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Gulfport Energy Corp (NASDAQ:GPOR)
Q1 2020 Earnings Call
May 9, 2020, 9:00 p.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Greetings, and welcome to Gulfport Energy's First Quarter 2020 Conference Call. [Operator Instructions]

I would now like to turn the conference over to your host, Jessica Antle, Director of Investor Relations.

Jessica Antle -- Director, Investor Relations

Thank you, and good morning. Welcome to Gulfport Energy Corporation's First Quarter 2020 Earnings Conference Call. I am Jessica Antle, the Director of Investor Relations. Speakers on today's call include David Wood, Chief Executive Officer and President; and Quentin Hicks, Executive Vice President and Chief Financial Officer. In addition, with me today available for the question-and-answer portion of the call is Donnie Moore, Executive Vice President and Chief Operating Officer.

I would like to remind everybody that during this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and business. We caution you that the actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we may make reference to non-GAAP measures. Reconciliations to the comparable GAAP measures will be posted on our website.

I would also like to note that the company intends to file a proxy statement and certain additional proxy materials in connection with the solicitation of proxies for its 2020 annual meeting. Shareholders are strongly encouraged to read the company's proxy statement and all other documents filed with the SEC carefully when they become available because they will contain important information. We will not comment on matters related to the 2020 annual meeting on this call. An updated Gulfport presentation was posted yesterday evening to our website in conjunction with the earnings announcement. Please review at your leisure.

At this time, I would like to turn the call over to David Wood, CEO of Gulfport Energy.

David M. Wood -- President, Chief Executive Officer and Director

Thank you, Jessica. Welcome, everyone, and thank you all for joining us this morning. I hope all of you, your families and your friends are staying safe and healthy during this challenging time. Before I get into our quarterly results, I wanted to touch on the steps we've taken at Gulfport in response to the COVID-19 pandemic to protect the health and safety of our staff and service providers in the continuity of our business.

As part of our business continuity plan, all office employees have transitioned to remote work, remaining fully committed as they work from home and continue being engaged in our day-to-day business. Our field operations staff have done a terrific job ensuring that our operations have continued without significant disruption while most importantly maintaining safe operations. We have formed an internal return-to-work task force to develop a detailed plan of how and when we will return to work at our physical offices, but no specific date has been set at this time. Our top priority is and always will be the safety and health of our employees, contractors and communities in which we operate.

Overall, I'm tremendously proud of how we've responded as an organization, and I want to recognize and thank all our teams for their focus, dedication and perseverance through this extraordinary time. The COVID-19 pandemic is causing a slowdown in both the global and domestic economy, which has resulted in severe demand declines for all fossil fuels heavily weighted to the oil and natural gas liquids markets. Oil prices have traded at 20-year lows and a dramatic reduction in capital spending from our oil-weighted peers has resulted in expectations for associated gas production to decline in the coming months and possibly through 2021.

This expected decline in associated gas from oil-weighted peers in addition to reduced capital spending from the U.S. gas-weighted producers has led to a recent increase in natural gas prices, especially as we look at the strip in late 2020 and 2021. With approximately 90% of our production being natural gas, we are well positioned to benefit from a gas price rally. We expect that U.S. gas production will decline over the next several quarters and believe this decline could lead to a tightening of the gas supply demand balance, especially if the domestic economy returns to a more normalized state in the near term.

However, we remain cautious as there are still many unknowns surrounding the short-term and long-term impacts of COVID-19 on domestic demand for gas. We are also cognizant of the potential supply response as prices approach $3. Considering all of these factors, we continue to believe medium-term natural gas prices will remain range-bound and consistent with our previous $2.60 to $2.90 per MMBtu projections. As we reach these levels in the forward strip, we will take advantage by hedging our future production, currently targeting the upper end of that range for 2021, and I will let Quentin provide more detail on what we have secured to date during the recent uptick in pricing.

During these unprecedented times, we continue to execute on our 2020 capital budget we laid out in February and remain committed to maximizing cash flow generation, reducing costs and ensuring strong liquidity through the remainder of 2020. For the first quarter, we reported approximately $16.6 million of adjusted net income and generated $128.3 million of adjusted EBITDA. Gulfport's operating cash flow before the changes in working capital and inclusive of capitalized expenses totaled $86.7 million, and due to our front-end-weighted capital program, resulted in an outspend of roughly $50 million for the quarter.

