Murphy Oil Corp (NYSE: MUR) Q1 2020 Earnings Call Transcript

Murphy Oil Corp (MUR) Q1 2020 earnings call dated May. 07, 2020

Corporate Participants:

Kelly L. Whitley — Vice President of Investor Relations and Communications

Roger W. Jenkins — President and Chief Executive Officer

David R. Looney — Executive Vice President and Chief Financial Officer

Analysts:

Brian Singer — Goldman Sachs — Analyst

Leo Mariani — KeyBanc — Analyst

Gail Nicholson — Stephens — Analyst

Muhammed Ghulam — Raymond James — Analyst

Roger Read — Wells Fargo — Analyst

Presentation:

Operator

And good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation First Quarter 2020 Earnings Conference Call. [Operator Instructions]

I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Kelly L. Whitley — Vice President of Investor Relations and Communications

Good morning, Jessica. Good morning, everyone, and thank you for joining us on our first quarter earnings call today. Joining me from El Dorado, Arkansas is Roger Jenkins, President and Chief Executive Officer. And with me in Houston is David Looney, Executive Vice President, Chief Financial Officer; Mike McFadyen, Executive Vice President, Offshore; and Eric Hambly, Executive Vice President, Onshore. Please refer to the informational slides we have placed on the Investor Relations section of our website as you follow along with our webcast today. Throughout today’s call, production numbers, reserves and financial amounts are adjusted to exclude noncontrolling interest in the Gulf of Mexico. Slide one. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist may cause actual results to differ. For further discussion of risk factors, see Murphy’s 2019 annual report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements.

I will now turn the call over to Roger Jenkins.

Roger W. Jenkins — President and Chief Executive Officer

Thank you, Kelly. Good morning, everyone, and thanks for listening in today. On slide two, Murphy had a strong first quarter with total average production of 186,000 barrels equivalents per day, consisting of 66% liquids and a near-even distribution between our onshore and offshore assets. We spent a total of $365 million of capex in the quarter. This accounts for approximately 50% of our revised full year budget with a new midpoint of $740 million, representing a further $40 million decrease following our latest April one announcement on capex. While prices are much different now, we still achieved strong pricing before gains and hedge positions in the first quarter, thanks to our diverse oil-weighted assets that are close to markets. In particular, our realized oil price was slightly higher than WTI benchmark of $46 per barrel for the quarter.

I’ll now turn the call over to our CFO, Mr. David Looney, for our financial update.

David R. Looney — Executive Vice President and Chief Financial Officer

Thank you, Roger. In the first quarter, Murphy’s earnings were substantially impacted by a noncash after-tax impairment charge of $693 million as well as a noncash mark-to-market gain on hedges after tax of $283 million. As a result, we had a net loss of $416 million for the quarter or negative $2.71 per share diluted. However, on an adjusted basis, Murphy had a net loss of $46 million or negative $0.30 per diluted share for the quarter. The adjusted earnings back out the noncash impairment charge and mark-to-market hedge gain as well as a gain in noncash contingent consideration, all three of which totaled $363 million after tax. I’d also like to point out that the quarter’s results were negatively impacted by an expense workover in the Gulf of Mexico that cost us approximately $40 million. As you know, these expense workovers can cause significant fluctuations in our reported LOE. And this was certainly the case in the first quarter. I’m happy to report that the well was very successful and is highly economic even in this price environment. Slide four. Murphy’s cash from operations of $393 million sufficiently covered $376 million of property additions and dry hole costs in the first quarter, including $21 million of King’s Quay spending that we expect to receive upon closing.

