Q4 2019 Earnings Call
[music].
Corporation fourth quarter 2019 earnings conference call.
If at any time during this call you need assistance. Please press star zero for the operator.
I would now let's turn the conference over to Kelly, Whitley, Vice President Investor Relations and communication.
Please go ahead.
Good morning, and take care, everyone for joining us on our fourth quarter earnings call. Today with me are Roger Jenkins, President and Chief Executive Officer, David Leeny 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 had 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 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, a 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 that make.
Actual results to differ for further discussion of risks factors see Murphy's 2018 annual report on Form 10-K on file with the FCC 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 to listen to our call.
Today on slide two throughout the course of 19, we successfully executed our corporate plan are producing oil weighted assets, while growing volumes within cash flow generating high return realizations and transform the company for a long term value as we continued to return capital to shareholders.
Total capital for our total production for the year every 173000 barrels equivalent per day with 60%. All we saw significant increases in production from our Eagle Ford shale assets in Gulf of Mexico assets, and our proud to be a top five Gulf of Mexico operator.
Basically all of our oil production Kens continues to be sold at a premium to WT.
West, Texas intermediate and as a result, we generated 145 million a free cash flow in 2019, we use these funds and additional proceeds from the sale of our Malaysia assets through returned more than 660 million to shareholders do an ongoing quarterly dividend and significant share buyback program.
We believe Murphy has transformed company with great potential heads as it contains developer Eagle Ford Shale, Canada, and Gulf of Mexico assets with promising upside from exploration programs and 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 and the kings key floating production system and are working definitive agreements regarding historical and future capital for the project, including reimbursement of approximately 125 million spent and 29.
Team.
I will discuss in more detail more detail our full 2020 capital plan after reviewing the fourth quarter and full year results slide three.
Fourth quarter production averaged 194000 barrels equivalents per day with 67% liquid volume production impacts includes non operated unplanned downtime of 1900 barrels equivalent per day in the goals.
Thousand barrel equivalents per day, a tear Nova and offshore Canada as well as operated unplanned downtime 1500 barrel equivalent due to a subsea equipment malfunction at our Niedermaier feel in the Gulf of Mexico. This resulted in a five day impact on the three will feel and one well remains down until repairs are complete.
My second quarter 2020.
Regarding terra Nova we forecasted to feel to remain down throughout 2020 to address safety equipment updates and complete the previously announced dry dock work. This results in approximately a 2000 barrel impact in offshore Canada production net to Murphy for all of 2020 and more than 3000 equivalents per day for the first quarter.
For 2020.
Eagle Ford shale production is negative impacted by 3600 barrel equivalent per day in the fourth quarter due to well work well workovers on high rate wells and Cat arena as well as a new east Tilden wells performing below historical tilda wells, but producing below the forecast we use in the quarter.
Overall full year 2019 production averaged 100 averaged 173000 equivalents per day was compromised comprised of 67% liquids, specifically oil volumes grew 14% from full year 18 to more than 103000 equivalents per day.
Due in part to the sale of Gassier Malaysian assets. In addition of all weighted Gulf of Mexico production.
Slide four.
Our reserve base remains sizable in 29 team at 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, 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. Andy cost is just under $13 per Boe.
I'll now turn the call over to David Looney previous commentary on the financial information.
Thank you Roger and good morning, everyone.
For the fourth quarter Murphy's results were significantly impacted by a large 133 million dollar noncash mark to market loss on our oil hedges, which averaged $56.42 on 45000 barrels a day. This year naturally the recent decline in oil prices over the last 30 days as.
Completely wiped out this lost 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 46 cents per share. However, when you.
Just for this mark to market loss in a few other items, we earned $25 million and adjusted earnings or 16 cents per diluted share.
The adjusted earnings back out not only the mark to market lost referred to above but also a noncash increase and 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 six 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 a significant transactions completed earlier in the year for the fourth quarter cash from operations totaled 336.
Okay and dollars, 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.
A 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 dollar share buyback program in October 2019.
Also during the quarter, we extended our debt maturity profile with the issuance of $550 million, a five and seven 8% senior notes due 2027 and used proceeds to tender and repurchased an aggregate of $521 million a senior notes due in 2022.
Financial strength and stable balance sheet or further exemplified by our net debt to annualized adjusted EBITDAX ratio of 1.5 times at the end of the fourth quarter.