As planned in our original 2020 budget, as we reduce activity throughout the year and capital expenditures decline, we expect to begin generating free cash flow during the second half of the year. During the first quarter of 2020, as expected, our average daily production declined following a muted level of activity during the fourth quarter of 2019. Our production was lower than expected by about 5%, primarily because of delays in placing several new Utica wells online during the quarter. These delays were due to a combination of third-party midstream constraints, inclement weather and our operational schedule shifting.

Our incurred capital expenditures for the first quarter came in well below expectations partially because of the same operational schedule shifting as well as continued drilling and completion efficiency gains and lower service costs. We reiterate our original budget to invest approximately $285 million to $310 million across our asset base during 2020 and currently expect to come in at or below the low end of this range. Due to very low oil and natural gas prices, we plan to shut in a portion of our operated production in the next few months, including a large number of vertical-producing wells in the SCOOP. We forecast these shut-ins to impact our near-term production by less than 20 million cubic feet of gas equivalent per day, and we'll continue to monitor pricing daily, potentially extending shut-ins should prices warrant.

As mentioned earlier, these are unprecedented times and we continue to evaluate not only our response, but also that of other producers. There is much uncertainty around associated gas volumes and the overall impact of what we might potentially see from shut-ins during 2020 on both our operated assets and those of our non-operated partners. As we sit here with one quarter of the year in the books and a marked improvement in natural gas prices ahead for us or later in 2020 and early 2021, we are exploring opportunities to take advantage of this and maximize returns for our business. Notwithstanding the uncertainties that COVID-19 impacts bring, being able to reshape our production ramp toward better pricing can add meaningful value, and we are looking closely at what that means to both the production guidance for the year and the timing of overall capital spend in 2020.

Considering all of these factors, Gulfport's previously provided production guidance for the full year 2020 should no longer be relied upon. On the cost front, we continue to focus on increasing efficiencies and improving our cost structure. As expected, our individual expense line items settled at the high end of our budgeted range due to the lower production volumes during the quarter. We expect our per unit cost to decline through 2020 as our volumes increase and we realize economies of scale. In addition, we have a number of ongoing initiatives to place to reduce our cost structure across the business, and Quentin will provide more details in his comments.

Lastly, we improved our balance sheet during the quarter through discounted bond repurchases, and we reduced total long-term debt by approximately $79.6 million as of March 31, 2020, when compared to year-end 2019. Quentin will touch more on our bond repurchases to date, but I'm very pleased with our efforts to improve our balance sheet in this environment.

Turning to our operations. We had an exceptional quarter on the efficiency front in the field. First quarter of 2020 marked the best quarter to date in both our core operating areas with respect to drilling days, achieving the lowest average spud to rig release metrics since entering both the Utica Shale and the SCOOP. We were also very active on the completion front, and as of March 31, we have completed over 70% of our planned frac schedule in the Utica and all of our planned 2020 frac activity in the SCOOP. It is important to note these results are following a muted level of activity during late 2019, with the majority of our equipment and crews restarting both safely and effectively during the quarter. Great credit to Donnie and his operational teams in making this all happen.

In the Utica, we spud seven gross wells during the quarter and currently have one rig drilling ahead in the play. The wells released had an average drill lateral length of 10,200 feet, and when normalizing to an 8,000 foot lateral, we average a spud to rig release of just 17.7 days, down 10.6% over full year 2019 results. Our 2020 program is focused on maximizing lateral lengths to allow us to deliver more with less. I am proud of the team for this record quarter at the drill bit.

Turning to completions in the Utica Shale. We began the year active and completed 15 wells during the quarter with three additional wells in progress at the end of March. The wells completed had an average stimulated lateral length of 11,500 feet, which includes four of the longest laterals completed to date by Gulfport in the play, ranging from 16,000 to nearly 18,000 feet. Incorporating both the drilling and completion activities during the first quarter of 2020, we estimate that Gulfport's Utica well cost averaged $980 per foot of lateral, approximately 10% below our budget of $1,100 per foot and $830 per foot of lateral when including D&C only. This improvement in our well cost is significant for our future development and highlights our drive to deliver a leading cost structure in the basin.

