SWN - Southwestern Energy
Second Quarter 2013 Earnings Conference Call
Friday, August 2, 2013
Officers
Steve Mueller; Southwestern Energy; President and CEO
Bill Way; Southwestern Energy; COO
Craig Owen; Southwestern Energy; CFO
Jeff Sherrick; Southwestern Energy; Senior VP of Corporate Development
Brad Sylvester; Southwestern Energy; VP of Investor Relations
Analysts
Dave Kistler; Simmons and Company International; Analyst
Scott Hanold; RBC Capital Markets; Analyst
Brian Singer; Goldman Sachs; Analyst
Doug Leggate; Bank of America; Analyst
Arun Jayaram; Credit Suisse; Analyst
David Heikkinen; Heikkinen Energy Advisors
Gil Yang; Discern Investments
Robert Christensen;Canaccord
Andrew Coleman; Raymond James
Charles Meade; Johnson Rice & Co.; Analyst
Biju Perincheril; Jefferies & Company; Analyst
Presentation
Operator: Greetings and welcome to the Southwestern Energy Second Quarter 2013 Earnings
Teleconference Call. (Operator Instructions) As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Steve Mueller, President and CEO of Southwestern Energy. Thank you Mr. Mueller, you may begin.
Steve Mueller: Thank you and good morning and thank all of you for joining us today. With me are Bill Way, our Chief Operating Officer; Craig Owen, our Chief Financial Officer; Jeff Sherrick, Senior VP of Corporate Development; and Brad Sylvester, our VP of Investor Relations.
If you've not received a copy of yesterday's press release regarding our second quarter 2013 results, you can find a copy of all of this on our website, www.swn.com. Also, I would like to point out that many of the comments during this teleconference are forward-looking statements and involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the Risk Factors and the Forward-Looking Statements sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.
I'm excited to begin this call today and for those of you who know me, the word excited isn't
often used. We just had an excellent quarter. The combination of high production and high realized gas prices or higher realized gas prices resulted in records for adjusted earnings, EBITDA and cash flow in the second quarter. Our production growth of 17% was primarily fueled by strong well performance from our Marcellus Shale properties, combined with more overall wells placed on production. As a result, we've increased our production guidance for the second time this year. Additionally, our well count to capital investments for the year have also been increased due to our recent acquisition and planned drilling on it, as well as faster drilling times and more efficiency.
I want to stop here for a second and remind you a little bit about our overall philosophy. In the Marcellus, it's obviously the best economics we have in the company and we've tried as best we could to put as much capital in that direction and we announced last quarter the acquisitions and didn't think we could spend much capital there this year. But we worked hard and Bill will go into more details about what we're doing there. But of that increase, there's about $140 million total; $93 million of acquisitions and the rest in some activity that we can do in that acreage.
And then when we talk about the Fayetteville Shale, we've always said that we wanted to keep it within cash flow and we've been trying to do that for the last two or three years and frankly, they've been so efficient that rather than drop a rig and drill the wells we said we were going to, we're going to keep 1 rig running. With that 1 rig running, we'll be able to drill faster this year and guarantee significant growth next year.
Now, that's all just part of our theme that we have for delivering more. As I said, we'll keep 8 rigs running in the Fayetteville all year due to our increased capital budget. One thing I didn't mention was when we started the year, we built our capital budget in the Fayetteville to basically balance running 8 rigs through the whole year and adding wells, we'll actually have $100 million of cash flow from the Fayetteville come back to our company. That's a great example of adding more for Southwestern Energy.
In Marcellus, we've learned a lot about productivity in our wells in Northern Susquehanna County and our production ramp out of that area has been tremendous, growing from zero to over 180 million a day in just seven months. And we just look at the wells drilled and the acreage that they're actually developing, it's less than 5% of that northeast corner of Range Trust area, but because of the geographic extent, we'll continue drilling farther north through the rest of the year. We already think we de-risked approximately 50% of our total position in Susquehanna North area. There's more to learn obviously and more to come from this area and the other counties as we start exploring some of the new acreage we purchased earlier this year, but the Marcellus is obviously giving us more.
I mentioned before that we're going to have higher cash flow from the Fayetteville and we're going to increase our capital budget. I've talked in several of the calls and talked with many of you about the fact that before we raised our capital budget we'd have to feel better about gas price and obviously we feel better about gas price too. It's always a discussion point this time of the year and especially in the heat of the summer, there's always a debate raging about what the gas price is going to be in the future. We believe most of the numbers point to the fact that there's a gap between supply and demand that's continuing to narrow and we remain encouraged that
we'll be in a $4.00 world long-term and we think that could happen late this year and early next year.
Now I want everyone to keep in mind that gas prices don’t drive our success. As we proved in 2012, our business model can generate returns in a much lower gas price environment and you can be sure we'll always be focused on disciplined investing, continued learning, keeping our costs low and delivering more value for the business.
I now want to turn the call over to Bill. He'll give you details on both our capital budget and our production, as well as some of the other great things going on and then Craig will recap with the financial results.
Bill Way: Thank you Steve. Good morning everyone. The execution of our drilling and completion programs in our Marcellus and Fayetteville areas has resulted in record production this quarter and has set the stage for a very good year for Southwestern Energy in 2013. The production performance from both areas has been truly outstanding and I want to personally thank our Fayetteville and Pennsylvania integrated teams for a truly terrific job.
