compared to last year and to set ourselves up for delivering on a program that can generate free cash flow by the end of 2019.

I look forward to being a part of this transformative year for the company. I'd also like to thank each and every employee at Roan who works tirelessly every single day to grow our company and to do so in a safe and efficient manner.

With that, we'll open up the call for questions.

Questions and Answers:


Thank you. At this time, as a reminder, if you do want to ask a question, just press "*1" on your telephone keypad. And your first question comes from Derrick Whitfield of Stifel. Derek, please go ahead.

Derrick Whitfield -- Stifel -- Analyst

Good morning, all.

Joseph Mills -- Executive Chairman of the Board

Good morning, Derrick.

Derrick Whitfield -- Stifel -- Analyst

Perhaps for Joe. Regarding your comments on Q1 wells being spaced too tightly, how many wells and sections broadly pertain to that statement?

Joseph Mills -- Executive Chairman of the Board

Let's see. We would have probably what? Ten wells out of the 15 that were probably spaced too tightly.

Derrick Whitfield -- Stifel -- Analyst

And I imagine that's two or three sections?

Joseph Mills -- Executive Chairman of the Board

Yes. Correct.

Derrick Whitfield -- Stifel -- Analyst

Okay. And then, historically, you guys have provided longer data production results in your quarterly updates. I understand the constraints of this quarter and your concerns with the spacing. Could you offer some context on how to think about the relationship between IP50 and IP30 rates for wells that are representative of your views for balance-of-year activity? I'd imagine their relatively similar based on choke management practices.

Joseph Mills -- Executive Chairman of the Board

Right. So, our hope and expectation is certainly -- that's why we wanted to give you an update on some recent wells that, again, are more optimally spaced. We're pretty excited about these recent group of wells. We think we've got them now -- at least, we think we've got both the completion recipe as well as the spacing pattern better identified. And as I said earlier, we're definitely focusing our efforts for the remainder of this year in an area that we know really, really well. While we think, across our acreage, we're very excited about the potential, but given that we've drilled the number of wells in this West Merge and the East Merge, kind of our more focused target areas, there, our development plans, we think the IP30s and IP50s will be more consistent with the most recent wells. Obviously, the recent wells, we don't have IP30s on them yet. But we're trying to give you a sense of the IP15s. Obviously, those wells will decline a little bit over the next few weeks but, as I said in my prepared remarks, we'll give you a lot more detail about those wells as we get to the end of this quarter.

Derrick Whitfield -- Stifel -- Analyst


Joseph Mills -- Executive Chairman of the Board

And we are employing pressure management as we speak. So, maybe to even give you a better context, the IPs that we're showing you, we're not trying to open these wells up like we did historically. We're definitely trying to manage the chokes because we really do believe in the pressure management, as we tried to show you the 16 representative wells from the fourth quarter. So, we're not trying to do these splashy IP24s that you've seen historically from either us or other operators. We're being a lot more deliberate. So, that's going to -- while the rates may appear to be lower and not as big as, let's say, other operators are showing in an IP24, we're doing that deliberately. So, we are definitely employing choke management, even early on in these wells' life, because we think it's the right thing for the reservoir.

Derrick Whitfield -- Stifel -- Analyst

Great. And then just one quick follow-on. Would it be fair to assume that the majority of your $500,000 savings per well is structural versus cyclical?

Joseph Mills -- Executive Chairman of the Board

You know, I'd like to think it's really -- obviously, we've now drilled 100-plus wells out here. We're definitely getting better at what we're doing. I want to give the team a lot of credit. We recently set a record in our drill times with a Mayes well. I think you're going to see us drive those costs down, continue to drive them down. Clearly, as we said earlier, we've seen pretty significant reductions in our completion costs. And that's driven by both vendor reductions, just in terms of the overall demand here in the basin, we're obviously able to negotiate better terms, but also the frac design itself. Right? We're optimizing that frac design. And so those two combined have given us significant reductions in our completion costs.

