Feb 24, 2017
Executives
Michael Hancock - Director of IR Bill Way - President and CEO Craig Owen - CFO Randy Curry - SVP, Midstream Jack Bergeron - SVP, Operations Paul Geiger - SVP, Corporate Development
Analysts
Charles Meade - Johnson Rice Tim Rezvan - Mizuho Securities Arun Jayaram - J. P.
Morgan Jeffrey Campbell - Tuohy Brothers Brian Singer - Goldman Sachs Kashy Harrison - Piper Jaffary Dan McSpirit - BMO Capital Markets
Operator
Greetings, and welcome to Southwestern Energy Company’s Fourth Quarter 2016 Earnings and 2017 Guidance Teleconference Call. At this time, all participants are in a listen-only mode.
A brief question-and-answer session will follow the formal presentation. In the interest of time, please limit yourself to two questions.
Afterwards, you may feel free to re-queue for additional questions [Operator Instructions]. As a reminder, this conference is being recorded.
It is now my pleasure to introduce Michael Hancock, Director of Investor Relations for Southwestern Energy Company. Please go ahead.
Michael Hancock
Thank you, Melisa. Good morning and thank you for joining us today.
With me today, are Bill Way, our President and Chief Executive Officer; Craig Owen, our Chief Financial Officer; Randy Curry, our Senior Vice President of Midstream; Jack Bergeron, our Senior Vice President of Operations; and Paul Geiger, Senior Vice President of Corporate Development. If you've not received a copy of last night’s press releases regarding our fourth quarter 2016 financial and operating results and 2017 guidance, you can find a copy on our Web site at swn.com.
Also, I’d like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes. Many of these 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. We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers.
For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our Web site. I’ll now turn the call over to Bill Way to discuss our recent activity and our plans for 2017.
Bill Way
Hello everyone. We appreciate all of you joining us on the call this morning.
I want to begin by sincerely thanking all of our employees across the country who came together and pivoted from some extremely difficult times and drove improvement in every aspect of our Company to deliver on the commitments that we’re going to talk about today and for 2016, and set the Company up for greater success in ’17 and beyond. I'm excited to be joined the room by members of Southwestern' leadership tem as we discussed our latest results, and the growing momentum we have built through 2016 to capture the opportunities ahead that are all around us and this year and beyond.
We made some bold decision and took some decisive actions in 2016, which allowed us to deliver on each of the commitments we made during the year, including the key priorities of capital discipline and a stronger balance sheet. So, as you saw in last night's release, the commitments are enduring and form the foundation of how we are moving forward.
Our 2017 capital plan is again aligned and within expected cash flow, which includes the remaining $200 million of equity raise in '16. We have arrested our production decline and have pivoted to a trajectory of value adding growth in 2017 with further opportunity, including the potential for economically driven double-digit production growth in 2018.
Given our lucrative vertically integrated business model, we are agile enough to flex our capital and response to market changes, while capturing the best economic contributions from our portfolio. Our capital plan for 2017 is expected to be in the $1.175 billion to $1.275 billion, again to be invested within cash flow and in accordance with our strict economic parameters.
This playing of economic growth opportunities is expected to deliver strong growth of approximately 17% in our Appalachia assets and 3% total company growth using the midpoint of production guidance. An exciting turn from last's year's decline due to significantly reduced activity.
This growth includes an exit-to-exit production rate increase of approximately 20% for the Company. Looking beyond 2017, the portfolio is expected to deliver double-digit growth in 2018, assuming a capital plan based on strip pricing and again investing within cash flow.
This substantial growth, when factoring in our position as one of the nation's largest producers and the size of our base volume from our vast core assets, is a tariff path forward. Capital allocation is based on individual project economics and prioritize based on returns against strip prices.
In Northeast Appalachia, we expect to run two rigs with the majority of the activity centered on our core Susquehanna County acreage with additional delineation testing throughout other portions of our acreage. In Southwest Appalachia, we anticipate running two rigs throughout the year, primarily drilling in the rich gas window of the Panhandle of West Virginia, targeting highly economic wells from our enhanced operational results and increased liquid pricing.
