Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2019 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.
Good morning, and thank you everyone for joining us on our fourth quarter earnings call today. With me are Roger Jenkins, President and Chief Executive Officer; David Looney, Executive Vice President and 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 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 results to differ. For further discussion of risk factors, see Murphy’s 2018 Annual Report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements.
Thank you, Kelly. Good morning, everyone, and thanks for listening to our call today. On Slide 2 throughout the course of ’19 we successfully executed our corporate plan of producing oil-weighted assets for our growing volumes within cash flow, generating higher return realizations and transform the company for a long-term value as we continue to return capital to shareholders.
Our total capital for — our total production for the year averaged 173,000 barrels equivalent per day with 60% oil, we saw significant increases in production from our Eagle Ford Shale asset and Gulf of Mexico assets and are proud to be a top five Gulf of Mexico operator. Practically all of our oil production continues to be sold at a premium to WTI, West Texas Intermediate, and as a result, we generated $145 million of free cash flow in 2019. We use these funds in addition of proceeds from the sale of our Malaysia assets to return more than $660 million to shareholders through an ongoing quarterly dividend and significant share buyback program. We believe Murphy as a transformed company with great potential ahead as we continue to develop our Eagle Ford Shale, Canada and Gulf of Mexico assets with promising upside from our exploration programs in the Gulf of Mexico, Brazil and Mexico.
Most importantly, we announced today we’ve executed a memorandum of understanding with ArcLight Capital Partners, regarding our 50% ownership in the King’s Quay floating production system and are working definitive agreements regarding historical and future capital for the project, including reimbursement of approximately $125 million spent in 2019. To discuss in more detail our full 2020 capital plan after reviewing the fourth quarter and full-year results.
Slide 3. Fourth quarter production averaged 194,000 barrel equivalents per day with 67% liquid volume, production impacts included non-operated unplanned downtime of 1,900 barrels equivalent per day in the Gulf and the 1,000 barrel equivalents per day at Terra Nova in offshore Canada, as well as operated unplanned downtime of 1,500 barrel equivalent due to a subsea equipment malfunction at our Neidermeyer field in the Gulf of Mexico. This resulted in a five-day impact on the three well field and one well remains down until repairs are complete by second quarter 2020.
Regarding Terra Nova, we forecasted the field to remain down throughout 2020 to address safety equipment updates and complete the previously announced drydock work. This results in approximately a 2,000 barrel impact in offshore Canada production net to Murphy for all of 2020 and more than 3,000 equivalents per day for the first quarter of 2020.
Eagle Ford Shale, production was negatively impacted by 3,600 barrel equivalent per day in the fourth quarter, due to well work — well workovers on high rate wells and Catarina, as well as a New East Tilden wells performing below historical Tilden wells, but producing below the forecast we used in the quarter. Overall, full-year 2019 production averaged 173,000 equivalents per day was comprised of 67% liquids, specifically oil volumes grew 14% from full-year ’18 to more than 103,000 equivalents per day, due in part to the sale of gassier Malaysian assets, an addition of oil weighted Gulf of Mexico production.
Slide 4, our reserve base remain sizable in 2019 with the purchase of Gulf of Mexico assets partially offset — offsetting the sale of Malaysia properties mid-year. Our total proved reserves at year-end 2019 were 800 million equivalents per day with 57% liquids. And we maintain reserve life of nearly 12 years. Additionally, we increased our proved development classification to 57% of total reserves from 50% in 2018. Overall, our one-year organic reserve replacement ratio was 172%, while our three-year F&D cost is just under $13 per BOE.
Thank you, Roger, and good morning everyone. For the fourth quarter Murphy’s results were significantly impacted by a large $133 million non-cash mark-to-market loss on our oil hedges, which averaged $56.42 on 45,000 barrels a day this year. Naturally, the recent decline in oil prices over the last 30 days has completely wiped out this loss, and in fact we would have a positive mark-to-market position at the close of business yesterday of approximately $56 million; largely as a result of this loss, we recorded a net loss of $72 million for the fourth quarter or a negative $0.46 per share.
However, when you adjust for this mark-to-market loss in a few other items, we earned $25 million in adjusted earnings or $0.16 per diluted share. The adjusted earnings back out not only the mark-to-market loss referred to above, but also a non-cash increase in the value of contingent consideration and a loss due to the early extinguishment of debt, all three of which totaled approximately $138 million after tax.
