SandRidge Energy Inc (SD) 2018 Q2 法說會逐字稿

Good morning. My name is Andrew, and I'll be your conference operator today. At this time, I would like to welcome everyone to the SandRidge Energy Second Quarter 2018 Earnings Conference Call. (Operator Instructions) Johna Robinson, you may begin your conference.

Thank you, operator, and welcome, everyone to the conference call. With me today are Bill Griffin, 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 to our website under the Investor Relations tab that we will be referencing during the call.

Keep in mind, today's call contains forward-looking statements and assumptions, which are subject to risk and uncertainty, and actual results may differ materially from those projected in these forward-looking statements. We will also make reference to adjusted G&A and other non-GAAP financial measures. Reconciliations of these measures can be found on our website. Finally, you will see us file our 10-Q later this afternoon.

Now let me turn the call over to Bill.

Thank you, Johna, and good morning, everyone. I appreciate you taking time today to join us for this review of SandRidge Energy's 2018 second quarter performance results and our go-forward outlook. Today's conversation will be referencing the second quarter investor presentation posted on our website earlier this morning, and I encourage you to utilize that for today's discussion.

As Johna mentioned, joining me are Mike Johnson, our Chief Financial Officer, who will be speaking to our financial results; and John Suter, our Chief Operating Officer, who will be providing an update on operations later in the call.

So if you will please turn to Slide 3. As most of you are aware, there've been a number of changes in SandRidge since our last call. Most significantly was the election of a new Board of Directors. Additionally, we have provided -- we have some exciting new well results in North Park that should have a meaningful immediate impact on the value of the company along with the Northwest STACK, where our drilling program is providing increased confidence in our geological model and ability to identify the best undrilled opportunities across our acreage position in this play.

The new board took control after our annual meeting in June and has hit the ground running, with numerous meetings and initiating a deep dive into all aspects of the organization. Some of these include a comprehensive assessment and understanding of the existing asset base and associated reserve development plan, the current strategic alternatives process and the evaluation of appropriate strategies to maximize shareholder value.

I know all of you are interested in the status of our ongoing process to solicit and review strategic options to the company's evolving plan for growth and value creation. This is a broad process that incorporates numerous possible outcomes that could create meaningful value opportunities and potential returns to shareholders.

We're currently evaluating submittals, several of which require reverse due diligence. The board and management are working expediently to evaluate each and every proposal while weighing them against the current value and potential of the company and our continued positive drilling results.

We're managing this process with the highest of priority and urgency, while maintaining a thoughtful and deliberate approach to ensure the resulting outcome is the best possible for all SandRidge shareholders. Everyone looks forward to definitive decisions in the near future, but, because this process is ongoing, I won't be able to add much additional insight during today's call.

In conjunction with the ongoing strategic alternatives process, the board is working with management on a longer-term plan that includes analysis of the company's cost structure, including compensation practices, cash costs, hedging program and ways to monetize noncore assets. Most importantly, we continue to target improvement in current declining EBITDA and are assessing the feasibility and associated risk of accelerating our activity levels to more quickly reverse current production trends and continue to deliver solid, predictable returns.

During our last 2 calls, we discussed our evolution to a leaner margin-focused company with meaningful upside and a broad spectrum of potential new opportunities. I am pleased to report that this transition continues, and the results are demonstrated with the achievement of additional cash cost savings during the quarter and supported by the fact that we're revising our 2018 guidance to reflect lower expenses and reaffirmation of the remaining key performance metrics.

Our current decline in production EBITDA remains a major focus item. The second quarter was challenging, as we encountered short-term production deferments in the North Park basin associated with frac fleet delays and extended simultaneous operation shut-ins during the completions of our newly drilled wells. These events negatively impacted our second quarter oil production in North Park, but the other operating areas met production guidance and budget projections.

Despite these delays, I'm pleased to report the new well results in North Park are far exceeding expectations. And as a result, we are reaffirming 2018 total company production guidance, as new well performance should make up this current quarter shortfall.