Additionally, in this area, we are very encouraged by the early results of our first Utica well and as a result have accelerated the timing for our second test well located in Washington County Pennsylvania, which was spud earlier this month. And you will recall that we had originally planned to begin our Utica testing in 2018, but results from wells and circling our position and our first well, provided us with the confidence to accelerate this activity.
In the Fayetteville, we are focused on several emerging opportunities within our acreage, and our activity in 2017 will advance our learnings on a number of fronts, including additional benches in the play. Part of this plan we will be to further our understanding of the high potential Moorefield and its stability to drive margin expansion in our asset.
We also are testing additional promising Fayetteville intervals. Success here and any other improvements in economics would only add to the economic and strategic benefit that the Fayetteville provides to the Company today with its cash flow generation capability and the optionality the core asset provides within the portfolio to allocate capital based on market dynamics.
To capture these learnings, the capital program includes one rig running throughout the year in the Fayetteville. As we execute this plan, our laser focus on margin expansion will continue to be a key priority as we identify additional operating efficiencies and to improve well productivity to enhance returns.
We are working to build on the realized savings in 2016 as we successfully adjusted the Company to excel in a lower for longer commodity price environment. Many of these savings are sustainable and each team continues to add even more to the bottom line for 2017.
These reduced cost coupled with improved commodity prices and a full-year of uninterrupted drilling and completion activity in 2017 is expected to have a material impact on future reserve bookings. As reserves utilize the 12-month look back on pricing, the average NYMEX used for our 2016 reserves was 248 per MMBtu.
Given the current price environment and assuming strip pricing at December 31, 2016, we estimate we would have the ability to book approximately twice as many reserves and add an increment PB10 value of $3 billion to $4 billion. In addition to our E&P assets, our marketing portfolio is also driving value, taking advantage of its optionality and maximizing price realizations based off of market dynamics.
Our view of basis is improving with the addition planned activity and the capacity that’s being built and that view is solidifying as we expect differentials to improve over the next two years as pipeline capacity is placed in serviced. So as you can see, we have tremendous opportunity ahead of us in 2017 and a plan that captures those opportunities.
Now let me turn over to Craig to discuss some of our financial highlights.
Craig Owen
Thanks, Bill, and good morning, everyone. As you saw in last night’s release, based on the hard work and dedication of the entire SWN team, we ended 2016 in very good shape financially.
At year-end, we had a cash balance of 1.4 billion and revolving credit facility capacity of $800 million, of which the $174 million was utilized for letters of credit. Our efforts throughout the year resulted in our net debt balance being reduced by approximately $1.5 billion from the end of 2015, exiting the year with only $316 million of debt due prior to 2020.
With our commitments to realizing expected returns on our investment program, we achieved our targeted hedging levels as we entered 2017. We currently have 516 Bcf of our 2017 gas production hedged with almost half of these positions being collars, providing upside exposure to improving prices.
We also have 272 Bcf of our 2018 gas production hedged predominantly with collars, and a smaller hedge position with 2019 gas volumes. Consistent with our strategy, we expect to continue adding to these hedge positions as we move throughout the year.
These hedging activities will help us achieve our expected returns, providing downside protection, while also retaining upside potential as prices improve. As Bill mentioned earlier, our relentless focus on margin expansion was a key driver to value creation in 2016 with our lease operating cost decreasing $0.05 per Mcfe when compared to 2015, which includes the 24% reduction in Southwest Appalachia.
We also achieved well cost savings, particularly in our Appalachian assets, while driving increased well productivity. We expect minimal service cost inflation in 2017, largely as a result of our vertical integration.
I will now turn it over to Jack to discuss some of the details of our operational update.
Jack Bergeron
Thanks, Craig. Good morning, everyone.
We ended 2016 in a very strong position, achieving the top-end of our production guidance while making strong progress on a number of our testing initiatives. First, in Northeast Appalachia, we continued testing our tighter stage basing, increase sand loading and optimize flow techniques.
