SM Energy Co (SM) 2016 Q2 法說會逐字稿

Good day ladies and gentlemen and welcome to the SM Energy second quarter 2016 conference call.

(Operator Instructions)

As a reminder this call is being recorded. I would now like to introduce your host for today's conference Mr. David Copeland, General Counsel. You may begin sir.

Thank you, Ronya. Good morning to all joining us by telephone and online for SM Energy Company second quarter 2016 earnings conference call and operations update. Before we start, I would like to advise you that we will be making forward-looking statements during this call about 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. For a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted to our website for this call, and the risk factors section of Form 10-K that was filed earlier this year and our Form 10-Q filed earlier this morning.

We will also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday.

Other Company officials on the call this morning are Jay Ottoson, President and Chief Executive Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Herb Vogel, Executive Vice President Operations; and Jennifer Samuels, Senior Director Investor Relations. I will now turn the call over to Jay.

Thank you, David. Good morning and thank you to everybody for joining us on this call this morning. I just want to start today by saying I have never been more proud of our people here at SM than I am today.

If you have had the chance to read our press release I think you already know that we had a great quarter relative to expectations. Our objective as a Company is to deliver differential value for our shareholders through debt adjusted per share growth in cash flows and add high quality drilling inventory over the long term.

I think our results this last quarter demonstrate that we today are a Company that is executing with real excellence on projects with high returns, even at low product prices. In our second quarter we beat expectations on every major controllable operating item and made better wells at lower costs in each of our major plays. Our capital spending is trending below plan for the year, while we are increasing production guidance.

And that result coupled with higher than expected proceeds from our divestiture program will further strengthen our balance sheet, improve our liquidity position and provides us with more flexibility and optionality going forward. Wade is going to review the quarter and our revised guidance for you.

Then Herb is going to provide you with some operational information that I think is just fascinating. Then I will wrap things up and we will take your questions. Wade?

Thank you, Jay. Good morning, everyone. I'm very pleased to reiterate that we witnessed outstanding execution this quarter and it directly flowed-through to our financial statements.

I am on Slide 4, if you want to follow along. Production exceeded plan by about 1 million barrels of oil equivalent driven by outperforming wells in both the Eagle Ford and the Permian, demonstrating very strong sequential production growth in both of those areas. Operating costs came in lower than planned in every line item.

Drilling completion cost continued to decline during the quarter while we continued to see faster drilling times driving lower than expected capital expenditures for activity to date. Financial results including adjusted EBITDAX, adjusted EPS and operating cash flow all exceeded consensus estimates by double-digit percentages. And as a result, we have raised production guidance, lowered capital guidance, and lowered guidance for all operating costs. In summary, better wells, lower costs.

So let's drill down on a couple of these points. You might have Slides 4 and 5 in front of you as I go through these. Production came in ahead of plan following particularly strong initial rates from six wells located in the high-gas NGL portion of the Eagle Ford, as well as completion of eight net wells in the Permian, all of which were good performers.

Oil production came in right at the midpoint of guidance despite delays in the Williston basin that pushed completions until late in the quarter. As a result, we've raised production guidance for the full year by about 2 million barrels of oil equivalent at the midpoint.

Third quarter production guidance comes down slightly from the second quarter just because third quarter completions are more heavily weighted to oil versus higher volume gas wells. This should result in our oil percentage increasing to about 31%.

LOE per BOE benefited from higher production rates as well as continued operating efficiencies. We expect LOE to increase in the second half of 2016 where we have higher work over activity in the plan, as well as we expect to normalize ad valorem expense. There was a true up in the second quarter that could potentially reverse in the third quarter.

Full-year LOE guidance, which includes ad valorem, is reduced to $3.90 to $4.30 per BOE, down $0.20 at the midpoint. G&A continues to come down as we emphasize cost savings across departments and at all levels of the Company, as well as continuing to hold on new hiring. G&A guidance for the full year is reduced by about $5 million at the midpoint.

In regards to commodity price differentials, we saw improvement in liquids differentials from the first quarter, while second quarter natural gas differentials came in lighter. A few points for forward modeling in those areas.