Slide seven.
Murphy strategy of focusing on high margin oil weighted assets continues to payoff is 95% of our oil volumes were again sold at a premium to WT 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 to be OE, Herbie away, a $31 and $30 per barrel in the quarter, respectively. These are clearly top notch assets and continue to drive our strong cash flow.
Year end year out.
Slide eight a key tenant 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 dollar 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 with that I'll turn it back over to Roger.
Slide nine as do again, our seventh year is incorporated into the very proud of our strict internal governance, which supports our operations and overall financial stability.
Our board members have tremendous experience in industry, particularly with operations and HSC and with their guidance and support Murphy continually kras responses to environmental safety issues, namely, establishing an HSC committee as far back is 1994, creating annual incentive plan compensation targets, Todd to environmental and safety performance several.
Two years ago, initiating our first sustainability report in 2019.
Murphy is recognized by assess as one of the highest government scores and rank 75% above our peer average on slide 10, our board of directors and HSC Committee, along with the company leadership remain focused on climate change safety and operational effects on the environment as it probably remember the environmental partnership Murphy monitor.
From tracks a variety of instance, bill rates with internal targets some of which are tied to compensation teams are encouraged to think beyond possible proposing ideals for sustainable operations, such as recycling, 100% of our produced water at our Tupper montney asset assessing 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 emissions from 2018 to 2020.
Now moving to slide 12, the Eagle Ford shale.
Addition of 18 wells coming online early in fourth quarter production averaged 50000 barrel equivalents, 77%. All 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 anticipated 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.
While month at our media you are well performance continues to improve in addition to the overall inter quarter mile range tightening considerably since 2016.
Slide 13 since acquiring the Kaybob Duvernay acreage in 16, we now have more than 80 wells in operation across the asset production remained essentially flat in the fourth quarter non thousand equivalents per day with 55% oil for the year well performance exceeded expectations by nearly 20% we've had several operational.
She wants in the area with drilling and completing our lowest cost well at less than $6.3 million us drilling the fastest well to date in 12 days and drilling the longest lateral to date at more than 13600 feet.
As part of our continual improvement profit process Murphy has begun using bi fuel to reduce its greenhouse gas emissions in diesel costs and the Kaybob Duvernay. This has already achieved a 30% reduction 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 align with 24 Bcf type curves and increase from the previous trend of 18 Bcf in 2018.
Overall, we generated positive free cash flow in 2019, with an average rollout realized price of $2 and 15 Canadian per Mcf.
Slide 16, and our Gulf of Mexico business.
Murphy is now on this newly expanded Gulf of Mexico portfolio for six months in the fourth quarter. This business generated 82000 equivalents per day at 85% liquids throughout the quarter. We brought three wells online after completing tie in and Workover activities dense. Additionally, as I mentioned earlier, we've executed a memorandum burners.
Standing regarding the kings key 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 drillship conducting two back to back sub sea Workovers and the first type of 2020.
We will detail later these projects along with others listed in the slide bring additional volumes on line to sustain our long term production rate as previously disclosed.
Our major long term projects actually see more month samurai are progressing nicely as well with subsea engineering and construction contracts recently awarded under budget.
Slide 19.
Well the first quarter 2020, we anticipate production of 181290 3000 equivalents per day accounting for natural declines and planned downtime, including more than 3000 equipments for day associated with Terra Nova remaining offline.
Production of 190000 to 202000 at 60% all this forecast for the full year 2020 based on a 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.
Im putting together our annual capital program. Our primary focus is to generate excess cash flow to cover our dividend as required new assets in the Gulf in 2019, Theres One project to St. Malo waterflood that 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 was protected this allows us to continue our long standing dividend and maintain approximately 1.5 net debt to EBITDA ratios.
Slide 20.
As we discussed in previous quarters, a five year plan the Gulf of Mexico cheese average production of approximately 85000 equivalents for 2020, our total Capex a 440 million generates full year average production of 86000 includes today with six operated in five non operated wells coming online throughout the year.
The 2020 project plans, a combination of platform rigs workovers and tie backs as detailed in the earlier slot overall, they will generate approximately $1 billion of operating cash flow this year.
Slide 21.