This work added significant value with material improvement over prior wells. One example is our Cramer pad in Susquehanna County where five wells were placed online with a total initial production rate of 92 million cubic-feet per day.
We are positive these actions are bringing value forward and improving economics and capital efficiency of our investment program. We also fill they will increase the EUR's, although at this time, it's too early to quantify the increase.
We also expanded our testing footprint on our core assets. We progressed our delineation efforts in Northeast Appalachia, testing our acreage in Tioga County.
Initial infrastructure was installed and first production commenced there in early January. The well results confirm the productivity of this acreage, and we’ll have additional activity in this area throughout 2017.
In Southwest Appalachia, the high profit completion test discussed on the last call were successfully completed with one well being completed utilizing 5,000 pounds of sand per foot and others utilizing 3,500 pounds per foot. This compares to our standard completion design of approximately 2,000 pounds per foot.
These high profit completions were successfully carried out by our operations team. We continue to test the technical limits of getting sand put away.
These wells were just recently placed online. And as we've said before, we don’t have enough flow history to provide clear conclusions at this time.
We should be in a position to discuss the results of these on our next call. Testing also continued in our Fayetteville area where we tested increased profit completions through the fourth quarter.
Early data suggests there, there is an average uplift in production volumes from these wells of approximately 30% over their offsets. The team will continue to monitor additional well data as they determine the optimal level of sand to use in order to maximize our well results and our economics.
Delineation efforts also continued in Moorefield where eight wells were drilled in the fourth quarter, seven of these wells are scheduled to be put online in early March. And we expect to be able to share the results of these wells on our next call as well.
The potential of the Moorefield has encouraged this about our ability to deliver enhanced economics and compete with capital within our portfolio. We would now like to get your questions.
So we’ll be able to turn it back over to the operator, who will explain the procedure for asking questions.
Operator
Thank you. We will now be conducting a question-and-answer session [Operator Instructions].
Our first question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question.
Charles Meade
If I go to the comments, I think you made in the press release about the double-digit production growth in 2018. Are there other important variables in that outlook beyond the natural gas price that we should be thinking about?
Bill Way
Not really. I mean, I think what we do is we take our hedging strategy, we take strip pricing, we combine those together and put them to our model to generate cash flow.
Depending on where the price, that actual strip pricing is, we look at two things; our economic model for the whole enterprise; and our individual investment criteria for individual projects. Because you'll now that we force rank our projects, highest PDI down, and then we invest within the cash flow that is generated from that model.
I think if there is a variable to 2018 and it's the same variable that has existed since we entered into West Virginia, is where you drill. We've seen a very strong improvement in NGL pricing.
Our flow regime and flow practices on wells in West Virginia optimize around both production and the generation of NGLs and liquids. And so we take that into account as well.
But our basic thesis of investing within cash flow and assuring ourselves through our hedging program is that our economics of the enterprise and our economics of individual projects thrives those. We are able to be very flexible, because of our vertical integration, but it will be very flexible because we have those items of financial discipline in front of us and it's about economic value generation, not just the production growth to grow production.
Charles Meade
So are we right to interpret that as the strip, as the 18 strip is as we sit here this morning is right around 292, so it's validate that, call it, mid-290?
Bill Way
That is correct. As you would know, we begun -- we continue -- our hedging strategy and hedging program is a rolling three year strategy and implementation plan.
And so as we work through this year, we've already begun doing a bit of hedging limited as it is at this point into 2018 and 2019. Again for two reasons, or many of the reasons; one of -- couple of which are we will assure ourselves that the returns that we’re projecting we’re going to get and we will manage that -- the volatility of some of those issues by putting on the appropriate level of hedges.
Charles Meade
And if I could just sneak one more in, I'm guessing on the Utica test, did you guys -- I just wondered, if you could give us a rate, you would have, so since you didn’t. Is there anything goes you can talk about on that well and what gave you the encouragement to accelerate your spud?
And when we might -- or when you might be in a position to want to share what you guys think the potential there is?
