SWEPI LP (NFG) Earnings Call Transcript & Summary

Ladies and gentlemen, thank you for standing by and welcome to the National Fuel Gas Company Appalachian Acquisition Conference Call. [Operator Instructions] I would now like to hand the conference over to your speaker today, Ken Webster, Director of Investor Relations. Thank you. Please go ahead.

Thank you, Christina, and good morning. We appreciate you joining us today for a discussion of National Fuel's announced acquisition of upstream and midstream assets in Appalachia. With us on the call from National Fuel Gas Company are Dave Bauer, President and Chief Executive Officer; Karen Camiolo, Treasurer and Principal Financial Officer; and John McGinnis, President of Seneca Resources. End of the prepared remarks, we will open the discussion to questions. Press release for this transaction as well as our updated investor presentation have been posted on our Investor Relations website. We may refer to these materials during today's call. We would like to remind you that today's teleconference will contain forward-looking statements. While National Fuel's expectations, beliefs and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last evening's release for a listing of certain specific risk factors. With that, I'll turn it over to Dave Bauer.

Thank you, Ken. Good morning, everyone. Yesterday, we entered into a purchase and sale agreement with a subsidiary of Royal Dutch Shell to acquire Shell's upstream and midstream gathering assets in Pennsylvania. Strategically, this transaction is a perfect fit for National Fuel. It's a one-of-a-kind opportunity to expand our integrated approach within our existing operating footprint, build scale and lower our cost structure, checks every box on what we're looking for in an asset, namely: it's proximate to our existing operations; includes both existing gathering assets and the potential for future gathering development that includes valuable firm transportation, in this case, on our own Empire Pipeline system. In addition, given where we are in the Natural Gas pricing cycle, we're requiring shallow decline in PDP assets at a very reasonable price, roughly $1,250 per 1,000 of flowing production. We expect to allocate about 55% of the purchase price to the upstream assets. Roughly 400,000 net acre package spans several counties in Pennsylvania, but it's the 200,000 acres in Tioga County that are most appealing to us. That acreage sits directly adjacent to our Tract 007 Covington and DCNR 595 locations, should be easily incorporated into our existing operations in that area. Incremental operating and G&A costs should be relatively small and as a result, we expect Seneca's cash unit costs should decrease by $0.05 to $0.08 per Mcfe. We value the upstream asset solely based upon the proved developed producing reserves that we will acquire. All of the wells have been online for at least a year and most wells for several years. So the assets exhibit a shallow rate of decline in the 20% area and we have a lot of confidence around our production forecast. Pricing has been volatile, so to further derisk the transaction, we've done a significant amount of hedging. Over the past couple of weeks, we've locked in pricing on the equivalent of 75% of the acquired production for 2021 and 55% of 2022 at some attractive levels, $2.70 plus for 2021 and $2.50 plus for 2022. Assuming these hedges and the current NYMEX strip, we estimate we're acquiring these PDPs at better than PV-20. Transaction also gives us increased flexibility to allocate capital across our different operating areas. It brings nearly 200 additional high-grade development locations in Tioga County, but many of which are return trips to drill Utica wells on existing Marcellus pads, similar to what we've done in our Clermont-Rich Valley area. Keep in mind that the Utica wells we've drilled in Tioga County have been some of our most highly economic wells in our portfolio. In the near term, we expect to incorporate these locations into our existing development plan with no increase in our overall capital or activity level. Seneca will still transition to a 1-rig program this summer with a focus on development geared to fill our Leidy South capacity. In the near term, you can plan on us drilling a pad or so for a year in Tioga County or 5 to 6 wells, which should keep our production in that area flat to slightly increased. Over the long term, as prices improve, this additional acreage provides considerable upside potential. The remaining 45% of the purchase price will be allocated to the Gathering system, which consists of 142 miles of pipeline and 31 leased compressor units, and which connects to our Empire Pipeline system on which Shell holds 200 million per day of capacity. Assuming an intercompany gathering and compression rate of $0.50 per Mcf, this acquisition will add over $40 million in annual revenue in fiscal '21 which will grow our Gathering business by more than 35% based on the midpoint of our fiscal 2020 guidance. As a result of this acquisition, we now expect to be significantly free cash flow positive in the upstream and gathering portions of our business. Given our hedge book and assuming $25 oil pricing and $2.50 gas pricing, I expect those businesses on a combined basis will be free cash flow positive by more than $100 million in the 12 months post close. We plan to finance this transaction in a way that maintains our investment-grade credit rating and I've had numerous discussions with the agencies to get their feedback. At this point, you can assume we'll issue a relatively proportionate amount of long-term debt and equity, including equity-linked securities. We've taken 2 steps to reduce the financing risk associated with this transaction. First, we negotiated an equity back stop arrangement with Shell, which allows us, at our sole discretion, to deliver up to $150 million of the purchase price consideration in the form of National Fuel equity and a predetermined share price of $38.97, which eliminates a lot of the risk around stock price movements. This back stop allows us to be opportunistic in accessing the equity capital markets with a known floor. Second, to enhance our short term liquidity, we entered a new $200 million credit facility with members of our bank group, which brings our total short-term liquidity available under our credit facilities to $750 million. While we can't predict exactly when we'll access the capital markets, we plan to have permanent financing in place prior to the July 31 closing date. In summary, this is a great acquisition for National Fuel. We're gaining a one-of-a-kind integrated package of lower-risk upstream and midstream assets at a very attractive price. In the near term, we add scale, lower our cost structure and improve earnings and cash flows. Longer term, as prices improve, the significant inventory of development locations in a highly prolific part of the basin should provide considerable upside potential. With that, I'll ask the operator to open the line for questions.

