SandRidge Energy, Inc. (SD) Q1 2019 Earnings Report, Transcript and Summary

Good morning. My name is Heidi and I will be your conference operator today. At this time, I would like to welcome everyone to the SandRidge First Quarter 2019 Conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session [Operator Instructions]. Thank you. Johna Robinson, you may begin your conference.

Thank you, and welcome everyone to the conference call. With me today are Paul McKinney, President and Chief Executive Officer; Mike Johnson, Chief Financial Officer; and John Suter, Chief Operating Officer. We would like to remind you that in conjunction with our earnings release and conference call, we have posted slides on our website under the Investor Relations tab that we will be referencing during this call. Keep in mind today's call contains forward-looking statements and assumptions, which are subject to risks and uncertainties, and actual results may differ materially from those projected in these forward-looking statements. We will also make reference to adjusted EBITDA, adjusted G&A and other non-GAAP financial measures. Reconciliations of these measures can be found on our website. Also, you will see us file our 10-Q later this afternoon. Now, let me turn the call over to Paul.

Thank you, Johna and good morning everybody. Thank you for taking the time to join us today and for your interest in SandRidge. We plan to review with you today our first quarter results and to provide updates on our operations and guidance. We'll be referencing the investor presentation that Johna just mentioned, we posted it on our website early this morning, and we encourage you to use it to follow along. We will begin today on Page 3 where we've included an overview slide with a map that highlights our location -- the location of our operations and a table that summarizes our current market and financial information and our company production reserves and asset information. We hope that you find the consolidation of all this information useful. Moving on to Page 4, this is a summary we shared with you in our last call that highlights our new business strategy, and the key components we believe lead to both near-term and sustainable long-term success for our shareholders. This strategy will continue to focus our efforts as a company and is one of the defining aspects of our culture that we believe will lead to competitive debt adjusted per share returns. Now moving on to Page 5, we provide a summary of our first quarter highlights which Mike Johnson will review with you in just a moment. Before turning this over to Mike, I want to share with you several points. First our results this quarter demonstrate early progress in our business strategy. Our production is up 4% over previous quarters, and we have substantially reduced our year-over-year cash costs with reductions in both LOE and G&A. We intend to continue our focus on reducing our cash cost, throughout the remaining quarters of this year and plan to limit our capital spending to stay within or very close to within our annual cash flow. In light of commodity prices and the environment we're in, we believe it is prudent to preserve our balance sheet. We also believe that by doing so we preserve flexibilities to take advantage of the opportunities in the marketplace. The next point I'd like to make is how pleased we are with the results from our drilling programs in both North Park and the Midcontinent areas, and the progress we are making in understanding the best way to develop the North Park play. If you recall, one of the objectives of our capital program in North Park this year was to reduce the uncertainty with respect to the resource in place and to test different well spacing and well configuration patterns to help define an optimum development plan. We included two well spacing tests in our program this year. One that began in the fourth quarter last year to test the equivalent of 23 wells per section and the other to test the equivalent of 15 wells per section, that is currently ongoing. We have early results from this quarter from the six wells that constitute the 23 wells per section test that provide new insights into well configuration and completion technology. John Suter will share more details in this regard later in this call. With respect to the 15 well spacing test that is ongoing, we hope to share those insights with you later this year perhaps as early as the third quarter. We believe it is important at this point to emphasize though that we are making the early investments and taking the time to complete the technical analysis necessary to define the optimum well spacing before full field development is underway. We hope that this gives our shareholders confidence that although other companies may be accused of rushing to develop their assets on close spacing only to encounter interference and suboptimal economics, SandRidge is investing in the technical due diligence necessary to ensure that we maximize the value of these resources. With respect to the regulatory change in Colorado, as many of you know, Colorado Senate Bill 181 is defined in law that various regulatory agencies are in the process of finalizing their rulemaking, and we will have more certainty as these new regulations are rolled out. However, we anticipate that our development plans will not be materially impacted, primarily because none of our leasehold is located in highly developed and populated areas. We look forward to working with Jackson County, the Colorado Oil and Gas Corporation Commission, the BOM and the local community to safely and responsibly continue our development plans there. So with all of that being said, we will turn this over to Mike Johnson and then later to John Suter to review our 2019 first quarter results. Once they're done, I'll be back to finish up with some closing comments.