Slide 6, a key component of Murphy strategy is to operate within cash flow with excess cash returned to shareholders through our quarterly dividend. As you can see on the slide, we achieved positive cash flow again for the full-year 2019 even with the significant transactions completed earlier in the year. For the fourth quarter cash from operations totaled $336 million, while property additions and dry hole costs came in at $335 million resulting in a $1 million in positive free cash flow. I will note that this is after considering a working capital change that resulted in cash from operations being lower by $57 million.
In fiscal year 2019 on the whole $1.5 billion of cash from operations funded $1.3 billion of property additions, thereby achieving approximately $145 million of total free cash flow for the 12-month period. As announced on our third quarter call, we completed the $500 million share buyback program in October 2019. Also during the quarter, we extended our debt maturity profile with the issuance of $550 million of 5.875% senior notes due 2027, and used proceeds to tender and repurchase an aggregate of $521 million of senior notes due in 2022. Our financial strength and stable balance sheet are further exemplified by our net debt to annualized adjusted EBITDAX ratio of 1.5 times at the end of the fourth quarter.
Slide 7, Murphy strategy of focusing on high-margin oil weighted assets continues to pay off is 95% of our oil volumes were again sold at a premium to WTI for the quarter, even with tightening differentials across the Gulf Coast markets. Our core Eagle Ford Shale and North American offshore assets continue to generate strong results with field level EBITDA per BOE of $31 and $30 per barrel in the quarter, respectively. These are clearly top-notch assets and continue to drive our strong cash flow year-in and year-out.
Slide 8, a key tenet of Murphy strategy is continual return of cash to shareholders through our long-standing quarterly dividend, along with strategic share buyback programs such as the $500 million program executed last year. This can only be accomplished through free cash flow generation, which we have done year-after-year. In all Murphy has returned nearly $4 billion of cash to its shareholders since 2012 through dividends and share repurchases with no equity issuances.
Thank you, David. Slide 9 as we begin our 70th year as incorporated entity we’re very proud of our strict internal governance, which supports our operations in overall financial stability. Our Board members have tremendous experience in industry, particularly with operations in HSE and with their guidance and support Murphy continually crafts responses to environmental safety issues, namely establishing in HSE Committee as far back as 1994, creating annual incentive plan compensation targets tied to environmental and safety performance several years ago, and issuing our first sustainability report in 2019. Murphy is recognized by ISS is one of the highest government scores and ranks 75% above our peer average.
On Slide 10, our Board of Directors in HSE Committee along with the company’s leadership remain focused on climate change, safety and other operational effects on the environment, is a proud member of the environmental partnership Murphy monitors and tracks a variety of instant spill rates with internal targets, some of which are tied to compensation. Teams are encouraged to think beyond possible of proposing our deals for sustainable operations such as recycling 100% of our produced water at our Tupper Montney asset, testing the scalability of significantly reducing greenhouse gas emissions, long-term with natural gas fueled frac pumps across our onshore portfolio. With our new portfolio, we anticipate a 50% reduction in emissions from 2018 to 2020.
Now moving to Slide 12, the Eagle Ford Shale. With the addition of 18 wells coming online early in the fourth quarter production averaged 50,000 barrel equivalents with 77% oil, this production level represents an increase of more than 23% from the fourth quarter of ’18. However given that no activity occurred in the last two months of the year production is anticipate to decline in the first quarter, as new wells will not have been placed online for now over 100 days. The 2019 program of 91 wells provides our onshore team ample runway to drive drilling and completion efficiencies, the refining well locations, rig timing and adjusting completion methods. As a result, our average cost improved to less than $6 million per well. Along with that our medium EUR well performance continues to improve in addition to the overall inter-quartile range tightening considerably since 2016.
Slide 13, since acquiring the Kaybob Duvernay acreage in ’16, we now have more than 80 wells on operation across the asset, production remained essentially flat in the fourth quarter at 9,000 equivalents per day with 55% oil. For the year well performance exceeded expectations about nearly 20%, we’ve had several operational achievements in the area, with drilling and completing our lowest cost well at less than $6.3 million, drilling the fastest well to-date in 12 days and drilling the longest lateral to-date at more than 13,600 feet. As part of our continual improvement process Murphy has begun using bi-fuel to reduce its greenhouse gas emissions and diesel costs in the Kaybob Duvernay, this is already achieved a 30% reduction in emissions for this area.
Slide 14, our Tupper Montney asset produced 260 million cubic feet per day during the quarter. We’re excited about our 2019 well results as they’ve been trending and aligned with 24 Bcf type curves, an increase from the previous trend of 18 Bcf in 2018. Overall, we generated positive free cash flow in 2019 with an average realized price of CAD2.15 per Mcf.