Additionally, the events that impacted oil production were compounded by our hedge book, which resulted in a loss for the quarter. While this is disappointing, drilling results are meaningfully positive and we expect to provide a clear line of sight to EBITDA growth in the near future, as we accelerate our transition to a production profile with an increasing makeup of higher-margin oil. The graph on this slide helps demonstrate the expected mitigation and production decline during the second half of 2018.

Additionally, we remain focused on aggressively cutting costs and improving margins. John and Mike will both speak to this in more detail later, but we have achieved significant reductions in our overall cash cost and expect continued progress on this key profitability driver.

Turning to Slide 4, our focus remains on value creation returns to shareholders. Near term, preservation and enhancement of cash flow from the Miss Lime is a priority. As a relatively mature asset, the key objective is ongoing improvements in efficiency and profitability enhancements.

We've continued to advance the utilization of our centralized operations center in Oklahoma City that provides the ability via real-time information from wells, facilities and personnel locations to prioritize and direct daily operations' activities on a 24-hour basis. This capability has resulted in incremental savings and operational labor cost and reduced downtime.

In addition to our labor reductions in G&A during the first quarter of this year, there were additional reductions in field labor costs during the second quarter, meaningfully attributable to the effectiveness of this operations command center.

While the impact of this capability has yielded cost savings, more importantly, it has provided the capacity to enhance production by directing operations personnel to the highest-production impact areas in need of attention. In short, reducing downtime and increasing production. We feel this is a unique capability that helps separate and distinguish us from others.

As mentioned earlier, mitigating the current production decline while ensuring strong returns on invested capital is a priority. While drilling results in both North Park basin and Northwest STACK are providing line of sight to future growth, there remain incremental capital investment opportunities within the core Miss Lime acreage position of the company.

In addition to our second half capital programs in North Park and the Northwest STACK, we have also initiated drilling on the first of 4 new wells in the Miss Lime that will collectively provide meaningful support to the production base of this key asset. These 4 wells are all expected to generate strong rates of return and value uplift.

John will provide more details shortly, but our most recent North Park basin results continue to generate increasing excitement. The fact that we have continued to drill and complete multiple wells, with initial production rates in excess of 1,000 barrels per day and well above our current type curve, significantly increases confidence that our reserve and value projections for the Niobrara in this play are valid.

We are confident that as the total oil production rates from this basin continue to grow, the interest and associated terms from outside parties to provide pipeline access to this area will expand even more quickly. We're accelerating our process to identify our midstream partner, but additionally, we continue to move forward with near-term solutions to mitigate emissions and continue the growth in oil production and expanded delineation of this asset.

In summary, as we move through the evaluation process of assessing strategic alternatives, the company has not lost sight of our day-to-day key business drivers, and we remain focused on creating profitable organic value growth.

I will now turn it over to Mike Johnson to provide commentary on our financial performance. Mike?

Thank you, Bill, and good morning to everybody on the call. The employees of SandRidge delivered key operating results that exceeded our expectations and are setting the stage for what we believe will be significant value creation in the future.

Our second quarter results reflect, among other things, considerable reductions to our production expenses and adjusted or cash G&A, which has enabled the company to reduce combined cash cost guidance for 2018 by $8 million at the midpoint. This over-performance was achieved at a time when significant effort and financial costs were incurred in connection with a proxy contest that also resulted in the acceleration of the majority of outstanding share and incentive-based compensation awards.

In addition, as Bill mentioned, we experienced declining production and lower natural gas price realizations at a time when we had a significant portion of our second quarter liquids production hedged at a WTI oil price of roughly $55 a barrel, leading to a net realized hedging loss of $11 million during the quarter.

In spite of these obstacles, our second quarter results reflect encouraging trends that shouldn't be overshadowed by these charges. We believe SandRidge is now poised to maximize the value of our existing asset base, and John will provide much more color on our operational outlook as part of his remarks in just a moment.

Slide 5 of our investor presentation offers a recap of our financial highlights and key cost reductions during the period. In the second quarter, our production expenses and adjusted G&A, all came in at or under budget, and both of these cost categories are down considerably year-over-year and sequentially compared to the first quarter.