Switching over to the SCOOP. During the first quarter, we spud five gross wells and currently have one rig drilling in the play. The wells released had an average lateral length of 9,500 feet, and when normalized to a 7,500-foot lateral, the wells averaged a spud to rig release of 37.4 days during the first quarter, a decrease of 32% when compared to our 2019 program average, and as I mentioned, the best quarter-to-date since entering the play.

When comparing first quarter results to past activity, Gulfport delivered one well with a spud to rig release of less than 40 days during 2019 and zero in 2018 and 2017. To date, three of the four wells drilled have been sub-40 days. These improvements were achieved while we were adding a new rig, increasing measured depths and increasing lateral lengths. Our first quarter performance exemplifies our focus on identifying areas of improvements, and we look to carry forward this momentum throughout the year. We established two Gulfport records during the first quarter, releasing a well with a spud to rig release of 39.8 days and subsequently breaking this with a new record of just 32.5 days, both occurring in the same quarter.

On the completion front, during the first quarter, we completed and turned to sales four gross wells with an average stimulated lateral length of 6,500 feet. Due to efficiencies on the pad and the current service cost environment in the basin, this activity came in roughly 30% below our forecasted 2020 SCOOP completion budget. Our activity in the first quarter completes our planned frac and turn-in-line program for the SCOOP during 2020. Incorporating both the drilling and completion activities, during the first quarter of 2020, we estimate that Gulfport's SCOOP well cost averaged approximately $1,080 per foot of lateral, approximately 30% below our budget of $1,500 per foot, and $1,065 per foot of lateral when including D&C only. We are determined to deliver consistent repeatable results in the SCOOP, and our first quarter progress highlights our continued emphasis on identifying, implementing and realizing efficiencies in this play.

In summary, while the macro environment was extremely volatile and uncertain, our continued focus on increasing efficiencies and reducing costs led to solid progress during the first quarter of 2020. We have a highly talented team at Gulfport who continue to aggressively manage costs, to enhance margins and increase free cash flow. We continue to execute on our 2020 capital budget provided in February and remain committed to exercising capital discipline, maintaining strong liquidity and evaluating all opportunities to enhance value for our stakeholders.

With that, I will turn the call over to Quentin for his comments.

Quentin R. Hicks -- Chief Financial Officer

Thank you, Dave, and good morning, everyone. As Dave indicated, we reaffirm our full year 2020 capex and cost guidance and are making every effort to improve our capital performance and per unit operating cost as we move through the year. During the first quarter, Gulfport incurred $127 million in operated D&C capital and $3 million in nonoperated D&C capital. In addition, land expenditures incurred totaled approximately $5 million in the first quarter of 2020. We currently expect roughly 75% to 85% of our capital budget to be incurred during the first half of 2020 and as a result are positioned to generate free cash flow during the second half of 2020.

During the first quarter, production averaged 1.05 billion cubic feet of gas equivalent per day, composed of 90% gas, 7% natural gas liquids and 3% oil. During the first quarter, our realized natural gas price before the effect of hedges and including transportation costs settled at approximately $0.69 per Mcfe below NYMEX prices, better than our guidance range of $0.70 to $0.80 per Mcf. As previously discussed, our 2020 guidance includes expected firm transport fees incurred during periods when our production falls below our firm transportation commitments, primarily in the SCOOP beginning in the second quarter. We continue to work to improve these realizations through midstream optimization efforts but are not reflecting these opportunities in our current guidance.

We reaffirm our full year basis differential guidance of $0.70 to $0.80 per Mcf and continue to work hard to drive results toward the low end of this range. During the first quarter, before the effect of hedges, our realized oil price came in at $2.55 below WTI. In the SCOOP during the first half of 2020, we have a large portion of our oil volumes under more seasonal contracts versus month-to-month agreements, which improved our realizations in the first quarter. This also provides flow assurance, and to date, we have not had any significant issues transporting our oil volumes. We continue to work with purchases in the basin to optimize our oil gathering contracts and are still guiding toward a full year of $4.50 to $5 discount to WTI, but we hope we can do better.

