Southwestern Energy Company (Ticker: SWN) reported Q3 2017 results today and held its conference call for analysts.
During the third quarter Southwestern invested approximately $320 million in the E&P business and participated in drilling 47 wells, completed 29 wells, and placed 37 wells to sales.
During the first nine months of 2017, Southwestern invested a total of $946 million. This included approximately $921 million invested in its E&P business, $21 million invested in its Midstream segment and $4 million invested for corporate and other purposes. Of the $946 million, approximately $85 million was associated with capitalized interest and $77 million was associated with capitalized expenses.
Highlights:
- Net income attributable to common stock of $43 million, or $0.09 per diluted share, and adjusted net income attributable to common stock of $29 million, or $0.06 per diluted share.
- Net cash provided by operating activities of $211 million and net cash flow of $248 million, up 23% and 43%, respectively, compared to the third quarter of 2016.
- Total net production of 232 Bcfe, including 153 Bcfe from the Appalachian Basin, an increase of approximately 10% and 26%, respectively, compared to the third quarter of 2016, despite third party gathering downtime in Northeast Appalachia.
- Achieved record exit production rate from the Appalachian Basin of almost 2.4 Bcfe per day, an increase of 42% compared to the third quarter of 2016.
- Realized C3+ NGL prices of $27.82 per barrel, or 58% of West Texas Intermediate (WTI), and realized total NGL prices of $14.47 per barrel, or 30% of WTI (net of transportation costs), up 75% and 106%, respectively, compared to the third quarter of 2016.
E&P segment
The operating income for the segment improved to $64 million for the third quarter of 2017, compared to an operating loss of $777 million during the third quarter of 2016 that included an $817 million impairment of natural gas and oil properties during this period last year.
Midstream segment
Operating income for the segment, comprised of gathering and marketing activities, was $46 million for the third quarter of 2017, which included a $3 million gain on sale of equipment, compared to $52 million for the same period in 2016. The decrease in operating income was largely due to a decrease in volumes gathered resulting from lower production volumes in the Fayetteville Shale.
E&P operational review
During the third quarter of 2017, Southwestern invested a total of approximately $320 million in the E&P business and participated in drilling 47 wells, completed 29 wells, and placed 37 wells to sales.
During the first nine months of 2017, Southwestern invested a total of approximately $921 million in the E&P business and participated in drilling 106 wells, completed 118 wells, and placed 130 wells to sales.
$3.4 billion in net debt
At September 30, 2017, SWN had total debt of approximately $4.4 billion and $3.4 billion in net debt. In the third quarter, SWN completed a public offering of $650 million aggregate principal of its 7.50% senior notes due 2026 and $500 million aggregate principal of its 7.75% senior notes due 2027. The proceeds from this offering were used to repay $758 million of the SWN’s 2020 Notes and to repay the outstanding balance of $327 million on SWN’s 2015 Term Loan. The SWN now has only $92 million in bonds due prior to 2022.
Southwest Appalachia
SWN’s net production from Southwest Appalachia was 52 Bcfe in the third quarter 2017, a 41% increase compared to the same quarter in 2016. Southwestern brought online 18 wells in Southwest Appalachia in the third quarter, which included 17 Marcellus wells and one Utica well. The 17 Marcellus wells had an average lateral length of 6,958 feet and an average cost of $6.7 million per well. In Marshall County, Southwestern placed the four-well Gladys Briggs pad to sales in July with an average completed lateral length of 6,576 feet. The pad is currently producing at a rate of 58 MMcfe per day, comprised of 42% liquids, with an average flowing casing pressure of 2,250 psi.
SWN set two drilling records in Q3
SWN set two drilling records in the third quarter. The first was on the John Hupp 3H in Brooke County, West Virginia, where 6,202 feet of lateral was drilled 100% in zone of a 15-foot target window, setting a new 24 hour drilling record. The second was on the William Rogers 405H well in Ohio County, West Virginia, which was drilled to a total depth of 13,927 feet in less than 10 days from rig release to rig release.