Based on the midpoint of our Capex guidance or onshore budget is expected to be 855 million with approximately 80% being allocated to the Eagle Ford shale. We're excited to continue or a more robust program in 2020 after having significantly decreased spending the last few years as we maintain our disciplined approach to capital allocation the 97 operating.
For wells coming online this year will primarily be focused in our constant 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 will steadily increase this plan, reaching a fourth quarter average of over 60000 equivalents per day is meaningful weighted growth brings us back to a level those not experienced in several years.
And 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 and drilling and completion efficiencies achieved.
And our prolific Tupper Montney, we're allocating 35 million to bring on online five wells at this level of capital spend these wells generate free cash at approximately $1.60 Canadian Aiko prices.
The limited spend within free cash flow in this larger 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 barrel equivalents of resources.
On the us side of the golf, we hold at 20% not working interest in amount, who right well. This massing prospects expected spud late in the second quarter. We're most excited about our two well program in Mexico first we plan to sponsor Lula appraisal well followed by new prospect targeting the first ever sub salt well in Mexico called about Appeals.
Yes.
Both wells are strategic and our future plans bought five Mexico, and Brazil will continue to mature several prospects as well as plant as well planning is ongoing our partner expects to FID spud the first well in early 2021.
Slide 23.
Look at our plans over the next few years I believe we'll be able to generate approximately 1.4 billion free cash after our dividend, while delivering approximately 5% production CAGR, all while maintaining 60% or waiting we will achieve this by allocating on average about 1.3 billion of capital annually.
With with this 1.4 to 1.5 billion program in 2020 expected to be the high last year of capital span.
Over the next five years, our Gulf of Mexico asset will maintain average annual production of about 85000 equivalents per day in Eagle Ford Shale currently is forecasted to have 10% to 12% production CAGR.
As we plan our annual spend of 100 million of capital on exploration, which allows us to drill three to five wells per year.
Im sure you agree this is a meaningful multiyear program.
Slide 24.
As we enter our 75 years the Corporation Murphy oil is well positioned for the future after coming off another year of top Cortile total shareholder return performance compared to our peer group. We've achieved of 95 percentile ranking in total shareholder return over the past three years, our newly transform portfolio with exploration upside as 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 western Hemisphere oil focused company. This positions us for long term value creation, I'm, especially proud to be one of the select companies generate free cash flow and return dividend significant dividends to our shareholders today.
And we have unique ability to create upside for our shareholders with continued strategic exploration programs, we're allocating capital to our high margin or weighted assets that generate profitable growth. We're doing all this while keeping a keen.
On ways, we continued operating sustainably in the future with that I'd like to turn the call over to our operator.
Questions and at that time, thank you.
Thank you.
Ladies and gentlemen, we will now begin the question and answer session.
So do you have a question. Please press the star followed by the one on your Touchtone phone you will hear with suite telecoms acknowledging request.
Should you wish to decline from the planning process. Please press star followed by Q.
And if there is no speakerphone, please let the handset before pressing any Keith.
One moment. Please my first question.
First question is from Bryan singer.
From Goldman Sachs. Please go ahead.
Thank you good morning.
During Brian .
My first questions on the Eagle Ford Shale you highlighted in the in one of the slides slide 12.
The expectations are 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 you are perspective, what you see as the upside versus downside risks to achieving the growth path that would push production to 60000 BOE a day in the fourth quarter.
Well, Brian we will see a continuation of that I'm not sure on the same trajectory that we've had in the past.
We will we see this to be slightly improving with Frac technology and great improvements. Our team has made also at this year's just a totally different program.
And last year more weighted in Karnes, and Cat Arena, and lessen Tilden area, where we had some problems in the fourth quarter for the Tilden areas nothing wrong with it at all it was an idea of these tilden wells were performing well above. The you are we have in our proven undeveloped reserves and in our long term plan.
And we maintain that level and it went back down to the level that we would have in the long term plan over very limited number of wells in the fourth quarter issue for capital allocation is a new very large partner BPX, which is actively drilling after their purchase of BHP and 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 until them, 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, which this year, we had very limited spend in the last two months in own into today.
In Eagle for Brian .
Great. Thank you and then second is a couple of questions on the offshore can you talk to the trend that youre seeing on the cost side, an upside versus downside risks there and then separately realize the downtime and volatility as normal part of operating anywhere, particularly in the offshore but can you talk about how youre risking downtime in 20.
