© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
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 the turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.
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 and Chief Financial Officer; Mike McFayden, Executive Vice President, Offshore; and Eric Hambly, Executive Vice President, Onshore.
Please refer to the informational slides we've 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 non-controlling interest in the Gulf of Mexico.
Slide 1; 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 exists that may cause actual result 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.
Thank you, Kelly. Good morning, everyone. And thanks for listening in today. On Slide 2, 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, which accounts to approximately 50% of our revised full-year budget with the new midpoint of $740 million, representing a further $40 million decrease following our latest April, 1st announcement on CapEx.
While prices are much different now, we still achieved strong pricing before gains in 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.
Thank you, Roger. In the first quarter, Murphy's earnings were substantially impacted by a non-cash after-tax impairment charge of $693 million, as well as a non-cash 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 the net loss of $46 million, or negative $0.30 per diluted share for the quarter.
The adjusted earnings back out the non-cash impairment charge and mark-to-market hedge gain as well as a gain in non-cash 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 4; 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, 31st, 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 in an average price of $54.35 per barrel.
Slide 5; 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.
Thank you, David. On Slide 7, we 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 costs 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 8; our Kaybob Duvernay production remained steady at near 10, 000 barrel equivalents per day for the quarter and the carry obligation with our partners now fully satisfied with the 11 operated wells brought online. To date, these wells are performing in line with type curves at high liquids volumes. And given the most - 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 9 in Tupper; for the first quarter 2020, Murphy produced and $246 million cubic feet per day. Four wells were drilled during the quarter, none of which will be completed until '21. 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 in 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 encountered more than 250 feet of net pay and came online with strong peak rate. As a result, we are evaluating a nearby subsea exploitation opportunity from the outcome of this well. The workover is complete at Cascade #4, as David mentioned earlier, along with the subsea equipment repair at the Niedermeyer Field with volumes now back online. Murphy's partner has spud the Mt. Ouray exploration well this week, with a net assumed cost of Murphy of $7 million.
While not in the slide pack today, we're pleased to see continued success in offshore Mexico near our Block 5 acreage with two discoveries announced just this week and 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 three-well rig program at Front Runner to two wells, no longer drilling or completing certain operated and non-operated projects and shifting timing of other projects. Murphy is near completion of the Dalmatian 134 Number 2 workover with the well scheduled to come online in the near-term. Expenditures for our long-term projects such as St. Malo waterflood and Khaleesi/Mormont, 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 our original plan.
On COVID, on Slide 14. As we've seen, we're working 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. 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 has adapted 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 incorporated learnings in our plans for returning to our offices soon.
On Slide 15, since crude oil prices 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 have 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 will be shutting down our office in Calgary. The closure of these two offices will be downsizing staff. We believe this will enhance our collaboration, 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 either the United States nor Canada. Overall, we expect to realize G&A 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 barrel equivalents 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 [ph] can be quite volatile in the oil prices and we'll have to continue to monitor that situation.
With the revised capital plan significant operational G&A cost reductions, Murphy remains competitive in a low-cost price environment. We've prepared the company the past several years through all the way to developments in transactions and appropriate balance sheet management. This is 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 reckon as in price cycle such as these that liquidity and financial strength is important and we make the tough - we made the tough decisions by reducing spending and costs across all fronts in order to maximize our future cash flows. We were 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 was particularly painful for us. This Company was founded year 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.
Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] Your first question comes from Brian Singer with Goldman Sachs. Please go ahead.
Thank you. Good morning. And Roger, on a personal note, I wanted to wish you good health on your recovery.
Well, I'm back, Brian. [Technical Difficulty].
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 all that's going on.
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 re-bid the rig for that and that bid is do 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 in the execution. And we think this is a good project. It certainly has breakeven prices in the 30 range for the rest of the field life. And we feel real good about those projects and want those projects coming forward, and it's going to lead to a nice production uplift for us at that time to the original plan of when we purchased it.
Great, thank you. 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?
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 and 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 pricing available due to our real advantage situations Flint Hills and Phillips and Corpus [ph] 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 a mid-30s kind of production. The Eagle Ford probably cost us about $400 million for that and all of our onshore, 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.
Great, thank you.
Thank you.
Your next question comes from Leo Mariani with KeyBanc. Please go ahead.
Hello, Leo. Good morning.
Yes. Good morning here, guys. Just a first question here on LOE. Certainly noticed that your LOE in the US 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 US in the second quarter, is it going to come down later in the year? Anything you can tell us on kind of trajectory there.