With respect to LOE, the recent and projected cost reductions are being seen primarily in both our Permian and Midcontinent assets and reflect reduced spend from additional workforce reductions, improvements from our operations center and pump by exception advancements, lower electrical cost, improvements to our bid processes that lowered chemical spend, converting facility maintenance staff from third-party sourcing to in-house staff, and the release of a number of compressors.

With a lower projected lease operating spend, we are lowering our original guidance range of $95 million to $105 million for 2018 to a range of $92 million to $95 million.

As for adjusted G&A, the year-to-date and projected cost reductions are occurring faster than anticipated and are being seen in a number of areas, including personnel cost, consulting and legal. The lower cash G&A costs we've seen year-to-date gives us the confidence to lower our original guidance range of $41 million to $44 million to a range of $40 million to $42 million.

Shifting to the balance sheet, our liquidity continues to be strong. Our cash position at the end of the second quarter increased slightly over the first quarter, and we continue to be undrawn on our $425 million credit facility. This reflects the fact that our capital expenditures during the quarter were primarily financed by our operating cash flows.

That said, we are highly motivated to end our production decline and intend to prudently take advantage of our substantial liquidity, with additional investment in primarily oily assets that we expect will yield high rates of return.

As shown in our appendix, there are no changes to report relative to our hedge portfolio during the quarter. Like most of our peers, we layered in these hedges at various times throughout 2016 and 2017, which has limited our ability to benefit from the recent run-up in oil prices. We are also currently working with our board to develop a go-forward hedging strategy.

With that, I'll turn it to John for his thoughts on our second quarter operational results and his outlook going forward.

Thanks, Mike. If you'll turn with me to Slide 6, you'll see we have several operational highlights to touch on. I'll cover them briefly, then go into more details shortly.

First in North Park, we're making good progress on this year's objectives. Subsequent to the quarter, we have some exciting new well results from 2 different spacing tests on the east and west sides of our core area. Wells from both tests targeted multiple benches and initial production results exceed our expectations. Current field production has ramped to over 6,000 barrels of oil per day, which is over twice the average first half 2018 oil rate.

We released our drilling rig in April, as planned, to evaluate results from the first of 6 western spacing test wells scheduled this year. We plan to deploy a rig in late Q3 to further advance tests that will optimize spacing patterns for future field expansion. In addition, we'll further delineate the less developed southern area of this asset.

Finally, we'll initiate the midstream partner selection process. Our chosen partner will execute planned gas and oil takeaway projects. I'll provide more color on these initiatives in coming slides.

In MidCon, our Northwest STACK asset continues to utilize 1 drilling rig under the Drilling Participation Agreement. So far, we drilled 8 wells this year under this arrangement. We continue to focus on delineating this asset, while improving our drilling and completion practices for future expanded development. In the Miss, we're using 1 rig to drill the first of 4 higher return projects.

Now on Slide 7, let's zoom in on North Park specifically. Well density and delineation efforts make up more than half of our spend from drilling and completion activities during the year. Non-D&C is made up primarily of central facilities, pipeline and other infrastructure pre-spend for our 2019 drilling program.

Moving to Slide 8, you'll see the colored lines on the map representing wells in the field that have at least 800 pounds per foot sand density in their completions, which defines our type-curve set. These impressive results are widely distributed between B, C and D bench tests and exist across a wide aerial portion of the core area. You'll note that our Gregory pad contains the 6 wells currently producing from our Eastern spacing tests. Also for reference, the Peters 16-12H13, the first well of our western test, is located on the Grizzly annex pad.

Let's go to Slide 9 to look at the early results of the first spacing pilot. Our goal was to test 1,320-foot spacing between wells in the same bench. We initially intended to test all 4 benches individually, but after further review of core and micro-seismic work, we believe we can recover Niobrara reserves from all 4 benches with 3 layers of drilling. This is -- highly cost-effective plan that accomplishes reserve recovery in the most capital-efficient manner.