Two commercial opportunities
In Marshall and Wetzel counties of West Virginia, SWN dedicated its dry gas Utica gathering rights to Williams Partners at competitive long-term gathering rates and concurrently expanded its wet gas Marcellus processing capacity optionality up to 660 net MMcf per day at immediately reduced processing rates. This new agreement is expected to add approximately $1.4 million in net present value per well for SWN’s lean gas wells.
Southwestern commenced a company-owned water infrastructure project in its Panhandle acreage in West Virginia to more efficiently transport water throughout the play. The project is expected to reduce completion costs by $500,000 per well beginning in late 2018 and reduce the break-even gas price by approximately $0.25 per Mcfe.
Northeast Appalachia
SWN’s net production from Northeast Appalachia was 101 Bcfe in the third quarter 2017, a 20% increase compared to the same quarter in 2016. SWN continued its delineation success utilizing enhanced completion designs in Tioga and western Susquehanna Counties, placing seven wells to sales with strong early results. Additionally, SWN placed its first three-well pad to sales in the Susquehanna County acreage acquired in 2015 with an average lateral length of over 10,000 feet and combined maximum rate of over 62 MMcf per day.
SWN also generated an additional $0.09 per Mcf on its Northeast Appalachia volumes with its financial basis hedges in the third quarter as basis differentials widened because of increased production and delayed in-service dates on new takeaway projects.
Fayetteville Shale
During the third quarter of 2017, SWN placed three wells to sales, including two Moorefield delineation wells. The two Moorefield wells had an average lateral length of 7,495 feet and an average cost of $5.3 million per well. These two step-out wells incorporated learnings from previous well results, delivering an initial production rate of 5.4 MMcf per day and an average EUR of 5.5 Bcf.
Additionally, SWN successfully renegotiated its Fayetteville firm transportation agreement, subject to FERC approval, providing savings of approximately $70 million from 2017 through 2020, including $45 million in 2018. This agreement also secures flexible take-away capacity at reduced rates of approximately $0.10 per MMBtu after 2020, a reduction of over 60% compared to the current average rate of $0.26 per MMBtu.
Hedging Update
As of October 24, 2017, SWN had approximately 139 Bcf of its remaining 2017 forecasted gas production protected at an average swap or purchased put strike price of $3.01 per Mcf. Additionally, SWN had approximately 473 Bcf of its 2018 forecasted gas production protected at an average swap or purchased put strike price of $2.99 per Mcf, with upside exposure on approximately 62%, or 295 Bcf, of those protected volumes up to $3.39 per Mcf. SWN also had approximately 165 Bcf of its 2019 forecasted gas production protected at an average purchased put strike price or average swap price of $2.97 with upside exposure on approximately 66%, or 108 Bcf, of those protected volumes up to $3.32 per Mcf.
Southwestern Energy conference call Q&A
Q: Regarding the economics of the well reserves, when you guys do your PDI, are within striking distance or is this more just encouragement to do more work?
Jack Bergeron, Senior Vice President- E&P Operations: No, we believe we’re in the development phase there. These wells averaged 72 foot lateral length. We’re shooting for, I think we’re still early, but greater than 2 Bcf per thousand feet, and these wells cost about 7.4 million per well, we have to truck a lot of water there because it was early, so we think we can still drive the cost down. But we’re very encouraged and continuing on and believe it’s a development project at this point.
Michael Hancock, Vice President Investor Relations: One thing I’ll add there, this the first time in that county that we’ve had a multi-well pad, so now you have four-well pad, they’re competing for the same rock and you got really good results which tells you even more about the quality of that acreage.
Q: And then I could maybe ask a related question about the Moorefield, so I get that you’re going to be doing this step-out 10 miles to 15 miles away from your existing pad with these last two wells in 2017. Can you talk us through with the possible pads that you’ll be on in 2018 with respect to the Moorefield? Will these two wells be definitive about condemning or confirming the application of the concept to a wider footprint or are we just going to still be in investigation in 2018 with respect to the Moorefield?