Overall our production in the second quarter grew by 17% over last year, fueled largely by faster drilling times in the Fayetteville and strong well results and increased activity in Pennsylvania, as Steve mentioned. As a result of this success, we've increased our production guidance for the remainder of the year, and further, we have increased our capital budget, which includes our acreage acquisition in Pennsylvania, which was closed in the second quarter, additional drilling activity due to faster drilling times and increased efficiencies and capital for our E&P Services group. As a result, our planned well counts will increase by 70 wells in the Fayetteville and approximately 15 wells in the Marcellus.
Let me begin with the Marcellus. We placed 37 wells on production this quarter compared to 21 wells in the first quarter. As a result, our gross operated production that had reached 400 million cubic feet of gas per day in mid April, further increased to 500 million cubic feet of gas per day by mid June. Net production for the quarter was 3 times greater when compared to a year ago, rising from 34 Bcf up from 10 Bcf in the second quarter of 2012. Our Marcellus production will continue to grow in line with available gas transportation infrastructure.
At this time we currently have agreements in place to allow us to transport over 800 million cubic feet of gas per day out of the area by 2015. We are pursuing opportunities for long-term access to additional firm takeaway capacity out of the basin and we'll keep you updated as things progress for us in that area.
In keeping with our plans for the area, we announced yesterday that we have entered into agreements with subsidiaries of DTE Pipeline Company which provide for additional firm capacity to both Millennium and Tennessee Gas pipelines on the Bluestone Gathering System in Susquehanna County. This additional capacity further strengthens our ability to move Marcellus gas to liquid markets from the area.
We also added 103 million cubic feet per day of additional firm transportation capacity on
various long-haul pipes comprised of a mixture of firm transport and short and long-term sales. The delineation of our Range Trust area in Northern Susquehanna County continues to provide us with strong results since we first put wells on in the area in late November. 18 wells were brought on production in the area during the second quarter, helping to further delineate the acreage to the east and north. In just seven months, gross operated production has increased from zero in the Range area to approximately 184 million cubic feet per day as of July 1st, from a total of 40 wells.
As a follow-up to our Blaine-Hoyd well in southern Bradford County that we announced last quarter, the production from this well continues to be very strong. And I'll remind you, this well had 32 stages in completion, a longer C-Lat of over 6,500 feet and after 90 days this well was still producing approximately 16 million cubic feet per day and had cumulative production of 1.5 Bcf for the second quarter. Earlier this week the well is still producing approximately 15 million a day.
We continue to experiment with our fracture stimulations, lateral lengths, flow techniques, further optimizing our well performance and believe we're getting closer to conclusions on how to best stimulate these wells.
Wells placed to sale in the first six months of 2013 have averaged 17 stages per well, compared to 12 stages in 2012, while average lateral lengths have been approximately 4,700 feet this year, compared to roughly 4,100 feet last year. Meanwhile, completed well costs have declined to $6.6 million per well in the second quarter compared to a little over $7 million per well in the first quarter.
On the midstream side, total gathered volume in the Marcellus was approximately 503 million cubic feet per day, from 167 miles of gathering lines in the field as of June 30th, half of which are Southwestern Energy owned and are gathering 300 million cubic feet per day. We also added first compression to the Range area in late June with another phase of compression scheduled to be placed in service in October. Additional compression was placed in service in Greenzweig yesterday and first compression at Lycoming is planned to come on later this year.
As more compression is installed in these wells, our wells will not have to compete as much against highline pressure and can then produce at high rates.
We have closed on the previously announced acquisition of approximately 162,000 net acres near our existing acreage position in Pennsylvania in May and we've included $50 million in our revised capital budget for drilling, lease renewals, participation in wells operated by others, seismic and other expenses on the new acreage.
Let me shift to Fayetteville now where we placed 126 operated wells on production in the first quarter at an average completed well cost of $2.3 million per well. Our completed well costs were up from $2.1 in the first quarter due to longer laterals and deeper average vertical depths. This however, marks the first quarter that our laterals have averaged over 5,000 feet since the inception of the play.
We continue to drill wells across the play and the resulting economic value from our wells in the second quarter continued to be enhanced by our vertically integrated services and further efficiencies continue to be a significant benefit in driving down our costs. Initial production rates from the wells during the second quarter returned to trend and averaged 3.6 million cubic feet of gas per day. For wells already brought on line in July, we've had an average peak initial production rates in excess of 4 million cubic feet of gas per day, with several high rate wells still climbing while cleaning up.
As Steve noted, with our current capital program of $900 million in the Fayetteville and the resulting additional well count, we project the division will now generate free cash flow of roughly $100 million this year, using prices to date and strip prices going forward.
And on the midstream side, our gas gathering business in the Fayetteville Shale continues to perform very well and at June 30 was gathering approximately 2.3 billion cubic feet of natural gas per day from 1,886 miles of gathering lines in the field.
If we switch to new ventures and update you on our progress there, to date in the Brown Dense we have drilled 8 wells. We remain very encouraged after watching flattening production profiles from both our BML horizontal well and the Dean vertical well over the last several months. We've seen further encouragement in the completion of our 8th well, the Sharp vertical well.
