Feb 27, 2015
Executives
Steve Mueller - CEO Bill Way - COO Craig Owen - CFO Jeff Sherrick - Executive VP of Exploration and Business Development Michael Hancock - IR
Analysts
Doug Leggate - Bank of America Merrill Lynch Drew Venker - Morgan Stanley Charles Meade - Johnson Rice Will Green - Stephens David Heikkinen - Heikkinen Energy Advisors Jeffrey Campbell - Tuohy Brothers Investment Research Michael Rowe - Tudor, Pickering Holt Bob Brackett - Bernstein Research Neil Dingmann - SunTrust Robinson Humphrey Dan McSpirit - BMO Capital Markets Brian Singer - Goldman Sachs
Operator
Greetings and welcome to the Southwestern Energy Company’s Fourth Quarter 2014 Earnings Conference Call. At this time, all the 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 your host, Steve Mueller, Chairman and Chief Executive Officer for Southwestern Energy Company. Thank you, you maybe begin.
Steve Mueller
Thank you, operator. Good morning and thanks all of you for joining us today.
With me today are Bill Way, our President and Chief Operating Officer; Craig Owen, our Chief Financial Officer; Jeff Sherrick, Executive VP of Exploration and Business Development; and Michael Hancock, our Director of Investor Relations. If you’ve not received a copy of this morning's press release regarding Southwestern Energy's 2014 results and revised 2015 guidance, you can find a copy of all of this on our website at swn.com.
Also, I’d 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 in the Forward-Looking Statements section of our annual and quarterly filings with the Securities and Exchange Commission. Although, we believe these expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.
Now let's begin. What a different a year makes, last year at this time the NYMEX price for natural gas is approaching $5 per Mcf, in a West Texas intermediate was trading around $100 a barrel.
As an industry we're talking about ever increasing capital budget, how fast the rig count we're growing in oil basins and how fast rig count oil basins. Today the talk is about much lower oil and natural gas prices significantly reduced budgets and how low service cost might grow to provide some short term relief.
Southwestern Energy is not immune to commodity price volatility and we've adjusted our 2015 guidance but our talk is not changed. Our track record will pass several years and our record results in 2014 again provide conclusive evidence that we can excel in volatile environment like today.
We do talk about cost and we'll certainly benefit from any short term decreases by the service industry but we continue to look for long term cost reductions and better well results that deliver economic benefit today and for many years from now when we drill those last wells on our assets. Our Fayetteville shale, Northeast Pennsylvania Marcellus and the new acquisition of West Virginia and Southwest Pennsylvania are uniquely positioned to supply that new and growing demand from a Gulf Coast of Florida and any other location in Eastern half United States.
When we combine these best in class assets, with our best in class operational experience, the company has created that wins in low price environments and excel those product price increases. You want to hear us talking today about drilling wells and not completing for time to time when we think commodity prices will increase.
We will do what we've always done in pricing environment that is simply drill economic wells and meet our economic hurdle, delivering $1.30 discount at 10% for every $1 invested. We know that if we consistently do that every day we will deliver the results and we'll set more near term records and create sustainable long term returns for our shareholders.
Our assets and team have already proved the flexibility required to thrive in these low price environments and these look no farther than 2012 when even though the industry experienced low natural gas prices than they've seen in almost a decade, Southwestern has near record EBITDA. As we look to the future additional high quality acquisitions over the past 12 months and a unique vertical integration will help us response quickly when commodity prices inevitably increase.
A future when the rest of the industry is battling over mothball equipment and complaining about write in cost. Let me now turn the call over to Bill Way, and he will talk about our operational results and some of those records.
Bill Way
Thank you, Steve and good morning everyone. As mentioned earlier we had an outstanding year in 2014.
At the end of each year I'd like to pause and reflect on what a highly talented of 2750 people were able to achieve throughout the year and as I reflect back in 2014 the list of accomplishment is long and I'm very proud of the hard work and commitment of all of our employee teams across the company that came together and delivered our strong results. I continue to be impressed with the dedication of our team members and their ability to create value plus in everything we do.
I'll start by sharing some of impressive highlights, the overall company achieved throughout the year. In 2014, we set a new record for production of 768 billion cubic feet equivalent which is up 17% compared to 2013.
We acquired 443,000 net acres, 413,000 of which closed in December where we estimate we added over 5,000 drilling locations and potentially over 45 trillion cubic feet equivalent of net recoverable resources to our already impressive portfolio. We ended the year with a new records for proved reserves with over 10.7 trillion cubic feet equivalent a 54% increase over last year’s reserves.
Our Northeast Appalachia area achieved refining and development cost of $0.48 per Mcf even better than the impressive $0.68 per Mcf realized in 2013. Fayetteville Shale generated the most cash flow in its history and was able to return over $300 million back to the company to invest in other areas of the portfolio.
In its 10th year of development the Fayetteville Shale reached 4 trillion cubic feet accumulative gas production and also delivered 24 of its past 30 wells since inception of the play based on average initial production rate. Our midstream services segment was able again to produce its highest EBITDA in its history while building for the future by expanding our Northeast Appalachia firm transportation portfolio to 1.4 billion cubic feet of gas per day allowing E&P asset to continue its impressive growth aspirations.
As you can see 2014 was a year of great accomplishments and there are many more. Looking forward expect more from us as we’ve got off to a great start.
As we enter 2015, our industry is experiencing reductions in commodity prices as Steve mentioned. As is customary practice for us here at SWN maintaining our financial discipline and investing its core to creating value plus for our shareholders.
As such we have reduced our planned 2015 capital investments announced in December by $600 million to approximately $2 billion while continuing to drill our best wells at the lowest cost. Even with this reduced capital program we are targeting substantial production growth of 23% for the year.