Slide 16 in our Gulf of Mexico business Murphy is now on this newly expanded Gulf of Mexico portfolio for six months and in the fourth quarter this business generated 82,000 equivalents per day at 85% liquids. Throughout the quarter, we brought three wells online after completing tie-in and workover activities. Additionally, as I mentioned earlier, we’ve executed a memorandum of our understanding regarding the King’s Quay floating production system.
Slide 17, our projects are moving along as planned in the Gulf, we’re currently have a platform rig drilling a three-well program at Front Runner as well as a drill ship conducting two back-to-back subsea workovers, in the first type of 2020. As we will detail these projects along with others listed in the slide bring additional volumes online to sustain our long-term production rate as previously disclosed. Our major long-term projects at Khaleesi / Mormont and Samurai are progressing nicely as well with subsea engineering and construction contracts recently awarded under budget.
Slide 19, for the first quarter 2020, we anticipate production of 181,000 to 193,000 equivalents per day accounting for natural declines and planned downtime, including more than 3,000 equivalents per day associated with Terra Nova remaining offline. Production of 190,000 to 202,000 at 60% of oil is forecast for the full-year of 2020 based on the capital plan of $1.4 billion to $1.5 billion. Of that amount, approximately $1.2 billion of our budget is allocated to our assets in the Eagle Ford Shale and offshore.
And putting together our annual capital program, our primary focus is to generate excess cash flow to cover our dividend as we acquired new assets in the Gulf in 2019 there is one project to St. Malo waterflood, the required capital in the near-term with production uplift expected in three years. This project impacted our capital allocation for 2020 as our dedication to cash flow capex parity led us to adjust our plan to ensure cash flow is protected. This allows us to continue our long-standing dividend and maintain approximately 1.5 times net debt to EBITDA ratios.
Slide 20, as we discussed in previous quarters our five-year plan the Gulf of Mexico achieves average production of approximately 85,000 equivalent. For 2020, our total capex of $440 million generates full-year average production of 86,000 equivalents per day with six operated and five non-operated wells coming online throughout the year. The 2020 project plan is a combination of platform rigs, workovers and tiebacks as detailed in the earlier slide. Overall, they will generate approximately $1 billion of operating cash flow this year.
Slide 21, based on the midpoint of our capex guidance, our onshore budget is expected to be $855 million with approximately 80% being allocated to the Eagle Ford Shale. We’re excited to continue our more robust program in 2020 after having significantly decreased spending in the last few years as we maintain our disciplined approach to capital allocation. The 97 operated wells coming online this year were primarily be focused in our Karnes and Catarina areas. In addition, we have an average 24% working interest and 59 gross non-operated wells scheduled to come online through out the year, primarily in Karnes County.
Over the course of 2020, our Eagle Ford Shale production was steadily increased as planned, reaching the fourth quarter average of over 60,000 equivalents per day. This meaningful oil weighted growth brings us back to a level that we’ve not experienced in several years. In Kaybob Duvernay, we plan to spend $125 million to bring online 16 operated wells as we fulfill our drilling carry early in the year. The Kaybob Duvernay is performing extraordinarily well across the board with exceptional results in drilling and completion efficiencies achieved.
In our prolific Tupper Montney, we’re allocating $35 million to bring online five wells at this level of capital spend these wells generate free cash at approximately CAD1.60 AECO prices. The limited spend within free cash flow in this large resource is well placed in our portfolio as a part of global requirements for natural gas as a coal replacement long-term and a lower carbon future.
Slide 22, our 2020 program fits nicely into our long-term exploration goals, we plan to spend approximately $100 million and drill four wells, enabling us to target over $500 million of barrel equivalents of resources. On the US side of the Gulf, we hold a 12% non-op working interest in the Mt. Ouray well. This prospect is expected to spud late in the second quarter. We’re most excited about our two well program in Mexico; first, we plan to spud Cholula Appraisal well followed by new prospect targeting the first ever sub-salt well in Mexico called Batopilas. Both wells are strategic in our future plans and by far Mexico. In Brazil we continue to mature several prospects, as well as plant — as well planning is ongoing. Our partner expects to spud the first well in early 2021.
Slide 23, as you look at our plans over the next few years, I believe we’ll be able to generate approximately $1.4 billion of free cash after our dividend, while delivering approximately 5% production CAGAR, all while maintaining 60% oil weighting. We’ll achieve this by allocating on average about $1.3 billion of capital annually with this 1.4% to 1.5% being program in 2020, expect to be the highest year of capital spend. Over the next five years, our Gulf of Mexico asset will maintain average annual production of about 85,000 equivalents per day, and Eagle Ford Shale currently is forecasted to have 10% to 12% production CAGAR. As we planned our annual spend of $100 million of capital and exploration, which allows us to drill three to five wells per year. I’m sure you’ll agree this is a meaningful multi-year program.