As a result, we achieved $17 million of positive free cash flow in the quarter. And as Roger mentioned, the total capex in the first quarter was equal to 50% of our updated full year guidance. Thus, the remainder of the year will show a significantly decreased run rate than what we saw this quarter. The company continues to maintain strong liquidity with $1.8 billion available as of March 31, including just over $400 million of cash and equivalents. Further, our first debt maturity isn’t until June 2022 and is only approximately $260 million, providing us with flexibility to appropriately manage the company through this commodity price cycle. Given our concerns about the May and June pricing and storage dynamics, in late March, we entered into additional crude hedges of 20,000 barrels of oil per day for those two months at an average price of $26.45. Overall, when looking at the full year 2020, Murphy will have an average of 48,000 barrels of oil per day hedged at an average price of $54.35 per barrel.

Slide five. Construction of the King’s Quay floating production system, or FPS, remains on schedule with first oil expected in mid-2022. As we announced last quarter, we have a memorandum of understanding with ArcLight Capital Partners, LLC and are in the process of negotiating transaction documentation with all associated parties. Although all the parties involved in the negotiations have been subject to various stay-at-home mandates, we’re still making good progress on the documentation and expect to close in the second quarter this year. The agreements will call for reimbursement of all of our previous capital outlays for the FPS, including $125 million in 2019 and approximately $21 million in the first quarter of this year.

With that, I’ll turn it back over to Roger.

Roger W. Jenkins — President and Chief Executive Officer

Thank you, David. On slide seven, go through some operations for the quarter. Murphy produced a total of 42,000 barrel equivalents per day in the first quarter from Eagle Ford Shale, consisting of 74% oil volumes. As planned, we brought on 14 wells online in the quarter in our Karnes and Catarina acreage with an average drilling and completion cost of less than $4.9 million per well. Our revised Eagle Ford Shale budget of $200 million for 2020 supports bringing online an additional 11 operated wells as well as five non-operated wells in the second quarter. We have no plans for the second half of the year to add additional wells. Slide eight. Our Kaybob Duvernay production remained steady at near 10,000 barrel equivalent a day for the quarter. And the carry obligation with our partner is now fully satisfied with 11 operated wells brought online. To date, these wells are performing in line with type curves at high liquids volumes. And given that most of our activity was originally planned in the first quarter, Murphy will only bring online five operated wells and six non-operated wells for the second quarter, thereby wrapping up activity for the year. Slide nine and Tupper.

For the first quarter 2020, Murphy produced 246 million cubic feet per day. four wells were drilled during the quarter, none of which will be completed until 2021. We also recently entered into an additional fixed price forward sales contract for the delivery of 25 million cubic feet per day at the AECO hub at an average price of CAD2.62 per thousand cubic feet for all of 2021. Moving on to slide 11 and the Gulf of Mexico. Murphy’s first quarter Gulf of Mexico operations produced 86,000 barrel equivalents with 85% liquids. The first well in our Front Runner rig program accounted more than 250 feet of net pay and came online with strong peak rate. As a result, we’re evaluating a nearby subsea exploitation opportunity from the outcome of this well. The workover is complete at Cascade four, as David mentioned earlier, along with the subsea equipment repair at the Neidermeyer field with volumes now back online. Murphy’s partner spud the Mt. Ouray exploration well this week with a net assumed cost to Murphy of $7 million. While not in the slide pack today, we’re pleased to see continued success in offshore Mexico near our Block five acreage with two discoveries announced just this week in the same rock and structures as seen in our prospects. Slide 12, further in the Gulf here.

The revised Gulf of Mexico budget of $315 million includes adjusting the 3-well rig program at Front Runner to two wells, no longer drilling or completing certain operated and non-op projects and shifting timing of other projects. Murphy is near completion of the Dalmatian 134 number two workover with the wells scheduled to come online in the near term. And expenditures for our long-term projects, such as St. Malo waterflood and Khaleesi/Mormont and Samurai, are still planned for 2020. Additionally, as mentioned earlier, construction of King’s Quay floating production system is underway. And timing is on track for first oil volumes to flow in mid-’22 as per original plan. On COVID on slide 14. As we’ve seen, we’re working in an unprecedented low oil price environment caused by the dual actions of a price war and, of course, COVID-19. Murphy’s main goal is to continue to operate safely through this challenging environment. And we’ve implemented protocol across our field and office locations to protect everyone’s health and safety with no impacts to production, project execution, supply chain or construction. At our field locations, Murphy’s adopted testing, screening and tracking with new standards for health protocol and mandatory screenings for offshore personnel. For office staff, the company implemented work from home and incorporating learnings in our plans for returning to our offices soon.