What happens in the Gulf of Mexico, we usually can get around $9 or $10 and when we have one of these workovers in the quarter, it goes up about $4. And we have another one in the second quarter and 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 half the expense. So, we're 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 non-dollar game and 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 costs out of the system and we'll continue to do so. And I just think the first of the year had these workovers and then it will get back to our normal run rate. And our Canada OpEx was looking very good, so we're not concerned about that.
And as for these workovers, there's probably nothing more, in the 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 OpEx swings, Leo, for us 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 our sales into the $9 range when we pull these workovers out.
That's very helpful. And I guess just with respect to kind of getting back to higher activity levels. I know it's tricky, 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 fair bit better than strip towards the end of the year and the start next year; where does Murphy want to put it's kind of first incremental dollars. So what areas do you start to spend money first when you look across the portfolio?
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 were part of. These are very, very nice projects; both Khaleesi/Mormont, 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 and most companies in our industry, cut back capital. And soon 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, 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 or pull 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 pull that back. So, we have two places to go with the capital. We heavily focused in competition between the Eagle Ford and the Gulf of Mexico at this time.
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. Did you guys have a pretty high degree of confidence that this deal can close here in the next month or so? Just trying to get a qualitative sense of how you're thinking this is progressing.
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, we have a good relationship with them. They are in the business, they understand the midstream business. There are several partners in these fields and these are big notebook agreements about running an offshore facility for 30 years in the Gulf of Mexico; maintenance, operating expenses, handling of the production, handling agreement. These are big, thick, lawyer-driven books and a lot of pages to review and that progress is going well.
There is 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.
Okay. Thank you, Roger. Appreciate it.
Thank you.
Your next question comes from Gail Nicholson with Stephens. Please go ahead.
Good morning, Gail.
Good morning, Roger. I'm glad you are feeling better. When we look at…
I'm not feeling better. I'm just working.
Well, I don't know if that's a good thing or not then. When we look at the improvement in operating cost at 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?
I would say at this time it's an even split. There's, of course, savings in the 20s around our onshore business and then 20s in our offshore business; split between a lot of chemical read bids, how we are disbursing chemicals offshore, that's a big cost. Sharing of the 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.
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 growth peak rate of the 7,000 barrel compared to your initial expectations of the first 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 their very good economics. This is pay had a much more expected net pay than we thought, and the amplitude response of the well makes us - allow us to take this off the main structure, 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, 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 has 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.
Great, thank you so much.
No. Thank you, Gail.
[Operator Instructions] Your next question comes from Muhammed Ghulam of Raymond James. Please go ahead.
Hey, guys. Good morning. Thank you for taking the questions. So can you guys talk a bit about how you choose which fields to shut-in; is it purely a matter of looking at cash cost or do you guys focus on other factors also?
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 business as a ratable raw 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 both the variable and the fixed cost. 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 through as to what those prices are to cover those costs. It's not just 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.
Okay. And what price - is there a rough price you can you give us as to when we would see the shut-ins come down? Would the current kind of June price be a reasonable number of when we would see a significant reduction in shut-ins?
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 this super contango between May was felt 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 the decision been made today, we would not be shut-in today. May has improved enough to probably allow us to flow as it were today. But you have to nominate crude in your customer and that's what happened in that situation.
We woke up today with the prices we have today, we wouldn't have a shut-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'd be in really good shape, but we made a decision earlier and June is looking very positive in that regard as to shut-ins.
Okay, understood. Thank you for the answers.
Thank you for the call.
Your next question comes from Roger Read with Wells Fargo. Please go ahead.
Good morning, Roger. How are you doing?
I'm doing well, Roger. I'm glad to hear you're on the road to recovery if not…
I'm recovering. It's fine.
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 when you think about where you've hedged before, obviously the markets [ph] are a little bit different today, but how are you thinking about hedging for the latter part of the year or into '21? 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 and 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 quarter? And the other things you talked about on the OpEx side and just general deferrals.
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's on the table with the hedging. You can move them around. You can do different things to them, but primarily more than likely we will maintain those hedges and look to do these two-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've focused on it every day. We need prices a little higher in '21 than they are now to consider hedging. We deal [ph] 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, but next year we need prices to be a little higher and reviewing that and have a minimum price involved that's ready to go, but not sharing that today.
Go ahead, whisper it in our ear.
No.
No, I'm 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 forward 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 that can give us some comfort about closing that transaction.
No, it's just a matter of these large legal documents, like four-inch notebooks, if you will, of documents. And we see no milestone that's required is marching toward closing both parties have worked a lot on the agreements. There is other multiple parties that would 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 a part of the closing or anything of that matter. It's moving forward for execution, and we feel good about it, Roger.
All right, that sounds great. Thank you, Roger.
No further questions at this time. Please proceed.
Operator, there's no further questions in the queue at this time?
No, there were no further questions. Please proceed.
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.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.