20 guidance given some of what we've seen here recently.
Well the downtime pitcher there is two types of downtime in offshore environment Theres downtime associated with unplanned events.
That happened two year from time to time.
We typically in have this year ever 5% allowance and our production curves for unplanned downtime or debt total downtime at our business actually in 2020, we have less planned downtime and a bigger allowance compared to prior years of unplanned downtime well, it's hard to predict on occasion, Brian are the mechanic.
Goal situations that happened on wells such as this sub sea malfunction of these new assets as I said earlier today, we have on these assets are six months.
And apparatus broke if you will on an umbilical power and hydraulic carrying line and we had disposal that up and repair. It those are difficult to place end to that level and a very rare in occurrence, but from a overdone overall downtime perspective, we have this benchmarked and this is what.
We normally do and what we normally seen Alps outside of one off events and we as we understand the sub sea system better. We believe we have that corralled at this time and have that confidently predict it also inside that downtime proper sense, a good bit for the year of Brian over 365 day period.
Good.
Evan include.
Hey.
A five eight excuse me seven days zero production in the Gulf for Hurricane typically our barrels in the Gulf War never all completely off I can't recall, a time when the entire golf is off production because different pipeline systems in different areas of operation and I feel that as appropriately risk as well and other risk.
Put into this that significant as if you're a barrel counter is the tear nov asset was supposed to produce until may and go in for six months dry dock came return in October and do 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 is this only happened.
On December 19th.
So thing we have that well you can't go lower than zero, Brian and I would put that in and we have or downtime manage with a lot of data.
In the Gulf and a long experience and now six months of learning the new sub sea 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 will need to increase I think for the providers of that service. We are seeing below budget on subsea equipment in 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.
We will issue about a day rate increase as its about days on location at the end of the day and the type of work we have at least three more months is just set up for these dual activity rigs involving completion and drilling simultaneously simultaneous operations and im 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 and offshore business.
Thank you.
Thank you.
Thank you. The next question is from Evan Jiabao at JP Morgan. Please go ahead.
Yeah, Roger just wondering if you could Ed good morning, Sir I was wondering if you could elaborate on the broad structure of the Kings key monetization you guys have a have a very good strong balance sheet is wondering why this was an important strategic objective to get done and maybe help us with what the terms could look.
Like.
I would considered our strongest strategic situation. We've done it was just an ability about.
The focus is on cash flow Capex parity.
One thing to know about these top of midstream situations all of Malaysia was done in this way all of the Thunder Hawk facility in the Gulf has done this way.
All of our business is in is done by major midstream being owned by someone else. We've operated this way for very long time and this is just a continuation of that plan.
We cannot disclose the rates that we're paying across this facility how the considered to be very good midstream rate. If you will balancing which our balance sheet. As you brought up makes that rate lower because we're a different credit risks and other folks may be participating in this business. It became a matter of our think mallow waterflood.
Coming into our capital allocation, which is significant long term project, it's performing very well and what we do over the next two years with that 300 million of capital and maintain the CAGR and growth that we had and we sought to financially.
Financial help on that one particular part of the project projects still a significant amount of capital for us and we decided to take our ownership in that and 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 midst.
Dream in the future, Alberta partner want that as well, but our overall opex of our company. When this comes online will remain a non or sub nine player and I feel from an overall perspective. This will not be seen in the financials and out I would also further say.
Into 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 room.
Okay and my follow up Roger.
It is on the model I was wondering if he could help us think about how the higher workover activity in the Gulf of Mexico, and potentially the Eagle Ford will impact.
Your Ela, we guidance for 2020 as wondered if you could also mentioned your thoughts on the oil price breakeven and 20 to cover the Capex is also the dividend.
Okay.
From an opex perspective.
I anticipate our opex to be about the same as this year.
As we have workover, our opex in the.
In the fourth quarter was nearly $3 impacted by single Workover that we conducted in an operating expense manner at our Chinook well of course that wells was came on at 13000 barrels equivalent per day, almost all oil and I would anticipate the workers. We have here, we have lower working interest in one of the Workovers.
And I don't see that being a major driver and differentiating our total opex for the year, which you could have quarterly increases as these wells are usually done and about.
Within a month or two work or 45 days is quite typical so that could be a bounce around in the quarter, but overall, our opex for the years of total company and in our Gulf of Mexico business should be sustained.