My hope and expectation is that you'll also see, even on the drilling side, reductions. And that's going to be from better drilling emphasis, in terms of staying in zone and hopefully getting better penetration rates. So, my hope and expectation is the $7 million becomes a pretty good marker for us. And, look, our goal every single day is to continue to improve on that. I mentioned that we've seen a few of the wells, like our Victory Slide, that we think will come in well below $7 million. It's early so we're still getting field tickets but my expectation is that we'll see those costs drift even below $7 million.

Derrick Whitfield -- Stifel -- Analyst

Very helpful. Thanks for your time.


And your next question comes from Ron Mills of Johnson Rice. Please go ahead.

Ronald Mills -- Johnson Rice -- Analyst

Good morning, Joe.

Joseph Mills -- Executive Chairman of the Board

Good morning, Ron.

Ronald Mills -- Johnson Rice -- Analyst

A couple of questions. One is maybe you can provide a little bit more of a description -- and I don't know if it's for you or David -- on the decision to reject versus recover ethane and just clarify the current run rate of 53 thousand Boe/day, what does that assume and is that just assume that you're rejecting it for May but you're going to recover it in April and July? I guess I'm trying to get more color around the way to think about the guidance and how it compares.

David Edwards -- Chief Financial Officer

Ron, I'll take that. When we look at our gas midstream, the majority of our gas lines are going to go to either Blue Mountain or Enlink. And they allow us the right to elect into ethane rejection or recovery on a monthly basis. We run an analysis about the economics between the two decisions and make that election on a monthly basis. For the May period, the economics favored rejection. As we said, we're in rejection right now. That has an impact of reducing Boe volumes by about 3.3 thousand equivalent a day, as compared to recovery. The guidance that we have for the balance of the year, so essentially the June-forward period, assumes ethane recovery. And as we said, as volumes grow through the balance of the year, that has a 3.5 Boe delta as compared to rejection.

Ronald Mills -- Johnson Rice -- Analyst

And is there any -- how does that decision impact also NGL realizations and was that one of the factors in lower NGL prices was the timing of rejection versus recovery? I guess that was kind of the biggest miss I had on mine was price realizations on NGLs. Or was there something else going on on NGL realizations?

David Edwards -- Chief Financial Officer

Sure. And a lot of questions about NGLs so let us just walk through the components of getting from benchmark prices to our realized prices. First, it's going to be the basket. And the basket is going to be sensitive to two things. First is whether we're in rejection or recovery and then, secondly, whatever spot NGL prices are going to be, which have been down in the past few months. Between the two choices, we realize about 37% of WTI in our rejection case and about 28% of WTI in a recovery case. The second factor is going to be that both Enlink and Blue Mountain levy a percent of proceeds fee on our NGL realizations. We reflect that as a deduct to pricing. So, a 7% reduction in pricing. And then third is our midstream fees for NGLs are realized against our realized prices, which amounts to about a $4.20 barrel deduct in our realized prices. So, accounting for those, we project about 26% to 28% realizations as compared to WTI in a rejection scenario and about 18% to 20% of WTI in a recovery scenario.

Ronald Mills -- Johnson Rice -- Analyst

Okay. And then, Joe, I think you just touched on this at the very end. When you think about your four rigs. And I see your presentation, they're really focused on the central and western Merge part of your position. Is that where you expect to maintain most of the activity this year? Do you plan anything else over toward Grady County where you had at least the early results from the Mayes -- much more oily? I'm just trying to get a sense as to how your activity shifts through your acreage.