Slide 24, as we enter our 70th year as a corporation Murphy Oil is well positioned for the future after coming off another year of top quartile total shareholder return performance, compared to our peer group we’ve achieved the 95 percentile ranking in total shareholder return over the past three years. Our newly transformed portfolio with exploration upside has a continued ability to deliver free cash flow above our competitive dividend yield.
In closing, I feel we’ve successfully made a monumental shift as we transform Murphy into a Western Hemisphere Oil focused company. This positions us for long-term value creation. I’m especially proud to be one of the select companies to generate free cash flow and return dividend — significant dividends to our shareholders today. And we have the unique ability to create upside for our shareholders with continued strategic exploration programs. We’re allocating capital to our high margin oil weighted assets to generate profitable growth, we’re doing all this while keeping a keen eye on ways to continue operating sustainably in the future.
Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] First question is from Brian Singer from Goldman Sachs. Please go ahead.
My first question is on the Eagle Ford Shale, you highlighted in one of the slides, Slide 12, do you expect — or that you’ve seen higher EURs from wells drilled in 2019. And I wondered if you could talk to what your expectations are in 2020 versus 2019 from a total in oil EUR perspective. What you see as the upside versus downside risks to achieving the growth path that would push production to 60,000 BOE a day in the fourth quarter?
Well Brian, we will see our continuation of that I’m not sure on the same trajectory that we’ve had in the past, we see this to be slightly improving with frac technology and great improvements our team has made. Also this year is just a totally different program than last year more weighted in Karnes and Catarina and less in Tilden area where we had some problems in the fourth quarter. But the Tilden area is nothing wrong with it at all, it was an idea of these Tilden wells were performing well above the EUR we have in our proven undeveloped reserves and then our long-term plan, and we maintain that level and then it went back down to the level that we would have in the long-term plan over a very limited number of wells in the fourth quarter.
The issue for capital allocation is a new very large partner BPX, which is actively drilling after their purchase of BHP in the Karnes area with some very nice up — lower Eagle Ford Shale wells and some very nice Austin Chalk wells. So they are replacing our typical capital allocation into Tilden and that we’re drilling more core of core this year and a totally different risk profile than prior years in Tilden where we haven’t drilled for several years. So we have confidence in achieving that because of the significance of our non-operated program and a very large non-operated program in the fourth quarter in which this year we had very limited spend in the last two months and own into today in Eagle Ford, Brian.
Great. Thank you. And then second is a couple of questions on the offshore. Can you talk to the trend that you’re seeing on the cost side and upside versus downside risks there? And then separately realize the downtime and volatility is the normal part of operating anywhere, particularly in the offshore, but can you talk about how you’re risking downtime in 2020 guidance given some of what we’ve seen here recently?
Well, on the downtown picture there’s two types of downtime in offshore environment, there’s downtime associated with unplanned advance that happened to you from time to time. We’ve typically and have this year of a 5% allowance in our production curves for unplanned downtime or that total downtime in our business. Actually in 2020 we have less planned downtime and the bigger allowance, compared to prior years of unplanned downtime. Well, it’s hard to predict on occasion, Brian are the mechanical situations that happen on well such as subsea malfunction of these new assets, as I said earlier today we’ve own these assets for six months and apparatus broke, if you will or an umbilical power and hydraulic carrying line and we had to spool that up and repair it, those are difficult to place into that level and a very rare in occurrence.
But from our overall downtown perspective we have this benchmarked and this is what we normally do and what we normally seen outside of one-off events. And as we understand the subsea system better, we believe we have that at this time and have that confidently predicted. Also inside that downtime 5% is a good bit for the year of, Brian over 365-day period have been include a — excuse me seven day zero production in the Gulf for hurricane typically our barrels in the Gulf are never all completely off, I can’t recall a time when the entire Gulf is off production, because we have different pipeline systems in different areas of operation. And I feel that it’s appropriately risk as well.
And other risk we’ve put into this, that significant as if your barrel counter is the Terra Nova asset was supposed to produce until May and go in for a six month dry-dock and return in October and due to the unknown situation there we went ahead and put that in as a zero. So that would have changed our prior discussions of production, as new information, if this only happened on December 19th. So I think we have that well, you can go lowering zero, Brian. And then we put that in and we have our downtime manage with a lot of data in the Gulf and a long experience and now six months of learning the new subsea systems we purchased and we feel comfortable with what we have.