The first stage restimulated in the Sharp well is the lowest part of the Brown Dense and is an interval that we had not previously tested in any of our previous wells. This interval seems to be more highly fractured than we've seen in previous sections. This interval of the well has been testing just over a week and is continuing to increase in rate and flowing pressures, with rates over 125 barrels a day; a 48 degree gravity oil; 326,000 Mcf of 1,275 Btu gas. We will likely stimulate and test the remaining 3 wells - intervals of this well in the next few weeks.
We've also seen industry activity pick up in the area as both public and private operators have requested drilling permits and 2 of 5 planned wells have actually been spud, with the remainder planned for later this year or early next. Overall, we remain excited about the Brown Dense and we're going to continue to work to unlock the commerciality of this play.
In our Denver Julesburg Basin oil play in eastern Colorado, we've begun flowback on our 15-stage Staner well on July the 18th and we'll watch performance of this well over the next 90 days. In the Bakken we've completed our testing on our second well. We are disappointed with the results that we've seen and we'll move on to other opportunities in our new ventures portfolio.
In New Brunswick we've successfully acquired two lines of 2-D seismic and look to acquire two more lines of 2-D this quarter. We remain on track with our goal of first drilling in late 2014.
To close, we're delivering more to our shareholders and we believe in the future of Southwestern and we believe that future is very bright, driven not only by the producible assets we have in hand, but also because of the potential of the early stage new ventures projects that we're working on. We will continue to update everyone on these over time, including some that are
undisclosed for now. In the meantime, we'll remain vigilant and continue to drive the process of innovation, keeping our costs as low as possible and adding significant value for each dollar we invest. And I look forward to talking to you more about the progress of these in the future quarters.
Let me now turn it over to Craig Owen, who will discuss our financial results.
Craig Owen: Thank you, Bill, and good morning. As Steve mentioned, our results in the second quarter were outstanding, driven by higher production volumes and higher gas prices. Excluding non-cash items, we reported net income of approximately $190 million or $0.54 per share for the second quarter, more than doubling prior year net income of $91 million or $0.27 per share.
Cash flow from operations, before changes in operating assets and liabilities, was a record $493 million. This was 16% higher than the first quarter and up 39% compared to the same time last year.
Operating income for our Exploration & Production segment was $253 million, over three times higher than the $82 million we recorded in the second quarter of 2012, again, primarily due to higher production and higher realized gas prices, partially offset by the higher expenses due to the increased activity.
We realized an average gas price of $3.85 per Mcf during the second quarter compared to $3.12 per Mcf in the second quarter of last year and have 169 Bcf of our remaining 2013 projected natural gas production hedged through fixed-price swaps at a weighted average price of $4.68 per MMBtu. We also have 233 Bcf of natural gas swaps in 2014 at an average price of $4.41 per MMBtu.
As for fuel differentials, we have protected approximately 128 Bcf of our remaining 2013 projected natural gas production from the potential of widening basis differentials through hedging activities and sales arrangements at an average basis differential to NYMEX gas prices of approximately $0.06 per Mcf. This includes approximately 50% of our expected Marcellus volumes that are protected through year-end. Although both NYMEX and fuel prices have declined from levels seen earlier in the year, we continue to watch the gas markets closely and will look for opportunities to add to our hedge position.
One of the softer basis points that the Northeast market has seen this summer is Dominion, which has the potential to impact approximately 15% of our Marcellus production through the shoulder season. One thing to remember is that when the new pipeline projects go in service this fall and winter and -- excuse me -- and winter demand arrives, these differentials should improve. And this is all reflected in our expectation of a $0.55 discount to NYMEX for the balance of 2013.
Our cash operating costs of approximately $1.24 per Mcfe in the second quarter continue to be very low relative to the rest of the industry.
Lease operating expenses for our E&P segment were $0.85 per Mcfe in the second quarter, up
from $0.79 per Mcfe in the second quarter of 2012, primarily due to higher compression and gathering costs in the Marcellus Shale, partially offset by lower salt water disposal costs in the Fayetteville Shale.
Our G&A expenses were $0.24 per Mcfe, down from $0.27 a year ago and were lower due to decreased employee-related and information system costs.
Taxes, other than income taxes, were $0.11 per Mcfe compared to $0.08 a year ago, and our full cost pool amortization rate in our E&P segment fell to $1.05 per Mcfe compared to $1.38 last year.
Operating income from our Midstream Services segment was relatively flat with last year at approximately $73 million during the quarter.
At June 30, our debt–to-total book capitalization ratio was 36%, essentially flat when compared to the end of 2012 and our liquidity continues to be in excellent shape. We currently expect our debt-to-total book capitalization ratio at the end of 2013 to be approximately 34% to 36% at current strip prices.
With our outlook for increased natural gas production, coupled with higher gas prices than budgeted and a low-cost structure, we believe we have not only a record year ahead of us in 2013, but also, the ability to create significant value for many years to come.
That concludes my comments, so now, we'll turn it back to the operator, who will explain the procedure for asking questions.
Question-and-Answer Session
Operator: Thank you. We will now be conducting a question-and-answer session. (Operator Instructions). However, all analysts, please ask only two initial questions, but you can rejoin the queue with additional questions. (Operator Instructions).
Our first question comes from Scott Hanold with RBC Capital Markets. Please proceed with your question.
Scott Hanold: Good morning.
Steve Mueller: Good morning.
Bill Way: Good morning.