We’ve demonstrated in the past that we can deliver industry leading returns in this least price environments and that is exactly what we will do in the year ahead. I’d like to discuss each of the operating areas in a bit more detail and I’ll begin with Northeast Appalachia.
Our production in 2014 grew to 254 million cubic feet which was 69% increase over 2013 volumes. We ended the year with gross operating production of over 1 billion cubic feet of gas per day compared to approximately 700 million cubic feet of gas per day at the end of 2013.
Total prove net reserves in Northeast Appalachia grew by 63% to almost 3.2 trillion cubic feet of gas compared to just less than 2 trillion cubic feet of gas at the end of 2013. Well performance continues to demonstrate the high quality of our acreage position.
As a reflection of this high quality the average growth reserves per well for our producing locations increased to 9.8 billion cubic feet in 2014 while the average growth reserves for well of our undeveloped locations grew to 9.6 billion cubic feet. This compares to 2013 average reserves 8.4 billion and 6.9 billion cubic feet per well for producing in undeveloped locations respectively.
As we progress on the development of this core asset we continue to drive down cost. In 2014 our average completed well cost for our operated wells was $6.1 million which is down from the $7 million average in 2013.
We’ve made the additional progress in our testing of steering targets and profit loading and we’ve completed 18 wells with over 2500 pounds of sand. These wells got initial productivity increase of 50% versus prior wells.
Our early test indicate that we can achieve productivity gains by pumping more profit per stage over 1 million pound and optimizing stage spacing to approximately 500 feet on average which allows us to place more profit and reduce cost. Further to upcoming year we will advance these efforts and hope to decrease well cost even further with additional testing.
In 2014 we made great strides in the development of our new Susquehanna County acreage. This development including drilling 61 new wells in the county during 2014 two of which were right near the New York boarder, both of these wells display strong results and are very encouraging for the northern portion of this acreage which includes the 47,000 net acres from WTX acquisition which Jeff will speak you in a few minutes.
We are developing the north part of our Susquehanna acreage further in 2015 and we expect per sales later in the year. In addition to the success we are having in lower Marcellus we’ve also advanced our upper Marcellus testing in 2014 and early this year.
We placed four upper Marcellus wells on production and the results are encouraging as the initial production rates have averaged over 6 million cubic feet per day of gas per well. Two of the wells were located above and in between lower Marcellus wells with several years of production history.
Interference and pressure data indicates little connectivity or interference with the lower Marcellus wells. And this indicates that we are accessing new reserves in the upper Marcellus that would not have otherwise been produced.
We also continue our delineation efforts in other areas of our Northeast Appalachia acreage and it achieved promising results. We drilled a well in Wyoming County where completed and tested only a portion of the 5,600 foot lateral.
The well flow tested 7.5 million cubic feet of gas per day with a flowing tubing pressure of the 1,000 PSI. Another example is in Tioga County where we drilled and tested our first well in late 2014.
We completed the portion of the lateral to determine flow characteristics within the Marcellus area. During the short term test we produced the rate as high as 8.2 million cubic feet per day from the completed portion of this lateral.
Our plans are to continue delineating our Tioga acreage during 2015 while the gathering system is constructed. Obtaining firm transportation capacity at economic rates is essential to the differentiating success we have been able to realize in Northeast Eastern Pennsylvania.
In 2014, our team was able to expand our firm transportation portfolio to 1.4 billion cubic feet per day, which gives us the capacity we need to continue our strong growth in that area over the next few years. In 2014 we realized over $200 million in additional revenue as a result of our firm transportation and sales portfolio compared to selling directly into local production zone industries.
In addition to the progress made with our firm transport portfolio, the team also was able to analyze an agreement that provides the additional gathering capabilities needed to further develop our prolific Susquehanna County acreage. For 2015 we are expecting another record year in this asset, we’re planning to run three rigs for most of the year and invest approximately $700 million as we target delivering 356 billion to 361 billion cubic feet of production, a 41% increase over 2014 volumes assuming the midpoint.
We plan to drill a total of approximately 90 wells in Northeast Pennsylvania in 2015 and the breakout of that activity by County includes 12 wells in Bradford County, 69 wells in Susquehanna County and 4 wells in the Lycoming County area along with five in Wyoming, Sullivan and Tioga areas. Our plans are effective in 2015 with the gross operated production rate of over 1.3 billion cubic feet per day which will set us up nicely for a strong 2016 and beyond as well.
In the Fayetteville shale we had our strongest production year in our 10 year history, we placed 454 operated horizontal wells on production during 2014 and produced 494 billion cubic feet of gas net to the company. As I mentioned earlier the Fayetteville shale generated over $300 million of free cash flow and the asset will generate free cash flow again in 2015 to help the development plans for other projects in the company.
The average initial production rates for the 454 wells we put online in 2014 was roughly 4.4 million cubic feet of gas per day compared to average initial production rates of 4 million cubic feet of gas per day in 2013. As I mentioned earlier 24 of the top 30 wells based on initial production rates were drilled in 2014.
With the decade of development behind us we continue to leverage our learning and find new ways to deliver even better results for the next decade of development. We also continue to progress our upper Fayetteville evaluation program in 2014 with the drilling of 17 wells in the core area of our AOI.
Notable performance has been seen in three of our oil barrel leased wells where initial production rates average 5.9 million cubic feet a day for the three wells. Our vertical integration in Fayetteville which includes drilling rigs, sand flack, two frac spreads and other field services once again created exception value throughout the year.
An average benefit of over $450,000 per well was realized on our wells from the use of vertical integration in the Fayetteville shale in 2014 giving us the lowest gross well cost in the area. We were also able to build and deliver 7 new rigs into the fleet which will bring increased efficiency to drilling operations for years to come.
