Murphy Oil Corporation (NYSE:MUR) Q4 2023 Earnings Call Transcript

Murphy Oil Corporation (NYSE:MUR) Q4 2023 Earnings Call Transcript January 25, 2024

Murphy Oil Corporation misses on earnings expectations. Reported EPS is $0.9 EPS, expectations were $1.03. Murphy Oil Corporation isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good morning, ladies and gentlemen. And welcome to the Murphy Oil Corporation Fourth Quarter 2023 Earnings Conference Call and Webcast. [Operator Instructions] I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Kelly Whitley: Good morning everyone and thank you for joining us on our fourth quarter earnings call today. Joining me is Roger Jenkins, President and Chief Executive Officer along with Tom Mireles, Executive Vice President and Chief Financial Officer and Eric Hambly, Executive Vice President, Operations. 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. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.

As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy’s 2022 Annual Report on 10-K on file with SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Roger Jenkins.

Roger Jenkins: Thank you, Kelly. Good morning everyone and thanks for listening to our call today. As we turn to slide two, I’d like to highlight Murphy’s ongoing focus on our priorities to Delever, Execute, Explore and Return throughout 2023, with another strong year of production and excellent execution, we achieved our $500 million debt reduction goal for the year and have reduced debt by $1.7 billion since the end of 2020. We produced 186,000 barrels equivalent per day for the year with 52% oil volumes. During the fourth quarter, we began procuring equipment for the Lac Da Vang field development in Vietnam and production resumed at the non-operated Terra Nova field offshore Canada with wells scheduled to ramp up production through the first quarter of this year.

In the Gulf of Mexico, we acquired an 8% working interest in the Zephyrus discovery for $13 million in the fourth quarter. For the year, we achieved 139% reserve replacement with preliminary total reserves of 724 million barrels equivalent and approximately an 11-year reserve life. In exploration, we were named a paired hybrid and 8 exploration blocks in the Gulf of Mexico federal lease sale 261 held last fall. We also continue preparing for our 2024 planned exploration wells in the Gulf and Vietnam and advancing seismic reprocessing projects in the Gulf of Mexico and Cote d’Ivoire. Due to significantly reducing debt prior to 2023, we’re able to reach Murphy 2.0 of our capital allocation framework last year, representing a debt level between $1 billion and $1.8 billion.

I’m pleased to say that we executed additional share repurchases totaling $75 million or 1.7 million shares at an average price of $43.42 per share in the fourth quarter. For full year 2023, we repurchased 3.4 million shares for $150 million at an average price of $43.96 per share. As a result, we have $450 million remaining under our share repurchase authorization at year-end. I’m pleased to return to the share buyback mode, where we have purchased $1.8 billion of stock in the last 10 years. We announced earlier today a 9% quarterly dividend increase to $1.20 per share annualized back to our level of 2016 and look forward to targeting Murphy 3.0 as we’re continuing delivering shareholder returns and reducing debt levels. On Slide three, Murphy’s production averaged 185,000 equivalents per day in the fourth quarter, 94,000 barrels of oil per day.

For the year, production of 186,000 equivalents with 98,000 oil per day. For the quarter, we realized over $79 a barrel of oil, reversing a slight premium to WTI. This is on a netback basis. As well as nearly $21 per barrel for NGLs and $2.12 per 1,000 cubic feet for nat gas. This led Murphy generating $788 million of total revenue in the quarter. And for the full year, we realized over $77 per barrel for oil and generated $3.2 billion in revenue, excluding NCI. On Slide four, great year reserves. Our preliminary proved reserves totaled 724 million barrels equivalent, representing a 139% reserve replacement ratio from year-end 2022. This increase is due in part to additional 13 million barrels equivalent of proved reserves for the Lac Da Vang field in Vietnam as well as AECO natural gas price changes.

Total proved reserves in 2023 were 57% proven and 41% liquids weighted, and we have a proved reserve life of 11 years. Overall, I am pleased to say we’ve maintained our proved reserves since 2020 with an average annual CapEx of approximately $1 billion, excluding non-controlling interest and including acquisitions, must also consider that our strong reserve outcome is based on oil price that was $15 per barrel lower than 2022. Further, our reserves, excluding Syncrude are 27% higher than a decade ago when we became an independent E&P company. I’ll now turn the call over to our CFO, Tom Mireles, to update us on our financial results. Tom?