It's important to note that we only have proved reserves in up to 8 wells per section in the core area, primarily in the D and C intervals. We now have strong B bench tests, which could be a large upside to our PUD category bookings to date.

The table in the bottom right shows the first 6 IPs from various benches within this test, averaging 1,305 barrels oil per day gross, 2 of which are producing over 1,500 barrels oil per day. Three of the wells exhibited approximately 40% higher initial flowing pressures than historical wells.

The graph on the top right shows the impact of the first 20 days, where 3 out of 6 wells have produced at nearly double the type curve rate. The last 2 wells of this initial Eastern pilot will begin flow testing in the next few weeks.

Now turning to Slide 10, it's pretty clear how the uplift from these recent successful wells benefit our program. Our current total field oil rate is averaging above 6,000 barrels oil per day gross. And in the first half of the year, longer period of SIMOPS than planned and delayed frac crews, as Bill mentioned, resulted in wells turning online a little behind schedule.

With these results, though, exceeding type curve performance, additional curtailments may be required until our midstream processing equipment is operational by year-end. In the interim, we will drill from different pads to utilize existing capacity and processing availability there. Despite these potential curtailments, we believe we will achieve our midpoint of guidance on oil.

Let's move to Slide 11 to review our objectives for the remaining 2018 North Park capital program. As I mentioned earlier, our rig returns in Q3 to drill the next 5 wells of the western spacing test to test 660-foot spacing in the same -- well to well in the same bench.

Similar to the Eastern pilot, there'll be 3 layers of development, but we think this 660-foot spacing will test the next opportunity for 8 wells per layer. The first well of this test produced an IP above type curve, giving us confidence to move forward. In addition to the Western spacing test, the remaining capital would be spent drilling 2 new step out wells at the far southern end of our core area.

As Bill mentioned last quarter, wells from our second half of 2018 drilling program should be online in early Q1 2019.

On Slide 12, you'll see overall performance of our 22 wells drilled to date that meet our completion requirements overlaid on the type curve. The economics table to the right outlines our criteria performance and SRL and XRL drilling inventory. Most of the planned development will utilize XRL designs, which deliver over a 100% rate of return and $6.9 million PV10 at current strip pricing.

Let's move to the midstream discussion on Slide 13. Currently, we are trucking oil with attractive differentials. We're combusting gas under flaring waivers as our pipeline plans move forward.

Two projects underway will progress our oil and gas processing capability. First, the installation of the permitted mechanical refrigeration unit will strip liquids out of a portion of our gas stream. Second, our gas-to-liquids plant will convert a portion of our lean gas completely to diesel and gasoline, further eliminating emissions from that stream. Both plants could be modularly installed at high-volume pad sites until pipelines are built.

On the pipeline side, we are awaiting a determination on plans submitted to the BLM in Q4 2017 to construct the first 36 miles of pipeline. The line will allow us to build an oil trucking facility north of Walden, Colorado and a nearby plant to process gas away from the field.

After testing multiple productive Niobrara layers, establishing significant proven reserves and achieving production rates at meaningful levels, we're now prepared to initiate the process to find a midstream partner. The partner will carry out previously engineered plans to lay lines to Rawlins and I-80 corridor. Numerous oil and gas lines in that area currently transport product to (technical difficulty) regional markets and refineries.

Moving to the Northwest STACK slides beginning on 14, we now continue to leverage the Drilling Participation Agreement to fund development. As you'll recall, our objective in participating in this agreement is to develop and delineate our Northwest STACK asset with minimal capital outlay.

In Q2, we spent only $1 million in drilling and completion cost. Of the 4 wells we drilled, 2 extended into Southeast Woodward County to delineate away from our Southwest Major County core area and to test additional outside leasehold. We plan to drill 16 wells in 2018, with a capital budget of $18 million to $20 million, including $6 million to $8 million in total drilling and completion costs.

Of the 6 wells that went to sales in the quarter, 5 produced at least 30 days for an average IP of 584 Boe per day consisting of 69% oil. Total Q2 net production was 2.7 MBoe per day, 43% oil. Our net production is the result of our lower interest on wells producing under the Drilling Participation Agreement. As evidenced by the chart on the lower right-hand corner of the slide, our gross production has increased by over 300% since Q1 of 2017.