Joseph Mills -- Executive Chairman of the Board

Great question, Ron. So, yeah, if you look at the investor deck that we put out on Slide 5, we're really highlighting the drill locations or the pads that we intend to drill for the balance of the year. And so, again, clearly, with the Victory Slide, you can see we've got -- what -- three or four pads that are offsetting it there in Grady County. So, we really like that area. And so, again, we're laying out for you on Slide 5 kind of where we anticipate spending the remaining capital dollars for 2019. And, look, we're opportunistic so if we see either offset activity that warrants us pivoting then, certainly, we'll do so. But at this point, given the -- look, the long lead times, I talked about the state permitting process here in Oklahoma, you can't stand up a rig in days. It takes months to get locations ready so we have to pre-plan all this well in advance. But we really like that kind of west area where the Mad Play wells are and then, of course, where the Victory Slide and the Earls are. So, again, Slide 5 kind of highlights for you where we intend to spend capital for the balance of this year.

Ronald Mills -- Johnson Rice -- Analyst

All right. Great. Thank you.


And your next question comes from Irene Haas of Imperial Capital. Please go ahead.

Irene Haas -- Imperial Capital -- Analyst

Yeah. And assuming that you stay at current rig count and frac crew, would you have any feeling as to what your 2020 growth rate might be? And, also, you've done a lot of choke management on your wells and you had talked about earlier that raised your oil EUR, and would this have material impact on your oil mix for your reserve at year-end '19? These are my two questions.

Joseph Mills -- Executive Chairman of the Board

Yeah, thank you, Irene. Great questions. Yeah, so, obviously, we're not going to give guidance for 2020 but suffice to say that we clearly, even with the program we have, we are anticipating, certainly, growth in 2020. As I said earlier, we're looking at 20% to 25% production growth year-over-year this year as compared to 2018, No. 1. No. 2 is we certainly will have growth in 2020. It may not be as robust but call it, I suspect, 10% to 15% will be the right answer. Obviously, we're still laying out our capital program for next year. What is important to us is still achieving free cash flow neutrality certainly by the end of this year. And so that's certainly driving a lot of our capital investment decisions is achieving that by the end of this year. And so that hopefully answers your first part.

The second part -- yeah. Look, so with this pressure management, and we think we're certainly seeing a much better, shallower decline on our oil production, we hope that's going to lead to higher EURs, ultimately, for the oil. And, obviously, only time will tell us that. Obviously, our engineers are studying that very closely. I'd like to say that that will impact our year-end reserves. That's certainly our goal. It's probably a little premature to say, ultimately, what the EURs are on these wells. But, certainly, that's why we're employing the pressure management is we do think it will help extract more oil production over the life of these wells.

Irene Haas -- Imperial Capital -- Analyst

Great. Thank you.

Joseph Mills -- Executive Chairman of the Board



And your next question comes from Eli Kantor of IFS Securities. Please go ahead.

Eli Kantor -- IFS Securities -- Analyst

Good morning.

Joseph Mills -- Executive Chairman of the Board

Good morning, Eli.

Eli Kantor -- IFS Securities -- Analyst

We appreciate that hiring bankers may widen the scope of offers and potential alternatives. Based on the indications you've received to date, can you give us a sense of what your preliminary expectations are if no additional offers or alternatives come to light?

Joseph Mills -- Executive Chairman of the Board

Well, yeah. So, look, the transactions committee is obviously studying all of these various opportunities. And, again, we will hopefully be announcing here very soon the engagement of at least one, and possibly two, bankers to assist us in this process. As I went through this, we have a lot of opportunities ahead of us, whether it's an outright sale of the company -- which we're going to do what's right for our shareholders. But, truly, the in-basin consolidation, at least for me, personally, makes a lot more sense. There's a lot of opportunities here for us to be the consolidator and we certainly are evaluating a lot of combinations.

Ultimately, the math will prevail. Right? What makes the most sense long-term for our shareholders and for the company itself? So, while I can't give you any specific direction, suffice to say that we have a lot to consider. I'm actually pretty excited about the opportunity set. I think there is a lot of very good-looking opportunities ahead of us. And, no surprise, in a consolidation story, the opportunity set is to, obviously, cut a lot of expenses out of the system, both G&A and LOE, and ultimately that translates to equity value. So, we are absolutely looking at a number of opportunities simultaneously.