Thomas Mireles: Thanks, Roger, and good morning, everyone. Turning to Slide five. In the fourth quarter, Murphy reported $116 million of net income or $0.75 per diluted share, $140 million of adjusted net income or $0.90 per diluted share. Due to another strong operational quarter, we achieved $414 million of adjusted EBITDA with $219 million of accrued CapEx, excluding non-controlling interest and acquisition-related CapEx. Murphy continued to return cash to shareholders in the fourth quarter by repurchasing $75 million of common stock at an average price of $43.42 per share. For the year, we achieved $709 million of adjusted net income and $2.1 billion of adjusted EBITDAX. Accrued CapEx totaled $1 billion, excluding non-controlling interest and acquisition-related CapEx. Further, our 2023 G&A expense was the lowest in more than 20 years.

On Slide six, as we discussed as of December 31, 2023, we had $1.3 billion of senior notes outstanding and $1.1 billion of liquidity and our next senior note maturity isn’t until December 2027. Since year-end 2020 and including our $300 million debt reduction goal for 2024, we will have reduced our total debt by 66% by year-end 2024. From 2020 through 2023, this resulted in about an $84 million reduction in annual interest expense on long-term debt. I’m pleased to say that during this time and more recently in alignment with our capital allocation framework, we have been able to increase our quarterly dividend and return to our 2016 level of $1.20 per share annualized. And since year-end 2014, Murphy has repurchased 24.8 million shares or 14% of the shares outstanding at that time.

While we are pleased to be back to our 2016 level on the dividend, investors are also advantaged by our balance sheet. Our net debt has improved 50% since 2016, and it’s the lowest since before 2012. Slide seven. As we first introduced a little over a year ago, our capital allocation framework defines three debt thresholds and corresponding shareholder return allocations. We’re currently in Murphy 2.0 with $1.3 billion of total debt and are targeting $300 million of debt reduction this year to reach Murphy 3.0. At that time, shareholder returns will increase to a minimum of 50% of adjusted free cash flow. Slide eight. At Murphy, we remain mindful of taking actions that benefit all stakeholders, and we are proud of our ongoing environmental and community stewardship achievements.

This is a focus at all levels of the organization and metrics such as greenhouse gas emissions intensity, safety and spill performance are all included in our annual goals. I’m proud of what we continue to accomplish at Murphy and highlight that these efforts are recognized repeatedly with top quartile rankings by third parties. All of our improvements can be found in our sustainability report, which is available on our website. And with that, I’ll turn it back over to Roger.

Roger Jenkins: Thank you, Tom. Let’s look now to the quarter results and our onshore assets we produced and combined 100,000 barrels equivalent today with 30% liquids weighting in quarter 4 and Eagle Ford Shale we produced 31,000 equivalents per day with 86% liquids. We brought on 3 non-operated wells in Tilden as all we had for the quarter. No wells were brought online in our onshore assets as well. In Tupper Montney, we produced 386 million cubic feet per day in the fourth quarter and initiated drilling a 10-well pad with 2 rigs. In Kaybob Duvernay, we produced 4,000 equivalents per day for the quarter, including 69% liquids. Turning to offshore in the quarter, Murphy produced approximately 84,000 equivalents per day in our offshore business at 82% oil.

The Gulf of Mexico production totaled 81,000 equivalents per day. We brought online operated Dalmatian number 1 well in the quarter as well as drilled, completed and recently brought online the Marmalard 3 well. Also during the quarter, we acquired an 8% working interest in the non-operated Zephyrus discovery for approximately $13 million after closing adjustments. And offshore Canada, we produced 4,000 equivalents per day. The non-operated Terra Nova FPSO resumed operations during the quarter and production is expected to ramp up this quarter in 2024. Looking at exploration as previously announced, we expanded our exploration portfolio in 2023 with the addition of 5 key blocks in Cote d’Ivoire, and we gain seismic reprocessing and the side for the opportunities in these blocks including advancing the field development plans for the undeveloped Paon discovery.