As a cost situation, Brian. There is going to be increase in day rates over the long haul. We do have that figured into our plans. I really don’t like to discuss the rates we have on different rigs. But of course that will be increasing that, we’ll need to increase I think for the providers of that service, we are seeing below budget on subsea equipment and subsea installation, which is overcoming most of that and we continue to have incredible efficiency on the large drill ships that are overtaking in any real issue about a day rate increase as it’s about days on location at the end of the day, and the type of work we have at Khaleesi / Mormont is just set up for these dual activity rigs involving, completion and drilling simultaneously — simultaneous operations, and I’m not concerned about costs in either of our businesses at this time. As I see efficiency eating up the increase in day rate and I currently, when we bid other equipment, it becomes lower in our offshore business.
Yes, Roger. I was wondering if you could — yes, good morning, sir. I was wondering if you could elaborate on the broad structure of the King’s Quay monetization. You guys have a very good strong balance sheet. I was wondering why this was an important strategic objective to get done. And maybe help us with what the terms could look like?
I would consider our strongest strategic situation we’ve done it was just an ability about, you know, the focus was on cash flow capex parity. One thing to know about these type of mid-stream situations all of Malaysia was done in this way. All of the Thunder Hawk facility in the Gulf was done this way. All of our business is done by a major mid-stream being owned by someone else. We’ve operated this way for a very long time and this is just a continuation of that plan.
We cannot disclose the rates that we’re paying across this facility, I would consider to be a very good mid-stream rate, if you will, balancing which our balance sheet as you brought up makes that rate lower, because we’ve different credit risks and other folks may be participating in this business, it became a matter of our St. Malo waterflood coming into our capital allocation, which is significant long-term project, it’s performing very well. And what would we do over the next three years with that $300 million of capital and maintain the CAGAR and growth that we had and we sought to financially yet — financial help on that one particular part of the project.
Project still a significant amount of capital for us and that we decided to take our ownership in that and financially form that out, if you will, and I’m very happy with the right we have it naturally, I can’t disclose that as it would tell what I will pay for mid-stream in the future or a partner want that as well. But our overall opex of our company when this comes on line, we’ll remain a nine or sub-nine player and I feel from an overall perspective, this will not be seen in the financials. And I would also further say the cash flow in this stream of our long-range plan is probably higher than the rate that we have. So I’m comfortable with all that, Arun.
Okay. And my follow-up, Roger, is on the model, I was wondering, if you could help us think about how the higher workover activity in the Gulf of Mexico and potentially the Eagle Ford will impact your LOE guidance for 2020? I was wondering if you could also mention your thoughts on the oil price breakeven in ’20 to cover the capex as well as the dividend?
Okay. From an opex perspective, I anticipate our opex to be about the same this year as we had workover. Our opex in the fourth quarter was nearly $3 impacted by a single workover that we conducted in an operating expense manner at our Chinook well, of course that wells was came online at 13,000 barrels equivalent per day, almost all oil. And I would anticipate the workovers we have here, we have lower working interest in one of the workovers, and I don’t see that being a major driver in differentiating our total opx for the year, but you could have quarterly increases as these wells are usually done in about within a month or two of work 45 days is quite typical. So that could be a bounce around in the quarter, but overall our opex for the year as a total company and our Gulf of Mexico business should be sustained.
From perspective, you take the midpoint of guidance in our capex, which is of course our goal. And also last year, we hit that goal and we’re under that goal from a cash flow spending on the cash flow statement, and I will only — we’re at that goal on accrual basis, which is not all the way through cash at this time, of course, it’s not our goal to use above that we do have a range for events that could take place, and now this oil price are clearly cannot go above the midpoint. If we look at the strip today with the recent virus impacts on oil pricing, we would probably need $55 there’s no problem, but if you looked at the current strip, we’d probably have to go in the low end of our capex guidance of $1.4 billion to the $1.45 midpoint and get in the middle of that in order to achieve to cover the dividend.
And when we do that we have some opportunities available that should not impact production as to some timing in various parts of the company that have preferred to disclose at a later time. But our goal is to cover it; our goal is to cut it if we need to, and be mindful of this, of course, our hedging as David mentioned earlier is helping us there in that regard and it’s included in what I said. So $55 WTI average for the year, which I still think is very achievable. It is not a problem at all. And in the 53 world, you’re only talking about $20 million, $30 million of capex to handle that, Arun.