Scott Hanold: Thanks. So when we look at that Marcellus EUR, or I guess, type-curve charts, and some of these recent wells that you’ve got, roughly 18 stages now seem to be performing to 16 Bcf EUR. That's pretty impressive. I mean, when you step back and look at your acreage, now that you’ve done a little bit more drilling, how much of your acreage do you think could be that
good? And if you have a general well location count that could be applicable, that would be appreciated.
Steve Mueller: Just kind of a general comment -- certainly the Chesapeake acquisition, which was 162,000 acres; we don’t have a whole lot of new information on that. That's one of the reasons we're trying to accelerate our capital budget, but I think it's safe to say -- we've talked in the past that we had 1,000 wells on the acreage we had before Chesapeake and in the Chesapeake, we had at least 300. And it's safe to say, whether it's the size of the well or the number of well count, there's probably at least 20% additional in all those categories.
Scott Hanold: Okay, great. Thanks. And then my follow-up is in the Fayetteville. The IP rates in the second quarter were pretty solid. It looks like the 30th and 60th day rates were a little bit lower than some of your prior groupings of wells. Was there anything specific to that?
Bill Way: Yes, the IP rates are higher and it just represents a geographic mix. We are drilling and completing wells across the play and as we mentioned last time, our focus is on value and so, with our low well cost, the opportunity to drill in some of the shallower areas and capture our 1.3 or greater PVI benefit is our objective. And so the well mix from the previous quarter and into this quarter is impacted by drilling in some of those areas.
The real important piece of it is that in our current drilling inventory for this entire year, we are in excess of our financial metrics in terms of drilling going forward.
Steve Mueller: And I think, Scott, kind of the easy way to think about it, it'll roll through just like the low IP did last quarter and I think you'll see a 30 to 60-day this next quarter. So it's just one of those boggles, as far as I'm concerned, in the curve.
Scott Hanold: Right, okay. Just wanted to check. Thanks.
Operator: Our next question comes from Brian Singer with Goldman Sachs. Please proceed with your question.
Brian Singer: Thank you. Good morning.
Steve Mueller: Good morning.
Brian Singer: Now, one of the key debates is how the wells in a Range Trust in Northeast Susquehanna County compare with some of the higher profile wells we've seen in Southern Susquehanna County. Beyond the 50% of Susquehanna overall as a prospective, can you add some more granularity on how far north and northeast you've tested within particular the Range area, and how the well performance is varying, if at all?
Steve Mueller: We'll kind of tag-team this between Bill and myself. We're from a distance across Range Trust, and to kind of remind everybody, we've got about 120,000 acres total in Susquehanna County, about 23,000-24,000 in the southern corner and then the rest is up in the northeast corner of the county. And we've been concentrating on the northeast corner in the last
several months.
We're about just over halfway north towards the New York line drilling and from just a pure drilling standpoint, and from a geological what-are-we-finding portion of it, wells are looking similar, at least that far north. The section does thin going north. The section does get shallower, so there's a little less pressure, so I would expect that the well spacing probably won't be quite as tight as you go farther north, but by the end of the year, we'll have drilled all the way up to the New York border. And we can talk all about that at that point in time. Anything you want to add, Bill?
Bill Way: Well, we're getting fairly consistent performance across the 40 producing wells on average up there. The more we get on compression, the higher the IPs are coming or the flatter the declines are, but from across the entire acreage all the way up to the Northeast, where Steve has talked about us testing, we're fairly consistent. We've seen wells as high as 9.5 million a day and several in the plus-7 million or plus-8 million area across a broad area of this play or this part of the acreage.
Operator: Our next question comes from Doug Leggate with Bank of America. Please proceed with your question.
Doug Leggate: Thanks. I guess if I could try on the Marcellus as well. So Steve, how should we think about, just for modeling purposes, where your rig count is now and how that's been allocated across the different areas as it relates to the type curves we should be using, because clearly, if everything is getting done on 17, 18-stage fracs, when are the marginal growth rates going to continue to move up?
Steve Mueller: I'm not sure I'd count rig count per se because we're getting better on how fast we're drilling the wells and we're cutting that time down, but I would think that as you look out in the future, at least near term, this year, we've said it would be around 100 wells and next year, we'll be in that roughly same number range, maybe a little bit more, 110 or 120, but that'll be the range that you're looking at next year on what we're doing.
And obviously, if we're getting 20% better wells and 20% more wells plus, we need to have more takeaway. And as Bill said, we're working on the takeaway too and as we get that takeaway, we might be able to go a little faster. I would assume that would be a late 2014, early 2015 at the earliest type of event though.
Doug Leggate: So Steve, let me be a little bit more specific -- so what I'm getting at is the well count is very helpful, but are those wells going to be designed on the larger frac stages? In other words, should we be looking at the bigger type curve or how should we be thinking about that?
Bill Way: We've been studying the spacing on these frac stages across the piece and we really believe that in Greenzweig and Range areas, so Bradford, Susquehanna County, we look like we're closing in on about a 240-foot stage spacing. In Lycoming, it's a bit further and we still have some work to do, so we're studying it in really in this broad range of 200 to 300 across Greenzweig and Range, but think we've landed about where we are.
We ought to have, by the end of the year, sufficient wells drilled in the Lycoming area too to better hone in on an exact spacing. We think some of the numbers that we've heard out in the industry of 600-plus are a bit too far apart, so we're honing in on that sort of 500 area. A lot of our drilling this year forward is in Susquehanna and Bradford in addition to the drilling that we talked briefly about on the acreage we purchased, but we do have wells planned in all the areas for the remainder of the year.