On slide 15, since crude oil price has collapsed in early March, we’ve previously revised our capital spending down twice with today’s announcement being our third reduction. As stated previously, the midpoint of our 2020 budget is now $740 million. We’ve reduced our budget across our portfolio and note that no onshore wells are planned to come online in the second half of this year. Murphy has also renegotiated contracts across supply chain, optimized operations and offshore workovers leading to $30 million to $40 million in operating cost reductions. Further, we have reduced executive and Board compensation as well as cut our quarterly dividend by 50%.As announced yesterday, after completing a thoughtful and rigorous review of the company’s operations and expenses and exhausting all cost saving initiatives, Murphy made the reluctant and difficult decision to close our headquarters in El Dorado and relocate our corporate headquarters to our existing office in Houston, Texas. Additionally, we’ll be shutting down our office in Calgary. With the closure of these two offices, we’ll be downsizing staff. We believe this will enhance our collaboration and operational efficiencies while achieving lower G&A expenses and expect these actions to be complete in the early third quarter of 2020. There will be no impact to field operations in neither United States nor Canada.

Overall, we expect to realize G&A and related cost savings, excluding the aforementioned restructuring charges, of approximately $50 million in 2020 and more than $100 million in 2021. Looking ahead to the second quarter. Production averaged approximately 179,000 equivalents per day for the month of April with approximately 7,000 barrel equivalents not produced due to curtailments and shut-ins, primarily in onshore. We anticipate 40,000 barrels equivalent production shut-in and curtailments for the month of May with the majority planned from offshore wells. At the time we made the decision on nominations in the Gulf of Mexico, prices were very low. Since that time, prices have improved greatly for June, especially without and without significant changes, we should flow in June in the Gulf of Mexico. But as we all know, it can be quite volatile in oil prices, and we’ll have to continue to monitor that situation. With a revised capital plan, significant operational and G&A cost reductions, Murphy remains competitive in a low-cost price environment. We’ve prepared the company the past several years through oil-weighted developments and transactions and appropriate balance sheet management. This has now come to fruition with approximately $1.8 billion of liquidity and no near-term debt maturities. Our streamlined portfolio with diverse assets provides flexibility through the cycle.

On slide 17, Murphy’s top priority always has been and will be maintaining the health and safety of our employees, contractors and communities where we work. Our strong safety culture and planning so far has prevented COVID from impacting any of our operations globally. Beyond that, we recognize in price cycles such as these that liquidity and financial strength is important. And we made the tough decisions by reducing spending and costs across all fronts in order to maximize our future cash flows. We’re able to preserve our largest resources and our unique exploration upside for the future. In closing, on behalf of my executive team, I want to express my appreciation to our employees, who are the driving force behind our company and culture, and to our dedicated employees in El Dorado and Calgary and to thank you again for all of your contributions. The El Dorado office closure is particularly painful for us. This company was founded here and has been an integral part of this community for many years.

With that, I’ll turn the call over to the operator for questions.

Questions and Answers:

Operator

Thank you. [Operator Instructions] Your first question comes from Brian Singer with Goldman Sachs. Please go ahead.

Brian Singer — Goldman Sachs — Analyst

Thank you.

Roger W. Jenkins — President and Chief Executive Officer

Good morning Brian.

Brian Singer — Goldman Sachs — Analyst

Good morning And Roger, on a personal note, wanted to wish you good health on your recovery.

Roger W. Jenkins — President and Chief Executive Officer

Oh, I’m back, Brian, going nowhere.