Bill Way
And Jack may have some specific comments he wants to make. But let me say upfront, and I've said this insight I got here is that, we can bring wells on, especially wells like this that are heavily latent with different testing protocols and trying to figure out exactly what we have.
And we can search flow wells and it all looks really great. We don’t do that.
We want to have enough credible information from having ramp the well up, getting the data from all of the technical or technology related investment we made so we can give you a solid picture. The additional flow rates that we modeled in AFE are being met or achieved or exceeded, and that gives us the confidence to continue to press forward.
The other piece of that is that we've got a lot of activity going on around us. And so studying that learning from that we’re able to make -- take that further step.
And as you watch and look and listen to the program over the course of the year, we're going to take a determined but measured approach to this. We have the opportunity to put one or two more tests on throughout the year.
But we are in that mode of testing, learning, and then trying to be as clear and transparent as we can with you all around when we put that data out there. You can take some confidence in the fact that we're going to do another one.
But I really want to have the facts as we know them out clearly before we go from there.
Operator
Thank you. Our next question comes from line of Tim Rezvan from Mizuho.
Please proceed with your question.
Tim Rezvan
My first question is on the guidance that you put out for 2017, as well as the initial comments about 2018. Should we think of those guidance I'm trying to put that to the scenarios you put out last fall in a slide deck about multi-year production growth CAGRs.
Should we think of that as the middle scenario there that 8% to 12% production growth CAGR that you discussed last fall?
Craig Owen
And I think that’s fair. I think that middle tier for 2018 was $1.25 billion capital programs.
So again, as Bill mentioned earlier, our capital investment will be dictated by cash flow levels. So, it’s a model that we put out there and provide some guidance.
We’ll invest at levels of cash flow, no harm to the balance sheet. But may be one way to look at it is well, something we invest exactly as we’ve guided cash flow comes in to the penny.
2017 as we’d guide will be a low production, most of that production will come flush into ‘18, which will make the maintenance capital level on '18 much lower. And I think we talked about in the past of '17 and '18 maintenance levels with '17 being roughly $700 million and then '18 stepping up from there.
But with the '17 program as we’ve guided, the '18 maintenance level really steps down through $500 million to $600 million for 2018. So, probably give you ranges around gross from maintenance level to gross, but that middle ground of that slide in our IR deck is about right and may be on today's pricing a little high from what cash flow would provide at a flat production level, but somewhere in there can be dictated by cash flow.
Bill Way
And just to underscore, again, whatever number is on there it will flex with our gas price and our ability to hedge according to our hedging strategies. We will maintain that rigor through time.
Tim Rezvan
And so my second quarter, if I could hop on the EBITDA again. I believe you said your second test is going to be in Washington County.
You don’t have a lot of acreage in Pennsylvania. Is that stepping out to the east, is that a delineation driven decision?
Or can you talk about how just thinking about the first few wells and where you spud them?
Craig Owen
I think we look across our acreage and look for ways to triangulate a testing program that can give us the best picture of our -- the expanse of our acreage, and look at geological and subsurface characteristics and our estimation of those same things in adjacent acreage to ours. And so, we also have to take into account obviously that we have a dry gas outlet in that place.
And so drilling well in an area where there isn’t any dry gas outlet means that you’ve got a flairs tested or you don’t flow at all. And we’re all about margin and not economics.
So the sooner we can get it going the better. And I would imagine there maybe some, as there also is.
There is no message in this other than sometimes you have lease holding opportunities to capture as well. So, that’s what drives that.
But even the current Utica well we have, we’re very mindful of every piece of this economic driver puzzle and we were able to negotiate a gathering agreement on that one well, actually through a wet gas system but at a dry gas rate to let us of test that. So, it's a very integrated comprehensive view and both the sub surface, our acreage position, the trying relation of all of those plus our mid stream and marketing side comes into play to maximize that, the potential for that.
Bill Way
And we’ll continue to do a handful more. We’ve got quite an acreage expanse and we’ve got quite a bit of Utica under that acreage.