In Vietnam, the Murphy Board sanctioned the Lac Da Vang field development project in the fourth quarter. Our two exploration wells planned in 2024 provide upside to this development, particularly as one well is very near the platform facility. Lastly, in the Gulf of Mexico, we were named a parent bidder on 8 blocks in the latest federal lease sale. These locations will provide near-field exploration opportunities close to existing assets. Now we’ll dig into our capital and production plans for the year. On Slide 13, on the capital side, our plan is structured so that we can continue generating sufficient free cash flow to advance our capital allocation framework. We forecast a CapEx range of $920 million to $1.02 billion with nearly 60% of the spending in the first six months of the year.

Overall, 85% of our capital plan is designated for development work with 80% of this supporting operated activity. As we target Murphy 3.0 with our $300 million debt reduction goal in 2024, I’m pleased we were able to announce this morning a 9% increase in our quarterly dividend to $1.20 per share annualized. We’re also targeting share repurchase equal to 25% of our adjusted cash flow for the year, and we believe these goals can be accomplished at a minimum oil price of $70 a barrel. On the production side for 2024, our forecast for the first quarter production range is 163,000 to 171,000 barrels a day, including 53% oil. This range is impacted by 13,000 barrels equivalent per day of total Gulf of Mexico downtime as well as 2,000 barrels of oil equivalent per day of onshore downtime, including the Gulf downtime of 6000 per day associated with the wells currently off-line that are scheduled for work overs and will return to production in the first half of the year.

Also includes 5,000 barrels per day for planned facility and downstream maintenance as well as 2,000 barrels equivalent per day of downtime to repair a damaged subsea equipment in the Mormont field in the Gulf of Mexico. For the full year 2024, we forecast production range of 180,000 to 188,000 per day, including 52% oil volumes. This forecast includes approximately 2,000 barrels equivalent per day of assumed annualized Gulf of Mexico storm downtime and accounts for 2023 divestiture of some 1,500 barrels equivalent per day in non-core Canadian asset sales. Consistent with several years, our annual plan focuses on maximizing free cash flow, which has led to a first type weighted capital program. As a result, we have seen material production growth from the first quarter to the fourth quarter each year in 2024 is forecast to have a similar trajectory with production rising to nearly 200,000 equivalents per day in the fourth quarter, which will be our fourth year in a row of higher fourth quarter production.

Now for more details on the individual assets, I’ll turn it over to Eric, our EVP of Operations. Eric?

Eric Hambly: Thank you, Roger, and good morning, everyone. Slide 15. Our 2024 capital budget of $320 million for the Eagle Ford Shale supports a program of bringing online 19 operated wells, primarily in Catarina, as well as 18 gross non-operated Tilden wells. Additionally, we plan to drill 11 operated Karnes wells, which are scheduled for completion in early 2025. With ongoing utilization of our optimized completion design, we forecast 2024 production of 30,000 barrels of oil equivalent per day with 71% oil volumes. We recently contracted a new high-spec drilling rig from Patterson-UTI Drilling Company, LLC. While only one well has been drilled so far, we are extremely pleased with the results and hope to see advanced drilling efficiencies throughout the year.

Slide 16. Turning to Tupper Montney. Our 2024 capital plan of $90 million includes bringing online 13 operated wells, all scheduled for the second quarter. We are drilling in this area today and are 85% complete on our first 10-well pad. We forecast for average production of 370 million cubic feet per day in 2024 with this plan and look forward to continuing our real-time frac optimization, which has helped us achieve some of our highest IP30 rates in company history in recent years. Slide 17. In Kaybob Duvernay, we have a $40 million capital plan for 2024 to support bringing online 3 operated wells in the second quarter as well as initiating drilling a 4-well pad late in the year. Overall, we forecast average production of 4,000 barrels of oil equivalent per day, with 67% liquids volumes in 2024.

Slide 18. Our total 2024 offshore capital plan of $370 million supports bringing online operated and non-operated tieback wells in the Gulf of Mexico as well as the progressing of the non-operated St. Malo waterflood project, the Lac Da Vang field development project in Vietnam and the Paon field development plan in Cote d’Ivoire. Through 2024, we will bring 4 operated subsea tieback wells online with the first being Marmalard 3, which came online earlier this month. Additionally, 7 non-operated wells are forecast to begin production this year. Combined, we forecast average production of 88,000 barrels of oil equivalent per day for 2024. Slide 19. As disclosed in our last quarter call, we experienced mechanical issues at 2 operated Gulf of Mexico fields in 2023.