Drilling improvements over time are seen on Slide 15. Since initiating drilling in the Northwest STACK, cycle times have been reduced to 18 days in the second quarter, a 71% improvement. Over the same time period, we've cut the cost per foot by 51% and improved the footage per day 170%. Given our successful well results and production growth in the play, we plan to apply our learnings to higher interest areas in the future.

The Sunkey well located in Major County, Oklahoma is an interesting case study, highlighting the success of some key advancements we've made in the Northwest STACK play. Look at Slide 16 to examine the result. A major step change for us has been the progression of our geologic interpretation, supported by a basin-wide depositional model using over 3,000 vertical logs and results from our core taken in 2017.

These learnings have led towards improved well selection as well as lateral placement within the Merrimack, targeting more brittle intervals that increases our efficiency of our stimulations. The Sunkey also tested an enhanced completion design with higher proppant density. The increase of total productivity, as seen on the graph on the bottom right of the slide, is a direct result of these developments.

Slide 17 shows you SandRidge's Meramec wells relative to other nonop wells in the Northwest STACK. Industry drilling is currently fluctuating between 16 to 20 active rigs in the field. As indicated on the map, SandRidge and other industry wells across the play show encouraging results near our core acreage in Southwest Major County and near our planned delineation areas.

Moving to Slide 18. In the second half of the year, we plan to continue our step-out efforts in Central Major, Northwest Dewey and Southeast Woodward counties. All planned drilling locations exist within areas of established production on the previous slide.

Moving forward to Slide 19. The Northwest STACK type curve is defined by economic parameters in the table on the top right. SRL wells generate a 35% rate of return, with a $1.9 million NPV-10 at current strip pricing. SandRidge and offset operators well performance compared to our type curve consistently outperform on gas and meet expectations on oil, thereby causing a pretty solid beat on a Boe basis.

As mentioned earlier, we've spud the first of 4 planned Mississippian wells subsequent to the quarter. On Slide 20, you'll see the 4-well composite program economics exhibit a 55% rate of return, with an NPV-10 of $2 million for the program at current strip pricing. We expect the wells to start coming online in late Q3.

I'll turn over to Bill now for some closing remarks.

Thanks, John. In summary, this was a challenging quarter, but one in which meaningful progress was achieved. Since early in the year, we've navigated significant change in the company's senior leadership team, organizational structure, and subsequently, with our Board of Directors.

We continue to listen and strive to be responsive to our shareholders. This organization remains focused on continuous improvement and solid operational performance, while working in parallel to assist all strategic alternatives. Our commitment remains unchanged to create value for our shareholders.

It's important not to lose sight of the opportunity that presents itself with SandRidge. First and foremost is that we have an incredible platform for growth. Not only do we have a clean capital structure, but as of August 2, we had $436 million of liquidity. This provides tremendous optionality, as we assess a multitude of options going forward.

Second, unlocking this incremental value is within our control and capacity. We have a mature HBP Miss Lime asset generating significant cash flow to fund development of a meaningful inventory of future wells in the North Park basin and the Northwest STACK. While we grow operating income in oil as a percentage of our product mix in these areas, we expect to extend our Miss Lime cash flow generation through extended expense reductions and targeted capital investments. We've demonstrated capabilities and competencies that are aligned with the asset base.

Additionally, we've taken major steps toward restructuring the company's cost structure and positioning the organization to efficiently and effectively execute our development program.

SandRidge is attractively valued relative to most standard industry evaluation metrics. While this is partially attributable to some individuals' perceptions of our various operating areas, we believe these views are misguided and remain dedicated to changing those impressions through delivery of tangible results.

I'm confident that continued success through the drill bit, further reductions in cash cost and demonstrated profitable growth in production and EBITDA will be the catalyst for this change. We remain focused on execution, returns, margin improvements and value creation for the enterprise.