The oil differential was narrowed mostly due to regional pricing in the Rockies. About 50% plus of oil production is from the Rockies. The impact of the Canadian wildfire supported higher Bakken prices. For the second half of 2016, we see the Rockies differential returning to the $7 range versus WTI.

Eagle Ford oil differentials improved slightly from the first quarter. For modeling going forward we use about $11 to $12 off of LLS. Conversely, Company-wide natural gas realizations were dragged down by about $0.10 due to Rockies production where too much regional supply and high cost contracts are pushing realizations to sub $1. You should note, Rockies only accounts for about 7% of our gas production.

On the NGLs we continue to suggest that you model a realized price in the range of 80% of Mont Belvieu. We continue to reject ethane where allowed as rising natural gas prices have kept the economics of ethane recovery in check.

Also, we added some hedges during the quarter. You can see the summary on Slide 6. These include 2017 oil collars, 2017/early 2018 natural gas swaps, and some 2017/2018 propane swaps. All of the details are in the appendix of the slide deck.

Capital expenditures of about $168 million came in significantly lower than planned. As a result, we reduced CapEx guidance for the year by about $35 million. Savings were realized due to do faster drill and complete time and lower vendor cost than planned. Net-net we are very pleased to report significant production growth for the quarter within cash flow.

Year-to-date adjusted EBITDAX of $399.4 million exceeds capital expenditures of $373 million. For the second half of 2016 we've got about $300 million in planned capital activity, which depending upon commodity prices, should be aligned with operating cash flow. The scenario positions us very well as we move into 2017.

In addition, as announced Monday, our asset divestiture process is going very well. We have two asset packages under purchase and sale agreements for total expected proceeds of $172.5 million. Just to repeat some of the key data points on this, closing dates are at the end of the third quarter.

Total production from these assets based on second quarter production was 3,300 Boe per day. Associated proved reserves as of year end 2015 are 9.5 million Boe. One package was predominantly Waterford assets in New Mexico and the second producing assets in North Dakota and Montana.

The North Dakota piece does not include acreage in our Raven/Bear Den, or Divide County assets. This package was actually divided up and the Powder River Basin portion is still in the sales process

The bottom line of all this, early alignment of capital expenditures and cash flow, combined with asset sale proceeds well in excess of our PDP expectations set forth in February, sets us up very well.

It might beg the question of whether we will ramp activity. Our philosophy and strategy are unchanged from last quarter's discussion. Liquidity and coverage remain priorities. At this point we expect to apply divestiture proceeds to reducing the balance on our credit facility. I will now turn the call over to Herb Vogel who will provide more operations detail behind our solid performance. Herb?

Thank you, Wade. Just to iterate, outstanding execution drove bottom-line results. Well performance drove production in the quarter, specifically from the Permian and the Eagle Ford, which I'll talk about in a minute.

Our efforts to realize efficiencies both on the capital side and operations side led to lower second quarter costs and the ability to lower guidance for both LOE and capital spend going forward. So on managing operating costs and S&D there are key goals and incentives for our employees in 2016. On the operating cost side we have been successful through several initiatives.

First, we are re-bidding nearly all activity down the chain and across the portfolio very frequently. Second, we are fully utilizing costs and revenue data now accessible as a result of last year's new ERP system implementation. Through big data management utilizing nearly real-time data available through this new system and modern digitalization programs, we now have the ability to quickly identify cost drivers and can prioritize those areas where we can have the most impact.

Specifically, nearly in real-time we can now attribute costs and net back revenues from every barrel of oil and Mcf of gas to individual wells and assess the cash flow from individual wells. On a very frequent basis we can now recognize any well that is not profitable, understand why, quickly address the issues, and optimize our cash flows down to the well level. We have all hands on deck from the IT department through every part of the organization to get this system in place and now we're seeing dividends that we hadn't originally anticipated.

Third, we're looking at systemic improvements and I will just give a few examples. Managing our produced water, which is a key contributor to our LOE more effectively. For example, in the Permian, using produced water in our fracturing operations rather than paying for disposal. And optimizing our artificial lift to yield better run times and lower electric power generation costs.