Steve Mueller: And I think to put a little more color on that, the areas we're in, Lycoming, the Susquehanna that we've drilled to date, and Bradford, you're probably around the 5,000-foot lateral on average. It's going to be a little bit longer in Lycoming and that 16 to 18 stages is probably where you're at.
We hesitated a little bit and we're now going south, and the geology gets a little more complex. We just don’t know if we can average for lateral lengths down there, and there will always be a spot where they’ll have a 3,000-foot lateral and you'll have lesser stages because of the lateral. But just going back to your question, which curves to look at, that 16 to 18 stage is what you want to look at.
Doug Leggate: That's what I was looking for. Thanks, Steve.
Operator: Our next question comes from Dave Kistler with Simmons and Company. Please proceed with your question.
Dave Kistler: Looking at the Marcellus a little bit as well, most recent well's 600 foot kind of increase in lateral lengths and call it 4 additional stages, if I'm just comparing the averages you gave us on the call between full-year '12, and first half of '13, cost down about $400,000 despite the longer laterals and more frac stages.
Can you break that down for us in terms of the cost benefit that's been driven by efficiency gains versus service cost declines versus maybe change in well designs, profits used, things like that?
Bill Way: I think to kind of break it down in some large chunks, and I can get some very specific details to you if we need to, we have frac costs having come down significantly. Our original frac stage or frac contract has some supplemental fracs added to it because of increased activity. So the cost per stage of frac has dropped rather significantly.
We are seeing faster drilling times, as we ramp up activity and get into the more manufacturing-type mode that we enjoy in the Fayetteville Shale. And so drilling times have gone from 16, 15 days down to 11, 12 days, which is putting a lot of downward opportunity for us to capture on just the days to drill. That is offset by these denser fracked wells. And so bottom line, you end up with kind of a summary. But the large chunks are faster, more efficient drilling, lower cost per unit on the fracture stimulation, offset by higher density fracs.
Dave Kistler: Okay.
Steve Mueller: And I'll just add, one thing on the fracs themselves, we are doing those a little bit different. Like a lot of the industry, we're putting more sand than we did probably a year ago, putting as much as we can into it. So we continue to adjust the amount of sand. But the actual frac itself hasn't changed much, other than that.
Dave Kistler: Okay. Appreciate that. And then in the CapEx increase, there was about a $50 million increase to corporate and other that you guys didn't address as you were walking through. Can you guys give us additional color on that?
Steve Mueller: I'll tell you what. Save that question for next quarter, and we'll talk about it in detail next quarter. It basically has to do with some equipment that we want to buy, but we're in negotiation stages. So we'll just talk more about that later.
Dave Kistler: Okay, great. Thank you, guys.
Operator: Our next question comes from Charles Meade with Johnson & Rice. Please proceed with your question.
Charles Meade: I'm curious, the incremental CapEx that you have for the acreage you acquired, is there one county in particular where that is going to be directed? And I guess I'm particularly interested in if you're going to drill a well in Wyoming County in '13.
Steve Mueller: The one we're trying to permit first is in Wyoming County, and that would be, at the best, middle of fourth quarter. But that's where we're shooting for first.
Charles Meade: Got it. Thank you. And then going back to the Range Trust area and the graph that you guys have in your press release. I'm curious, can you talk a bit about what kind of gathering line pressure you're currently producing against and what gathering pressure you'd like to see in a mature gathering system?
Steve Mueller: Bill addressed a little bit of that in his conversation about putting on compression. And anywhere that we don't have compression, which I would say is about two-thirds of the production we have right now, we're flowing against basically 1,100 pounds, 1,100 to 1,200 pounds. Ultimately, this field will be probably be 100 pounds. But when we talk about putting on compression today, we're talking about going down to about 400 pounds.
Bill Way: They're 2-stage compression.
Steve Mueller: Yes, it'll work its way down. So you'll see us talk over the next few years in getting everything down to 400 pounds, and then you'll see another group of that come back later.
Charles Meade: All right. Thank you for that detail. That might be enough to do some kindergarten-level fluid dynamics or something like that. Thanks for the question.
Operator: Our next question comes from Arun Jayaram with Credit Suisse. Please proceed with
your question.
Arun Jayaram: Steve, was wondering if you could maybe give us your thoughts longer term on basis differentials out of the Marcellus, realizing that you largely addressed this through your firm. But just wanted to get your thoughts on it. And do you think, for companies who don't have firm, we could see kind of a seasonal type of market in the shoulder season, somewhat like we saw the Rockies back in the day. So just wanted to get your thoughts on what basis could look like over time.
Steve Mueller: I think for the next few years at least, it's going to be very volatile. And depending on where you're at and who's putting what into what lines, you could have big swings. We've seen it several times in the last year and a half, and I think it continues for the next few years.
Ultimately, everything we've done says that Marcellus fills up the northeast and has to go back to the south and Midwest. If it starts going back in the south and Midwest, it's competing with gas that's already there. And so that differential has to ultimately get more into national-type differential range.
So I don't know what the exact timing is. Is that 3 years out or 5 years out? But what we use for a differential out to about 3 years going out, is a minus $0.22 to $0.23, to NYMEX average. So I think you're going to see a lot of bouncing around, but it's heading towards that direction.