Turning to NGLs. Before the effect of hedges, our realized NGL price came in at approximately 33% of WTI. We reaffirm our guidance to be 30% to 35% of WTI for the full year of 2020. Our realized prices continue to be supported by our strong hedge position, and during the first quarter of 2020, we realized a hedge settlement gain of $0.74 per Mcfe or $70 million. We currently have 774 million cubic feet per day of gas hedged with swaps at a price of $2.91 per MMBtu in the second quarter, which represents the majority of our production for the quarter. Given the increase in natural gas strip pricing we have seen in the second half of 2020, we recently added additional natural gas swaps in the second half of the year, and we currently have approximately 357 million cubic feet per day hedged at an average swap price of $2.86 per MMBtu.

We also recently started to build our hedge book for 2021. We currently have 250 million cubic feet per day hedged in 2021 at an average floor of $2.46 and a ceiling price of $2.81 per MMBtu. Although these collars are slightly below our medium-term price expectations of $2.60 to $2.90 per Mcf, they allow us to achieve the midpoint of that range and were also instrumental in getting our borrowing base successfully approved at the $700 million level. We also recently chose to unwind our 2020 oil hedges ahead of the borrowing base redetermination, representing roughly 5,000 barrels per day for over $40 million in cash proceeds. These proceeds allowed us to repay a portion of our outstanding borrowings on the revolver and we subsequently took the prudent step of reestablishing a floor for our oil production during the third and fourth quarter of 2020 at $35.60 per barrel.

Maintaining a strong strategic hedging program is an important element to supporting the long-term economic development of our assets, and we continue to look for ways to add hedges for downside protection and to support our cash flows. In terms of cash expenses, our per unit operating expense, which includes LOE, production tax and midstream gathering and processing totaled $0.82 per Mcfe during the first quarter. These expenses were in line with our 2020 full year guidance and were slightly below the first quarter 2019 levels.

First quarter LOE totaled approximately $0.17 per Mcfe, $0.01 above the high end of our guidance range due to absolute volumes being lower during the quarter. We forecast LOE to be to trend lower as our production increases and expect to be within the previously provided guidance range for the full year. Production taxes for the quarter totaled $0.05 per Mcfe, at the low end of the expected range, due to low pricing due to the low pricing environment during the quarter. Midstream gathering and processing expenses totaled approximately $0.60 per Mcfe in the first quarter, at the high end of the range, and similar to LOE, we expect our per unit midstream expense to decline throughout the year as we bring online incremental production.

Recurring G&A, including both cash and capitalized portions, totaled $17.6 million during the first quarter. On an annualized basis, the first quarter G&A spend is in line with our full year guidance range of $69 million to $74 million. As we move through the year, we continue our relentless focus on cost improvements, and as I mentioned in February, we are turning over every stone working to improve our cost structure. We have several financial initiatives in place to reduce costs and are asking every employee throughout the organization to do their part to enhance margins.

During the first quarter, we began reaching out to all of our vendors and service providers across all aspects of our business in an effort to reduce costs. We continue to look for opportunities to further improve our midstream expenses and are working aggressively at mitigating our excess firm transport costs. We have active ongoing constructive discussions with many of our midstream providers surrounding optimization and cost reduction efforts and are cautiously optimistic we will improve our midstream cost structure through the remainder of the year. In the field, echoing Dave's comments, our well cost per lateral foot reported in the first quarter are a testament to these ongoing initiatives and the focus across the company to increase efficiencies, reduce costs and enhance margins.

Moving to the balance sheet. We recently completed our spring borrowing base redetermination. And while we've seen an uptick in 2021 gas strip prices, unfortunately, the bank price decks were not reflective of this upward momentum. Overall, the banks remain very cautious and conservative, and that is reflected in our $700 million borrowing base. As we look toward the second half of 2020, we will need to renew the revolving credit agreement as it matures in December of 2021. Given the bank's current risk-off sentiment, we are focused on improving our balance sheet and cost structure as much as possible prior to the renewal of this facility.

This conservatism and risk-off sentiment demonstrated by the banks permeated through all aspects of our business over the last several months, including surety providers, who have increased the required levels of credit support, which has resulted in current letters of credit outstanding of approximately $327 million. We do not expect any significant further letters of credit postings and are actively working to reduce the current letter of credit postings over the next several months. Our ability to move postings to surety bonds becomes more promising as gas prices improve and our balance sheet quality improves.