Thank you, Paul. I will be commenting broadly on various aspects of our earnings release, as well as Slide 5 of our earnings presentation. Our first quarter results have put us right on track to meet or exceed expectations and guidance for 2019. We posted a net loss of $5 million in the quarter compared to a net loss of $41 million in the first quarter of 2018, and generated adjusted EBITDA of $41 million in both of the first quarter of 2019 and 2018. We're pleased with this level of cash flow in the current quarter given a 12% decrease in average oil prices during the period, and 36% decrease in natural gas liquid prices, partially offset by 7% increase in natural gas products. In the aggregate, we had a 15% reduction in the blended price of our commodities, yet held adjusted EBITDA flat. This was achieved as a result of continuous efforts to lower our cost structure throughout 2018 and the first quarter of 2019, as well as the benefit derived from our natural gas swaps in the first quarter. With respect to controllable cost, LOE decreased 3% year-over-year and 2% on a BOE basis. G&A decreased $4 million or 27% and adjusted G&A decreased $2 million or 17% year-over-year. Additionally, natural gas swaps opportunistically added last year on 4.5 Bcf of first quarter 2019s production at an average price of $4.28 per MMBtu, generated a cash benefit of $5.1 million for the quarter. Although, we currently have no derivatives in place, we intend to layer in additional commodity prices derivatives during 2019 as the right opportunities arise. Because our 2019 capital expenditure plan is front-end loaded with roughly 70% our capital schedule to be invested in the first half of the year, we exited the first quarter with $20 million drawn on our revolver and a little over $7 million in unrestricted cash. Based on the current strip for oil and natural gas, we expect to exit 2019 undrawn on our credit facility and otherwise debt free, demonstrating once again our commitment to operating within our cash flow. This allows us to maintain attractive debt metrics and plenty of liquidity available to grow the company, while executing our development plans in 2019 and beyond. It should be noted our spring borrowing base redetermination is underway with our bank group, and we plan to have this completed in the coming weeks. The existing facility matures in March of 2020 and consequently the amount drawn on our facility is classified as a current liability. We will be seeking to amend the existing facility to include an extension of the maturity date for at least one other year. I'll now turn it to John for his thoughts on our first quarter operational results, and his outlook going forward.