Arun Jayaram: That's helpful. And just as you've added some firm transportation, I just wanted to see if you could talk about the competitive dynamics. How expensive is it to get the firm transportation out of the basin?
Steve Mueller: Well, the firm that we announced yesterday really is not firm, it's gathering capacity to get us to the firm. And then we had just a small amount of firm we talked about in our press release, and Bill talked about.
There's plenty of people who want to build pipe, and there are some projects that still are not fully subscribed. And really, while there's several companies talking about needing it, we haven't seen upward pressure on the cost of that firm at all, just because there's a lot of people who build, if someone starts pushing prices up.
So I don't know that there's a reason to believe that that'll go up significantly over any period of time here.
Arun Jayaram: Okay. And just my final question, Steve. You talked a little bit about the Brown Dense, as well as the Bakken. What are your future thoughts on New Ventures from here? And could M&A come into the picture in terms of adding another area outside of the Marcellus and the Fayetteville?
Steve Mueller: You kind of asked a 2-part question there. I'll start with the M&A part. We actively look at various kinds of projects and we look at areas all the time. And our M&A, from
our standpoint, is an extension of our exploration, in that what we're looking for, it may be an area that we'd like to get into and you can't get into the conventional leasing, but you might buy some production to get into it or somehow figure out how to start, get a seed point, then grow off that seed point.
So we're looking all the time. And the classic case of doing that was the acquisition we did in the Marcellus, where we could do a bolt-on in an area we want to continue to expand in.
On the exploration side, we believe strongly in the exploration component that we have. We'll continue doing exploration, and you'll have some projects that work and then you'll have some projects that don't seem like they're going to work. And certainly, the Bakken, we said is in that category. All the other ones that we're working on today, we think we can still make it work, and we'll figure out if it can or can't, as we go through.
So we're excited. I think, I said this several times. We've got about 1.3 million acres, not counting New Brunswick, that we're working with, that would be what I call the normal exploration thing to expect from us. And going forward for the next, at least 3 to 4, 5 years, expect us in that 1.3 to 1.5 million acre range. Some won't go out of the system because they're successful. Some will go out because they're not successful, and we'll keep adding to it.
Arun Jayaram: Thanks a lot, Steve.
Operator: Our next question comes from David Heikkinen with Heikkinen Energy Advisors. Please proceed with your question.
David Heikkinen: Just kind of a very specific question, as most have been answered. Your wells in the Marcellus, per quarter, have bounced around a little bit, as you've got pads coming online. Can you give us an idea of the number of wells you'll put on production in the third quarter and fourth quarter? And then, does that ever get kind of load leveled at a flat level or does it kind of bounce between 20 and 30?
Bill Way: Our expectation is that we'll continue at about probably 25 wells. We're going to put on 100 wells this year, or maybe a couple more. You look forward to how that balances out. In the sort of Bradford County area, we'll get about 35, 37 of those. The Range area will get about 55 to 60 of those. And then we will schedule the remainder across the piece.
And so you'll see us, again, not change our total more than I announced, and we'll just stay on sort of this pattern. The first quarter was a little bit lower, second quarter was a little bit higher, to catch back up. And you'll see us kind of do that, be in that range.
David Heikkinen: And just a follow-up on that. Is there pipeline capacity and already run to the Chesapeake acreage? Or is that something that is in the roughly $50 million of capital that you added?
Bill Way: In the Susquehanna area where we have overlap, obviously, in the interest that just joined up with ours, any of that opportunity is covered by our transportation capacity. Out and
about in the Tioga and some of the other areas we're evaluating, there are some existing transportation arrangements and there are some that we have yet to work through. But we're still in the evaluation stage on that, and that'll be part of the timing of where exactly we drill.
David Heikkinen: Okay.
Steve Mueller: And, David, one of the reasons we're drilling in Wyoming, there is a pipeline down there that we think we can get into. And Bill mentioned Tioga. The Penn-Virginia line goes right through our acreage in Tioga, and we already have some capacity on that line, and we're looking at how to get some more capacity and some more firm takeaway out of there.
So those, Susquehanna and Tioga and Wyoming at least have some basic infrastructure. When we start talking about the other acreage, like in Sullivan County, you're going to have to build some pipeline takeaway there. So our first wells in those areas will be more trying to figure out what's there, so we could justify pipelines.
David Heikkinen: Okay. Thanks, guys.
Operator: Our next question comes from Biju Perincheril with Jefferies. Please proceed with your question.
Biju Perincheril: Couple of questions. It looks like the Blaine-Hoyd well, the declines are maybe not as severe as you had initially feared. Does that change how you're thinking about the well design in terms of lateral length and sort of the frac density?
Bill Way: It instructs us, I think is probably the best way to say that. We wanted to try to test sort of some end members of frac density, a combination of that, flow methodology, and frac design. That has given us one of those. We'll continue to look for opportunities. In fact, I think we have another one planned for another, what I'll call high-rate test or high density, high flow rate, number of those methodologies, and we'll continue to put that into our thinking.
Right now, as I said before, I think we're happy with the sort of 240 stage spacing, although we're not final, that certainly instructs us. Lateral lengths are governed by a couple of things. One, just economics and opportunities to extend them. And, certainly, we are doing that. The other piece of that unit is geography. And you'll see us drill different lateral lengths in some areas, just depending on unit size.
Biju Perincheril: Okay. And do you have an early read on what the EUR might be for that well?