We moved two of these new rigs to operations in the Northeast already. As of December 31, our gas gathering business in the Fayetteville, was gathering and transporting approximately 2.4 billion cubic feet of natural gas per day through over 2000 miles of pipe.
This business generated over $360 million in EBITDA in 2014. In the Fayetteville shale we plan to invest approximately $560 million in 2015 as we drill between 225 and 235 gross wells and delivered production of 448 billion to 453 billion cubic feet.
The Fayetteville shale remains a key component of the portfolio and its resource size and closed proximity to growing long term demand along the Gulf Coast. In Southwest Appalachia in the previously announced acquisition we closed the transaction to acquire 413,000 net acres in West Virginia and Southwest Pennsylvania in December and we hit the ground running.
We're ahead of our operational plan and we've recently received good news from the state of West Virginia that they passed the bipartisan bill allowing drilling permits to be transfer between operators, avoiding re-permitting of the planned wells. This action has enabled West Virginia operations to get off to a strong start and we're excited to bring investment to the state and to continue to work with a very supportive government.
As the permit transfer issue was being resolved, our initial activity was focused in Washington County Pennsylvania. We completed drilling operations on our first well the Roberts Shorts 5H, which included an approximately 8100 and 50 foot horizontal lateral.
The lateral portion of the well was drilled in less than 3 days. We plan to complete the well in the first quarter; we've also recently completed two additional wells in the county which will return to sell later this quarter.
We are leveraging our experience in the Marcellus in Northeast Pennsylvania into our Southwest Appalachia operations in both our drilling and completion designs. As in which we expect to see continued improvement, our reduced drilling times, improved lateral placement and more effective completions.
With the permit transfer issue now mitigated we have brought an additional rig into the area and we are rigging up as we speak to drill our first well in Ohio County West Virginia. Our 2015 plan in Southwest Appalachia includes resting approximately $520 million and participating in 50 to 55 wells almost exclusively in the Marcellus.
We plan to drill approximately five wells in Washington County Pennsylvania and four wells in Bard County, 15 wells in Ohio County, 18 wells in Marshall County and 9 wells in Westwood County, West Virginia. Additionally, we’ve initiated an aggressive work over program on existing wells in the area to help optimize production.
In closing we had a record setting 2014 and we are preparing to continue with that momentum in 2015 where we will once again keep our focus on delivering industry leading shareholder value. With the strength of our legacy assets and integration of our new Southwest Appalachia area the future is extremely bright here at Southwestern Energy.
We look forward to discussing more outstanding results at the end of the first quarter with you. This concludes my comments and I’ll turn call over now to Jeff Sherrick for an update on business development and exploration activities.
Jeff Sherrick
Thanks Bill. 2014 was an incredibly busy year for us on the business development front investing approximately $5.8 billion in total.
We were involved in eight separate transactions that in the aggregate added approximately 400 million cubic foot equivalent per day of net production and 900,000 net acres into the portfolio for future development. I’ll quickly recap the major transactions.
Earlier in the year we acquired 380,000 net acres in 3 trillion in the [indiscernible] basin in Western Colorado. We keep up for testing of that acreage in second half of the year by drilling four vertical wells and one horizontal well.
The well through 692-811 which we reported on initial production rate of approximately 408 barrels of oil per day 448,000 cubic feet of gas per day and 1193 barrels of completion order from our 4663 foot lateral in late December. This well is located in the black oil window the play and is currently shut in for a pressure build up test.
Three of the four verticals have been completed in our test in various perspective intervals predominately in the gas condensate window for reservoir. The fourth vertical well drilled in 2014 will be completed later this year.
Early results from both the vertical and horizontal wells have been encouraging and we plan to drill two additional horizontal wells in 2015 and the gas condensate window for long-term testing and one additional vertical well in each of side of the acreage position. We then announced the West Virginia and Southwestern acquisition from Chesapeake in October acquiring 413,000 net acres of approximately 336 million cubic foot equivalent a day of net production.
This transaction closed on December 22, 2014 and as Bill mentioned few moments ago, we’ve hit the ground running the area and we are excited to be starting the process of extracting the value of the enterprise when we make the purchase. In the separate transaction we also acquired 30,000 net acres and approximately 29 million cubic foot equivalent per day of net production from Statoil in the same area of West Virginal and Southwest Pennsylvania and this transaction close on January 27, 2015.
Our final sizable transaction for the year was in Northeast Pennsylvania where we acquired approximately 47,000 net acres and 50 million cubic feet per day of net production from WPX. In addition to the E&P assets we also acquired firm transportation of 260 million cubic feet per day and an 86% ownership in the small gathering system.
The transaction was announced in December 2014 and was closed on January 30, 2015. The WPX deal is our eight hold-on acquisition in Northeast Pennsylvania and one of the exciting things about this transaction is it brought significant value to company in multiple ways.
The E&P increase in existing production fit seamlessly into our current Susquehanna operations and justify the purchase and when you add the value the foreign transportation capacity to move additional gas out of the region on the Millennium pipeline system, the deal easily pays for itself in a great way. 2015 has begun with the same quick pace in which 2014 ended.
While we are in the process of closing the Statoil and WPX transactions we have been very focused on making good progress on the assets divestures that we announced as part of the acquisition financing. Each of the assets identified for divestiture which are in East Texas in our E&P operations along with the gathering system in Northeast Pennsylvania we’ve been actively marketing the access during the first quarter.
We have received the very high level interest in all the assets and remain confident in our previously announced proceeds range of about $600 million to $800 million. We anticipate announcing these sales in the next few weeks and closing well occur in the second quarter as previously discussed.
With that I will now turn it over to Craig Own to discuss our financial results for 2014.
Craig Owen
Thank you, Jeff and good morning. We had a very strong 2014 achieving record results driven by higher production volumes combining with our emphasis on cost control and efficiency and slightly higher realized gas prices.