And so we’ll continue to place those where we can eventually get to the place where we can go into more of a development mode. And as one would expect, the other piece of that equations you get your cost down.
And so we’ll continue to work that too.
Operator
Thank you. Our next question comes from the line of Arun Jayaram with J.
P. Morgan.
Please proceed with your question.
Arun Jayaram
Bill, I want to start a little bit with the CapEx, and just philosophically, just talking about the decision, last year you had to make some tough decisions and went down to zero rigs operating. And now, the capital program contemplates about 200 million of outspend versus CFO.
I understand that you did have some cash from the balance sheet. So, just want to get around that philosophical view as you approach '17 and '18?
Bill Way
So, let me start with the last year question. We walked into the year, gas prices were south and heading further south.
When we ran our economics on our individual wells anywhere, when you end up with $1.70 gas, there are no economic well locations to be going after. And we don’t have a hedging position or any certainty about the next couple of years, which is the gas price that helps those economics become reality.
The prudent and right thing to the o is to stop. And so, we did.
And as we progressed through the year, as prices recovered from, as you would well know a very significant abrupt holt by the industry in investment and prices, and the street began to rise .And our hedging program that we instituted in a formal way in early '16 began to come together .We were able to restart those. And as I said earlier, we look at the Company model and we look at the individual well-by-well model.
They both have to be get a green light before we’ll go and do that. Even with our vertical integration, again, you go down under the depths of where gas prices went, just to make sense to do that.
Now, you’ll recall when we restarted our drilling and completions, that activity was funded by $500 million equity raised capital allocations to this activity. We invested about $300 million of that, and then carry forward in projects that are ongoing and other activity carry forward of that into 2017.
And so that all the teams are very clear. We keep all this allocation and capital in very clear bucket, so nobody is going to the balance sheet and looking on the balance sheet and saying oh there is cash flow there, why am I using that, because it's not for that purpose.
We had capital allocated for drilling and completions, $500 million we bought $200 million in. So the $200 million out what appears to be $200 million outspend, not that at all.
It is the carry-in from last year. And then the cash flow, based off of our projections of gas price supported by our hedge program and that activity is supported by the next three years’ view really of gas prices.
And remember it takes more than one year for investments to pay out. And so, we watch that.
We just to be clear, as we've been working on the budget now for several weeks and probably our finance guys maybe several months, and we made a change just recently and pulled back of it because we saw the trend for gas prices to -- were coming down versus the model that we have produced. And so, we’ll continue to watch that.
Our ability to flex is present, obviously, because of our vertical integration. And so, really if you take a look at our budget or what we put out there in the range we put out there, and you take the forward curve and you look at that and you combine that, especially with our 2017 hedge position, then that generates a level of cash flow.
And then you take the allocated capital from the equity raise and add that to that, and that's how we got to the numbers. I'm sorry if it's not clear on -- we are not going to deficit spend, and we are not going to go on to the balance sheet and take the money that is there under our financing that we did where we had to draw on our various lines of credit or whatever.
We are -- that is not for that purpose, that is liquidity, that is part of the -- running for the Company. We will use the cash flow in a very prudent way.
And if we see a change, we will amend that up to where it is today. So, somebody could ask me later, what happens if gas goes to $4?
Well, we don’t just keep raising the capital where it is today is the upper end of that and then we have other decisions to make following that.
Arun Jayaram
Thanks for the answer. And just the second question I had regarding your commentary around your expectations that the differentials would narrow for you in 2018.
Why don’t you -- if you could give us some thoughts on what that could do versus your 2017 guidance? And how important is Rover?
I think, you have a couple of hundred million on that line. How important is that as you think about the 2018 differentials guidance?
Bill Way
Sure. Let me have -- ask Randy to step-up here and give you chat about that.
Randy Curry
If you noticed, we put a pretty wide differential forecast out there. And you kind of zeroed in on and hit the nail in the head.
Rover is going to have a material impact, not just on us but on the basin, and so it will. And there is quite a bit of variability in the assumptions on the timing.
