SM Energy Fourth Quarter and Full-Year 2018 Earnings Results February 20, 2019
C O R P O R A T E P A R T I C I P A N T S David Copeland, Executive Vice President, General Counsel Jay Ottoson, President and Chief Executive Officer Wade Pursell, Executive Vice President and Chief Financial Officer Herb Vogel, Executive Vice President, Operations P R E S E N T A T I O N David Copeland: Welcome to SM Energy s Fourth Quarter and Full-Year 2018 Results Webcast. Before turning our discussion over to Jay, I will point to Slide 2 and remind you that we will be making forward-looking statements regarding our plans, expectations and assumptions regarding our future performance. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. Please refer to the cautionary information about forward-looking statements in today s earnings release, the IR presentation posted to our website, and the Risk Factors section of our 2018 Form 10-K for further discussions of these risks. Results for the quarter and full-year 2018 also include non-gaap financial measures that we believe are useful in evaluating our performance. Reconciliation of these measures to the directly most comparable GAAP measures and other information about these non-gaap metrics are provided in our earnings release and IR presentation. Speakers today are President and CEO Jay Ottoson; Executive Vice President and CFO Wade Pursell; and Executive Vice President of Operations Herb Vogel. I ll now turn the webcast over to Jay. Jay Ottoson: Well thank you, David. Good afternoon and thank you to all of you for joining our year-end review. 2018 was a very successful year for our company. We met or exceeded our objectives across the board, turning the corner to production growth after completing our planned divestitures. We made good progress in further delineating our acreage, and based on field test data and extensive analytical work, we ve been actively adjusting our development plans to ensure that we are achieving good incremental returns on the last dollar spent in every spacing unit. I believe that our 2018 results reflect the top tier quality of our retained assets and premier operational execution. 1
As we look forward, the next big milestone in our transformation of the Company is to begin consistently generating free cash flow and achieving that objective, starting in the second half of this year, is our most important priority for 2019. Wade and Herb will now give you more color on our 2018 results and our 2019 operating plan. Wade? Wade Pursell: Thank you Jay. Good afternoon. I ll start on Slide 3. Last year at this time we laid out a strategy with three pillars to successfully execute the 2018 plan. The first was to drive substantial growth and high margin production, focusing our capital allocation to the RockStar area of the Permian Basin. Production growth in the Permian was targeted at 75% and was actually more than 90%, notably beating our plan estimates. In turn, this supported a 66% increase in our operating margin. The second was to drive further capital efficiency, both by optimizing well performance through technology and detailed cost management. Our Operations team was outstanding on this front. Efforts resulted in significant value creation as evidenced by increased reserves and PV-10. Herb will provide more detail on this shortly. The third was to manage the balance sheet by divesting noncore assets. We sold the Powder River assets as planned, and also our remaining Bakken assets, generating proceeds beyond the plan expectations and reduced absolute long-term debt by $325 million. Simply put, all three were achieved and cash flow grew more than 50%. Fourth quarter and full-year 2018 results were pretty straightforward and the details were disclosed in the press release, the accompanying IR presentation and in the 10-K to be issued tomorrow morning. I ll focus the rest of my remarks on our plans for 2019, beginning on Slide 4. As Jay stated, the key objective of the 2019 plan is to generate free cash flow in the second half of the year and position the Company for long-term profitable growth and free cash flow generation from our core assets in the Permian and Eagle Ford in 2020 and beyond. Specifically, the plan reduces total capital spend in 2019 compared with 2018 by more than 20% to just over a billion dollars. The plan also generates nearly 20% growth in Permian Basin production, delivers solid full-cycle returns on the last dollar spent per spacing unit using our base case $55 oil and $3 natural gas prices, and maintains leverage in the 3X area which should really begin to fall in 2020 with continued cash flow growth and free cash flow generation. Moving to Slide 5, our total capital spend budget at the midpoint of guidance is $1.035 billion, of which roughly 90% is for drilling and completion, and about 10% is for capitalized overhead and facilities. Of the D&C capital, approximately 80% is allocated to Permian and 20% to the Eagle Ford. Our partner in the Eagle Ford has renewed our JV and they carry 100% of the costs. In terms of activity in 2019, we are looking at a modest decline from 2018. In the Permian Basin we plan to drill and complete approximately 100 net wells, and in the Eagle Ford we expect to complete approximately 18 net wells, while the JV anticipates completing 12 gross wells. I m now on Slide 6. This activity is expected to result in total production of 45 million to 48 million BOE or 123,300 to 131,500 BOE per day with approximately 43% to 44% oil in the commodity mix. Effectively, that is roughly 20% growth in Permian production and flat Eagle Ford production. The plan reflects relatively flat production in the first half of 2019 with production growth expected to be back-end weighted 2