For example, in the Eagle Ford by changing from rod pumps to plunger lift. And evaluating chemical treatments for effectiveness and optimizing the supplier and cost. All this and many more are delivering bottom-line, systematic and sustainable LOE reductions across the Company.

Switching gears now, given our increased production guidance and decreased CapEx guidance for the year, I'm going to spend some time elaborating on the drivers behind that production out performance and lower CapEx year-to-date. That is, why we're getting better wells at lower costs.

Turning to Slide 8, great reservoirs and great assets keep surprising the upside and Sweetie Peck is no exception to that rule. Our new completion designs and landing zone optimization led to a 12% increase in our production expectations for the year from Sweetie Peck. The 12 new wells we completed so far this year are exceeding expectations and enabling further completion enhancements. And turning to Slide 9, just briefly, you can see that others are starting to recognize that Sweetie Peck is truly a tier-one oily asset and that we are delivering wells that are some of the best in the Midland Basin.

Turning to Slide 10, new at Sweetie Peck since last quarter is further improvement in our operational performance. During the second quarter we reduced the number days from spud to total depth for 7,600 foot laterals from almost 19 days in the first quarter to under 14 days in the second quarter. And that is best in class in the basin.

That translated into lower CapEx per well, as shown in the figure on the right, down to $5 million to drill, complete and equip for the last six wells we completed during the second quarter. We continue to see opportunities to drive better well performance by looking at tests we started implementing over two years ago.

As shown on Slide 11, we began to see significant benefits after about a half year of production from tightening stage spacing of fracture stimulation from 200 feet to 167 feet. In the test shown, after almost two years, we saw that the tighter stage spacing improved our cumulative production by 17%.

While the data we can show is limited to one test for now, we just implemented this improvement in three new lower Spraberry wells and expect that the increased costs of the additional completion stages will result in stronger production from these wells and yield even higher returns. In terms of increasing our undrilled inventory at Sweetie Peck, we are very encouraged by the middle Spraberry that we completed earlier this year.

While this well had a manufacturing defect in the steel casing that restricted us to flowing back only 11 of the 26 stages simulated, we saw production per lateral foot that was very similar to our successful lower Spraberry program average as shown in Slide 12. While early, after 60 days, the cumulative production from the middle Spraberry well was within 5% of the lower Spraberry average despite the temporary impact of a frac hit from an offset completion during this period, followed by some issues with the artificial lift employed on that well more recently.

The fundamental properties of middle Spraberry production at Sweetie Peck are also encouraging. With 38 degree API of oil versus the 39.5 degree API oil in the lower Spraberry well tells us there is sufficient thermal maturity to support very productive wells, even at the shallower depth. The gas oil ratio is also sufficiently high to provide the reservoir energy to drive longer-term performance.

Each new interval we add at Sweetie Peck could add about 100 wells of 7,600 foot lateral lengths to our inventory, so this is significant. Obviously, that number goes up if we drill 5,000 foot laterals and down if go to 10,000 foot laterals. Summing up the Permian, at Sweetie Peck we have a tier-one oily asset where we continue to deliver better wells and lower costs that are best in basin. Our Permian Basin team has demonstrated the ability to deliver bottom-line performance each quarter and to grow our inventory.

Turning to Slide 13 and the Bakken Three Forks now, during the second quarter we completed 17 new wells late in the quarter. Rain related road closures in the Divide County area and installation of new seal assemblies in three of our new Raven/Bear Den completions, delayed those completions until later in the quarter than we had planned.

As a result, much of this new oily production will show up in the third quarter and beyond. Given early positive results on some tests of diverter technology and completions earlier this year, our standard completion design in the Divide County area now includes diverter technology. New well CapEx in the Bakken continues to drop through efficiencies like pad drilling and market conditions.

Four of the 11 Divide County wells we have completed year-to-date were drilled, completed and equipped for less than $3.9 million each. Overall we have an excellent contiguous and largely HBP asset in North Dakota. It is a great operating environment up there with new infrastructure in place and an SM team that is successfully driving performance and improving the rates of return on investment in the new wells in the Bakken and Three Forks.