Excluding certain non-cash items we reported net income in 2014 of 801 million or $2.27 per diluted share compared to 704 million or $2 per diluted share in 2013. Net cash provided by operating activities before changes in operating assets and our abilities was a company record at 2.3 billion up 14% compared to 2013.
Operating income for our exploration production segment was just over 1 billion compared 879 million in 2013. This increase was primarily due to higher volumes and realized prices partially offset by higher operating cost and expenses due to increased activity levels.
For the year we realized an average gas price including hedges of $3.72 per Mcf which is up from $3.65 per Mcf in 2013. Excluding the hedges our average realized gas price increased to $3.74 per Mcf from $3.17 per Mcf last year.
We currently have 240 Bcf or approximately 27% of our 2015 projected natural gas production hedged to fixed price swaps at a weighted average price of $4.40 per MMBtu. Our hedge position combined with the cash flow generated from our midstream business provides protection on approximately 40% of our total expected cash flow for 2015 assuming current prices.
Additionally, we had approximately 310 Bcf of our 2015 expected gas production protected from the potential warning basis differentials to hedging activities and sales arrangements at an average basis differential to NYMEX gas prices of approximately minus $0.17 per Mcf. In February, our 2015 year-to-date natural gas discount, which is inclusive of transportation in both Northeast Appalachia and Southwest Appalachia is estimated to be about zero resulting in realized prices estimated to be approximately flat to NYMEX.
Our detailed hedge position is included in our Form 10-K filed yesterday. We once again kept our focus on keeping cash cost low in 2014 and cost structure continues to be one of the lowest in the industry.
With all-in cash operating cost of approximately $1.32 per Mcfe in 2014 compared to a $1.25 per Mcfe in 2013. That includes our LOE, G&A, net interest expense and taxes.
Lease operating expenses for our E&P segment were $0.91 per Mcfe in 2014 up from $0.86 per Mcfe in 2013, primarily due to increased gathering and compressing cost associated with our growth in the Fayetteville shale in Northeast Appalachia. Our G&A expenses remain flat at $0.24 per Mcfe for the year; taxes other than income taxes were $0.11 per Mcfe in 2014 compared to $0.10 per Mcfe last year.
The full cost pool amortization rate in our E&P segment increased slightly to $1.10 per Mcfe compared to $1.08 per Mcfe last year. Operating income from our midstream services segment was $361 million in 2014 up from $325 million reported last year.
This increase was primarily due to an increase in gas marketing margins and increased gathering activity from our Fayetteville Northeast Appalachia assets. We invested approximately $7.4 billion in 2014, which includes approximately $5 billion for our West Virginia and Southwest Pennsylvania property acquisition from Chesapeake.
As a result of this acquisition at December 31, 2014 our debt to total book capitalization ratio was 60%, up from 35% in 2013. We had 300 million drawn on our $2 billion revolving credit facility at year end '14 and we also had 53 million of cash on our books.
Since year end, we raised 2.3 billion in net proceeds from our equity offering and 2.2 billion in long term notes which had the effect of lowering our debt to total book capitalization to approximately 40%. These transactions allowed us to pay off and terminate 364 day bridge.
A bridge loan that we took out in place to initially finance adjusting transaction. As Jeff mentioned last month, we closed two other large transaction that were announce in the fourth quarter for a total of 653 million.
The net proceeds of 600 million to 800 million from the previously announced asset sales will be used to pay-off the 500 million term loan that we took out in December with the remaining proceeds to pay-down the balance of our revolver. As Bill mentioned we've revised our capital investment program and guidance for 2015, excluding the acquisitions previously announced and closed in December and January, our capital investments are now expected to be 2 billion for 2015 down from 2.4 billion last year.
This reduced capital program provides strong production growth over 2014, solid quarter-over-quarter growth in 2015 and assuming a similar capital program is expected to be able to produce low teen growth in 2016. We are guiding an expected differential plus transportation cost with discount of $0.70 to $0.85 per Mcf in 2015, which when combine with our estimated actual discount of about zero for February year-to-date in Northeast Appalachia and Southwest Appalachia, resulted in average natural gas discount from March through December of $1.20 to $1.30 per Mcf in these areas.
We currently expect our debt to total book capitalization ratio at the end of 2015 to range from 39% to 41% assuming current prices. We have an exciting year ahead of us; the strength of the portfolio will once again be demonstrated as we look to generate value for our shareholders in 2015 and beyond.
That concludes my comments, so now I'll turn it back to the operator who will explain the procedure for asking questions.
Operator
Thank you. [Operator Instructions] Our first question comes from the line of Doug Leggate with Bank of America Merrill Lynch.
Please proceed with your questions.
Doug Leggate
Thanks. Good morning everybody.
Steve, I don’t know who you want to [indiscernible] or maybe take it yourself, but obviously you’ve had a lot of moving parts on the balance sheet and I’m curious as to, what is the target if there is such a thing, for the balance sheet? Whether it be a debt to EBITDA coverage ratio or some other metric?
And just in the same context, can you talk about any other moving parts in terms of disposals and plan proceeds beyond what you have highlighted this morning? I’m thinking specifically about the vertical wells you inherited and perhaps any other well that you can see on par?
I’ve got a follow-up please.
Steve Mueller
As far as the ratio what we’ve been concentrating on is EBITDA ratio and if you think about where we were before we did the acquisition that was a middle 1.3 to 1.5 type range number and our goal is by 2017 we get in close to that range. So we’ve built our capital budget.
We’ve built our thought process on doing that. As far as other dispositions go we have mentioned in the past that probably some of the conventional assets on the new acquisition that we did will be potential disposition candidates that would be as early as late this year and probably more in 2016.