due to the completion schedule, including no net completions in the Eagle Ford until March. More details with respect to specific line items are included in Slide 7 for your reference. Regarding hedging, as you probably know we are very well hedged in 2019; the details are in the appendix to the slide deck. In closing, I think is a very exciting time for the Company. Achievement of an extremely important objective is right in front of us, and that is growing annual production on a high single-digit percentage basis while generating free cash flow. Our 2019 plan shows that starting in the second half of the year and then continuing in 2020 and beyond. Thanks for your time and I ll now turn the call over to Herb. Herb Vogel: Thank you, Wade. I will start by summarizing our year-end reserves before moving on to our 2018 operational highlights and 2019 plans, first for the Permian and then for South Texas. Turning to Slide 8, which shows our proved reserves and PV-10 as of December 31, 2018. The increases in these metrics year-over-year are largely a result of our asset quality coupled with excellent operational execution, benefiting as well from improved commodity pricing. Proved reserves at year-end were 503 million barrels equivalent, up 185 on a retained asset basis. We added 188 million barrels equivalent through drilling and extensions. As shown on the slide, this was 119 million barrels net of the 69 million barrels of revisions and development plan changes which were affected by the five-year rule. Reserve growth, summing additions less revisions from year-end 2017 to year-end 2018 was 2.7 times our 2018 production of 44 million barrels equivalent. Noting the higher SEC price decks using reserve calculations, we ran a sensitivity on reserves at year-end strip pricing $50 oil, $2.70 gas and $23.70 NGLs. In this hypothetical case proved reserves would only have been nominal 12 million barrels equivalent lower, demonstrating the high returns and low breakeven prices of our asset base. PV-10 at year-end was $5.1 billion, up $2.3 billion on a retained asset basis, demonstrating the value creation achieved at our core assets. Permian value was up about $1.6 billion based on our successful delineation and development drilling, and Eagle Ford was up about $0.6 billion as a result of the increased value per well under our revised development plans with longer laterals and wider spacing. I d like to make one additional point here as it relates to calculating our Eagle Ford PV-10 or NAV, which should be incorporated into your models. Our transportation charges will improve significantly in the coming years with contract terms that reduce our gathering fees by more than $0.20 per wet million BTU in mid 2021. In addition, our earliest and highest priced long-haul transport commitment rolls off in 2023. At today s rates, replacing this contract would yield more than $0.30 per wet million BTU improvement in netback gas prices starting in mid 2023. Slide 9 provides more context related to the value of the portfolio transition that we embarked on in 2016. Here you can see the large increases in year-end proved reserves and PV-10 over the past three years. You can also see the impact of the divestitures on our year-end reserves. This is a remarkable improvement in value over this time period. Now, turning to the Midland Basin in 2018 and Slide 10. During the fourth quarter in the Permian we achieved among the highest average IP-30 of any quarter to date for the 36 wells that reached their IP-30 3
during the quarter. In all, 29 new RockStar wells reached 30-day peak rates that averaged about 1,400 barrels equivalent per well and included wells in three intervals and across our position; 12 were fully bounded, and they averaged 9 wells per section within Zone, and then obviously more in plan view. In particular, 2 Beesly Wolfcamp A wells located in the middle section of RockStar, an area we refer to as Big Iron, had averaged 30-day IP rates over 2,000 BOE per day per well, and one of these was fully bounded, the other half bounded. On the west side of the Midland Basin, we added a total of seven great new Sweetie Peck wells that averaged nearly 1,500 BOE per day per well peak 30-day rates. These were also completed across three different intervals, three Lower Spraberry, one Wolfcamp A and three Wolfcamp B. Slide 11 brings all this together for the RockStar area to show that our latest quarter s wells once again outperformed the average of our previous 104 wells. We are certainly improving. Production performance is proof positive, and I need to thank all of our multidisciplinary teams and advanced data analytics for driving that. I d now also like to summarize some of the key accomplishments specific to our Permian operations team who were able to exceed plan metrics in 2018. Most notable accomplishments for the year included, first, big steps in capital efficiency. Slide 12 was updated through year-end. We doubled the number of stages pumped per day year-over-year and increased the stages per day by over 150% since the third quarter of 2016. I need to point out that these are big stages, typically over 300,000 pounds of sand and over 8,000 barrels of fluid per stage, and that pumping more stages a day reduces our spend on ancillary services as these contractors spend less time on the well pad. Our contract for local sand started to deliver and enabled us to increase from about 20% local sand in the first quarter to just about 100% local sand by the end of the year. This results in significant cap ex savings for us. We successfully completed four wells with nominal 15,000 foot laterals at RockStar. These wells are more capital efficient because a higher percentage of the entire length of the well produces hydrocarbons than shorter laterals. Second, testing new intervals. During the quarter we brought online our first Middle Spraberry well in the RockStar area, the McFly Well. It hasn t yet reached