Current SN Stock Info

$450 million capital budget for 2018

Eagle Ford juggernaut Sanchez Energy (ticker: SN) reported fourth quarter results and year end reserves today, reporting a net loss of $79.4 million, or ($1.01) per share, for the quarter and a net loss of $35.1 million, ($0.46) per share, for 2017.

Most of this quarterly loss is due to losses on derivatives, and after adjusting for this and other one-time charges Sanchez reported adjusted earnings of $21.8 million.

Q4 production nearly reached 82,000 BOEPD, right on target with the company’s 80,000-84,000 BOEPD guidance for the quarter. Full year 2017 production was about 70,320 BOEPD, for a year-over-year growth rate of 31%. Sanchez expects to grow nearly as rapidly in 2018, with the midpoint of guidance representing 29% production growth. That would take 2018 average production up over 105,000 BOEPD.

Higher production, longer laterals, lower CapEx in 2018

Sanchez will achieve this growth by spending about $450 million in 2018, $100 million less than the company spent in 2017.

Half of all spending will develop the company’s Catarina acreage, while almost all the rest will go to the Comanche area. Sanchez does not anticipate significant service cost inflation in 2018, and the capital budget reflects minimal increases. The company reports average horizontal well lateral length will be 8,000 feet in 2018, up from about 6,500 feet in 2017.

Sanchez Energy Expects 29% Production Growth While Decreasing Spending by $100 Million

Source: Sanchez Energy Investor Presentation

Sanchez also announced the sale of $500 million in senior secured first lien notes, which will be able to fund capital plans for the next several years.

Successful development test of Lower Eagle Ford drives 88% reserves increase

Proved reserves increased 88%, to a record 363 MMBOE, with a reserve replacement ratio in excess of 760% and an organic reserve replacement of approximately 172%.

This reserves increase is partially due to the company’s recent successful Lower Eagle Ford development tests, which indicated staggered well spacing is viable in the play. The test involved a four-zone stack development involving 17 different wells. The Lower Eagle Ford wells showed an average 30-day peak production rate of 1,252 BOEPD, while Upper Eagle Ford wells averaged 675 BOEPD. This test added 800 gross drilling locations in Sanchez’s Comanche drilling inventory,

Sanchez CEO Tony Sanchez III commented, “The new three-year plan we announced last month reinforces our commitment to financial discipline and capital efficiency.  While the plan calls for the company to reduce annual capital spending for the years 2018 through 2020 to levels approximately $100 million lower when compared to 2017, we continue to project significant production growth in 2018 and over the three-year planning horizon.

“The company’s inventory of low-cost, high rate of return drilled-but-uncompleted wells, or ‘DUCs’, and active drilling program are expected to organically increase production and cash flow over this period.  These higher production levels, together with better operating margins and improving oil price fundamentals, give us line of sight to full-cycle free cash flow generation at the corporate level,” Sanchez said.

“We announced a comprehensive financing strategy in February 2018 to fully fund our growth plans for the next several years.  After successfully executing this plan, we currently have liquidity totaling $834 million, which includes $650 million in cash and $184 million of borrowing availability under two credit facilities.  Given this significant liquidity position and potential for additional strategic divestitures, we see an opportunity to fully develop the Company’s world-class asset base and provide the cash flow needed to reduce our financial leverage over the next two to three years.  With a continuous focus on financial discipline, measured growth and deleveraging, we believe we are well positioned to deliver significant shareholder value.”

Q&A from SN conference call

Q: Any commentary you can provide on some of the grassroots wells that you’ve drilled at Comanche versus the DUCs in terms of performance, how they’re performing relative to the type curves, and what do you think may have driven some of those differences?

SN: We are seeing a pretty significant divergence in performance that is with the grassroots wells outperforming the original set of expectations and the DUCs either meeting or missing particularly on a Boe basis but not necessarily on a revenue basis because they are producing a little bit more order.