Jack Bergeron, Senior Vice President- E&P Operations: What we’ve done is laid out geographically we’ve mapped the area where the Moorefield is and we’ve initially went in and did our development pad on the English pad and now we’ve stepped out to the edges of what we’ve mapped and these are our delineation wells. It will prove-up there is gas between the wells, we still need to prove up the economics, but we think we’re a lot — these delineation wells each prove-up somewhere between 10,000 and 12,000 acres, and we think we’re on the way to finding the limits of our 100-plus 115,000-acre possibility in the Moorefield.
Q: What do you think about your future reinvestment opportunities in the Fayetteville and obviously the Moorefield could play into that, but just talk about given the lower midstream cost, how you think about reinvesting in ’18 and beyond?
William Way, President and Chief Executive Officer: Yeah, I’ll start with the kind of the agreement that we’re able to reach at a high level and these agreements for transport expire in ’20 and ’21, and so the opportunity to amend them and extend them to consolidate with a very strong player and stretch those agreements under the future indicative of the fact that we’ve got a long tail of production in the Fayetteville.
Second, the opportunity to structure an agreement whereby the first tranche of that rides a sort of a base decline curve takes the risk out of excess MVCs from us and then provides opportunities for both us and the pipeline with option capacity above that, as we optimize the capital investments going forward, look at Moorefield results such as some other opportunities. And so it’s a very well-structured agreement that enables us to improve the competitiveness of the entire Fayetteville asset as we prioritize capital to the highest PVI project. So when you step back and you look at how do we allocate capital, we allocate capital highest PVI projects and we challenge each of the areas to drive further competitiveness of their individual plays by sharing knowledge applying that knowledge and taking actions like this, the work we did in West Virginia around renegotiating our gathering and processing agreements, the work we’re doing on well improvements all to drive those that realize value improvement and then we allocate capital based off the highest returns on those investments
Q: As you can tell the market is just not valuing growth in the same way and there’s clearly been a premium on free cash flow generation. As you think about your 2018 program and beyond, how do you think about the value proposition of the company and how could that shift the way you’re thinking about allocating capital on a go-forward basis?
William Way, President and Chief Executive Officer: Well, I think that our allocation of capital on the highest return projects is perfectly in line with the way to create shareholder value, improve returns, it is perfectly aligned with the dialog of the day in the industry and especially in investment community of focusing on quality returns in quality projects over production growth, and so that’s exactly what we are doing. As we look at the allocation of capital for 2018, it will be like any other year, our focus is on creating value, improving returns on every dollar we invest. We’ll take the options of investing at the drill bit and weigh those within debt reduction and any other options that come to the table to again create the highest value-adding plan to go forward. And we already have begun to shape that plan and as we work through the balance of the year to look at the winter look at how pricing comes together we’ll be able lot that down orbit. This isn’t about production growth at all cost, it hasn’t been for us, and it won’t be for us going forward. It’s an outcome of all.
Q: In the press release last night there is mention of an advanced completion design in Susquehanna, but there was a little bit of light on the details. I was just wondering if you could share what the new advanced completion design was and perhaps more importantly the broader application towards the other pieces in your portfolio?
Jack Bergeron, Senior Vice President- E&P Operations: Well, this is Jack. Without giving you all the details, because we think it’s competitive advantage, it is tighter cluster spacing stage spacing and we long ago went to a pretty high sand loading there, but it’s really changing the stage spacing and completion intensity.
William Way, President and Chief Executive Officer: And the application of that learning and just for — to broaden the question a bit, any operational commercial technical learning that we have in a particular area is immediately transferred to the other parts of the company and evaluated for application and then applied and you get different results. You can have an advanced completion in this case, you’ll recall we are kind of one of the leaders in upsizing, sand loading up to a size 5,000 pounds a foot. All of those kinds of activities are looked at to be applied everywhere else. And you get greater impacts on some, in some areas and greater impacts and others on other areas and that blend in the way we operate those assets as a joined up view is enabling the transfer of knowledge and more importantly the application of knowledge to move faster across the enterprise.
Q: I wanted to ask a question on the added basis hedges that you put in place, securing a much better basis protection relative to what you’re realizing now. Granted there’s probably some seasonality in those contracts, but is there a practical limit to how much you’d be willing to hedge on basis and do you have a general view for how your corporate-wide basis should improve in 2018?