We have a rig currently on location at Neidermeyer, and the workover is expected to be complete in the second quarter of 2024. For the Dalmatian subsea safety valve repair, we anticipate completing this repair in the middle of 2024. We also have zone changes planned at 2 operated Marmalard wells in the first quarter of 2024. Additionally, earlier this year, we experienced an issue with subsea equipment in our Mormont field, and we’ll be making that repair in the first quarter of 2024. The non-operated Lucius #9 well workover has been completed and the well is forecast to return to production shortly. Additionally, the previously disclosed non-operated Kodiak 3 well stimulation and zone addition is scheduled for mid-2024. Slide 20. As announced last quarter, our Board sanctioned the Lac Da Vang field development project in BLOCK 15-01/05 in Vietnam.

We have allocated approximately $40 million of CapEx to the project in 2024 to support facilities construction. To ensure capital efficiency, the field will be developed in phases through 2029, reaching first oil in 2026. Overall, Murphy is targeting 100 million barrels of oil equivalent estimated gross recoverable resources, and we booked preliminary net proved reserves of 13 million barrels of oil equivalent at year-end 2023. We forecast a field will achieve gross production of 30,000 to 40,000 barrels of oil equivalent per day or 10,000 to 15,000 barrels of oil equivalent per day net to Murphy. The field is 96% oil and we will receive a premium to Brent oil pricing. And with that, I will turn it back to Roger.

Roger Jenkins: Thank you, Eric. As to exploration, our total 24 exploration plan of $120 million support the drilling of 2 Gulf of Mexico and 2 Vietnam exploration wells, which combined target approximately 120 million barrels equivalent on a net mean unrisked resource basis. Additionally, this plan funds related exploration costs and ongoing geological and geophysical work. In the Gulf of Mexico, participating in 2 Oxy operated wells, which are forecast to spud in the second quarter of 2024, both of these opportunities are located near infrastructure. In Vietnam, in addition to the Lac Da Vang field development, which is ongoing, we’re planning to drill 2 exploration wells in 2024, and I look forward to the upside possibilities that these material near-field exploration prospects provide.

The rig has now been secured to drill both wells beginning with the HSV exploration well in Block 15-2, which will spud in the third quarter of 2024 and target a mean upward gross resource potential of 170 million to 430 million barrels equivalent. We anticipate the [indiscernible] exploration well in Block 15-1 was flood in the fourth quarter of 2024. This well is just to the southwest of our Lac Da Vang field development and will target a main upward gross resource potential of $65 million to $135 million equivalent. Overall, these two exciting prospects gained further advantage by infrastructure provided by our nearby Lac Da Vang field. On Slide 23, in Cote d’Ivoire, we’re excited about the initial work completed on our newest country entry, including initiating size and reprocessing and looking forward to advancing the opportunities across our five significant blocks.

As well in 2024, we continue reviewing commerciality and field development concepts for the Paon discovery in Block CI-103, which is appraised with multiple wells by a previous operator. As part of the agreement on the block, we are committed to submitting to the government a viable field development plan by the end of 2025. Clearly demonstrated in 2021, 2022 and 2023, Murphy has done a tremendous job in reducing debt. We have built a strong, safe balance sheet for the company and resulted in a 0.7x debt to trailing 12-month EBITDA based on third quarter results. We’ve been able to accomplish this delevering of our assets and generate significant free cash flow, as highlighted by our peer-leading 13% cash flow yield and $23 per barrel of oil equivalent metric.

I’m proud that Murphy is a leader in these attributes and with reaching our $1 billion debt target later this year, which ties to one times EBITDA at a mid-40s pricing, we will be able to continue our effort to return cash to our shareholders with a much safer balance sheet and safer than our peers with no bonds to be refinanced in our business until late 2027. As we look to Slide 26, we maintaining a very similar long-term plan to what was disclosed a year ago as we now incorporate the LDV field development as well as higher exploration spending, all of which supports long-term oil production growth. Overall, we forecast to achieve our $1 billion debt target in 2024 with no additional debt maturities until 2027 and we accomplished this in part by reinvesting approximately 50% of our operating cash flow in our business.