If it comes on mid June as the Company has professed, that will have a very positive impact middle of year. If it somewhat layer, we’ll receive less of that.
So Rover is a key to the 2017 outlook and the differential in it, because it does have potential, has such a material impact. We will -- that’s really puts behind the wider range out there.
Arun Jayaram
Okay, thanks a lot.
Bill Way
And maybe I'll comment that for the crowd. We also have a basis hedging program that attempts to mitigate that volatility.
And we can talk about that later, if you want. But, everyone of these kind risks we've got a plan to look at how do we mitigate those.
And it's very methodical through each of these.
Operator
Thank you. Our next question comes from line Jeffrey Campbell with Tuohy Brothers.
Please proceed with your question.
Jeffrey Campbell
I sense it's important to the 2017-2018 story, I was just wondering if you're contemplating, beginning to hedge NGL?
Randy Curry
Yes, and we have done -- we've entered into that, particularly around that ethane. And we’ll definitely be considering that as we go forward.
There has been some uptick in the liquidity, and ethane and propane as the markets gotten deeper and the export capacity has increased. And so we want to take advantage of that.
Jeffrey Campbell
And so the question I wanted to ask. So I was just wondering if you're moving toward a stack pay test with more hit in the Fayetteville?
Or do they tend to be more perspective in different leases?
Bill Way
As far as stack pay, we are doing stack pay on some of the benches of the Fayetteville, if you want to look at it that way. And we drill from the same pads, both Moorefield and Fayetteville wells.
But there are significantly different. One wellbore we’ll not adequately be able to develop it.
We are doing, again off the same pad, we'll drill a Moorefield well and a Fayetteville well, and we’ll drill them to be able to optimize the recovery.
Randy Curry
And if we see an opportunity, as you kind move out from wherever your focus area is, and if any of these intervals or variables get then enough, we will obviously test it to see.
Jeffrey Campbell
And I think what I was thinking that was being able to produce both of the zones on the same pad, not a model bore, the thing where…
Bill Way
And we do that regularly.
Operator
Thank you. Our next question comes from the line of Brian Singer with Goldman Sachs.
Please proceed with your question.
Brian Singer
You had performance related upward revisions across each of your key areas. Can you talk about the drivers of each and any future implications?
And also, if there were any differences in Southwest PA with regards to production mix from those revisions?
Bill Way
Specifically, to the performance revision, as you look at the FTC pricing, real world pricing, you have a lot of those wells come off of the reserve deck. And so, as you go forward, there is a mechanism that brings those back on if you’ve done, they come back on, it's PDP.
And so that’s the basis of some of those performance revisions. The performance revisions we continue to see in Northeast Appalachia has to do with production mechanism that we’ve got, those wells continue by their production regime to outperform or a decline base that we’ve got in the reserve system.
And so those are the continued performance revisions that you see to the positive up there.
Brian Singer
Is there a sense of what, and maybe you mentioned of the performance revisions, which ones were essentially price revisions or which one do you -- what percent is more true performance versus just higher prices allowed to booking again?
Bill Way
Sure. The vast majority of those our performance based.
The prices were negative in period, so those were against true performance revisions to the positive.
Brian Singer
Okay.
Bill Way
Other piece of revision that we have is that you might be seeing is we had significant operating expense benefits on the performance that we’ll roll-up to a performance revision. The big driver of those, again West Virginia has to do with improve gathering processing of these that we gain at the beginning of last year.
And then we had also as the guys have talked about an aggressive assault on margin improvement there that has yielded quite a bit of success in driving cost out of our system. We are forecasting those well with that lower operating expenses of significant gain on not only additional value created and various -- and extension of tail reserves as those wells have longer lives.
Brian Singer
And then shifting back to the Moorefield, what are you looking for from the wells that you’re going to be bringing online to define success?
Jack Bergeron
Economic success, without a doubt -- our best well we’ve ever drilled in the Fayetteville is Moorefield well. As far as EUR, we’re looking -- we’ve got some very long laterals, we’re just looking to prove up areas.