Brian Singer — Goldman Sachs — Analyst

That is great. First question is with regards to the King’s Quay. You did mention no change to the original plan mid-2022. And I just wondered if there are any changes you see either up or down to the cost structure and then whether there are any risks to the timing as a result of what’s going on.

Roger W. Jenkins — President and Chief Executive Officer

No. We feel real comfortable. The project execution, we did pull out our expat staff out of Korea at a very appropriate time and a very good call by our safety management team. But we continued on with local staff at Hyundai shipyard, where we’re working, was able to continue to work the entire time. The well beyond 50% complete on the project, we’ve lined up all the vessels to move the structure to the Gulf of Mexico, feel real good about it. I think from a cost structure side, of course, that contract was signed a while back. But we rebid the rig for that. And that bid is due like tomorrow. And I anticipate that to be very favorable to us. Many of the other contracts have been reworked. And we’re seeing a pretty good shape on the cost structure. Certainly, after buying a project like LLOG with significant work to be done, you’re quite fortunate almost a year later to have the capex be identical or slightly lower to that with all those assumptions. So we’re certainly in that position, and we anticipate help from the rig and the execution. And we think this is a good project. It certainly has break-even prices in the $30 range for the rest of the field life, and feel real good about those projects and want those projects coming forward. It’s going to lead to a nice production uplift for us at that time to the original plan when we purchased it.

Brian Singer — Goldman Sachs — Analyst

Great. And then my follow-up is with regards to the Eagle Ford. Can you just talk a little bit more about some of the price points at which you would bring back completion and drilling activity and how you think about price points for maintenance mode versus going to maintenance mode versus going to growth mode?

Roger W. Jenkins — President and Chief Executive Officer

Well, at this time, Brian, I think me and everyone else that’s in this type of role are looking at liquidity and slowing down and not rushing to bring wells online in this price environment. It’s all about what we can cover with our cash flow and capital allocations decisions in 2021 and what brings forward the best EBITDA and best returns for our company. It’s not really about getting back on to any type of growth profile. And we have to continue to get stabilized there. We’re in pretty good shape on shut-ins in the Eagle Ford. There were some curtailments for some other reasons in the month of April. But we’re not caught up in that today. We have nice we have pricing available due to our real advantaged situations, Flint Hills and Phillips in Corpus, where we sell oil in the Eagle Ford real close to delivery points, putting us greatly advantaged in these type of shut-in situations. So we have to get that stabilized and get into our 2021 budget to maintain kind of a mid-30s kind of production, the Eagle Ford probably cost us about $400 million. For that in all of our onshore, our Eagle Ford is probably only $325 million. So working on that and working on our long-term projects for next year and working through that capital and trying to improve capital allocation to deliver higher value, and EBITDA is our focus right now, not really determining a price to get back on the growth plan again or anything like that at this time.

Brian Singer — Goldman Sachs — Analyst

Great, thank you.

Roger W. Jenkins — President and Chief Executive Officer

Thank you.

Operator

Your next question comes from Leo Mariani with KeyBanc. Please go ahead.

Roger W. Jenkins — President and Chief Executive Officer

Hello, Leo. Good morning.

Leo Mariani — KeyBanc — Analyst

Good morning here, guys. Just a first question here on LOE. I certainly noticed that your LOE in the U.S. was up quite a bit in the first quarter. I know you guys had a significant workover going on that I think drove that higher. Just trying to get a sense of how we should expect that to trend in the next couple of quarters. I think you guys said you had a Dalmatian well workover going on in the second quarter. So should we continue to see LOE a little bit elevated in the U.S. in the second quarter? Is it going to come down later in the year? Anything you can tell us on kind of trajectory there.