its IP-30 but to date it is performing similar to our Lower Spraberry wells which are characterized by a longer period of production to reach peak, followed by a shallower decline. We are very pleased with the performance to date and anticipate that it will reach peak IP-30 this quarter. What is important about this well is that it is producing from an interval that we didn t even value at acquisition time in late 2016. During the fourth quarter, we also drilled one Wolfcamp D and one Dean well in the RockStar area. We are completing them now and should have them on production later in the year. We are excited to see the results because offset operators have seen success in these intervals. These are two more intervals that were not valued at the time of acquisition. Third, we designed and constructed our backbone produced water management system through the core of our RockStar acreage. This reduced trucking of produced water and mitigated our spend on third party water disposal. Importantly, we also have control of an efficient system that enables us to ensure disposal is available when our new wells are ready to be turned in line. 4
Wrapping up on 2018, we previously released information about the impact of the force majeure events which affected two of the third-party operated gas plants which process our gas, and also pointed to two separate weather events. I won t replay that now but I will say that we were fortunate that we were able to reroute some of our gas production to other plants. We also previously announced that one of those thirdparty gas plants continues to remain out of service. We expect this to be back in service at the end of this month and have adjusted our guidance accordingly. Turning to Slide 13 and our Permian operational plans for 2019, currently in the Permian we are running five rigs and three completion crews; we ll add another rig next month. The 25-well Merlin-Maximus development on four pads is on schedule and everything is running smoothly to date. We expect 24 of the 25 wells to be on production by the end of the quarter. You might recall that this development includes nine Lower Spraberry, 11 Wolfcamp A and five Wolfcamp B wells. Overall, we plan to complete about 100 net wells this year, which is about he same count as last year. However, as I will elaborate later, the distribution of the intervals completed this year will be quite different than last year. Many more Lower Spraberry wells this year. In RockStar, we are planning on an average initial well cost of $7.7 million which includes an average operated lateral length of 10,300 feet, about 1,800 pounds of sand per foot, and 167-foot to 200-foot stage spacing. Compared with well costs from last year, we assume increased rig rates and decreased completion costs as we take advantage of local sand pricing and completion design optimizations. In the Permian, we believe that we have about 12 to 16 years of economic drilling inventory on our acreage in known intervals that would be developable at current activity and cost levels. Over the last two years we published sweet spot maps which showed in the RockStar area in particular which intervals worked over a large area. We found that savvy land investors really appreciated those maps and increased the cost and value of acreage around and adjacent to our acreage position. This year, we decided that rather than show maps we would just characterize how many intervals we believe we can drill as a percentage of our 82,000 acre Permian position. After having completed another 100 wells in the Permian in 2018, testing new intervals and seeing offset operator well results, our confidence level has grown in understanding which intervals worked where and what spacing levels would be appropriate. We concluded that just over one-half of our acreage has four to five intervals that can be drilled economically, and the remainder supports two to three intervals across our entire Permian position. Our inventory estimates incorporate specific spacing assumptions by localized area and interval, which are supported by production performance from offset wells. We are calculating our Permian PDP BOE decline rate at 47% from year-end 2018 to year-end 2019. These same PDP barrels would decline by 31% the following year from year-end 2019 to year-end 2020. To better understand and model our production guidance, I should point out one characteristic of this year s program that is different from last years which affects our oil production guidance. Last year in the RockStar area only about 9% of the wells we brought online were Lower Spraberry wells. In this year plan, 36% of our new completions will be in the Lower Spraberry. You might ask what are the implications of this change and the distribution of intervals completed. 5
Turning to Slide 14 which we showed last year, as you can see Lower Spraberry wells ramp up to peak production more slowly than Wolfcamp wells. As a result, our 2019 oil production profile builds with a slower ramp-up. However, because the Lower Spraberry is shallower, the wells cost less to drill, and with ultimate recoveries similar to the Wolfcamp A, the returns are nearly the same. Now let me turn to South Texas and some of the accomplishments of the team there in 2018. We previously shared with you our revised development plans which increased lateral length and spacing throughout the Eagle Ford. While our average completed lateral length in 2018 was just over 9,000 feet, we drilled 10 new wells with 12,000 foot laterals, most of which will be brought into production in 2019. We started producing some of our wider spaced wells and anticipate that at midyear we will begin to share results with you. Turning now to Slide 15 where I will introduce our Austin Chalk results in South Texas. In previous calls, I mentioned that we were testing the