Hey, good morning. I wanted to follow-up a little bit on the Eagle Ford here, certainly noticed you guys had some workover downtime in the fourth quarter, just looking at your first quarter Eagle Ford production guidance, it looks to be down roughly 15% versus 4Q. I know you talked a lot about well timing. Just wanted to kind of get a sense of whether or not there are also ongoing workovers in the first quarter of ’20, kind of, impacting that production and then maybe you could just speak a little bit to this production, sort of, cadence throughout the year. I know you mentioned the 60,000 in the fourth quarter, should we see a pretty steady ramp in 2Q and 3Q, so just maybe help me out a little bit on some of the directionality on the Eagle Ford here?
Thanks. Leo. So in the fourth quarter, we did have some impact from more well work on higher rate wells than typical when we have sort of routine artificial lift repair work across Eagle Ford, we saw a similar level of activity, but we happen to have more downtime related to higher rate wells more of the 300 to 400 barrel a day wells, instead of the 40, 50, 60 barrel a day wells. So that was sort of an abnormal bit. We did have some new wells come online in September in Catarina that had a fair bit of downtime that we went out and did some sand clean out work on those, those wells have now all but about one has returned to normal production rates. So from that workover activity in Catarina, we’re probably seeing about 500 or 600 barrels a day of lingering impact from that as we head into January. The rest of the field is sort of in line like normal.
In the East Tilden wells, which Roger highlighted underperformed our forecast, but exceeded prior expectations from wells from 2015 and earlier. Those wells impacted our quarter by a little over 700 barrels per day. The impact of that in the early part of 2020 is about 1,000 barrels a day, and that impact will decline through the year. So we are seeing a little overhang at the early part of the year. We expected to have natural decline in the Eagle Ford with our well cadence wrapping up, mostly in September and in October of last year, our new online well delivery this year, our execution of our drilling and completion program has been going very well. We do have a program of wells coming online that in the first quarter resembles what it looked like in the first quarter of 2019. And then a little bit more waiting in the later part of the second quarter for our operated Karnes wells coming online. So it’s slightly later ramp-up of new wells in second quarter then you saw in 2019. But then a strong push for the rest of the year with more higher IP wells in Catarina and Karnes contributing late in the second quarter and third quarter and a big push of non-operated Karnes wells in the fourth quarter of 2020.
Okay. Very helpful color. So it certainly sounds like it’s pretty back half weighted on the Eagle Ford growth in ’20 here.
It will always be that way, Leo. When you stop spending at the end of the year to front-end load capital, which is going to become a common thing in Shale. We’re not just Murphy. It’s harder to do it that way.
Our program in 2020 has 14 wells coming online very late at the end of the year in Karnes. So we have a more steady well delivery in 2020, compared to 2019. So we should exit the year on a high instead of on a downward trend with natural decline. So a little bit different look this year of our program.
Okay, that’s good color for sure.. And I guess, just wanted to follow-up a little bit on sort of the kind of the next couple of years in terms of how you guys are thinking about the outlook. I know you said that 2020 is the high for capex, I mean, it sounds like that kind of comes down here, you know, into ’21. I know you guys talked about the 85,000 BOE per day in the Gulf of Mexico. But as I kind of looked at your slides and seeing some of the tie-in schedules. Just wanted to get a sense, it looked like there weren’t a lot of wells in the Gulf coming on until late in the year in ’21. So should we expect Gulf production to go down a little bit in ’21 and then go up a lot in ’22 is Khaleesi and Mormont come on anything you can sort of say to that?
This year, would be a high watermark of production over the next couple of years in the Gulf, but not much significant decline nearly, of these wells are pretty high rate wells when you see them on this chart also not highlighted here. The non-op wells, so it’s just Kodiak in which we enjoy a large working interest there, one of our more profitable fields with incredible positive gifts. Very confident in averaging this, I would say the capital to deliver this is probably below prior guidance. And we have significant wells coming on here in this list and also in the non-op both at St. Malo and Kodiak and as — and Lucius as well. So the non-op is not highlighted here, but very confident about our long-term production profile of this 85 goal and less capex toward the end of the planning period.
Got it, OK. So, yes, it sounds like there is a number of other wells just on in the slides that are going to help to back fill some of that. Okay that makes sense.
And these wells are very high production, Leo, with various working interest, but these are high-rate wells we deal with here.
Okay. No, that’s helpful. And I guess maybe just lastly on the exploration. On your Slide 22, just wanted to see if we get a little bit more color on some of these prospects coming up later in the year in terms of what you thought potentially would be at Batopilas or the well that you’re going to be I guess testing in early ’21 in Brazil, just trying to get a sense of what kind of the gross recoverable targets are in those wells?