And there are some other things out there that we’re looking at that maybe sales or sales candidate in the near future. I won’t go in a lot of details here I just mention one of them.
We actually have a gas storage field in Arkansas that, under some previous agreements we couldn’t do anything with them until about June of this year. You might see us sell that one and maybe clear some other small assets.
You can tune on that one and watch the year as it plays out.
Doug Leggate
You are not to waver the point, but obviously what one past overview on gas prices to see you get to that 1.3 to 1.5. Is that target we should take as, this is where you absolutely went to get to, or is it subject to gas prices as well, that’s in 2017 timeline?
Steve Mueller
I think the target for you to think of us, we will get under 2 by 2017 and we will manage our business to do that. Our goal though is to be below well under 2 and near that mid 1.5 range.
If gas price is $2.50 per three or four years you’re going to see this under 2 rather than close to 1.5 and if it’s more like 3.50 you’re going to see it’s in that 1.5 range.
Doug Leggate
That’s very, very clear. My follow-up is really on take away capacity.
Obviously in the northern Marcellus, my understanding is obviously a big bump in the volumes in Q4. It seems you’ve got a 1.3 Bcf to be at [gross capacity].
What are your plans to utilize that and if you give us an update on where the take away restrictions might be over the next couple of years in the Southwestern Marcellus as well? I’ll leave it there.
Steve Mueller
I’ll just remind everyone, on the Southwest Marcellus we designed that program to ramp up fairly slow and we did that for two reasons. One, we didn’t know exactly all of the things we would run across and issues that we might hit along the way and as Bill said right now we’re little bit ahead of schedule, and I remember rolling about 60 days into this.
But the other kind of restriction we had on it was that we knew for next couple of years that we had only a certain amount of firm that we could get to and we built our plan based on the firm that we thought was available to us and some of that we have today, some of that we’re in the process of getting. As we get it we’ll talk more about it.
Because of that what we did was in early 2015, 2016 all the growth all of the upside is basically built around that Northeast Pennsylvania and as you mentioned we have more than enough capacity there today and our marketing group is actively -- we are not using the day as actively marketing that and you’ll see just like you have in some early quarters little bit higher marketing value as you go forward over the next few quarters. By the time we get towards the end of the year in 2016 we’ll have grown into that overall firm and basically from that standpoint I guess what I’m saying is even if we stumble in southwest a little bit in what we just bought the company will be fine and the guidance we’ve given will work for 2015 and Craig said 2016 was a low double digit growth, with the high single digit growth we think we can achieve that.
Doug Leggate
Thanks Steve. I appreciate the answers.
Operator
Our next question comes from the line of Drew Venker with Morgan Stanley. Please proceed with your question.
Drew Venker
Good morning everyone. You obviously had a pretty substantial CapEx cut with this latest revised guidance.
I was just hoping you could talk about what the impact might be on the '16 and '17 spending plan, compared to what you had announced previously. Seems like across all of Appalachia a lot of producers are scaling back and I would think that would have some impact on the supply balance, at least for 2016.
Steve Mueller
Obviously, 2016 budget depends on what the gas prices and what the oil prices as you look out into the future, I think the comment that Craig made probably says it best. We can invest $2 billion in 2016 and still have that high single low double digit growth rate during that year and that would -- what would mean that we've pretty severe gas price in 2016 as well and if you can project that out to 2017 and invest $2 billion again and you've another difficult year from a pricing standpoint we're still in high single digit growth range.
We kind of done the bookings, we're comfortable with that we can give good delivery on the low side of price and then the other side of gas price comes back during that period of time you'll see us grow faster.
Drew Venker
Thanks Steve. Just as a follow-up on the budget for '15.
The CapEx cut was pretty significant, even in just your main drilling programs. Fayetteville and Marcellus and obviously the production didn't change a whole lot, so can you talk us through what the main driver was there?
If this is service cost improvements or well performance?
Craig Owen
Yes, there are three places where in general we made some cuts. We had some discretionary capital and by discretionary it's important but you could at this year or next year and that was part of it and that discretionary capital had no production with it.
There was we're looking at our new assets in West Virginia and really we just revise some things because we've some guesses going in and we know it worked now and that actually revised down a little bit and then in the Fayetteville shale from the original $2.6 billion capital budget we drop from 6 rig program to 4 rig program and there you can see the corresponding decrease there. That to in place there was any production decrease in the system and that's why the production in general could stay high while the capital was going down as you go through it, so that's the basic answer on that.
Drew Venker
Thanks Steve.
Operator
Our next question comes from the line of Charles Meade with Johnson Rice; please proceed with your question.
Charles Meade
Good morning everyone. Steve, I'm wondering, you addressed this a bit already with an earlier question, but I wondered if you could add a bit more clarity to how you're selling your gas in Appalachia?
I think going back to Craig's comments; I think you probably inherited some of that debt to M3 exposure from Chesapeake that's helping you out here in the beginning of the year. But some of your other operators, particularly up in the northeast, have talked about projecting some price related curtailments, and with your discussion, your firm transportation out there, my sense is you're not as exposed to that.
But I wonder if you could clarify that or maybe illuminate a bit more about your thinking in your exposure there?
Steve Mueller
Yes, as you said a lot of what we have in the new acquisition is M3 type pricing but as far as some kind of pricing that would make us shut in wells or do something, we factor that all into our capital budget so I don't see anything on the horizon there.
Charles Meade
Okay, okay, that's helpful. And then going back to your guidance, there's a, you guys bumped up the oil component of our volume guidance a bit and you actually, looked like you beat 4Q on that front as well.
So, wondered if you could talk about maybe what's changed in the last two months that led you to increase those oil volumes and what's behind it?