Roger W. Jenkins — President and Chief Executive Officer

What happens in the Gulf of Mexico, we usually can get around $9 or $10. When we have one of these workovers in the quarter, it goes up about $4. And we have another one in the second quarter in the original plan, was for it to be another $40 million-type workover. But the well is practically complete today with a great execution by our team there, almost for high fee expense. So looking forward to the second quarter being better than the first, even though they have a workover. And then in our Eagle Ford Shale, kind of a $9 gain in a typical run rate there but still need to bake in the continued savings that our procurement team is coming up with and our execution team. We continue to beat cost out of the system, and we’ll continue to do so. And I just think the 1st of the year, had these workovers in it, we’ll get back to our normal run rate. And our Canada opex is looking very good. So we’re not concerned about that. And as to these workovers, there’s probably nothing more in industry more economic than an offshore subsea workover at the rates that we get. And these are at any mid-cycle pricing, well over 100% rate of return. So these workovers are super economic even in times like this and need to be done. But they do drive the opex swings, Leo, for us and but when you pull that out, Murphy is probably on a run rate of a little over $10 for the first quarter, which I think is pretty good from an oil-weighted company with diverse assets like we have and get ourselves into the $9 range when we pull these workovers out.

Leo Mariani — KeyBanc — Analyst

No, that’s very helpful. And I guess just with respect to kind of getting back to higher activity levels, I know it’s tricky and there’s a lot of variables going on. But just trying to get a sense, if we do get a decent price recovery, sort of a fair bit better than strip towards the end of the year and to start next year, where does Murphy want to put its kind of first incremental dollars? So what areas do you start to kind of spend money first when you look across the portfolio?

Roger W. Jenkins — President and Chief Executive Officer

Well, we have it on both fronts, and we’ll have to make decisions between our offshore and onshore. We have our long-term projects that we’re part of. These are very, very nice projects, both Khaleesi/Mormont and Samurai and St. Malo waterflood, enormous long-term reserves for our company. So those are in our system and will be executed. Then we have our Eagle Ford, some really good locations across the business there, especially in Karnes. We had a very big program in non-op in Eagle Ford that has been deferred by that company, like most companies in shale or most companies in our industry cut back capital. And so it will be a matter of the best Eagle Ford wells versus these workovers and pent-up work that we have in the Gulf of Mexico, we would anticipate lower costs in the offshore to continue and in onshore. So it will be a competition between those. It’s quite close on rate of return on those type of projects. And we’re in the middle of determining that to put our first dollars to work. So we have a lot of opportunity and a lot of unique things we can do. We’re pulling back some of our projects in the Gulf that can be brought back to execution mode. And with the pullback in the Eagle Ford, we had a really nice program this year and pulled that back. So we have two places to go with the capital, heavily focused in competition between Eagle Ford and the Gulf of Mexico at this time.

Leo Mariani — KeyBanc — Analyst

Okay. That’s very helpful color for sure. And just lastly, real quick, on the King’s Quay FPS deal, certainly understand that, that was delayed. I’m sure a lot of it was COVID-related. But just wanted to get a sense, do you guys have a pretty high degree of confidence that this deal can kind of close here in the next month or so? Just trying to get a qualitative sense of how you’re thinking this is progressing.

Roger W. Jenkins — President and Chief Executive Officer

Yes. We feel good. This is a new to-be partner that’s currently our partner and own a significant portion of Delta House in which we operate and produce that we purchased in the Gulf of Mexico, a good relationship with them. They’re in the business. They understand the midstream business. There are several partners in these fields, and these are big notebook agreements about running a offshore facility for 30 years in the Gulf of Mexico, maintenance, operating expenses, handling of the production, handling agreement. Now these are big, thick, lawyer-driven books and a lot of pages to review. And that progress is going well. There’s no indication of any issue around this environment or anything like that pushing that back. And we’re very happy about the execution going forward. The pace is a little behind where we were thinking before. But as you brought up, working remotely and things of that nature slowed that back a bit. But we feel confident about it, do business with them, know them, working with them and all the partners. And I feel very good about it, Leo.

Leo Mariani — KeyBanc — Analyst

Okay, thank you, Roger. Appreciate it.

Roger W. Jenkins — President and Chief Executive Officer

Thank you.

Operator

Your next question comes from Gail Nicholson with Stephens. Please go ahead.