We’ve moved out a few that I would call step out areas but just testing to see the economics of the play there. We’re very confident that the Moorefield works.
We’ll determine which is where to land the well optimally. And we’ve added more and more sand trying to make better and better wells just like we’ve done everywhere else; again, with the idea of creating economic value.
Brian Singer
Is there a 30 day or 90 day, or 180 day rate you’re looking for to stay or get this through the economics you’re looking for?
Jack Bergeron
We could usually tell within 100 days of production, get early indication of EUR. Initial rate does give us 30 day rate will give us the amount of water that comes back to Moorefield, generally has more water.
But we’re able to determine fairly quickly about economics and whether we’re going to expand the program based on the rates that we have after we bring wells on.
Bill Way
Brian, you’ve probably seen some of the public data we have on that. But the Moorefield, as Jack said, has outperformed our standard phase of well on rate reserves little bit higher cost, but not significant.
So, that is driving those economics. And an actually number 30 day test or 180, all this depends on where we are and what those costs are.
But drilling back to Jack's point, it's all driven by economics and whether that’s initial rate or overall value driven based on the EUR and real cost, that’s what we’re driving towards ultimately.
Jack Bergeron
And then there is a flow through improvement, because this gas gets gathered by our mid-stream business and taken on to markets. So, it's the benefits continue through all the way to the market.
Bill Way
And one of the things about having a program in the Fayetteville this year that's more extensive that really lowers our cost by able to reuse the water that does come out in these Moorefield wells, and so that improves the economics even more.
Operator
Thank you. Our next question comes from the line of Kashy Harrison with Piper Jaffary.
Please proceed with your question.
Kashy Harrison
So, with the northeast PA, you’re making solid progress on the well performance. I understand that it's too early to quantify the improvement in EURs.
But, if say you held that EUR just flat and you assumed that you’re just accelerating those reserves. Can you just help us quantify how much the value or the returns of those wells are improving?
Jack Bergeron
Well, we’ve tend to view -- this as Jack, Kashy. We use PVI as a metric and it's bringing the value forward if we got no additional reserve.
And just anywhere from $0.10 to $0.12 of PVI just by, again brining on a well that’s averaging 17 million a day versus a well that would average 5 million a day and stay flat for quite a while. The big change in EUR and partial in the rates, but even more on the EUR that we expect is the fact that we’re putting more sand, tighter states facing and touching more rocks, that's why we think the EURs -- we’re confident they will increase.
Bringing the value forward through our flow techniques again as it's accretive and it just brings value forward and helps our PVI metrics.
Kashy Harrison
And then can you just give us just your current views on the natural gas macro and the NGL macro just for everyone on the call?
Randy Curry
Sure. Kashy, this is Randy.
On the natural gas macro, clearly the 17 curve was negatively impacted by, primarily weather related influences, extremely warm winter again. That being said, I think there is an emerging consensus of this 5 million balance, normalized for weather is tightening year-over-year, somewhere in the tune 3 to 5 Bcfe a day.
And I believe there is some -- actually a reason had some positive outlook that we will go back to a storage position, maybe a middle of the year that's closer to the five year curve, and so I think it pertains some strengthening there. NGL prices on the macro level again, I think there is a positive outlook, really on the basis of the anticipated demand coming online in the Gulf Coast, and the Mount Bellevue area to the tune of 600,000 barrels a day or so.
That coupled with some of the export capacity that's come on has really lifted the NGL complex year-over-year. Our NGL realization for the first quarter of this year is going to be double with one of the quarter before or the year before.
And so with our access to the Belvieu area with the capacity out of Southwest Appalachia, we intend to right that and capture some of that uplift.
Operator
Thank you [Operator Instructions]. Our next question comes from the line of Dan McSpirit with BMO Capital Markets.
Please proceed with your question.
Dan McSpirit
You talked about reducing debt in the press release as the opportunity is presented. Could you expand on that step?
And then may be how proceeds would be sourced to do so?
Craig Owen
Dan, this is Craig. We got $40 million of bonds due on 2017.