Thanks Mike. Total company production for the quarter was 3.2 million barrels of oil equivalent, comprised of 27% oil, 28% NGLs and 45% natural gas at an average lifting cost of $7.21 per BOE. The company brought 15 wells to sales, primarily comprised of wells that were undergoing drilling and completion operations as we entered the year. CapEx for the quarter was $71 million with $54 million in drilling and completion costs. 2018 carryover activity contributed to more heavily weighted capital spend in the first quarter compared to the remaining quarters of 2019. Rig utilization will be substantially reduced in the second half of the year unless cash flow increases warrant additional development activity over current plans. Let's begin the review of our assets with an update on our North Park activity. During the quarter, we utilized one rig and made meaningful progress on three strategic objectives that are critical to our long-term development plan. These objectives are; one, gathering technical and production data to evaluate optimal spacing, or maximizing present value and oil recovery; two, establishing additional production and improving the geological understanding of our northern and southern leasehold along the eastern side of the play; and three, driving down development cost with pad drilling and completion optimization. If you'll turn to Slide 6, I'll address our valuation work related to our first objective to determine optimal spacing. We've acquired and are still unpacking comprehensive technical data from our microseismic and tracer test program. We implemented for the Western spacing test involving the Peters wells. We've gleaned some early knowledge and expect the complete analysis to be finalized soon. What we've learned so far is that the Niobrara fracture simulations in this area of the play tend to be tall and narrow with the current job design. This suggests that optimal spacing for this reservoir could be accomplished with two rows of wine racked wells, ensuring that no lateral is positioned directly on top of one another. We're still reviewing east-west spacing but the data suggests that 15 wells per section appear to be more appropriate based on preliminary conclusions. We continue to assess and apply our technical learnings for an optimal development plan that will maximize value. On Slide 7, you'll see we developed our Western spacing test with six Peters wells utilizing a 23 equivalent wells per section pattern. These wells averaged a peak rate of 450 barrels of oil and confirmed well interference based on tracer surveys and microseismic testing. While still making substantial oil volumes and an estimated 10% to 15% rate of return, these wells were purposely drilled to test the high side of our spacing options and still be within normal oil recovery ranges indicated by well core data. Establishing high density spacing early in the development of the play and applying more optimal patterns allows us to drill fewer wells knowing that limit, while achieving the same amount of reservoir recovery. Moving now to Slide 8, our second objectives of delineating the southern and northern federal units along the east side of the play. During Q1, three new surprise unit wells one XRL and two SRLs, finished drilling and were completed in our planned southern delineation program as described last quarter. These wells diverse three new sections that hadn't previously been tested within the core area, and are producing approximately 1,800 barrels oil per day; one of the SRLs has consistently averaged 800 barrels of oil per day, which is twice the type curve expected oil rate. In addition, two Ray Ranch SRLs were drilled near the highly productive [Janet] Castle wells. All five are in early stages of initial production testing. We'll have detailed information on their 30 day IPs for the Q2 call. On the northern side of the play, we deployed the rig to drill on a six well pad. The Peterson Ridge unit two and six were drilled as XRLs to reach the farthest limits north to-date. From this same pad, we now are drilling south on the second of four patriot wells. We are testing a 15 well per section two row wine rack pattern based on technical evaluation of our initial micro seismic results. The remaining Patriot wells will finish drilling by the end of May. Infrastructure build-out will commence after the regulatory stipulation period, and allow all six wells to come on later in the third quarter. We are excited by the early results in both the northern and southern extensions of the play. The southern wells are already producing with IPs averaging above type curve and better than expected pressures. The northern wells have had excellent gas shows while drilling the laterals, which has been historically a positive indicator of strong hydrocarbon production upon completion. Our eastern acreage resource assessment plan continues to progress. As mentioned last quarter, we intend to drill two to four vertical wells with minimal capital on the eastern flank to further validate resource potential and hydrocarbon mix before committing to horizontal development. We have an approved permit to drill on the far northeast block of acreage. We anticipate spudding the first vertical well this year. Another similar evaluation location has been proposed in the far southeast areas of our acreage. Moving now to our third quarter objective in North Park on Slide 9, we are focusing on reducing drilling costs and improving completion performance metrics. We've successfully reduced our drilling costs by 24% since 2017 to now $110 per foot in Q1 2019. We also reduced Q1 stimulation costs by 17% to approximately $55,000 per stage during that same time period. This will save significant capital over the 270 planned stages left to frac this year. On Slide 10, as mentioned last quarter, we expected a production ramp in the first and second quarters from North Park with six wells that were undergoing drilling and completion as we entered the year. The first quarter North Park gross average production was 3,600 barrels of oil per day and our current daily spot oil rate is approximately 7,000 barrels oil per day. Our Q1 production ramp was slightly delayed due to work required immediately before entering into a regulatory stipulation period with confined work hours. A temporary shut-in period was required mid-March through early-April to complete necessary artificial lift installations and production facility build-outs for the Peters' Surprise unit and Ray Ranch wells. Now that work is completed, we are seeing the anticipated production gain from last year's drilling. On the infrastructure side of our business, we completed the Surprise central tank battery, the second of six planned to handle all the anticipated future field production. Later this year, we will construct the Peterson Ridge unit and the Willoughby central tank batteries for new wells. Gas processing through our MRU continues to average a throughput of 2 million a day as planned. The contracted GTL skid faced some manufacturing delays, but is scheduled for commissioning in early Q3 of this year. Now, I'd like to move from our North Park basin asset to the Midcontinent assets on Slide 11. Our Mississippian assets contributed 2.7 million barrels of oil equivalent 18% oil, 31% NGLs and 51% natural gas, a 5% increase over Q4 2018. Under our gas processing agreement we've been in a period of ethane recovery, which has bolstered our Mississippian NGL yields for the quarter. On Slide 12, we brought seven new Northwest Stack Merrimack wells to sales during the quarter that produced the 30 day IP per well average of 576 BOE per day, which is 76% oil. We're in the process of drilling the final two wells to conclude the drilling participation agreement. For the wells that went to sales during the quarter, our high interest wells that resulted in 29% increase in Northwest Stack production versus the prior quarter. We have additional locations identified that support the plays' infill potential. In closing, I'm excited about our progress toward our North Park strategic objectives and our Northwest Stack initial test rates. Most of all, though, I'd like to thank the team for our excellent safety record for the quarter with a total recordable incident rate of zero for company personnel. I'll now hand it back to Paul for closing remarks.