I can say that time is always of the essence. You'll find I'm a big believer, you move on things. When opportunities present themselves, you make decisions. And so that is clearly something that we're trying to do. Any M&A, whether it's consolidate or go the other way, takes some time. You have to evaluate these things and negotiations, etc. So, I wouldn't assume anything is imminent but we clearly are looking at a lot of opportunities and plan on moving on those opportunities as soon as we can.

Eli Kantor -- IFS Securities -- Analyst

On the liquidity front, can you talk about how a high-yield offering, non-core asset sale, equity offering, or any other potential options you're looking at rank as you look to not only boost your position but potentially finance some of the consolidation activity you just mentioned?

David Edwards -- Chief Financial Officer

Yeah. Let me take an overarching approach to talking about liquidity. So, working to enhance the liquidity situation has been one of our primary focuses right now. And if we revert back to earlier in the year, we had been pursuing traditional sources of capital to term out a portion of our credit facility. While the strength in the high-yield markets for upstream issuers is not quite where we want it to be to launch an inaugural bond, our thought was that we could issue attractive second lien capital, given the robust asset coverage and low leverage of the company. However, given indications of interest that we've received in the past few months on a strategic initiative, including outright sale or M&A, we're very mindful about issuing long-term capital right now as a liquidity solution. So, as such, we're actually working on alternatives where we can source shorter-term, low-cost capital to supplement our liquidity while we work down the path of strategic initiatives.

Eli Kantor -- IFS Securities -- Analyst

And then, lastly, going back to the spacing conversation, the spacing on the Earl unit looks consistent with the revised density assumptions that you discussed last quarter. Do you view the Woodford results there to be a reflection of a geologic anomaly unique to that unit or are the results there going to potentially have you revisit your spacing assumptions across a wider area of your footprint?

Joseph Mills -- Executive Chairman of the Board

No, that's an excellent question. Yeah, look, I think it's more localized geology there. And so we clearly -- look, the Woodford, we probably spaced it -- we did space it too tightly but I think it's more localized to that unit and maybe that immediate little area. I do not want you to infer that the Woodford is not an acceptable target over a broad area. That is not true. We're very excited about the Woodford as we are the Mayes. The truth is, in the Earl -- and, again, you saw the rates on the Mayes -- we've encountered a second bench in the Mayes there that we're very excited about. So, that actually opens up a bigger opportunity set for us in that localized area for the Maybe. But, yes, the Woodford there, very localized, is not what we expected. It's a little tighter and so we're going to pivot. But, again, it's not over a broad area. It's very, very localized.

Eli Kantor -- IFS Securities -- Analyst

Great. Thank you.


And this concludes our Q&A session for today. At this time, I'd like to turn the call back over to Mr. Joe Mills for closing remarks.

Joseph Mills -- Executive Chairman of the Board

Great. Thank you. Well, listen, ladies and gentlemen, I first want to thank you for your time this morning to listen to our story. I remain very excited. As I said earlier, I think this will be a transformative year for our company. I'm very excited to be here as a part of the team. We really have an exceptional team here and so we're really focused on the future right now. So, with that, we look forward to follow-up calls and, certainly, at these upcoming conferences -- and I think we're going to be attending the Stifel and the J.P. Morgan conference here in the next month. So, hopefully, I get a chance to meet many of you guys at those. So, with that, thank you and I hope everyone has a great day.


And this does conclude today's conference call. You may now disconnect.

Duration: 43 minutes

Call participants:

Alyson Gilbert -- Manager of Investor Relations

Joseph Mills -- Executive Chairman of the Board

David Edwards -- Chief Financial Officer

Derrick Whitfield -- Stifel -- Analyst

Ronald Mills -- Johnson Rice -- Analyst

Irene Haas -- Imperial Capital -- Analyst

Eli Kantor -- IFS Securities -- Analyst

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