I would say the surprise is that the new wells are doing so significantly better. I mean, we commented on the results in the Briscoe Cat South. That’s our first major multi-pad sort of oil craft development that we’ve had on the asset and, thus far, looks like every bench that we’ve been producing has outperformed the original type curves either moderately or significantly depending on the zone. We just never encountered that same sort of outperformance on any of the existing DUCs.

And the DUCs had a few different things than what we’ve done on the grassroots development. Number one, we have pushed out a little bit longer laterals. We – those are a part of the factors. But the other is that a lot of the DUC spacing was spaced at somewhere around that 400-foot lateral and plain whereas the comments that we had from the new results, we’ve pushed out lateral spacing to our typical 600 feet, and that difference of that 150- or 200-foot lateral spacing in zone seems to be making a pretty big difference in terms of how these wells are doing. So the combination of lateral lengths and employing spacing had been, I would say, more optimal on the grassroots. It’s probably making the difference between the two.

Q: Could you discuss your approach on balancing the desire to maximize the return on invested capital for the program and the testing of the additional horizons given that those can have both complementary and opposing forces?

SN: Yeah, we’re doing both. We are continuing to test the numbers that we’ve disclosed do involve a fair amount of continued testing. And Chris alluded to higher well costs, but some of those higher well costs are largely driven by significantly longer laterals and tighter stage spacing.

So in these recent wells – we do have recent wells that are being drilled and completed that have upwards of 40 to 45 stages, a different completion design and targeting different areas. So we are continuing to test. That’s all incorporated in the model. We do account for – in our production growth forecast, we do account for risk type curves from that testing. What we don’t account for is necessarily success on those tests resulting in more a – more drilling locations or high-grading of drilling locations, which we would do at the time. So, theoretically, if we were to get some positive tests that we looked on a returns basis and those were better than something we’re currently drilling or had on the docket to drill, we can easily replace that with the higher return opportunity. So, there’s going to be some variance in our growth rates and that’s going to be driven based on what we’re getting from the R&D practices that were employing. But they are in our numbers.

Q: Looking at the guidance you provided back in January for 2018, 2019, and 2020, it sort of points to sort of like CAGR of production somewhere in that 7% to 9% timeframe going out. Obviously, the price deck has been moving in your favor.

Just curious, as you think about free cash flow being generated, how do you feel about I guess are weighing increasing that rate of production growth versus perhaps distributing some of that cash to the shareholders that’s kind of been the theme of late distributing cash to shareholders. Just want to hear how you think about that?

SN: So I would say the compounded annual growth rate you stated is probably a couple of hundred basis points lower than I look at it, but I think you’re in the range, right. You said 700 to 900, I’d put it at kind of 8% to 11%. But it’s so – it’s in that range.

Keep in mind that that has a – that’s built off of a big ramp to between 17% and 18% when we’re bringing all these DUCs online. So the 2017 to 2018 production ramp is very substantial. And then 2018 to 2019 we’re going off of that flush production that we generated in 2018. So it’s a more moderate ramp, so don’t look at that and be deceived by, oh this is a single digit compounded annual growth rate. Now it’s coming off of a big initial first step.

In terms of returning cash to shareholders, I think that absolutely is a top priority goal. The one thing we would do well before that is to delever the company. We used leverage to buy in this asset and the shell asset prior to that and to fund our drilling growth over the last several years. And I think that leverage was put to good use. Now we’ve got a world-class asset with a huge contiguous position and we’ve got plenty of drilling to do for the next 15 to 20 years.

So I really would think about the company right now in terms of priorities one, two and three being deleveraging and then if we’re generating excess cash absolutely, returning it to the shareholders in the form of buybacks or dividends.

Keep in mind, management employees here are the largest shareholders of the company. So I think it would be a really good thing if we got ourselves to a point where we were paying a dividend or we were in a sustained buyback program which is another form.

But we do view returning cash to shareholders as also being achieved by de-levering, right? Because we’re just adding to the intrinsic value of the equity by doing so. And I think we would witness an expansion in our in our enterprise value to cash flow trading multiples, and everybody would benefit. So all three of those deleveraging, dividends and buybacks are just different forms of really the same thing, and those are our goals now.

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