Bill Way: Not really. We're still pretty early in that. But as we figure that out, we'll get back to you on it.
Biju Perincheril: Okay.
Steve Mueller: It will be a significant --
Bill Way: It'll be bigger.
Steve Mueller: It will be significant. And I've said this in the past, we do have some 15 Bcf wells already on our books. And this one with the longer lateral and the tighter perforations, is going to be well above that.
Biju Perincheril: Got it. And then question on the well cost. You talked about well cost coming down in the Marcellus. But when I look at sort of CapEx per well, in the latest guidance versus the initial guidance, it moved up a bit. Can you see what that difference is? Is that a more facilities cost or new areas?
Bill Way: You'll recall from, compared to previous quarters, our average stage, our average number of fracs is moving up. So it'll work into the average. And as we get more consistent around 17 stage fracs, that's where you'll see the variance in well cost primarily. We're drilling under contract with half of our own rigs and half of third parties', so those costs are fairly fixed and understood. Again, incremental fracs too, our sort of base frac contract in Marcellus are at a much lower level, and that number is also well understood and agreed.
So a lot of that will just depend entirely on sort of the mix and lateral length and number of stages for a lateral.
Biju Perincheril: Okay. Got it. Thanks.
Operator: Our next question comes from Gil Yang with Discern Investments. Please proceed with your question.
Gil Yang: The LOE went up and you cited the increased compression/gathering cost to the Marcellus. Are any of those costs due to capacity that you're paying for that you're not fully utilizing, maybe transportation in there? Or is that a trend, a cost trend that we should expect to see as Marcellus grows?
Steve Mueller: No, it doesn't have anything to do with capacity we're not using. I will say on the Fayetteville Shale there's some capacity that we are not using. But that would be under the transportation side that you'd see it, and it's about $0.07/Mcf right now. On that LOE the basic difference is we have an escalator clause with our gathering company and you had a little bit of an increase on escalation this year on that portion of it.
And then, because of gas price, basically the compression gas that you use in flu was up a little bit also. And those are your two major areas.
Gil Yang: All right.
Bill Way: And also included in that is the mix of gathering cost as we ramp Range further and further along, that gathering in that area is slightly at higher cost than the Bradford County area.
Gil Yang: Got you.
Bill Way: Part of it.
Gil Yang: And the second question I have is, based on the mix of wells you're drilling and areas you're drilling in the Fayetteville, can you sort of predict where your Fayetteville well costs are going to be trending for the remainder of the year?
Bill Way: I think that you'll see the costs probably right around where they are. Couple of things of note that might tweak that a little bit. The external or third-party completion contracts that we have, have a gas price trigger in them. So, as gas prices go up, and if we saw a quarter -- and this is a look-back quarter, so that's when it happens -- you see gas prices go up. There's an adjustment that will increase, potentially increase the cost of that.
At the same time, we continue to drill faster and faster. And so our own pumping company takes on more and more of the frac rather than -- so that's sort of an offsetting increase and could bring them back down. But we think that the $2.3 number is a pretty reasonable number going forward, with all those moving parts.
Gil Yang: All right, great. All right, thank you.
Operator: Our next question comes from Robert Christensen with Canaccord. Please proceed with your question.
Robert Christensen: Thank you. As you left it, I think, last quarter you were seeking to buy firm transportation up in the Marcellus from those that had basically slowed their drilling effort. I just wondered what the markets, or the secondary market, of FT looks like to you guys right now.
Steve Mueller: One of the things we were doing at the end of last quarter, which we've done, is make sure that we had insurance on a line called the Constitution line that's supposed to be in in 2015. We wanted to make sure that we had firm, that if that line got delayed we didn't have to delay anything we were doing. We've done that. We've got that in shape.
We also wanted to fill in some holes in 2014 and then some holes we had in 2015. Most of that is done. We've still got a little bit more to do.
And so, part of the answer is when you look at 2014 and 2015, there are small pieces you can buy from various places and fill in the holes. When you start looking and say I want to have a layer of 50 million or 100 million a day and I want it for four or five years, that is a really tight market. And there's a little bit, as I mentioned, that -- so projects that are either on the drawing boards or will start next year or on the tail ends, we're doing the work and we can get a little bit from. But certainly we're going to need some more pipe out of the area and we're going to have to commit to some of that pipe as it goes through. We're trying to figure out who that is we commit to and do that relatively quickly so some lines can get built.
Robert Christensen: My second question relates to the Sharp well. That well in the Lower Smack, touched down in a high pressure area. I mean, it was six, seven miles away from where
you had been drilling.
Bill Way: Hello?
Robert Christensen: Yes, I was questioning -- we're all trying to understand the areal extent of high pressure.
Steve Mueller: Yes, let me just give you a little perspective. As you said, it was six or seven miles away from what we had drilled. It's about six miles from a well that a private company drilled and put on line earlier this year. That well is a vertical well and there's a long story behind it. Basically, it's going to be a commercial well out of the Brown Dense. So we drilled half way between our production and their production. We did have high pressure in the well that we drilled, in the Sharp well. And as we said, they fracked, went -- tried to cross the entire vertical interval. We fracked the lowest amount of that -- in the production rates we talked about that 125 barrels a day, just on that first of four stages of fracs.
Robert Christensen: Got it. Thank you.