Our average annual capital spend of $1.1 billion will support a 5% CAGR through 2026, increasing production up to an average of 195,000 equivalents per day to approximately 95,000 of oil equivalents per day produced in our offshore business. Through 2026, we remain focused on achieving first oil in Vietnam with key exploration wells planned in the Gulf, Vietnam and Cote d’Ivoire and conducting additional geophysical studies. Overall, our payout to shareholders will increase during this time as we reached 3.0 of our capital allocation framework. Longer-term, we plan to reinvest approximately 45% of our cash flows, achieving an average production level of 210,000 to 220,000 equivalents per day with more than a 50% oil weighting. We’re forecasting generating ample free cash flow to allocate towards additional debt reductions, further shareholder returns and accretive investments as well as supporting any exploration success.

Additionally, as part of this plan, we remain committed to achieving metrics that are consistent with an investment-grade company. This year’s plan has higher production levels in 2027 and beyond with significantly higher offshore production in those years compared to last. And further, we did lower our gas price in this plan, which you can be seen in the footnote of the slide. As we wrap things up here on Slide 27, as we look back, we had a great year on safety and protecting our people, we continue achieving new company lows every year on emissions intensity. We made strides in executing our capital allocation framework and achieved our decade low debt level on a net basis. We continue to reap the benefits of an oil-weighted high-margin asset base, and we grew our proved reserves.

This team is excited to advance our field development project in Vietnam and began the procurement process last year. We look forward to a potential upside in the area with our upcoming exploration wells. And also expanded — we’ve also expanded our exploration portfolio with additional blocks in Cote d’Ivoire. We have a solid foundation to move forward. We’ll continue building on our strong safety culture and target additional emissions intensity improvements. Shareholder returns remain at the forefront, and our debt reduction has only strengthened our balance sheet, and it made us more resistant cyclical commodity prices. Our business, a large multi-basin portfolio generates peer-leading cash flow metrics, but further support our shareholder returns while providing future optionality from our operations.

Lastly, we look forward to maintaining our exploration capabilities to augment our portfolio in a measured approach. In closing, as always, I thank our incredible employees for their continued dedication and hard work supporting our company. That’s the end of our prepared remarks today, we stand by for our calls, and we have a long list of calls here today. So here we go.

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Q&A Session

Operator: Thank you.[Operator Instructions] Your first question is from Arun Jayaram from JPMorgan. Please ask your question.

Arun Jayaram: Yes, good morning Roger and team.

Roger Jenkins: Good morning, Arun.

Arun Jayaram: Roger, I was wondering if you could shed some more light on your 2025 and 2026 kind of outlook. You’ve outlined a $1.1 billion average CapEx program from 2024 to 2026. And help us understand what type of spending projects you see in 2025 and 2026, which will impact the CapEx trajectory as well as how do you see spending trending in the LDV development, it looks like about $40 million this year, but obviously probably going to rise as you get closer to first oil?

Roger Jenkins: First on the question, thanks for that. We do have a plan this year. We consider to be fairly consistent with latest prices and plans. We’re going to be like $1 billion CapEx Company in those years. And if you look at our CapEx from 2023, 2024, it’s very similar, and I suspect it remains so. We have an ample list of Gulf of Mexico, 2P projects we call them the last — we have over 2 or 3 years of rig work there if we want it. We’ll be keeping our Eagle Ford Shale in that same level and reaching up to the field our plant in the Montney. The LDV project is not super expensive for Murphy, probably around $300 million total and it will be spread over 3 or 4 years very nicely. There will be no big slugs of CapEx there.

And I would consider the CapEx in Vietnam to go up in 2025 and 2026, almost doubling or slightly more and pull back in some of our non-op projects at St. Malo gets going. Terra Nova finally finishes their work. And that we get higher production in Montney to go forward. This plan is a very robust plan and what’s more robust about it in the past as we have found more offshore projects to do with Vietnam. We have a much more — much bigger offshore business. If you compare plan to plan, our offshore production is some 10,000 barrels a day higher than 2027. Our total production in 2028 is much higher than it was in the final plan and our oil production is 5,000 or 6,000 barrels a day in 2028 compared to last year’s plan. So this is a really good plan.