Okay from some perspective, you take the midpoint of guidance.
And our Capex, which is of course, our goal and also last year, we hit that goal.
We're under that go from a cash flow spending on the cash flow statement and I'll only were at that go alone accrual basis, which is not all 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 I 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 is 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 the 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 up preferred to disclose at a later Tom but our goal is to cover our goal is to cut it if we need to and and be mindful. This of course, our hedging as David mentioned earlier is helping us there in that regard and is included in what I said so.
$55.
BTI average for the year, which I still think is very achievable is not a problem at all and in the 53 world.
Only talking about 20 $30 million capex to handle that Iran.
Thanks to the color Roger.
Thank you.
Thank you. The next question is from Leo Mariani from Keybanc. Please go ahead.
Yes.
Hey, good morning.
Paul a little bit on the Eagle Ford here.
Certainly noticed you guys had some workover downtime in the fourth quarter I'm just looking at your first quarter Eagle Ford production guidance, it looks to be down.
Roughly 15% versus four key you I know you talked a lot about well timing just one kind of get a sense of whether or not there also ongoing workovers in the first quarter 20 kind of impacting net production and then maybe could you speak a little bit too.
Just production sort of cadence throughout the year I know you mentioned the 60000 in the fourth quarter should we see at pretty steady ramp in Twoq and Threeq huge Didnt help me out a little bit on some of the directionality on the Eagle Ford here My of Eric take that 40 Leah.
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 happened to have more downtime related to higher rate wells more of the three to four.
Hundred barrels a day wells instead of the 40 50 60 barrels 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 Cat Arena, we're probably seeing about.
Out five or 600 barrels a day, a lingering impact from that as we head into January .
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 from wells from 2015 in 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 1000 barrels a day and that impact will decline through the year. So we're seeing a little overhang at the early part of the year, we expected to have natural decline in the Eagle Ford with our well costs.
Cadence wrapping up mostly in September and October 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.
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 as slightly later ramp up of new wells in second quarter. Then we you saw in 2019, but then a strong push for the rest of the year with more higher.
The wells in Catarina and Karnes contributing late in the second quarter and third quarter and a big push of non operated cards wells in the fourth quarter.
2020.
Okay very helpful color. So it certainly sounds like it's pretty back half weighted on the Eagle Ford growth in 20 here.
Yes, it will always be that way Leo when you stop spending at the end of the year to front end low capital, which is going to become a common thing and 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.
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 little bit different look this year bar program.
Okay. That's good color for sure I guess, just wanted to develop 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 cap X. I mean, it sounds like that kind of comes down here in one to 21 I know you guys talked about the 85000.
Per day in the Gulf of Mexico, but I think kind of looked at your slides and seeing some of the tie ins schedules just wanted to get a sense.
Look like there weren't a lot of wells in the Gulf coming onto a late in the year in 20 wines. So should we expect well production to go down a little bit in 21, and then go up a lot in 22 is Collegium Lamont come on anything you can sort of data that.
This year would be a high watermark of production over the next couple of years in the Gulf, but not not much significant decline there Leo These wells are pretty high rate wells. When you see among this chart also not highlighted here the non op wells, So just kodiak and which we enjoy a large working interest there one of our more prop.
A couple feels with incredible positive DS 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 Anand Lucius as well.
So that the non op is not highlighted here, but very confident about our long term production profile of this 85 goal and and less capex toward the end of the planning period.
Got it okay. So yes, it sounds like there's a number of other wells just on the slides that are going to help to backfill some of that okay that makes sense families. With these wells are very high production that Leo with various working interest, but these are high rate wells, we deal with here.
Okay, I know that 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 somebody's prospects coming up later in the year in terms of what you thought potential would be in Japan pillows.
For the the well that you're going to be.
I guess testing nearly 21 in Brazil, and 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 top matters requires many many partner approvals and therefore, we do.
I do not have here I mean, typically in the Gulf of Mexico, you anticipate any exploration well to be a 75 million barrel plus type opportunity those are what we're always targeting there.
And our chiller area in Mexico, We had a discovery there last year was disclosed and that was a crystal position well with.
Good bit of all that is at flat spots. If you will need to come off that structure into a ficker reservoir and one of the wells, who did not have 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 structure of the chiluba well and then.