Thank you, John. In closing, we'd like to summarize by saying that we have experienced a solid quarter executing on our program and key elements of our strategy established at the beginning of the year. As John pointed out earlier, our operations team delivered according to plan and advanced several important strategic objectives in North Park that will reduce cost and set up efficient future development of this field. In the Northwest Stack wells are meeting or exceeding type curve, and we have expanded our inventory of attractive drilling opportunities there. Overall, our capital spending program is going according to budget. And although, we are drawing on our RBL in the early part of the year, we expect to exit the year with zero balance as long as commodity prices remain favorable. As you can see on Slide 13, we are reaffirming our guidance with no changes to make at this time. However, as we stated in our last call, we are focused on further reducing cash costs below the level achieved in 2018, and we are actively evaluating opportunities to improve shareholder value. With respect to current market conditions we continue to experience volatility in the commodity prices as we observe majors competing for large independence with coveted assets and for strategic reasons. We believe we are entering a time in our industry where opportunities for consolidation are more likely. And as these conditions mature, we believe the industry will see increased A&D activity as these companies rationalize their portfolios. It is our hope that to be an active participant in that marketplace. Having said all that and at this point, I'd like to express my sincere appreciation to all of you joining us on the call today, we'll now turn the call over to our moderator and open for question.

[Operator Instructions] Our next question comes from the line of Bill Dezellem with Tieton Capital. Please go ahead.

Good morning and thank you. A couple of questions, first of all, did we see correctly on the graph that the North Park production is at its highest level that it has been. Was that correct?

Yes, it is correct.

And then I do want to circle back to your comments about costs per foot coming down, both on a drilled basis and then the per frac stage basis. Would you talk to what you have done to accomplish that and how much more you view as possible?

It really has been a number of things, I know that a bit selection has been -- in the lateral has been a key thing for us. We have really refined our mud program to be able to drill these wells with lesser mud weights, helping not only from reducing cost of lost mud but also just allowing faster penetration rates. And certainly, additional bidding of key elements from casing, applying learnings from two or three years now in the basin, but I would say probably the latest has been a bit selection and mud program improvements. And then as far as where can that go, I think we've drilled wells down as low as I believe it's about $92 per foot and we continue to get closer and closer to what we currently see as a technical best on our abilities, and I think that we will continue to make improvements there. We often modify that faster and cheaper. And then certainly from a total cost standpoint, again, the big money is in completion and that stimulation cost reduction has made a significant impact. We think we can get wells down closer to $6 million that we're drilling now for these long laterals in situations or we can skip the rig and not have to have rig movement costs.

And on the cost per frac stage, what have you done there and what's the magnitude of what you think you might be able to do accomplish going forward?

So I think that we have made changes in both design and number of stages, pump rates, just a number of variables. We've also worked very tightly with our primary vendor up there. And by working together, we can figure out what's the most efficient for them to get the most stages per day, as well as find out what their key cost points are. And by working together as a team, we've really been able to both gain some profit margin here.

And if I may ask one additional question, on the M&A front, Paul. Would you discuss what it is from a strategic perspective that you're looking for and how the perfect deal would look to you?

Bill, that's a good question actually. To us, we are looking for opportunities to perhaps acquire PDP production that with that PDP production comes undeveloped opportunities that present superior economic returns than the portfolio that we currently have. We're very excited about the economics in North Park, and so that looks real attractive. But as we stated last quarter in our call, much of the inventory that we have in the Midcontinent, especially referring to the Mississippian line, we need higher prices before that becomes a compelling investment. And so again, the ideal candidate for an acquisition target would be one that brings some production with it, but it also brings an inventory of drilling opportunities that are economically superior to the average of our portfolio.

And do you have particular regions of the country that you are most focused on? I guess I should ask, are you focused on the U.S., are you looking to go outside of the country. What insights there?

We are focused on the United States. We don't believe right now is the time for us to be looking abroad. We are focusing primarily on financial returns. If you look at the talent that we have here at SandRidge, I believe we can operate in any of the basins in North America for sure in the United States. And so I would say that we're more opportunistic. So it's all about the opportunity. So, we want a really good deal. We are financially stable. We think that there are -- we're entering a time period in the industry where more and more opportunities are going to emerge. And so we just want to be prepared to take advantage of them. And we want the best deal we can get and make sure that whatever we acquire is an accretive opportunity that creates value for shareholders. And so within a specific basin, I can't really say there's any basin that's a primary thing. But of course, the Permian Basin is always an attractive one. We like the Powder River and the Bakken. We like East Texas in the Haynesville play. We like the Eagle Ford. And so those are the areas that we've evaluated various different opportunities. We look at those areas and they have opportunities there that we believe demonstrate the economic returns that we believe our shareholders would want us to pursue, and so we'll see.

And there are no further questions in the queue. I turn the call back over to Paul McKinney.

Okay, again very much thank you guys. Thank you everyone for participating in the call. Thank you, Bill for your questions. We're excited about what the future holds for SandRidge and our investors, and are encouraged by your support. This is the end of our conference call. And thanks, again.

And this concludes today's conference call. You may now disconnect.