[Operator Instructions] Our first question comes from Gordon Loy.

This is Gordon Loy from Raymond James. And my first question is you guys show a tighter kind of Utica type curve on Slide 38. And I see that you guys are expecting the acquired assets to have a similar type curve. Does this imply that same kind of well level metrics that you guys show in the appendix for the EDA Tioga Utica wells and also flat to the acquired assets?

Yes. The answer to that is yes.

That's helpful. And then I have -- my one follow-up question is how would -- do you guys have any kind of initial remarks on the Marcellus locations compared to their existing EDA Marcellus wells?

Yes. We have quite a bit more Utica wells, around 150, we think, on their acreage or on the acreage that we're acquiring, and around 30 to 35 Marcellus wells.

Yes. And I guess my question was more around you guys have any idea of what the performance of those wells will be? Will they be similar to your EDA wells? Or how will they compare on a performance basis?

Yes, they'll be similar. We have 1 well that we've drilled in 007, the Marcellus well that came in at about 1.5 to 1.6 Bcf per 1,000 foot. It's been a very good well, and we would -- we're assuming that the Marcellus wells, what's left to drill there would perform about the same.

Your next question comes from Chris Sighinolfi.

It's Chris from Jefferies. Congrats on the deal, Dave. I think we're all past or due that tuck-in Appalachian deals for years, and it appears that patience is a virtue. It seems like a real unique opportunity, so well done.

Yes. Thanks, Chris.

I wanted to follow-up on a couple of questions. One, you mentioned the back stop with Shell and that was in your release last night. You also mentioned having -- plan is to have permanent financing in place by the time the deal closed. But I was just curious, the duration of this, of the back stop with Shell, does it terminate on deal close?

Yes.

And then how should we think about -- obviously, you mentioned EPS accretion. You gave us the $125 million EBITDA figure for the first year of ownership, which, if I just use some broad strokes about 50-50 debt equity financing and think about what the interest component of that is and Seneca's historical tax rate, gets to some pretty big numbers relative to kind of a consolidated company EPS profile today. I'm just curious, from a depreciation standpoint, what sort of schedule should we think about for the assets given that you valued only PDP?

Well, the -- from the upstream side, it will get blended into our overall DD&A rate. So under the full cost accounting, you sort of lump everything into one bucket. So we're in the, what, low 70s per Mcfe basis today. We think once the -- we add in these acquired reserves, that should go down by about $0.05 per Mcfe, everything else being equal. And then on the gathering side figure in kind of the 20- to 25-year depreciable life consistent with the life of the reserves that we're acquiring.

Okay. So we can run the production at your DD&A rate and then think about -- I think you said 45% of the deal cost being allocated to midstream and just straight line at 25 years, just as a rough ballpark?