Well, I mean we — to disclose these type of matters requires many, many partner approvals and therefore we do not have here. I mean, typically in the Gulf of Mexico, you’d anticipate in the exploration well to be a 75 million barrel plus type opportunity, those are what we’re always targeting there. In our Cholula area in Mexico, we had a discovery there last year was disclosed, and that was a crestal position well with good bit of oil that is — had flat spots if you will, and we need to come off that structure into a thicker reservoir in one of the wells, who did not have a water level in the zone, and that we’ve done a lot of seismic work there and also a very nearby opportunity with an ideal seismic response to all the structure of the Cholula well. And in that kind of area from that well and the nearby opportunity that’s identical to it, same age depth next door, if you will, these are 100 million barrel-type of things that we’re derisking in that pretty large area.
So we have two businesses in Mexico right now, one is a middle Miocene small tieback zone in the 100 million barrel range Northeast of the Talos discovery that we can easily add to and add-on to very similar to what we do in the Gulf. And there’s Batopilas well is a large well above $160 million equivalents of size and it’s a very large Miocene structure underneath salt. And so those opportunities, and of course, our Sergipe-Alagoas basin, we’re not disclosing the size of those opportunities, which you can anticipate something like that with the partner that we have to be quite large. And hopeful for those to be large and there you go with the above 500 and that’s all we can say about it. Again a typical well in the Gulf 75, we’re touching a good bit of, close to 100 and beyond in the Gulf — in the Mexico region with these type of very expense [Indecipherable] of wells, treat wells, in fact. And then a big future opportunity for us in Brazil that we’re very excited about. But have limited disclosure at this time.
Two questions, I think the market doesn’t fully appreciate the benefit of St. Malo really post the ’24 timeframe. Can you just, kind of, talk about how the production looks once it comes online in ’23 and then how that scope forward and how long — the longevity of those volumes in the system?
Good morning, Gail. St. Malo comes on late ’23 early ’24 kind of peaks, it adds over 5,000 barrels a day net production to our offshore portfolio and adds about 32 million barrels of reserves our share and significant NPV, NPV in $150 million to $160 million range with about an 18% to 20% rate of return at $55 flat oil. So it’s significant and comes on at a good time for our offshore portfolio.
Great. And then on 2019 Gulf of Mexico had some very healthy differentials. Can you guys just provide some color on how you guys are viewing GOM differentials in 2020?
Yes, I think that the differential picture in the Gulf has been much better than forecasted from an IMO 2020 perspective that was really hasn’t been a major impact. The diffs are lower than they were in parts of ’19. Today, in our Mars business where we mark off of Mars in the Gulf of Mexico, these would be all of the assets we purchased from Petrobras, as well as our older Medusa and front-runner feels. It’s about 36% of our production, these diffs are clearly over $1 year-to-date, the February diff and that’s $1.40 positive, some CHOPS has forecasted to be below dollar negative, in fact. And that we see this to be much better than originally thought.
In HLS in the Gulf, around 21%, this is some very, very high margin crudes around our Kodiak non-op well and all of our LLOG business we bought and the dalmatian field that we have and be working over soon quarter four, there was a $4 positive and now we’re clearly in the 350 positive range there, and I feel good about that. Another nice situation for us is Magellan East Houston, MEH which represents 33% of our old liquids coming out, Eric’s business in Eagle Ford. And this two have been about a $3.40 or $3.40 positive to WTI basis in which we mark the crew. So overall, we’re still to be positioned and I believe when you look at transportation and the realized price of our company, and where our barrels are located. We will always be positive to almost any peer, because the unique nature of where we’re selling these barrels and very happy about the deals that we have, we think it’s a competitive advantage And so why we added our Gulf business and allocate more capital to our Eagle Ford business. If you have the higher prices, you’ll always have advantage.
Thank you. [Operator Instructions] And next question is from Paul Cheng from Scotia Bank. Please go ahead.
If you have to adjust the capex should we assume it is only in Eagle Ford or that you will also adjust in other areas?
No, as again I’d prefer not to disclose this at this time. We have some field development plan approval payments in Vietnam that are part of our plan, which if you make that milestone that can be delayed, and we are seeing some different costs and some exploration at the end of the year. We’re trying to make those reductions naturally where we do not adjust our very high return capital allocation to workovers and tie-backs in the Gulf, nor change our rig schedule in the Eagle Ford at this time. I feel comfortable we can do that and we will, if we need to do it we’ll do it.
Nice. And in Brazil have you guys already identify what is the well you’re going to drill next year — early next year?
We have a good idea — we have good idea of it of course, but we’re dealing with a large partner there. And I think you could go back and monitor their disclosure on another super large project there in over time, and you would anticipate a similar disclosure here as well.