Jason Kurtz, Vice President – Marketing and Transportation: Yes, so what we’re looking at when we continue to add basis, it is we try to match those basis hedges with our NYMEX hedge program that we have in place. So what we’re trying to achieve is an overall effective hedge with our program.
Q: On the water handling project that you’re undertaking, long-term vision for this: One, is this included in your capital plan already; and then two, are there applications to other areas where you want to put this in; and then ultimately once the infrastructure is built out, is that something that you’d like to retain or is it something that you’d like to monetize?
William Way, President and Chief Executive Officer: Well, the water project is — the genesis of it, I think, is really leveraging off of a practice that we use very, very successfully in Pennsylvania, where we have a quite a network of capability to move water from pad to pad and avoiding trucking cost and trucking — both trucking cost on the road and trucking cost which is hired to get water around. This opportunity, especially in West Virginia with a train and the remote sites and the space needed and everything really brings further enhancement to the well economics. It is — will be a part of how we develop this play because of the results that we got in Pennsylvania. And as we look to expand it across our development areas, we’ll do that in phases, it is in our capital program and the first three phases of it actually are in our capital program, and we’ll continue to look for opportunities to expand it going forward.
And to your question around will we keep it, I mean it’s certainly an integral part of our operation, but you always look for opportunities to enhance value and we’ll see when the time come.
Q: What percentage of your pre-reserves is from the Fayetteville at this juncture?
Paul Geiger, Senior Vice President – SWN Advance: We release that on an annual basis, so the quarterly numbers are not simply put out. But generally as we look at that now, you’ve got about a-third of the reserve base is Fayetteville.
Q: Just a quick question related to the water infrastructure project in Southwest PA. When you think about getting a rate of return on that, do you have the opportunity to sell services to third-party operators?
William Way, President and Chief Executive Officer: We absolutely do. And we would set the project up for that opportunity.
Q: Can you talk more about lateral length in both Northeast Pennsylvania and then in the Southwest Appalachia and how do you see your lateral length moving over the next year and what would any constraints may be on that?
William Way, President and Chief Executive Officer: Well, the lateral length, we do try and maximize lateral length wherever we’ve successfully gone over 12,000 feet with good success wins, no issues there. Currently our lateral lengths average 5,500 feet in Northeast Appalachia and 7,500 feet in Southwest Appalachia. We do look to expand that, we work with land owners that’s usually the — the requirement is if it’s already a unit, you have to work with the landowners, we’ve successfully been able to do that in some areas and we’re continuing to pursue that. We feel very comfortable with longer lateral lengths where we can drill them and are working on those as we speak.
Q: When you look at optimizing activity in the future in the Fayetteville Shale area, it looks like some of those more recent Moorefield wells were at a longer lateral length. And I think traditionally the Fayetteville ones were little over 5,000 feet. What is the limitation on drilling longer laterals in the Fayetteville adjusted depth that you’re working there, and can you extend those little bit longer?
Jason Kurtz, Vice President – Marketing and Transportation: We have drilled some longer and we will do that. We actually have easier land situation there than we do in Appalachia, but yes, we are very comfortable some of the — even the depth we have no problem drilling 7,500 to 9,000 feet there.
Q: And so as far as next steps, is it still sort of in project mode versus something that you would consider to move to more development as you look into ’18?
William Way, President and Chief Executive Officer: Yeah, really we need to continue to understand the expense of the Utica under our acreage and the quality of it and then as we very clearly disclosed, we’ve got to get the well cost down. And so there is a continuous drive to understand the risks associated with drilling these wells. We are — once we go to development mode, we have a very, very clear track record of driving well cost down dramatically. These are expensive wells, so we’ve challenged the teams to get the one-off wells performance down as well, and that gives us the confidence to go forward. But the subsurface what we’re seeing, we’re interested in — we’ve just got to get the cost down. We have a path to get there and that path is mapped out. And so the teams need to demonstrate that in the coming wells and then we can put it in the capital allocation analysis system that we have and again it’s heads-up competition.