I appreciate your time today and will now turn it back to the operator for questions.

(Operator Instructions) Our first question comes from the line of Lin Yang with FM Capital.

Two questions, please. The first of all, any potential impact you can see from the current political environment in Colorado. Although you're in rural areas, not supposed to be impacted by the setback movement, for example, but any potential spillover effects, for example, drilling permitting process?

Yes, this is John. I don't think we have any issues to-date. We work with the regulatory authorities to try to keep up with various rulemaking and haven't had any issues or concerns from them to this point where we sit in Jackson County.

Okay, great. And second question is, any potential tax assets you have that may be offsetting some capital gains tax, if you were to sell any assets, for example, the North Park asset for higher value than the company acquired back in '15 -- '16?

Yes. We have substantial net operating loss carry-forwards. Those are more carefully outlined in our 10-Q that we're going to file this afternoon. But we do have substantial remaining tax attributes available for any series of transactions that we might undertake.

(Operator Instructions) Our next question comes from the line of Bill Dezellem with Tieton Capital Management.

I have a group of questions. First of all, would you please share with us, relative to the North Park assets, the production coming online on those new wells above expectations? What do you think is the primary driver behind that?

Well, Bill, there are multiple things going on out there as we've started to evolve and walk down the learning curve in the North Park, and in particular, with the Niobrara. As John mentioned, one of the key drivers here is the continued evolution of our completion techniques and how we complete these wells. We think that's certainly important.

The second piece is somewhat a function of the rock itself. We've continued to evolve on where we land these laterals and target specific intervals, and I think that's been particularly effective as well.

And then, as you start thinking about the decline rates on those wells, I guess let me ask 2 questions. First of all, what would be your initial expectation before you saw the success of these wells and what the decline rate would be? And then secondarily, does this higher level of success impact the decline rate one way or another?

Well, it is early time and it's difficult to tell. But I would point you back to the fact that there have been wells drilled in this particular area and have been producing for a number of years, which were the initial basis for our type curve.

As we started applying new generations of completion techniques after acquiring this acreage position, we started seeing additional uplift associated with those techniques. And therefore, I believe it was last year, at some point in time, we increased our type curve.

As John saw -- demonstrated with the type curve that we have out there now, these current wells are even outperforming our uplifted type curve, but it is early time, so it's difficult to predict. But in general, my expectation as we sit here today is incremental IP will ultimately yield more reserves.

How the decline looks initially is still somewhat unknown, but we have drilled good wells out here, even prior to this quarter. And all in all, they continue to follow our type curve projections.

And the type per curve projection would put you at what sort of a decline after 1 and 2 years?

Let me pull back to that particular slide. I'll tell you what -- we'll have to get back with you on that particular question. I can't tell you what the decline rate is in 2 years, but if you would look at that type curve graph on Slide 12, I think you can get some kind of general feel for the level of decline as we enter the second year there.

My apologies. That's right, it is right here. And then my last question is you have enough different things happening between here in this line and the other assets that -- I'm hoping you can share with us what you expect the increase in production to be from the wells that were completed in Q2 or post Q2.

And then you still have a group of wells that would, I guess, fall under the still-to-be-completed or ducts. And I'm trying to grasp just the incremental uplift that you anticipate versus the second quarter production as reported from those wells, one that have been completed and the ducts?

If I follow the question, you're trying to get a clear line of sight on the second half of the year and how much incremental production would be associated with the wells yet to be completed as of the end of the quarter, and I believe we're talking in reference to the total company with that question.

I would just point you to the fact that we're going to continue to do that. We -- but -- what we see -- I can't -- what I would point you to is the guidance that we provided for the year as probably being the best indicator that -- as to doing the math to what the second half production performance projections will be.

There are no further questions at this time. I'll now turn the call back over to Mr. Griffin.

Thank you, again, for joining today's call, and we look forward to providing new updates in the near future on our strategic alternatives process along with results and outcomes of the current activities discussed today. I appreciate your interest, and please give us a call with any further questions. Thank you.

This concludes today's conference call. You may now disconnect.