Now turning to Eagle Ford and Slide 14, I think it's important to convey a few specifics on why we over achieved on production in 2Q and are increasingly confident that our operated Eagle Ford is a top-tier gas and NGL asset, whose close proximity to the key gas and NGL markets provide further benefits to the bottom-line via stronger relative product cycling.

So through our substantial and successful testing work over the past two to three years, we have increased confidence in our well placement designs. Our most recent wells in the gas and NGL areas are now staggered in the lower and upper Eagle Ford. We have spaced them at 625 feet within each of the upper and lower Eagle Ford, or 312 feet between wells if you look from above from a map view perspective.

Given early planning and our large leasehold position, we have been able to drill laterals that average around 8,000 feet long in these areas, and that has driven really excellent capital efficiency. And then we have coupled the longer laterals with our higher sand loading of 2,000 pounds per foot of lateral to drive near wellbore fracture complexity without stimulations to deliver very strong wells.

We often get questions comparing well performance with others in the area, so another important point I will make about our production performance here is that we choke manage our wells. You might ask, what is choke management? This means that as we start flowing back wells, we open the choke valve on the production line to [sale] more slowly to control and initially limit the pressure drawdown on the reservoir.

There are three major bottom-line benefits and several lesser benefits of restricting reservoir pressure drawdown through choke management of our wells. First, this is very capital efficient. If we were to pull these new wells hard to report really high initial production rate, like high IP 30s, we'd need to use more CapEx to install larger and more expensive production equipment to achieve high initial rates that would be followed by steep declines.

Second, we a found that choke management enables our wells to stay on a very shallow decline, effectively a plateau in production for several months, much longer than we originally anticipated, and probably an additional benefit of our higher sand loading and completion and complex near wellbore fracture system. In fact, on Slide 15, you can see that in two of our recent tests of staggered upper and lower Eagle Ford wells, we have maintained rates of around 9 million to 10 million cubic feet per day, per well, that is per well for extended periods of time.

In the lower right figure you can see that we maintain rates at an average of over 9 million cubic feet per day per well for over six months. And in the upper figure with our latest six well stagger completions in this area also including diverter technology, we've produced these wells for over three months with very limited decline.

And then third, our most recent finding is that after two years of choke management our wells actually achieve higher cumulative production than if we had pulled them hard to report high IPs and decline them from there. Since the majority of the value attributed to a well originates from the first two years of production, this is a real positive to the rate of return on our investment, and we would expect leads to higher ultimate recoveries too.

Given the findings I just talked about, we looked extensively at public data from other Eagle Ford operators and what they were seeing in their results. We found that several operators choke manage like we do, while a few others open their chokes early and report some very impressive initial rates.

In Slide 16, you can see a comparison of the top 10 operators across the entire Eagle Ford trend as measured by the total number of wells completed since 2014. Each with over 100 completions since then. The red bars indicate the peak rate reported, the highest month production, reported per 1,000 feet of lateral length as indicated on this scale on the right.

The gray bars indicate the ratio of the first 24 months of production that initial rate. As you can see with company F, in particular, the very high initial rate does not translate into continued performance at lat level through two years. In fact, they exhibit more rapid production decline rate. We then did an additional analysis of the results of companies operating near us in the southwestern portion of the Eagle Ford trend and in the gas NGL area.

As you can see on Slide 17, our gas and NGL focused wells that are all choke managed achieved the highest two-year cumulative production relative to initial month production of all the nearby operators. So you might ask what does all this mean? What I just talked about really addresses the underlying drivers for our outperformance during 2Q in terms of gas and NGL production.

In addition to stronger initial production rates from our new completion design, our new wells in the gas and NGL areas remain on production plateau longer and declined much more slowly than we had forecast. This is the bottom line being delivered from the better wells and lower costs that we have talked about at a well level.

The improvements that are achieved through out newer completion designs are giving us stronger wells and you can see that in the results. Now turning to Slide 18, from a marketing perspective we wanted to point out that our Eagle Ford position benefits from it's location relatively close to Mont Belvieu. Transportation and fractionation cost to get our NGLs to market are lower than from any other basin in the US.