Reflecting the previously mentioned letters of credit and the current revolver draw of $108 million, current liquidity totals approximately $269 million, which provides us adequate liquidity to fund our 2020 plan at current strip pricing. We continued our discounted bond repurchase program through the first four months of the year. Year-to-date, we have retired approximately $73 million of senior notes for $23 million in cash spend, reducing our net debt by $50 million. In total, since middle of 2019, we have reduced our unsecured notes outstanding by $263 million, capturing roughly $102 million in discount and reducing our annual interest burden by $11 million.

We continue to look for opportunities to reduce our leverage profile, and with our bonds continuing to trade around $0.50 on the dollar, we think there are opportunities to capture this discount and reduce our leverage while improving our cash flow. Our Board views liability management in the context of risk management, reducing our downside risk to ensure we benefit as gas prices rebound to more rational levels in the future. We recently engaged Tudor, Pickering, Holt, Perella Weinberg and Kirkland & Ellis to help us more formally explore these options, and we'll provide an update on these efforts when appropriate. Our goal is to improve our balance sheet in a way that unlocks value for all of our stakeholders.

Before I turn the call back over to Dave, I want to address the recent tax benefit preservation plan, which was put in place by Gulfport's Board of Directors last week. As of December 31, 2019, Gulfport had approximately $1.3 billion of federal net operating losses, also known as NOLs. These NOLs are a valuable asset to the company as they can be carried forward to future years and used to offset future taxable income and save a significant amount of future cash tax expense. Under IRS rules, the ability to utilize these NOLs in the future could be significantly impaired if a so-called ownership change were to occur within the meaning of Section 382 of the internal revenue code.

Generally, an ownership change under this definition occurs if the percentage of the company's stock owned by one or more of its 5% holders increases by more than 50% over a three-year rolling period. In light of the recent trading volumes in the company's stock in midst of the current market disruption, the Board determined it was appropriate to adopt the tax benefit preservation plan to prevent a significant limitation on our ability to utilize NOLs in the future.

With that, I'll turn the call back over to Dave for closing remarks.

David M. Wood -- President, Chief Executive Officer and Director

Thank you, Quentin. In closing, while it is constructive to see the increase in the 2021 natural gas strip, the near-term price dynamics in 2020 remain uncertain. Given this, we remain focused on executing a returns-focused business plan with a strategy aimed at reducing costs, operating safely, maintaining liquidity and positioning the company for long-term value creation. Our 2020 outlook and financial plan to substantially reduce capital spend and preserve our quality inventory ensures Gulfport is well positioned to manage and enjoy the benefits of a commodity rebound as it occurs, which may be just ahead of us.

As we have said before, size and scale matter, and the management team continues to explore opportunities to increase scale and bring further efficiencies to maximize returns. We remain committed to our vision of transforming Gulfport into a sizable natural gas-weighted producer with a strong balance sheet and leading structure that allows us to generate sustainable returns within our medium-term price range of $2.60 to $2.90 per MMBtu.

This concludes our prepared remarks. Thank you again for joining us for our call today, and we look forward to answering your questions. Operator, please open the phone lines for questions from the participants.

Questions and Answers:

Operator

Thank you. [Operator Instructions] Our first question today comes from Jason Wangler of Imperial Capital. Please proceed with your question.

Jason Wangler -- Imperial Capital -- Analyst

Hey, good morning guys. I wanted to ask, you kind of mentioned it, I think, Quentin, on the hedges that you added specifically for 2021. As you think about hopefully building that hedge book up, is there a preference in swaps versus collars? Or perhaps there was a reason there? Just kind of curious what your thoughts are as you kind of build that.

David M. Wood -- President, Chief Executive Officer and Director

Yes, Jason, this is Dave. I hope you're doing well. Your family is doing well. And I hope everybody else that's on the call is managing through this very difficult time that we're in. I think our overall goal in 2021 is to end up with us hedge positioned as strong as we can, as close to $3 as we can. I think at the time we placed those collars in, we were really trying, as Quentin mentioned in his opening remarks, to address the spring redetermination process. I think we've added subsequent collars better than that, still within our price range.