We’re going to accumulate between $5 billion and $6 billion of free cash flow from 2024 to 2028 million with the assets we own today, and we’ll be able to return massive amounts to our shareholders through buybacks and have very large dividend levels because it will be purchasing so much stock. And we’re extremely well positioned with this plan. It’s very much a consistent plan with inflation and things happening and resurging a plan like you do every year. And it’s in a really good shape, Arun.

Arun Jayaram: Great, thanks Roger. And I just had a follow-up. I was wondering if you could give us an update on the life extension plan, how that went to Terra Nova, and just kind of the ramp that you expect maybe some details on how you expect that ramp to play out kind of net to you — net barrels?

Roger Jenkins: I’m so super pleased with that execution. I’m going to let Eric cover it for you.

Eric Hambly: Thanks, Roger. That’s a great question. On Terra Nova, as we highlighted before, the life extension project was completed at the end of — created completed, sorry, in the middle of last quarter, fourth quarter of 2023. And we produced about 1,000 MBOE [ph] average in the quarter. We expect that the production will ramp up here pretty soon after they complete sort of the final stages of additional compressor commissioning. And in the first quarter, we expected to come up to around 4,000 barrels a day. And then on an average basis because it’s ramping through the quarter. And then for the last three quarters of the year, we expect production to be in the range or be around 5.5000 BOE per day net to Murphy.

Arun Jayaram: Great. Thanks a lot gentlemen.

Roger Jenkins: Thank you Arun. Appreciate your call.

Operator: Thank you. The next question is from Neal Dingmann from Truist Securities. Please ask your question.

Neal Dingmann: Hi morning. Thanks for the time. Roger, for you or Eric. Could you just talk a little more on color on Slide 18. I really think the upside from your Gulf obviously the Gulf offshore development seem to be quite material. And I’m just wondering, is the 300 kind of change that you talked about recently, I guess, to be exact, is that for just the first 3 projects Marmalad, Khaleesi and Mormont maybe just talk about the timing behind. I know you have a time line in here, but just maybe give a little more color on this, if you could because it looks so sizable.

Roger Jenkins: Thanks, Neal. They’re spending across all of it, and I’ll let Eric give you more detail.

Eric Hambly: Yes, sure. So 1 of the things we’re trying to highlight here is where we’re spending money this year. Obviously, if you look at the slide, you see production coming online from new wells across the year in the Marmalad, Khaleesi Mormont fields. We are also highlighting that we’re spending money in other fields, and it’s basically long lead equipment that we’re spending on in 2024 that will contribute to new volumes and new wells coming online, 2025, 2026, etcetera. And if we wanted to, we could make a table like this that would go on out to 2028, but we didn’t do that. So as Roger highlighted a few minutes ago, we expect relatively stable spending in our overall offshore business with all of these really awesome investment opportunities we have to continue to bring in more wells and do workovers, etcetera, in our offshore business and maintain those offshore volumes flat for the next several years with just the known stuff we have without an exploration success anywhere.

Roger Jenkins: Yes. Further on that, Neal, we have our Board meeting and we project our projects these are well in excess of 100% rate of return. And later on in the slide deck, we talk about workovers, which are unfortunate some of these wells had some mechanical problems after fix, the payout on these wells are 3, 4 months. So everything we do offshore 150%, 170%, 200% rate of return. So near infrastructure and unlike onshore, they’re spending on things without necessarily drilling. We have to buy long-lead equipment items, production equipment, drilling equipment casing. They’re spending on things associated with all these developments. This is some of the best investment you can ever make in the oilfield today.

Eric Hambly: Neal, one thing you may want to have a look at Slide 39 in our presentation, where we try to highlight the depth of our offshore inventory. We don’t disclose every single well by itself, but we do attempt to show you how strong and resilient they are. So the majority of our offshore identified projects breakeven below $35 a barrel. So super robust, super strong, high return. They’re well identified. These are known things in our portfolio that we’re planning to bring forward over the next several years.