Steve Mueller
I think we learned a lot more in the last two months basically, we had most information where we're using when we put that original number together was data we got in November from Chesapeake and now we actually have field data and we've got well information, so it's just having more data in last 60 days.
Charles Meade
Okay, great, thank you Steve.
Operator
Our next question comes from the line of Will Green with Stephens; please proceed with your question.
Will Green
Good morning everyone. A few years back, we were talking about how in the Fayetteville drilling times had reached technical limits, couldn't be reduced much further and yet the last couple of years you guys have really quickened the pace.
You know, can you speak to how much of that has been technology versus the experience with the rock? And you know, being mindful that you guys have been in the Fayetteville a lot longer, and as you just mentioned the Marcellus was kind of originally built to go slower.
Are you still seeing those sorts of same step changes in, technology or experience with the rock in places like the Marcellus?
Craig Owen
Yes, I'll start with Fayetteville, I think there was some tough discussion in the past about whether or not we've reached the technical limit and I think when you got a well portfolio of drilled well that top 4,000 you got a lot of opportunities to learn and our teams have just continued to better understand the rock, have better placement of the laterals and be much more accurate in those drilling plans in that drilling capability. So that combined with a little bit of friendly competition between rigs does drive further improvements.
We have new rigs that were designed to be able to drill a day faster than the rigs they replaced. So in the later time technology is beginning to help us with increase capability on those rigs.
And then it just continues learning. We are moving a couple of rigs north to east some in Marcellus, Northeast Pennsylvania and some in Southwest Appalachia.
Already we’ve seen drilling improvement times in Northeast Pennsylvania from our learnings in the rock our learnings from what we’ve picked up in the Fayetteville and our drilling teams that are moving up into that regions. So we brought drilling days down and continue to bring those down in northeast.
In southwest there are lot of the assumptions and things that we put out on numbers of rigs and all of that were based off of industry drilling times. We’ve seen significant improvement, both from the industry and even in the work that we’re doing our first well that I mentioned earlier the lateral portion drilled in three days and this is again leveraging some technology, leveraging some experience and just getting better and better understand of rock.
So we do expect that we’ll get further drilling time improvements in all of our areas. We tend to track wells rather than rigs because of that and so you’ll seen Southwest Appalachia for example we’ve changed the number of rigs and it is more driven by the fact that we believe that we can learn even faster than we projected and we will drive those times down.
Will Green
Great. And then I apologize if I missed it in the prepared remarks.
But you know, what I’m thinking about the 50 to 55 wells you guys are looking at in Southwest Appalachia, obviously there is a lot of primary objectives that you guys liked when you acquired that acreage, how are you thinking about the breakout of those 50 to 55 wells?
Craig Owen
I gave out the kind of counties. But we’re primarily targeting the Marcellus and wet areas of the Marcellus is the real objective at this point in time.
In the future as we learn from the industry as we get ourselves up and running in that area we’ll obviously be looking at the Utica and some of the areas. But right now for ‘15 absent some couple of weeks old wells we’re targeting the wet portion of the Marcellus.
Steve Mueller
Let me add, I don’t anyone to think that we’ll bullish on the liquids. We’re targeting the wet area because that’s where we have -- the gathering sits in place and that processes in place and will expand as we get into 2016 in some of the gas areas.
The other thing I’ll just mention when we talk about the reserves we have on the books in the new acquisition all of that basically except for that conventional is Marcellus. We only have one well total in our reserves as Utica.
So there is a bunch of upside there in the future for all those horizons.
Will Green
Great. I appreciate the color guys.
Operator
Our next question comes from the line of David Heikkinen with Heikkinen Energy Advisors. Please proceed with your question.
David Heikkinen
Good morning guys. Steve, you just set up the question, going into 2016 as you think about maybe some of the gas areas how much midstream capital is needed?
And how do you think about that spend over the next couple of years in the Southwest Marcellus region?
Steve Mueller
As we go through the year one of the things you’re going to see is we’ll talk about our overall strategy for the various zones and the various parts of the play. Today there are four different gathering systems, one that is the conventional one and three other gathering systems they have gaps in them, they need to have kind of the strategic work on what’s there and then there is a certain [indiscernible] amount of acreage that we don’t have any kind of gathering on and most of the Utica falls in that category.
So during the year we’ll figure out how much we’re going to do versus third party, we’ll work with third parties to fill in some of those holes. And I can talk better about it.
But certainly we’ll look hard at using our midstream and our ability is to do part of that.
David Heikkinen
Okay. And then, on the same thought of updating attack curves and as you go into your own development program and see your own well results, should we think about like maybe second quarter call August, September timeframe, maybe, where you’d have some internal new updates as far as your southwest region type curves?
Steve Mueller
That might be a little bit early but maybe it somewhere around the -- certainly in the same half of the year. The wells that we’re drilling right now, they get put on in the second quarter, if they get put on basically right now barely we can make that September timeframe, but volume will reveal itself.
David Heikkinen
Got it. Thanks guys.
Operator
Our next question comes from the line of Jeffrey Campbell with Tuohy Brothers Investment Research. Please proceed with your question.
Jeffrey Campbell
Good morning. You mentioned earlier in your remarks today that you gave southwest Appalachia a closer look in forming CapEx.
Is it possible to discuss what 2015 CapEx and production in that area looks like on a year-over-year basis? I'm curious to know the extent to which the southwest Appalachia has been subject to the same high grading and cost cutting as your two legacy plays?
Steve Mueller
We don't have that much information on the previous operator's activity. Well count I think is roughly the same between the two years but I don't know what their capital was and so I really can't say much about 2014.
Jeffrey Campbell
Okay thanks. At least the well count is in there, that's helpful.
In your reserve areas, that we talked about Southwest Appalachia is having 54% of acreage held by production, how much of that percentage, how much will that increase in 2015 when the program is complete? More broadly, what are the pressures to drilling and hold acreage over the next several years?