Roger W. Jenkins — President and Chief Executive Officer

Good morning, Gail.

Gail Nicholson — Stephens — Analyst

Good morning, Roger, I’m glad you’re feeling better. When we look at…

Roger W. Jenkins — President and Chief Executive Officer

I’m not feeling better, I’m just working.

Gail Nicholson — Stephens — Analyst

Well, I don’t know that’s a good thing or not. When we look at the improvement in operating costs of over $30 million, is that fair to assume that, that is predominantly driven by offshore? And how is that split between the renegotiation of contract optimization versus delaying workovers?

Roger W. Jenkins — President and Chief Executive Officer

I would say, at this time, it’s an even split. There’s, of course, savings in the 20s around our onshore business and the 20s in our offshore business split between a lot of chemical rebids, how we’re dispersing chemicals offshore, that’s a big cost, Sharing of facilities and helicopters with nearby partners, looking at every dollar to squeeze out additional efficiencies offshore. I’d say that the money is split between the two businesses at this time, Gail.

Gail Nicholson — Stephens — Analyst

Okay. Great. And then looking at Front Runner, you counted over 250 feet of pay. Can you talk about future opportunities there and then how the gross peak rate of the 7,000 barrels compared to your initial expectations of the first well?

Roger W. Jenkins — President and Chief Executive Officer

Well, it’s probably two times our original expectation. While these wells are super economic, they’re not high rates. The facility is there and you do the project on an existing older platform, so very good economics. This pay had a much more expected net pay than we thought and the amplitude response of the well. The seat makes us allow us to take this off the main structure of Front Runner off into a subsea exploitation opportunity near the field. And then we’ve been focusing a lot with the new seismic grid that we bought for the entire Gulf. And when we bought LLOG and formed a JV with Petrobras, we’ve taken all of our seismic into one large seismic grouping, if you will, and doing a lot of reprocessing and looking near field and looking for normal exploration opportunities. And this is one that’s come out of that effort, where we can tie the success of this well to an exploitation opportunity. And that’s the whole business and very, very happy about what we’re seeing there.

Gail Nicholson — Stephens — Analyst

Great, thank you so much.

Roger W. Jenkins — President and Chief Executive Officer

No, thank you Gail.

Operator

[Operator Instructions] Your next question comes from Muhammed Ghulam of Raymond James. Please go ahead.

Roger W. Jenkins — President and Chief Executive Officer

Good morning.

Muhammed Ghulam — Raymond James — Analyst

Good morning guys. Thank you for taking the questions. So when you guys talk a bit about how you choose which fields to shut in, is it purely a matter of looking at cash costs? Or do you guys focus on other factors also?

Roger W. Jenkins — President and Chief Executive Officer

How that’s done is in the Gulf of Mexico, we sell into two grades of crude, a Mars blend and an HLS blend. And these have differing differentials. May was a very difficult month. And if people understand the crude physical sale businesses, a ratable role calculation that is caused by the super contango we have between these trading days when crew went almost went negative, and that made the May physical delivery price quite low. We then look at the both the variable and the fixed costs. We know a variable and fixed for every platform and every pad that we have in the Eagle Ford and our well. And we look to as to what those prices are to cover those costs. It’s not just out looking for a certain margin there. And when we reach that, we discuss with our partners and then we move forward with decisions to maximize the cash flow for the company.

Muhammed Ghulam — Raymond James — Analyst

Okay. And what price is there a rough price you can give us as to when you would see the shut-ins come down? Would the current kind of June price be a reasonable number that we would see a significant reduction in shut-ins?

Roger W. Jenkins — President and Chief Executive Officer

Yes. The June price is well above the May physical price, probably $10 to $11 higher today or more. And so this recent little run-up in crude and away from the super contango between May was thought to be the shut-in month. And when you go through those formulas to get to these crude differentials, that caused May to be very poor. June is much better. May today, had decisions made today, we would not be shut-in today. But May has improved enough to probably allow us to flow as it were today. But you have to nominate crude and your customer. And that’s what happened in that situation. If we woke up today with the prices we have today, we wouldn’t have a shut-in, in May and nor would we anticipate one in June. But we need these prices to hold and not have volatility as we get into the trading-off of the crude month, which is around the 20th of every month. But right now, we’ve been in really good shape. We made a decision earlier, and June is looking very positive in that regard as to shut-ins.