Yes. That would be reasonable.

Okay. And nothing should change really with Seneca's tax rate relative to what we've seen historically. Is that a fair statement? Or is there something we should pay attention to?

Yes. I don't think anything should change, at least not in the near term.

Okay. And then Dave, you mentioned -- and it was in, again, the release and I thought the presentation was a very good overview as well. You mentioned the quality of the pipeline contracts being picked up in the deal. And I'm just curious, it looks like there's a bit more of capacity there than maybe there is flowing production. Your plans for that capacity, is that something you can utilize existing Seneca EDA volumes to direct -- to that capacity? Is that something you look to resell?

Yes. So we didn't put a lot of value on the other capacity. I think the interesting part about the Dominion capacity that we're picking up is that it would allow us to move volumes from Tioga County to Leidy and then ultimately onto the Leidy South capacity that we'll have in service next year. So that gives us some optionality on how we fill that. Some of the capacity also gets further west into the 219 markets. And Justin Loweth is on the call. Justin, you can feel free to chime in on that as well.

Sure, Dave. Thanks. So as Dave just alluded to, we're really excited about the Empire capacity that gets to some excellent markets and is certainly a contract we would look to further extend into the future. The Dominion capacity, there's about 25 a day of that capacity that we would look to utilize at all times. And then as Dave was alluding to, the other 75 has some option value for us. It could make sense at certain times of the year. But once Leidy South is in service, given the high deliverability of these wells, it's a nice tool to have in our marketing portfolio to potentially utilize gas from this area as part of filling that 330 day (sic) [ 330,000 Dth/d ] commitment. And so I think that's the way to think of it. The other element of this is that we will be able to utilize some of this capacity holistically with our existing Tioga assets and we're a little bit -- we need it. So it will be helpful to us. We've got a little more gas than we have takeaway with our existing assets today. So this is very complementary also from a marketing portfolio perspective.

[Operator Instructions]

This is Tim Winter from Gabelli Funds. Congrats on the acquisition. I was wondering if you could provide a little more color on the offering. I guess the press release says adjustments at closing bring it down to $500 million. And if you're going to be at 50-50, should I assume $250 million of debt and then $150 million of equity to Shell? Then you said equity-linked securities, would that be, say, another $100 million of like convertible equity? How should I allocate that?

Yes. I mean certainly on the debt side, I think that's a fair way of looking at it. The way I view the Shell back stop is literally as a back stop. It will allow us to be flexible as we access the equity portion of the capital market. So it could be -- it's all going to come down to what we're able to achieve. If we could do an equity offering at well better than $38.97, we certainly would go more in that direction. If an equity-linked security got us more bang for the buck, we can go in that direction. So at this point, I don't want to be and really can't be more specific on the specific instruments that we'd use other than to say that we're going to go in the direction of the -- of where we're getting the best cost of capital and we're going to do it before closing.

Great. Would the number be close to $250 million plus or minus?

Yes. Yes, I think that's fair.

Okay. And then I was wondering if you could just help me reconcile the -- I guess the press release says production 70 to 70 Bcf (sic) [ 70 to 75 Bcf ] out of the new properties. It looks like the annual production guidance didn't go up. Is that a timing nearly as much? Is that a timing thing?

Yes. We only have 2 months of production in this fiscal year.

Your next question comes from Chris Sighinolfi from Jefferies.

Guys, I'm back again. I just wanted to clarify a couple of points. So Dave, you mentioned an anticipation of $100 million of initial year free cash flow across Seneca upstream and Gathering segments. I'm just curious, the intent for that cash flow and given, I guess, the fact that E&P is a little bit larger share of NFG's earnings and cash flow profile now. Does it speak to a need to take leverage down more than it was before? Or can you just talk about maybe the use of that cash and where you see long-term leverage sitting?

Yes. So if you look at next year, it's going to be a big year for us on the pipeline side with our FM100 Modernization Project, that's the -- sort of our half of the Leidy South project. So I'd see the excess cash going to fund that. So you view it as deleveraging because previously we had planned on financing that entirely with leverage.