Steve Mueller
About half of the activity I think in 2015 will form acreage to some sort -- about maybe a third of the activity, it's not that big on any given year, it’s very manageable but we also have the ability to extend leases as in order due to lease expansion provisions included in the agreements.
Jeffrey Campbell
Okay, thanks very much, appreciate it.
Operator
Our next question comes from the line of Michael Rowe with Tudor, Pickering Holt; please proceed with your question.
Michael Rowe
Hi, good morning I just wanted to dive into little bit more on liquids pricing. You all I think previously said you expected 30% realizations for NGLs relative to WTI, how is that really changed in terms of your updated guidance?
Steve Mueller
It hasn't.
Craig Owen
When comparing, make sure you've included that as well as there is transportation [D dot] coming NGLs of about $6 that it will include in that as well but as Steve said it really hasn't changed.
Michael Rowe
Okay and I guess on the same note then in terms of the drilling economics for your wet gas Marcellus in at $275 seller Mcf world, I'm just curious to see if you can talk about your anticipated returns where the liquids prices are today?
Craig Owen
I don't generally comment about every one of our area, besides it’s there, what we'll do is the same thing we did in 2012 where we high graded we didn't, when we moved on a pad we drill the very best wells in the pad but in each case we were very comfortable that we could reach our economic hurdle at 1.3 pbi we always talk about and we will do that in every one of our areas, so this year's high grade program there maybe a little bit of inefficiencies and then you may have to go back to pad in the future but everywhere we drill in this environment we'll do that. And again with that chance there is some kind of assumption by cost and we're using this year roughly $3.25 on the gas price, $3.75 next year and $4 flat for ever after that and I think we're using $60 give or take average over the next three year oil price.
Michael Rowe
Okay and just one follow up if I could, you actually took down CapEx guidance for Northeast Appalachia while the production guidance there actually increased a little bit so is this really a function of planning service cost, high grading or both?
Craig Owen
It's a function of better wells than evenly projected when we hit the budget, we did take included in the capital budget for Northeast Pennsylvania with some additional land and other non-production bearing type capital that we just pushed out and so you had better wells that ways in their production, the capital changes were really not drilling and completion related.
Steve Mueller
And I think somebody else has mentioned talking about service cost, we really have not adjusted anything based on guessing future service cost, we certainly have already captured a little bit of cost and then we put that in there but none of our estimates have any kind of service cost featured drops in them.
Michael Rowe
Okay, great, that's helpful, thank you.
Operator
Our next question comes from the line of Bob Brackett with Bernstein Research; please proceed with your question.
Bob Brackett
Yes, most of mine have been asked but a couple of quick things, one of the things I loved about your earnings release in the past was that table of quarter-by-quarter 30 day rates for your key assets, I noticed it's dropped out, was that an oversight or you're going to bring that back because I miss it?
Steve Mueller
Yes, you'll see it next week, what happened was that the release has been so large and we had one from Northeast Appalachia and we have one from Fayetteville and when we put out our new IR material next week, you'll see both of those tables and then you’ll have the quarterly data in that overall. So, stay tuned on that part.
Bob Brackett
I apologize for that disclosure. The other quick one, BHP was selling their Fayetteville looks like no one wanted it, what you kept you from being interested in that asset?
Steve Mueller
I think the baseline kept us from being interest and we just did a $5 billion acquisition that was really the balance sheet more than it was asset so.
Bob Brackett
Okay, thanks.
Operator
Our next question comes from the line of Neil Dingmann with SunTrust Robinson Humphrey. Please proceed with your question.
Neil Dingmann
Most of my have been hit but just couple of things very quick. On Slide 8, I think Douglas talk about this earlier so you guys talk about sort of a takeaway and what’s going on.
I guess just two things I had what’s your thoughts about the takeaway in some of the newer areas especially as you look down south around up shore in Louis County would be more than -- are you bringing more infrastructure in takeaway in that area as well. I’m just trying to get an idea of where the infrastructure, I understand the line is coming on but I’m just not quite certain on how they are going to, or what regions they’re going to tie up to?
Steve Mueller
Neil, you’re talking about our gathering infrastructure?
Neil Dingmann
Yes, sir.
Steve Mueller
Yes, we’ll talk more detail about that but it’s going to be -- have to be some kind of back loan run, north-south, across our acreage and around our acreage and where exactly it goes I don’t know but it will certainly head in that direction towards southern counties and there is a small gathering system there already, but it certainly doesn’t have the capacity to do what we want to do. I don’t think we can upgrade it.
But we’re working on that right now. My guess is it’s going to be almost north-south line runs across the four or five counties there.
Neil Dingmann
Okay. And then just lastly, on that Slide 26 it shows the Northeast Appalachia just the tight curve there what you guys kind of I guess now if you had a certain estimate on the curves and it still turning into these so it looks like they’re turning pretty close to that I don’t know the [12Ds] or so but it doesn’t look a little bit different I guess in this slide deck versus and I was looking like against September and some of the backups may if you can just comment on sort of how you forecast some of these Northeast Appalachia type curve these days.
Steve Mueller
I think you’ve seen a little bit different mix from quarter-to-quarter. If you think about last year at this time it was almost all Bradford data and this year we drill a lot of the Susquehanna wells.
But other than that mix the discussion that Bill had about the fact that we’re hitting very good wells there isn’t anything fundamentally change. There are EURs are up little bit because we know more about that wells, it’s really just that.
Bill Way
We have upgraded the completion as I talked about before and the quality of our landing in zone and our ability to steer is improved quite a bit as well so we’re optimized where we land staying in of the whole well and then profit loading as we talked about earlier.
Neil Dingmann
That helps; it’s a great point there. Thank you.