So I'm pleased with where we are today. It represents about 1/4 of our projected production today for 2021, and we hope to be able to build upon that. As far as the specifics of why that particular mechanism, we don't have a particular bias. It's really just trying to accomplish the overall goal, which is to build a hedge book as complete as possible and as close to $3 as possible. And I'd hope Quentin to add anything to that.

Quentin R. Hicks -- Chief Financial Officer

Yes. The only thing I'd add is we kind of hand this expectation of $2.60 to $2.90 price, and we wanted the banks were using a price deck in the redetermination that had somewhere around a $2.10 or $2.15 on average price for 2021. So adding collars with a floor of $2.46 really added value to from the bank's perspective and allowed us to get to that $700 million borrowing base. And it also allowed us to achieve the midpoint of that $2.60 to $2.90 range of $2.75 because the collar range again was $2.46 by $2.80 or $2.81. So that was the reason for that. Going forward, we'll look at collars and swaps, targeting probably the higher end of that $2.60 to $2.90 range.

Jason Wangler -- Imperial Capital -- Analyst

Okay. That's helpful. And then as you mentioned, I think, and you have mentioned in the past, thinking that gas prices are going to kind of hopefully do better here as we go throughout the year. There's still some wells, obviously, that you guys are bringing online. Is there a way to, I guess, kind of bring those on in a pattern that you guys see as fit? Or is that schedule kind of fixed based on what you guys have already set up?

David M. Wood -- President, Chief Executive Officer and Director

Jason, I think that really gets to the key issue that we're trying to manage for this year. Clearly, over the last few weeks, the outlook for natural gas has changed, and it's become more positive going forward. And we want to take advantage of that. We see the second half of the year being stronger. We also see 2021 being a better year, which follows on from the comments that Quentin just made regarding wanting to get our hedge book built as best we can for next year because the potential is that 2021 could be a very good year for this company. Because any time gas prices get close to $3, I think we do pretty well.

So what we're looking to do now is through a program of choke management and also delaying some wells coming on and managing how our production profile looks for the rest of the year is move some molecules from this low price part of the year into the higher price part of the year. And when we set our budget and plan together and published it in February, really our peak production was in 2Q, clearly not the best time to have your peak production. And so what we're doing now is working across our business to move those molecules so that we can maximize the returns.

And what I think will happen here is once we get our plan for the remainder of this year and also get our hedge book and our plan in sight for next year is we'll come back out with a published guidance in terms of production for this year and with a look into 2021. And I think people will see that, that move on top of the way the gas price has changed actually increases the value to our company. So that's the overall plan, Jason, is what we're trying to accomplish.

Jason Wangler -- Imperial Capital -- Analyst

I appreciate the color. Thank you.

Operator

The next question is from Welles Fitzpatrick of SunTrust. Please proceed with your question.

Welles Fitzpatrick -- SunTrust -- Amalyst

Hey, good morning. I know it might be difficult to quantify, but can you guys talk at all to the expected impact of non-op shut-ins? And if those happen and accelerate, does it present an opportunity where maybe there could be some trading, some blocking up of the position?

David M. Wood -- President, Chief Executive Officer and Director

Yes. Welles, I think that's a good question. Actually, the vast majority of our production is operated. So really, the non-op component is relatively small. Donnie, I'd let you kind of provide extra color around that. But certainly, optimizing our footprint, as you aimed that question, Welles, I think is a good thing, and it's part of what we look at. So I'll let Donnie provide some color on that.

Donnie Moore -- Chief Operating Officer

Yes, Welles, this is Donnie. Yes, I mean, I think that is something that we're always continuing to try to do. As far as the non-op volumes, they're pretty small, as Dave alluded to, especially here in the SCOOP. We have small interest in a lot of different wells. So really not that impactful that I can see right now. But yes, we'll continue to try to work with others and see if we can block this acreage as well as up in the Utica, especially.

Welles Fitzpatrick -- SunTrust -- Amalyst

Perfect, thank you so much.

David M. Wood -- President, Chief Executive Officer and Director

Thanks, Welles.

Operator

The next question is from Steve Dechert of KeyBanc. Please proceed with your question.