Okay. And then if we think about maybe where -- I know there's multiple ways to think about the capital structure, I think you guys have talked about debt to capital, I believe we'll obviously look at debt-to-EBITDA as well. Is there -- I'm not talking about maybe immediately, but over the course of time, is there a range that you think is a soft target we should think about under the new profile?

Yes. I would certainly keep our investment-grade credit rating which would have debt-to-EBITDA below 3.5x. Personally, I'd be more comfortable in the 2.75 area to have some flexibility. So long run, I think of us trying to get to that level or better.

Okay. And then, John, on Friday's earnings call, Holly had asked you about CapEx for '21. And I think you were very careful about how you answered that saying there were things out there, but you thought sort of plus or minus $350 million. If I look at Slide 10, it would seem to indicate that that was not -- that it was not contemplated in that answer, but I just wanted to verify that.

Yes. Chris, there's been no changes on that side of it since Friday.

Okay. And then I guess a final question for me, Dave. Just you mentioned deal close 7/31, but deal effective Jan 1 and I think I got the answer with your clarification to Tim. You're just including the components of fiscal 4Q in the update. But I guess, in what way does effective 1/1, how should we think about that?

Well, 1/1 is the date at which the valuation was done. And then we do post-closing adjustments to reflect cash flows that would have occurred in between Jan 1 and July 31. So it ends up being as if -- from an accounting standpoint and a consideration standpoint as if the effective date is July 31.

Okay, understood. That's perfect. That's what I had suspected, but I just wanted to make sure.

Your next question comes from Holly Stewart from Scotia Howard Weil.

Maybe just -- maybe just a few questions, John, just trying to think about, right now, I think as we move through the next half of 2020, the rigs and the WDA. As you move into '21, was this deal -- does that sort of change things? I guess how should we think about rig positioning in 2021?

Yes, Holly, it will essentially stay the same. At times, the rig will jump over into the EDA. It'll actually move into Lycoming over the next couple of months for -- to drill a few wells there, but then it'll come back to the WDA. So we're going to -- we'll continue -- that rig will continue to drill most of its -- of our inventory in the WDA. We really won't get active drilling in Tioga, I would say, until very late fiscal '21, but really for more early fiscal '22. And again, that's as long as gas prices improve a little bit.

And then in terms -- well, I guess, maybe just a follow-on to that, what do you think you need to see? Is it -- I think when we talked on Friday, it was the 22 strip being more supportive. Is that just the answer in terms of additional activity here?

Yes, that's exactly right.

And then maybe just comments on the midstream side, incremental capital that it would take to sort of connect your existing system with Shell's system.

Yes. It should be very low, Holly. Most of the -- well, for one, the Gathering system already connects into the Empire system. Long run, we'd have the ability to potentially tie in the Shell system with our existing Covington 595 Gathering system. But from a, call it, fiscal '21 and '22 time period, we're not looking at really any meaningful amount of midstream gathering capital. I mean in a low millions of dollars.

Yes. Okay. That's great. And then maybe just to bridge the gap here on the couple of numbers that are being thrown around, 350 wells producing per barrel lease. I think you guys mentioned 185 locations. And then you'll split that between the Marcellus and the Utica. John, do we know exactly how many Utica wells they have producing today?

We do, but I don't have that number with me. So let me talk with Ken and we'll get that back to you.

Okay. And then maybe, Justin, made some comments on the FT capacity. Any color you can provide on just what that incremental capacity does to your overall FT costs in your loan portfolio?

Sure, Holly. Yes. It's -- so it's net accretive to our overall level of -- if you think about it from a perspective of what do we realize relative to NYMEX on our -- on all of our gas sales, this portfolio that we are acquiring here incorporated into our own business will be accretive by, call it, very specific buy like $0.10 or so. And so if you think about realized differential, a couple -- $0.03, $0.04 tighter to NYMEX. So it's a net positive. It was part of the attraction of the opportunity for sure, improves our overall margins.

There are no further questions at this time.

Well, thank you, Christina. We'd like to thank everyone for taking the time to be with us today. A replay of this call will be available later today on both our website and by telephone and will run through the close of business on Tuesday, May 12. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com, and to access by telephone, call 1 (800) 585-8367 and enter conference ID number 5176472. This concludes our conference call for today. Thank you, and goodbye.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.