The slide shows the frac spread of NGLs in dollars per million BTU by basin in a $30 and $60 oil price environment. This data is provided by En Vantage. As NGL prices rebound from their lows of late last year and early this year, we are poised very competitively as the largest net NGL producer in the Eagle Ford. All this leads to the excellent bottom-line returns that we can achieve with $3 per Mcf gas and recent NGL pricing in the gas and NGL portion of our operated Eagle Ford position as shown in Slide 19.

Note that the returns shown on that slide assumes a 6,500 foot lateral. The wells I showed you earlier have 8,000 foot laterals, so the returns are even higher. In addition, our ability to stagger our upper and lower Eagle Ford completions in this area doubles our inventory relative to expectations just a couple of years ago.

So wrapping up, we are very pleased to be positioned with top-notch tier-1 oily assets in the Permian Basin at Sweetie Peck, and top-tier gas and NGL assets with our operated Eagle Ford position. Our continuous and relentless focus on improvements and completion designs and capital costs, that is better wells and lower costs, is progressively delivering improved bottom-line financial performance quarter to quarter and you can see that in our 2Q operational results. Now back to Jay. Jay?

Well, thanks, Herb. Just some really interesting stuff there. I want to just say how much I appreciate you mentioning the implementation of our new accounting and land systems. Something we don't talk near enough about, but a project over the last several years that was very well executed, very important to our future growth as a Company and now really having significant impacts on our bottom-line results.

In closing I would just like to emphasize again the across the board nature of our out performance this last quarter. In particular, the balance between our cash flows and capital spending was significantly better than we had projected earlier this year, and our well performance was just outstanding. We will continue to drive toward higher-margins and give priority to our liquidity and ultimately to our debt adjusted growth. I'm comfortable saying that in the $50 oil and $3 gas world, we clearly anticipate in 2017 that we can grow while aligning our cash flows with CapEx at a capital spend similar to this year's spend.

Our vision is to be a premier operating Company with top-tier assets, delivering differential performance for our shareholders. I'm just very encouraged by our recent performance and very enthusiastic about the future of the Company. With that I will open the call for Q&A.

(Operator Instructions)

Kyle Rhodes, RBC Capital Markets.

Hi good morning guys. Permian obviously delivered a great quarter here. I was hoping you could update us on the expect to completion counts there for 3Q and 4Q 2016 and how you see that production growth trajectory continuing in the back half of the year?

Okay. We're just sticking straight to plan. This is Herb. There is no change from what we have talked about for the year around 40-some completions in the Eagle Ford.

Just over 50 in the Bakken and about 20 to 24 in the Permian by the end of the year. There is no change in our plan. We are plowing along on that.

Okay. Got it. And maybe just touch on any down spacing pilots or delineation work in the Wolfcamp A or D that may be on the docket before year-end 2016 here.

We are basically sticking we haven't made any changes. Some cases we have tightened up the spacing and as we get results from those wells we will be sharing them. We don't have any new results to report on Wolfcamp A or any other areas other than the individual wells we've talked about previously.

Got it. Are there any plans for the backup maybe. That's what I was trying to get at.

Yes. We are basically just straight on the program where we plan to drill wells. We are rally not making any changes there.

Got it. Okay. I guess maybe just touching on service costs, real quick I know on some of the service earnings calls we've heard some of the bigger providers saying that pricing discounts are coming to an end here in short order.

Just sounds like you guys certainly didn't see that in 2Q. I'm curious what you are seeing out there on a leading edge basis. I'll leave it there. Thanks.

I would say as we rebid activity it is a little bit basin dependent. Some areas we are still seeing as we rebid work that they are coming down. And in others we see they are flat and not really changing much.

And then there's some specific items where we see slight increases on some tangibles. But they are relatively minor it was really overall down for 2Q and we've locked in stuff for 3Q. We don't really see a change there.

I hope that gives you the color you were looking for.

Thanks guys.

Kevin Smith, Raymond James.