Okay. So you were not be able to give us a — maybe a peak drill target or anything related at this point?
Okay. And when you say early next year. Are we talking about the beginning of the first quarter? What…
Yes. The rig plan there is involved with permits and the schedule of our partners, well involving some other blocks that they have. And I anticipate it to be early in ’21 at this time. Yes, sir.
Okay. And that may be that I missed it. Wonder when you’re saying that you’re not going to have any well coming on stream in the Eagle Ford for the next 100 days?
No, no, no, that’s from the time we put a well on in early October and we’re going to have some wells flowing Saturday. So it’s been a long time.
That capital allocation of our front-end loaded Shale program impacts and we overstated production above our typical EUR, we got burned for that in the fourth quarter. Now we have that issue on top of a long-term planned front-end loaded project. We’ve been drilling with three rigs there starting right at the end of the year. And we’re bringing on a significant 10-well pad here pretty quick and feel good about our guidance and what we’re doing there.
We are, Paul. We’re starting this — we’re starting Saturday morning. It’s been a while, what I’m trying to say is it’s hard in a Shale play to and you’ll find that rare to not put a well on in a 100 days and but we’re back clicking and adding wells throughout the quarter and we have significant cadence of wells building, as Erik described earlier in the call.
Okay, and final one from me, can you give us some — what is the East Tilden, the well performance in the fourth quarter that you’re talking about? And what was the corporate forecast that you guys use? And have you already adjust that forecast or do you think the East Tilden well in the fourth quarter were an anomaly and your capex forecast is still, OK.
Sure, Paul. So the East Tilden wells, we brought those wells online their IP30s were basically in line with our forecast. They’re not the exact number, but somewhere around 800 BOE per day average for the eight wells. So they look really good for about 30 days after that we started to see a steepening decline. So the — as I mentioned, heading into January the gap between our prior forecast and the current production performance for the total of the eight wells was about 1,000 BOE per day, and we expect that gap will be there, but it will decline through the year as the expectation prior declines like wells always do.
Thanks for taking the question. One of the point you made in your, kind of, intro is you’ve reshaped the asset base to be a Western Hemisphere pure play. But you still have the Vietnam exploration and it feels like it’s a little bit of an afterthought at this point. So I’m curious what the logic is for retaining those assets?
There’s significant upside in those assets. We have a significant discovery there that we’ll be bringing online, we’re currently doing feed, and we’ll be having field development plan approval there through the government — the government there were so slow. And we — with our capital allocation have not been rushing them if you will. It’s a very unique situation. We just added another block with a one well commitment, we have a series of prospects that are low risk drilled by jack-ups and allows us all type of upside, but at this particular time with the capital allocation of having a limited CAGAR and free cash flow and building a business with significant free cash flow. It has been slowed in the first couple of years for our business, but we will be definitely drilling there next year, and this is a sleeper for us that’s significant and allows us all type of flexibility involving different parts of our business going forward.
So like Vietnam, have a very unique position, a very inexpensive entry position, a very nice discovery there, there will be — being put into our long range plan it’s inside what we’ve disclosed here and very excited about it. Just not being a large capital there this year for all those reasons that we read about every day.
Okay, one more exploration question, if I recall, I think it was five or six years ago you made efforts to do some drilling in Suriname, one of the first, I think, international E&Ps to do that. And then that kind of fizzled the way now, of course, we’re seeing Suriname headlines on a seemingly daily basis. I’m curious, if you have any interest in revisiting opportunities in that emerging geography?
We’re interested in all opportunities in the Hemisphere in which we focus, which is South America, Gulf of Mexico proper and Mexico offshore where we have a significant block and we’ve recently added in Brazil another segment in Portiguar Basin. Those wells we were drilling so many years ago, we’re totally different play, a totally different time. We — as you know, have been a global explore, but we’re trying to focus in on having more information and more focused in on data and just the basins in which we work. Just because we haven’t participated, it doesn’t mean we haven’t looked there and the price of poker there was above what we wanted to do. And also on occasion in a country like that it sounds simple, but when you see the different agreements that you agreed to, to look at someone’s day will be very limiting you in a business development perspective going forward. And in some of those places we’re unable to make an agreement that we would prefer to work in. So we look in this region, we’re not against working there, but haven’t found an opportunity that we would like to participate and where we can add significant shareholder value.
Okay. We have no more questions today and that will end our call today. We appreciate everyone for listening in, and we’ll see you at our next quarterly result. Thank you so much.
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Post time: Feb-24-2020