What kind of area from that from that well and the nearby opportunity that is identical to it same age depth next door. If you will these are 100 million barrel type of things that were de risking in that pretty large area. So we have two businesses in Mexico right now one is a.
Middle Miocene small tieback zone, and the 100 million barrel range northeast of the Telos discovery that we can easily add to an add on to very similar to what we do in the Gulf. This bad appeal as well as is a large well above $160 million equivalents of size and it's a very.
Large amassing structure under the salt and so those are those opportunities and of course are.
Gee Alagoas space and we're not disclosing the size of those opportunities, but 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 Thats all we can say about it.
Again, a typical well in the Gulf 75, we're touching a good bit of coast hundred and beyond in the Gulf and the Mexico region with these top of very expense and expensive wells treat wells and fat and then a big.
Big future opportunity for us in Brazil that we're very excited about but have limited disclosure at this time.
Okay. Thank you for the color.
Thank you.
Thank you. The next question is from Gail Nicholson from Stephens. Please go ahead.
Good morning Gale.
Joe Your line is open you May go ahead with your question.
Oh, sorry.
I apologize good morning Roger.
Good morning Jen.
I think mark it doesn't fully appreciate the benefit update I'll really how does the 24 time, Brian can you kind of talk about how the production looks.
The comes online and 23, and then how that step forward and how long the longevity of those volumes in the from.
Mike's going to handle that for you. This morning, Gail right here.
Good morning Gale.
St. Malo comes on late 23 early 24 kind of peaks. It adds over 5000 barrels a day net production to our offshore portfolio and adds about 32 million barrels of reserves.
Our our share and.
Significant NPV NPV and on $150 million to $160 million range with about a 18% to 20% rate or return.
55 dollar flat oil.
So it's significant and comes on at a good time for our offshore portfolio and last for very long time, yes.
Well into 2050.
Great and then 2019 Gulf of Mexico had been very healthy differentials can you guys just provide some color on how you guys you're viewing.
Friends Open 21.
Yes, thanks that the differential pitcher in the Gulf has been much better than forecasted from an IMO 2020 perspective that was.
Yes, really hasn't been a major impact the diffs are lower and they were in parts of 19.
Today in our Mars business, where we we mark off of Mars in the Gulf of Mexico. These to be all the assets, we purchased from Petrobras as well as our older Medusa and front runner feels it's about 36% of our production. These diff Sir.
Clearly over a one dollar.
Year to date the February diplomats $1.40 positive this at some shops as forecasted to be below.
Dollar negative in fact and at least in this to be much better than originally thought.
In HLS in the Gulf around 21%, there's some very very high margin crudes around our our Kodiak non op well on Oliver log business, we bought and the Dalmatian field that we have them 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. These juice in EMEA age, which represents 33% of our oil liquids coming out of air business in the Eagle Ford and this to have been about a 340 year.
340 positive to WT basis in which we mark the crude so overall, we're still to be position than a belief when you look at transportation.
And the realized pipe price of our company and where our barrels are located we will always be positive to almost any pier because the unique nature, where we're selling these barrels and very happy about the device that we have we think it's a competitive advantage and swine, we added our Gulf business and allocate more capital to our Eagle for business. If you have the huh.
Our prices you always have advantage.
Great. Thank you.
Thank you gave.
Thank you, ladies and gentlemen, as a reminder, should have any questions. Please press star followed by one.
And next question is from Paul Cheng from Scotiabank. Please go ahead.
Hey, guys morning, Paul.
Well if you have to had just a cap ex should we assume is all in Eagle Ford or that you. We also had jet side.
No as again I'd prefer not to disclose this at this time, we we have some field development paint plan approval payments in Vietnam.
That are part of our plan and which if you make that milestone that can be delayed and we're seeing some have differing costs in 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.
Or 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 will do.
Hi.
In the seal have you guys already identify what's what is the well you go into next year in the next year. It Where's that again, Paul I missed that.
But sales for Jay we have we have a good idea we have good idea of of course, but up.
Good we're dealing with a larger a partner there in that thank you could go back and monitor their disclosure on another super large project there in overtime and even anticipated similar disclosure here as well.
Okay. So you will not be able to give us a maybe IP to the takeaway on anything related to it at this point.
We will as we get towards ended the year I would imagine.
But it will be.
It will be a nice one.