Muhammed Ghulam — Raymond James — Analyst

Okay. Understood, thank you for the answers.

Roger W. Jenkins — President and Chief Executive Officer

Thank you for calling.

Operator

Your next question comes from Roger Read with Wells Fargo. Please go ahead.

Roger W. Jenkins — President and Chief Executive Officer

Good morning Roger, how are you doing?

Roger Read — Wells Fargo — Analyst

I’m doing well. Roger, I’m glad to hear you’re on the road to recovery, if not…

Roger W. Jenkins — President and Chief Executive Officer

I’m recovered, it’s fine.

Roger Read — Wells Fargo — Analyst

Okay. A lot of the kind of, I think, more important steps have been hit here. But I was just curious, you did a little bit of hedging in June or for June. And we think about where you’ve hedged before, obviously, markets are a little bit different today. But how are you thinking about hedging for the latter part of the year or into 2021? Is obviously, we’ve got some steepness in the curve. So I was just curious, are you thinking about it as protecting a percentage of production, an absolute number of production? Or are you a little more maybe price-sensitive at this point now that you’ve managed to get capex under control as we think out over the next couple of quarters and the other things you talked about on the opex side and just general deferrals?

Roger W. Jenkins — President and Chief Executive Officer

Well, right now, we feel we’re in really good shape. Our hedge position, starting off at over $56, was a very, very good position to be in. I think what we’ll see over the next few quarters is everything is on the table with the hedging, can move them around and you can do different things to them. But primarily more than likely, we’ll maintain those hedges and look to do these 2-month-type deals that we did in May and June to protect things that we see in the market. We don’t have a plan to do that right now, but it could easily come up. We focus on it every day. We need prices a little higher in 2021 than they are now to consider hedging. We deal it as a price as a risk management away from what we’re doing. And we’ve typically had hedging in our business for the last few years, actually have done very well with it. And but next year, we need prices to be a little higher and are reviewing that and have a minimum price involved that’s ready to go but not sharing that today.

Roger Read — Wells Fargo — Analyst

Go ahead, whisper it in our ear. No, just kidding on that. One last question for you, just to beat the King’s Quay horse one more time. Is there any particular milestone we should be looking for at this point or you’re really just progressing pretty much to the close of this transaction? And what I mean by that, is there a particular lending issue or anything like that, something we may see in the headlines, to give us some comfort about closing that transaction?

Roger W. Jenkins — President and Chief Executive Officer

No. It’s just a matter of these large legal documents to like 4-inch notebooks, if you will, of documents. And we see no milestone that’s required. It’s marching toward closing. Both parties have worked a lot on the agreements. There’s other multiple parties that have to approve them or signature off on them. And it just takes time, especially with the situation we’ve been through here recently and just a part of executing a large complicated set of documents. The financing and all those things are not a prerequisite or part of the closing or anything of that matter. It’s moving forward for execution and we feel good about it, Roger.

Roger Read — Wells Fargo — Analyst

All right, that sounds great. Thank you, Roger.

Operator

We have no further questions at this time. Please proceed.

Roger W. Jenkins — President and Chief Executive Officer

Operator, there’s no further questions in the queue at this time?

Operator

No, there were no further questions. Please proceed.

Roger W. Jenkins — President and Chief Executive Officer

Okay. Thanks, everyone, for joining us today. We wish everyone good health and safety during these very difficult times. And we’ll be moving forward here, and thanks for the questions and calling in today. If you have anything to follow, please call our IR team. And have a good day, and thanks a lot. Appreciate it.

Operator

[Operator Closing Remarks]