And I think if you add up the mid-points of cash flow guidance that we've given plus that equity raise, that’s the number that’s above our capital investments. So, certainly it can be sourced from that.
But just an overall theme is we're not going to do any harm to the balance sheet on leverage or anything like that without standards or what not. So, we're going to source from cash flow and the cash we have on hand.
But that will be -- that $40 million, we can easily take care of that within our cash flow generation for the year. And then certainly we’ve got some bonds, sometime in January-February of ‘18, it comes most of them, some later in the year.
And we’ll think about those and thing about our 20's. We’ve got between bank debt and bonds.
We’ve got a lot of flexibility I guess is the point, a lot of options and how we can address that. We look at overall complex and as we go through and to the extent, we change our capital program based on economic factors.
Any of that cash flow could be utilized for debt and we’ll manage that throughout the year.
Dan McSpirit
On the PDP F&D cost, they are trending lower and that’s a good thing, obviously. Any thoughts on what should be expected on the magnitude, or does that change over time?
And maybe what that means for the all-in economic breakeven price for the locations and the portfolio today?
Craig Owen
Those PDP F&Ds certainly have seen the benefit of those coming down over the last couple of years. And you’ve seen that with continued focus and really the lion share of our capital allocation going to our Appalachian assets.
We kind of laid-out of magnitude of what those look like between the different types of wells we can drill in West Virginia and then Northeast Appalachia as well. Certainly, you see that, just call it in the $0.40 to $0.60 range, $0.40 to $0.70 range for those assets in particular.
So, certainly continue to focus on that as that drives those economics.
Dan McSpirit
What that means for the all-in economic breakeven price for the locations in the portfolio today?
Craig Owen
Those breakevens, as Randy mentioned, with NGL pricing looking to be, maybe 2x over last year. Certainly, that has a big driver on the economics of the West Virginia assets.
I think significant increase there or that type of increase really pushes down that breakeven from natural gas prospective. And that our well performance along with just the pricing we are at today drives up our inventory as well.
Dan McSpirit
And then just lastly here, just revisiting the question on differentials, just to clarify that the low end of the differential guidance range reflects Rover being operational, and maybe that’s just good as it gets for differentials, at least where we sit today. Is that correct?
Randy Curry
It does reflect the company’s guidance on an in-service date or ‘16 or for midyear '17. And then as Bill had mentioned earlier, we do have an active hedging program now that will ensure that we’re able to lock-in differentials consistent with the plan.
Operator
Thank you. Ladies and gentlemen, we have reached the end of our allotted time for questions.
I would now like to turn the floor back over to Mr. Way for closing comments.
Bill Way
Thank you. And thanks for all the questions, and we’re happy to answer any other ones along the way.
Before I go to my closing comments, I do want to say that I trust that we’ve cleared up any concerns about any outspend of capital and any concerns about our commitment to the disciplines that we have delivered and shown throughout this entire year of 2016. There is some very tough times.
But we’ve emerged from that and with that same level of rigor and discipline. 2016 was a transformational year for our Company.
And as you can see, we have much to be excited about from that work and for 2017 and beyond. We’ve already begun building momentum -- building our momentum created through that -- our lower cost structure.
Again, the economic and capital allocation discipline, operational and technical excellence, it's growing by the day. And ability to reach all key high value markets for our products and the focus on economics ahead of production growth from our vast assets.
We are one of the nation's larger suppliers and we take a lot of pride in that. And therefore, managing our business with rigor and discipline around economics to drive the economic value lets us stay in that position.
Our relentless focus on creating long-term economic value for our shareholders drives everything we do. And I hope that we’ve been able to give you some color on that.
And we look forward to sharing more of these results. And I know the wells that everyone is excited about, especially what we look forward to getting those out as well.
And we look forward to continue to talk to you about other areas where we reach to add value plus and increase our performance. So, thanks all of you for joining us on our call today.
And we hope you have a great weekend.
Operator
Thank you. This concludes today's teleconference.
You may disconnect your lines at this. Thank you for your participation.