Okay and when you say early next year, we talking about the beginning of the first quarter.
Yeah, the rig the rig plant the rig plan there is involved with permits in the schedule of our partners well involving some other blocks that they have and anticipate it to be.
Early in 21 at this time, yes, Sir okay.
Talking about roughly 60 90 days well.
Trying to understand that way I would imagine so.
I would imagine so yes.
Probably 90.
90 days, so probably sometime in the second quarter for the result as possible yes, Paul.
Okay.
And.
Maybe I missed it.
Once you when you're saying that youre not going to have any wells coming on stream in Eagle Ford for the next hundred days no no no. That's from the time, we put a well alone in early October and we're going to have some wells flowing Saturday.
Thats been a long time.
Oh, I see I think and but for that in the capital allocation of a front end loaded shale program impacts and we overstated production above our typical you are I've got burned for that in the fourth quarter now we.
I have that issue on top of long term planned front end loaded project that we've been drilling with three rigs there starting right at the end of the year.
And that we're bringing on a significant Tim well pad here pretty quick and feel good about our guidance and what we're doing there.
So why the first quarter, we not going to CND well coming on stream.
We are all we're starting this restarting Saturday morning.
It's been a while what I'm trying to say as it's hard in a shale play to and you'll find that rare to not put a well on and 100 days and but we're back clicking and adding wells throughout the quarter.
Significant cadence of wells building as Eric described earlier in the call.
Okay. That's fine the one for me.
Can you give us some what is the used to.
Well performance in the fourth quarter that you're talking about in what was the.
Compact full cost that you guys use and have you already had just that focus on your thing the used to it and well into full quota.
And that nominee annual corporate full colleges still okay.
Eric asset 40, Paul.
Sure Paul So, though is still than wells, we brought those wells online their IP thirtys were basically in line with our forecast there not the exact number it 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.
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 1000 Boe per day, and we expect that that gap will be there, but it will did decline through the year as the the expectation prior.
Declines like wells always do.
Thank you.
Thank you. The next question from Pavel Molchanov from Raymond James. Please go ahead.
Thanks for taking the question on.
One of the point you made in your kind of intro is you have reshaped the asset base could be a western hemisphere pure play.
But you still have the Vietnam exploration and it it feels like it's a little bit of an afterthought at at this point. So I'm curious what the logic is for retaining those assets.
Oh this significant upside in those assets and we have a significant discovery there.
That will be bringing online. We're currently doing feed and we'll be having field development plan approval there through the government the government their work so slow and we with our capital allocation have not been rushing NIM. If you will.
It's a very unique situation, we just added another block with a one well commitment and we have a series of prospects that are low risk.
Joe by Jackups and allows us all type of upside, but at this particular time with the capital allocation of having a limited CAGR 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, we would definitely drilling there next year and this is a.
Sleeper for us that's a significant and allows us all top of flexibility involving different parts of our business going forward. So.
Like Vietnam have a very unique position a very inexpensive entry position.
Very nice discovery, there that will be being put into our long range plan, it's inside what we've disclosed tier and.
Very excited about it just not being a lot of capital there. This year for for held for all those reasons that we read about every day.
Okay, one more one more exploration question on as I recall I think it was five or six years ago you made.
Effort to.
Do some drilling and Suriname I wonder the first I think international MPC could do that I know that kind of fits all the way now of course, we're seeing Suriname headlines on I know seemingly daily basis I'm curious if you have any interest in revisiting opportunities in that emerging geography.
Okay.
We're interested in all opportunities in the hemisphere in which we focus which is.
Which is South America Gulf of Mexico proper and Mexico offshore, where we have a significant block. We've recently added in Brazil, another segment imported by basin.
Those those wells, we were drilling so many years ago were totally different play a totally different time.
We as you know have been a global explore but we're trying to focus and own having more information and more focused in on data and just the basins of which we work.
Just because we havent participate 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 differing agreements that you agree to to look at someone's day with very very limiting you.
In a business development perspective going forward and in some of those places were unable to make an agreement that we would prefer to work in so we look in this region were 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 appreciate it.
Thank you so ill say that with the.
We have no more questions today and that will end our call today. We appreciate everyone for listening in and we will see at our next quarterly result, thank you so much.
Ladies and gentlemen, this concludes our call for today, we thank you for participating and we ask that you. Please disconnect your lines.