Operator
Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Please proceed with your question.
Dan McSpirit
Thank you and good morning. First one if you could clarify the 1.4 Bcf a day in Appalachia firm transportation includes capacity on constitution, correct?
If so, can you remind of that amount as well as the overall cost of the capacity in place?
Steve Mueller
It does not included in 2015 and 2016 we’ve had nearly 1.4 today but late in 2016 we assume constitution come on and that’s 150 million a day to us. And what actually happens, some capacity we have today falls off as we go into 2016 and constitution comes on and so it’s basically got flat about 1.4 for year.
Dan McSpirit
Okay, great. And then just the overall cost of that capacity?
Steve Mueller
Our weighted average cost for all of our portfolio there is right about $0.36.
Dan McSpirit
Okay, great. And then a follow up if I may and maybe a more theoretical question on capital efficiency, how much that maybe an overused term these days.
If the company like other producers drill the best locations today in light of slow commodity prices, what is that mean for capital efficiency in the out period that is, would it nationally decrease as the remaining locations in inventory of same lesser quality? Holding all of those constant.
Steve Mueller
It certainly would, part of the reason we did the acquisition is that, that acquisition has a large amount running room with large amount of high quality wells in them. But certainly you’re drilling very best well first the other ones are going to be a little less than that well.
So you will see that, for the industry or our company or for an area you will see that at all the time.
Dan McSpirit
Yes, got it. Thank you.
Operator
Our next question comes from Brian Singer with Goldman Sachs. Please proceed with your question.
Brian Singer
Thank you. Good morning.
I wanted to follow up on the impact of commodity prices and cost on your longer term growth strategy. In late December you showed production in ‘17 being up about a Bcfe a day versus 15, I believe that was run at 4 for a couple of years and then 4.50 in ’17 you mention you’re not ready to make a statement on cost but can you just talk to whether you feel like you could still achieve these targets and what gap price you would need to meet those objectives?
Steve Mueller
Well, I think to hit those exact numbers we need above the gas price we put in that sheet actually, and I’m not sure about the 450 in ‘17 because whatever you get in ‘17 is really based on ‘16 wells and early ‘17 wells, but long term we saw that several times we think we're in a $4 world and a high $3 world -- $4 world, we think we can hit those targets and then all of a sudden we’re talking about this 4 was as if it's low $3 world and what we do in that world.
Brian Singer
Got it and then assuming the bulk of that incremental production comes from Appalachia and I know not all of it is natural gas but how much additional firm transport do you need to achieve those targets and how much do you expect to you as the local markets, because it seems like incrementally there is like couple of hundred million a day that you've locked in right now.
Steve Mueller
Yes, I think between now and '16, we will -- when you say local markets I won't quite describe what they will, what we'll do is work with other operator sort of excess capacity and use user capacity and so I think on a percentage basis selling into what you call it a daily market, isn't going to be that higher percentage and we think there are plenty of excess capacity to work on between now and '16. You will see us in the near future commit to probably close to Bcf a day that would the '17, '18, '19 type timeframes and then really we believe the market is changing a little bit and historically we talked about the fact that you have to have firm.
At some point we believe in the not too distinct future, Northeast will have more than enough capacity from a takeaway standpoint and then firm isn't as important. So one of the things you will see us doing, whether it’s for one Bcf and I'm talking about or any other firm that we might think about adding on top of that, we're looking at the shorter contract term life not necessarily the 15s and 20s but more like the 10s and we will certainly be watching very closely the cost and where that's going to is it go through because once it do have all the capacity you need then the firm isn't as important and it actually becomes an issue, we paid a lot for that we've long term timeframe on it.
So we know we need a Bcf a today, we know that somewhere around 2020 we could certainly be producing 2.5 plus Bcf a day out of that new acquisition and so there is a Bcf we need and we'll kind of sort to what else we need after that.
Craig Owen
Just seems the acquisition close we’ve picked up another 175 million a day on a three year term. So, our guys are out opportunistically picking these very comfortable with we can continue to do that.
Brian Singer
Sorry, I've a lot of follow up but can you talk to what was the cost of those incremental projects are relative to say the cost of underwriting a new pipeline out of the region or reversal?
Steve Mueller
I won't talk a lot about just to say that since these are committed by other companies and its available today, their price was low so you're talking $0.30 type numbers or $0.40 numbers and I’m talking 50 to 60s.
Brian Singer
Thank you.
Operator
Thank you. Ladies and gentlemen we've reached the end of our allotted time for questions.
I'd like to turn the floor back over to Mr. Mueller for closing comments.
Steve Mueller
Thank you. I start the call today and talks about the differences that happened between this time last year and today, while there is a lot of differences, I also talked about the consistency that make us as premier company.
We've talked about we've got world class assets and advantageous in geographic areas, operated better staff that just doesn't promise that we can reach lofty goals and lofty production we've already done it and that experience is being brought to new projects and is unmatched by almost anyone in the industry. I do want to make one last point, like all companies we develop plans and we've talked about our plan today but I also want to make sure we don't just plan, we prepare and we prepare for what might occur when the plan doesn't work and when the plan doesn't work.
If change is required we know to do, we do it quickly and then we prepare again. And it's really from our standpoint the only way you work in a business like ours where there is higher volatility and I think what you see in 2014 with our records what you seen over the last three years we've been able to do as proven that ability of planning and staying prepared as we go through.
More proof for that is the fact that we were able to capture some very high quality assets this last year while others in the industry worried about how to respond to difficult price environment. I think that sets us apart, I'm excited about what we're going to do in 2015 for Southwestern Energy and thank you for being part of our call today and have a great weekend.
Operator
Ladies and gentlemen this does conclude today's teleconference. You may disconnect your lines at this time.
Thank you for your participation and have a wonderful day.