Steve Dechert -- KeyBanc -- Analyst

Hey, guys. And I just want to get a better sense of the production cadence for 2020. Is 2Q down quite a bit from 1Q 2020 with 3Q and 4Q up a lot? Or is it more like 2Q is just down a little bit?

David M. Wood -- President, Chief Executive Officer and Director

Yes, Steve. Yes, so the way I'd look at it is we want the second half of the year with the higher prices to have more production. So moving the peak in 2Q, as I mentioned, to the right or into the third, particularly in the fourth quarter. So I would look at 1Q, 2Q as being pretty similar, is the way I would model it, with hopefully a better exit rate and higher production in 4Q. That's our plan.

Steve Dechert -- KeyBanc -- Analyst

Okay, great, thanks.

Operator

The next question is from Jane Trotsenko of Stifel. Please proceed with your question.

Jane Trotsenko -- Stifel -- Analyst

Good morning and thanks for taking my questions. Yes, the first question is regarding potential curtailments in Utica, especially in 2Q. In terms of duration of the potential shut-ins, is there like a certain natural gas price that you would like to see before bringing the volumes back online? Or is it just a matter of getting through 2Q?

David M. Wood -- President, Chief Executive Officer and Director

Yes, Jane, that's a good question. The production that we've curtailed here is about 20 million cubic feet equivalent. It's about 95 wells. So that tells you that they're very small producers, given that volume. It's about 80% gas. The remainder is liquids. It's the liquids piece on those very low-producing vertical stripper wells, if you will, that really creates an economic value. And as we've seen the falloff in oil prices, the economics of those wells have changed negatively.

And I think the appropriate step for us was just to say: "Hey, let's shut those wells in." As oil prices increase, which is going to be the important driver, we would look to bring those wells on. So as we currently look, let's call it two or three months, and then we'll hopefully see some price improvement to the point where some of those wells will come back on. But it's not a big volume, but I think it's an appropriate thing for us to do. The one thing that we did spend time looking at is, because those are old vertical wells for the most part, they do hold some of the leased footprint for us. And we wanted to make sure that we weren't in any lease jeopardy by shutting those wells in. So that was the thought around all of that.

Jane Trotsenko -- Stifel -- Analyst

I see. I see. The second question is on SCOOP. And I saw that you guys are running one rig in SCOOP and obviously completing and bringing wells online. What's the plan for that rig for the remainder of the year?

David M. Wood -- President, Chief Executive Officer and Director

Yes, I'll let Donnie fill in the his operations team is doing a great job, so I'll let Donnie make the comments on the rig.

Donnie Moore -- Chief Operating Officer

Jane, yes, I mean right now we've actually finished all of our completion work in the SCOOP at planned and budgeted for the year right now. So we'll kind of watch that as we go along. The rig should be and it's always been planned to be here all year. So it will continue drilling. And we'll also have the one rig up in the Utica. So we have one in each asset.

Jane Trotsenko -- Stifel -- Analyst

Okay. Okay. The last question is, if I may, on Midship project. If you could provide some color, such as, for example, how much is flowing on that pipeline and how the volumes are going to ramp up over time?

David M. Wood -- President, Chief Executive Officer and Director

Yes. Yes, I'll let Donnie again touch on that.

Donnie Moore -- Chief Operating Officer

Yes, Jane, as I think we've mentioned before, it's just getting started up this week. So just starting to move some volumes through it as that thing gets commissioned out. And it will continue to ramp up over the next coming weeks, really.

Jane Trotsenko -- Stifel -- Analyst

Awesome. Thank you.

David M. Wood -- President, Chief Executive Officer and Director

Okay.

Operator

Our last question comes from Dun McIntosh of Johnson Rice & Company. Please proceed with your question.

Dun McIntosh -- Johnson Rice and Company -- Analyst

David, just a quick question on kind of capital cadence over the remainder of the year. I know that previously you may have mentioned in the prepared remarks and I just missed it, but the plan is still for kind of 85% of capex in the first half of the year. And then I guess the thought is that you go ahead and complete those wells and then just wait to turn them in line in the back half of the year. And then taking that a step further, with the capex being so low in the second half and volumes ramping and hopefully into a higher price, you should be in a position to throw off some pretty good cash in the second half of the year. So how do you think of allocating that toward the revolver versus additional repurchases of your bonds?