Austin Chalk and would share the results once we had sufficient production performance history. On this slide you can see a map on the upper right, showing where we have obtained Austin Chalk production data on our acreage. On our left, we show the production performance of our latest Austin Chalk completion which began producing in July. The Galvan Ranch C917H has a relatively short lateral but achieved a very strong three-stream IP-30 of over 2,000 BOE per day. What I want to draw your attention to in the production figure is not only the relatively flat condensate decline rates, but also the very high NGL production rate. When factoring in only two-stream production, the very significant value enhancement of the NGL stream can be overlooked. So, what we like about the Austin Chalk is the higher condensate and NGL yield that these wells deliver relative to both the Upper and Lower Eagle Ford, and how that can benefit returns and value. Specifically, the condensate yields in the Austin Chalk are about double those in the Upper Eagle Ford and about six times those in the Lower Eagle Ford where we have data. The NGL yields in these same areas are 20% to 30% higher in the Austin Chalk. The gun barrel view shows the 917H and offsetting wells in the Lower and Upper Eagle Ford. From tracer and pressure data we were very pleased to see very limited interaction between the offset Eagle Ford and the Austin Chalk wells despite relatively close spacing. Building from the encouragement of the 917H results, we just completed an Austin Chalk well that is shown in the map in blue with a completed lateral length that exceeds 12,000 feet. Given the positive results we have seen, we have plans to drill three more this year, shown in black on the map. With continued success, we will integrate our Austin Chalk development plans with the Upper and Lower Eagle Ford to grow our top tier inventory. Now, turning to Slide 16 and our South Texas operational plans in 2019. First, we re currently running two rigs and two completion crews. Our joint venture partners elected to continue activity and fund a second phase which will include drilling six and completing 12 gross wells in 2019 in our Eagle Ford North area. This is an area where we are significantly extending lateral lengths and increasing spacing to demonstrate the value potential. We are excited to enter this second phase and expect to see a significant uplift in value from the wells, especially relative to previous expectations from tightly spaced pilots. Our completion plans include 18 net wells with average lateral lengths of 11,570 feet and 1,040 foot spacing within zone at an average well cost of $6.9 million. Our average completion design will utilize 2,000 pounds of sand per foot, with 225 foot stage facing. Now, we re really excited about the potential for these new wells which we believe will provide a multiple fold improvement in the NPV pre well relative to our previous development program. You may see that 6
our 2019 plan holds Eagle Ford production flat relative to 2018 with about 18 new completions, reflecting expected improved well performance. Note that our planned average lateral length this year is about a 28% increase over last year. Increased lateral lengths and spacing between wells in the Eagle Ford increases the value per well and our asset value while reducing total development capital and our nominal growth well inventory. As you can easily picture, one 15,000 foot lateral can replace two 7,500 foot laterals and deliver similar rates with less cap ex, and that leads to value enhancement. In South Texas, we believe that we have about 12 to 14 years of economic drilling on our acreage in known intervals that would be developable at current activity and cost levels. We are calculating our Eagle Ford PDP BOE decline rate at 29% from year-end 2018 to year-end 2019. These same PDP barrels would decline by 17% the following year from year-end 2019 to year-end 2020. With that, let me summarize by saying that in 2018 we enjoyed outstanding operational execution that demonstrated the top tier nature of our assets. We demonstrated significant improvements in capital efficiency. In 2019, we will initiate new steps to optimize our capital spend, continuing our track record of performance. Specifically, this year we expect to deliver nearly 20% growth in Permian production and deliver notably improved returns in the Eagle Ford, and we plan to continue testing the upside potential of new intervals at both our top tier assets. With that, I ll turn the call back over to Jay. Jay? Jay Ottoson: Thanks Herb. In conclusion, I d like to make two points on Slide 17 and 18. First, as indicated by independent observers, we re making great wells in the Midland Basin, and our average well performance there improved significantly from 2017 to 2018. As Herb mentioned, the wells that reached their peak IP-30s this last quarter had among their highest average IPs of any group of wells we have announced to date. We ll continue to optimize our program in the Permian to create value in 2019. When we get to year-end, we re confident that we will be able to show you this same kind of year-overyear value improvement performance in our Eagle Ford program. Lastly, I d like to note that in 2018 we produced our first corporate responsibility report which is available on our website. This past fall we also reached out to a number of our larger shareholders with an offer to discuss corporate governance and social responsibility issues. I d like to thank all of you who engaged with us in those resulting conversations. We found them to be helpful in understanding the priorities of our investors. With that, I will close by saying thank you to you for your interest, and we look forward to addressing your questions on our quarterly conference call tomorrow morning. 7