Good morning and congrats on a great quarter. I appreciate all the color on the Eagle Ford production. Clearly the Gavlan wells, Ranch well results were really strong. I'm just trying to make certain I understand was the production [beat] solely due to higher IP rates or was it some combination of better IP rates, lower base decline or a possible change in your choke plans?

I think am following your question. So, when we forecast production for a year we have certain declines baked in. And as we are enhancing our completions we don't have a real good ability to say exactly how well it'll do so will decline wells away.

And when they come on really strong and we can see it with really high pressures and then as we start producing those pressures decline less rapidly than they would have previously. And so we are able to open the choke and the rate is maintained. And we found that we are getting five, six months type of plateau levels on our wells.

So when we got into 2Q we have those wells and those figures five of them started last year and then six of them started during the quarter. That's really where the over achievement came from. So it's not so much the base declines on the other wells it's not getting on decline as fast on wells that came on last year and the new ones this year.

Okay.

Does that makes sense?

Yes. Basically if I correct just restate what you said, production hasn't decline from wells as you've put on over the last six months?

Yes.

I'll just chime in there too, I think it's important as you look at the press release, we did experience some delays in the Bakken on a number of our completions which hurt us on the oil rate. But we offset that basically got right back to our target numbers on oil because our Permian wells have been outperforming so much, again relative to our expectations.

Understood. And lastly I will jump back in the queue, as you think about your second half [joint] plans at Sweetie Peck is there any plans to drill anymore Middle Spraberry or is everything going to focused on lower Spraberry?

No more plans to drill the Middle Spraberry. We locked in our program which is really Wolfcamp B and lower Spraberry focused because we knew what the expectations were for those.

And we basically we're really working to optimize our program. And that's why we're getting the cost reductions we're seeing, the capital reductions we're seeing. So we're not going to drill another Middle Spraberry well this year.

Okay thank you. Once again great quarter.

Thank you.

Chris Stevens, KeyBanc.

Good morning guys great quarter. Just wanted to touch on the M&A a little bit. What is the appetite at this point to go out there and maybe make an acquisition? And any thoughts on sort of size of what you would be interested in looking at?

And then if you could possibly comment on what your thoughts are on the valuation that we have seen maybe out the Permian whether it's Delaware or Midland?

That is a pretty broad question. This is Jay. In general we're obviously very interested in continuing to improve the quality of our assets. The types of acquisitions we look at and are interested in are ones which will perform as well as or better than our best assets.

We look at every deal that comes up in our core areas. Certainly the Permian Basin is an area of great interest to us. And we look at everything that has come up.

I appreciate the fact that when you look at the headline numbers on Permian deals they seem expensive. But I think a lot of the reason for that is that people are simply proving up more and more intervals there. If you actually look at it on a per interval basis I still think the numbers are not unreasonable.

We are continuing to look at those and I wouldn't be surprised at all certainly we are going to focus on that. I don't know that there is a size limit that we necessary look at there. There's a lot of creative ways to do these deals.

And I think you have to keep your mind open a little bit to that as we move forward.

Okay. Understood. I guess may be of I could just touch a little bit on the outlook here as we head into next year. Any sort of initial indication of what the rig count might look like between your core assets and is there a potential for a third rig in the Permian at some point?

We don't have a defined plan yet as I said I think at capital level similar to this year we believe that a $50 and $3 world we can grow within our cash flows next year. We have several different scenarios we've looked at between the Eagle Ford and the Permian. Moving rigs around that can get us to that. I don't have exact rig counts to give you yet.

Okay. Thanks a lot. Great quarter.

Thank you.

(Operator Instructions)

I'm not showing any further questions. I would now like to turn the call back to Mr. Jay Ottoson, President and CEO, for any further remarks.

Well I think it's clear everybody is out looking at inventory numbers now. I haven't seen them yet, I will look forward to that.

Thank you so much for today for your questions and for your interest in our Company. We look forward to talking to you again next quarter. Thanks.

Ladies and gentlemen thank you for participating in today's conference. This concludes today's program.

You may all disconnect. Everyone have a wonderful day.