David M. Wood -- President, Chief Executive Officer and Director

Yes, Dun, I think that gets to really some of the key things that we're trying to accomplish. So I think it's a very good question. Quentin in his prepared remarks said that we spend between 75% and 85% of our planned capital in the first half of the year. With this relook at how we want the production to shape for the remainder of the year, I think we can generate, as you said, better returns and more free cash than we thought originally we're going to generate. We need to get that all planned out. I think having the wells both behind choke and ready to come on production actually derisks that production profile. It's a lot easier given COVID-19 issues, etc., etc., to actually have things behind the choke to just bring them on when you need. So really, I see that as being one of the benefits.

As we hope the year is going to materialize and we do see that generation of free cash above where we had originally thought, then we can start to look at what 2021 looks like. And as I mentioned in one of the earlier questions, I really think 2021 can be a very good year for this company. It takes a couple of things for us to do that. It takes being able to hedge at somewhere closer to $3, which I think we've made a good start. And I think the strip is going to allow us to accomplish some of that. And then also, it means getting ready in the second half of the year to have wells ready to come on.

And so when we republish our guidance for the year in a few months or whenever we get it done, I think everybody will get a much closer view of what the second half activity would look like, and I'm not opposed to being a little bit more active, if all of the good things have happened, and that 2021 looks as promising as it is. So that's another reason for us taking a little pause here and taking a look at the business. So we could see some growth next year, if gas is at $3, I'm hopeful for that. And I think we want ourselves to be planned that way.

Dun McIntosh -- Johnson Rice and Company -- Analyst

All right. Great. And then maybe just kind of more of a macro question, basin specific. In Appalachia, I mean, at what point do you think that people start to kind of add rigs back and pick up activity, maybe not go forward specifically, but some of your peers? And do you think that there's a little bit of a risk baked in there with just the pressure that's been on this space and kind of you are getting some relief with falloff in associated gas production and as oil volumes get shut in, but on the other side of that, obviously, there's a lot of people that want to are going to be looking to take advantage of a higher price. So how do you kind of weigh the risk or think about the gas market as if it gets to a point where people start putting rigs back to work and the durability of price under a scenario like that?

David M. Wood -- President, Chief Executive Officer and Director

Yes, Dun, I think that gets to the real core issues as we look at the gas game. And as we mentioned in our remarks, I think $2.60, $2.90 has been our, what I call mid-term price view. It was that way last year. It's that way now. So I don't see any reason to change that. I think the dynamics as to why that range makes sense of change, certainly in light of the oversupply in oil and COVID-19. I think that when we start to see gas prices at the $3 range, I think that's going to be close to where it's going to get to. I see some people saying it's going to be $3.50 or $3.80 or $4. I think if it does do that, it will be very, very brief. And so I think more toward the $3 game.

I think the big question for this year is going to be where storage ends up and where demand falls. I think there's the opportunity in 2021, which is why I think 2021 has the chance to be a better year, kind of a $3 type price range, is because with reduced supply and potentially a winter that's not quite as full for storage in the end of 2021 versus where it is now, we could see some support around that. But people are going to drill into it, as you quite rightly say, or open up wells that are oil producers that have associated gas into that. So all of those factors suggest to me that this $2.90, $3 range is probably the upper part in general with occasional spikes above that. And we just need to be in a position to take advantage of it, which we are.

Dun McIntosh -- Johnson Rice and Company -- Analyst

All right, thank you. Thank you. I appreciate it.

Operator

[Operator Closing Remarks]

Duration: 46 minutes

Call participants:

Jessica Antle -- Director, Investor Relations

David M. Wood -- President, Chief Executive Officer and Director

Quentin R. Hicks -- Chief Financial Officer

Donnie Moore -- Chief Operating Officer

Jason Wangler -- Imperial Capital -- Analyst

Welles Fitzpatrick -- SunTrust -- Amalyst

Steve Dechert -- KeyBanc -- Analyst

Jane Trotsenko -- Stifel -- Analyst

Dun McIntosh -- Johnson Rice and Company -- Analyst

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