Operator: Our last question comes from Andrew Coleman with Raymond James. Please proceed with your question.
Andrew Coleman: Good morning and thanks for taking my call.
I had a question more about the compression issues that were brought up earlier on the Fayetteville. When you look at the reserves that were, I guess, compared at the end of last year, how much of that was a result of the compression needs there in the field?
Steve Mueller: I'd say zero. It's really not a compression issue. We're talking about that LOE being up a little bit. You have to run the compressors. And so if gas price goes up a little bit, that feed / run on the compressor -- I mean, the gas you use there on the compressor goes up a little bit. So we'll always have that. Hopefully that number goes up quite a bit because gas price went up quite a bit.
Andrew Coleman: Okay. Perfect. And then, up to the Bakken, I guess given the well result up there, how (inaudible) I guess stop that program? Or should we be looking to impair any of the acreage you have up there? Or is that -- or (inaudible) going down the road?
Craig Owen: This is Craig Owen. We'll conservatively explore our options, as was mentioned earlier. As a full-cost company we don't have impairment by play. We kind of analyze that as -- in a total pool basis. And that will continually be a part of our full costing we test every quarter.
Andrew Coleman: Okay. And have you disclosed the total amount of the spend you have on acreage up there?
Steve Mueller: We have not.
Andrew Coleman: Okay.
Steve Mueller: But it's roughly $100 million.
Andrew Coleman: Okay, so a small amount. Thank you very much.
Operator: There are no further questions in queue at this time. I would like to turn the call back over to Mr. Mueller for closing comments.
Steve Mueller: Thank you. I started the conversation today saying I'm excited. Hopefully you could tell why I was excited as you went through the call and you saw our press release today.
Our strategy is to provide ongoing value to our shareholders. And we really concentrate on trying to do something that the others can't. And we think that's important to being in the business. And so we challenge ourselves every day to consistently make better decisions. We want to learn faster. We continually ask how we can develop our fields wiser than anyone else can and then we drive innovation throughout the Company.
That's the real thing I'm excited about. The numbers are great, but we continue to innovate. We continue to learn. And that innovation takes several forms. The one we really look at is that incongruity, the anomaly, that small little hint that leads things like the Fayetteville and the new Marcellus plays.
And I think this quarter shows progress in all kinds of innovation. It shows progress in all of our drivers. And as a result, we hit new heights in many of our key metrics. I think the shareholders deserve nothing less from us and I'm excited that next quarter we should even see more of that.
This year's already provided significant upward revisions to our plans. And as we look at the next quarter I'm excited, again, to talk more to you about how we've even added more value.
Thank you for listening today. Have a great -- certainly for the ones listening in Houston, but across the US, have a cool weekend.
Operator: This concludes today's teleconference. You may disconnect your lines at this time and have a wonderful day.
Explanation and Reconciliation of Non-GAAP Financial Measures
We report our financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, management believes certain non-GAAP performance measures may provide users of this financial information with additional meaningful comparisons between current results and the results of our peers and of prior periods.
One such non-GAAP financial measure is net cash provided by operating activities before changes in operating assets and liabilities. Management presents this measure because (i) it is
accepted as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.
See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the three and six months ended June 30, 2013 and 2012. Non-GAAP financial measures should not be considered in isolation or as a substitute for the company's reported results prepared in accordance with GAAP.
| 3 Months Ended June 30, |
| 2013 | | 2012 |
| (in thousands) |
Net income (loss): | | | |
Net income (loss) | $ 245,631 | | $ (405,132) |
Deduct (add back): | | | |
Impairment of natural gas and oil properties (net of taxes) | -- | | (496,370) |
Unrealized gain (loss) on derivative contracts (net of taxes) | 55,954 | | (51) |
Adjusted net income | $ 189,677 | | $ 91,289 |
| 3 Months Ended June 30, |
| 2013 | | 2012 |
| |
Diluted earnings per share: | | | |
Net income (loss) per share | $ 0.70 | | $ (1.16) |
Deduct (add back): | | | |
Impairment of natural gas and oil properties (net of taxes) | -- | | (1.43) |
Unrealized gain (loss) on derivative contracts (net of taxes) | 0.16 | | -- |
Adjusted net income per share | $ 0.54 | | $ 0.27 |
| 3 Months Ended June 30, |
| 2013 | | 2012 |
| (in thousands) |
Cash flow from operating activities: | | | |
Net cash provided by operating activities | $ 505,414 | | $ 392,727 |
Deduct (add back): | | | |
Change in operating assets and liabilities | 12,777 | | 38,200 |
Net cash provided by operating activities before changes in operating assets and liabilities | $ 492,637 | | $ 354,527 |
| 3 Months Ended March 31, |
| 2013 |
| (in thousands) |
Cash flow from operating activities: | |
Net cash provided by operating activities | $ 372,138 |
Deduct (add back): | |
Change in operating assets and liabilities | (54,114) |
Net cash provided by operating activities before changes in operating assets and liabilities | |
$ 426,252 |
| 3 Months Ended June 30, |
| 2013 | | 2012 |
| (in thousands) |
E&P segment operating income: | | | |
E&P segment operating income (loss) | $ 252,546 | | $ (718,277) |
Deduct (add back): | | | |
Impairment of natural gas and oil properties | -- | | (800,652) |
E&P segment operating income excluding impairment of natural gas and oil properties | $ 252,546 | | $ 82,375 |
