西南能源 (SWN) 2014 Q4 法說會逐字稿

Greetings, and welcome to the Southwester Energy Company's fourth-quarter 2014 earnings teleconference call.

(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 may begin.

Thank you operator. Good morning and thank 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 have 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 www.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 which are beyond our control and are discussed in more detail in the risk factors in the forward-looking statements sections 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 difference a year makes. Last year at this time, the NYMEX price for natural gas was approaching $5 per Mcf, and our West Texas Intermediate was trading around $100 a barrel. As an industry, we were talking about every increasing capital budgets, how fast a rate count would grow in oil basins and how fast count would grow in oil basins.

Today the talk is about much lower oil and natural gas prices, significantly reduced budgets and how low service costs might go to provide some short-term relief. Southwestern Energy is not immune to commodity price volatility, and we have adjusted our 2015 guidance, but our talk has not changed. Our track record over the past several years and our record results of 2014, again provide conclusive evidence that we can excel in volatile environments 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 in West Virginia and southwest Pennsylvania, are uniquely positioned to supply that new and growing demand from the Gulf Coast to Florida, and any other location in the eastern half of the United States. When we combine these best in class assets, with our best in class operational experience, the Company has created the wins and low price environments, and excels as product price increases.

You won't hear us talking today about drilling wells and not completing, or trying to time when we think commodity prices will increase. We will do what we have always done in every pricing environment. That is simply, drill economic wells and meet our economic hurdle of delivering $1.30 discounted 10% for every dollar invested. We know if we consistently do that every day, we'll deliver results that will 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. You need to look no farther than 2012, when even though the industry experienced low natural gas prices than they had seen in almost a decade, Southwestern had near record EBITDA. As we look to the future, the addition of high quality acquisitions over the past 12 months and our unique vertical integration, will help us respond quickly when commodity prices inevitably increase. A future when the rest of the industry is battling over moth-balled equipment and complaining over rising costs. Let me now turn the call over to Bill Way and he'll talk about our operational results and some of those records.

Thank you Steve and good morning everyone. As mentioned earlier, we had an outstanding year in 2014. At the end of each year I like to pause and reflect on what our highly talented team of 2,750 people were able to achieve throughout the year. And as I reflect back in 2014, the list of accomplishments is long and I'm very proud of the hard work and commitment of all of our employee teams across the Company, who 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 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 record for proved reserves, with over 10.7 trillion cubic feet of equivalent, a 54% increase over last year's reserves.

Our northeast Appalachia area achieved a finding and development cost of $0.48 per Mcf, even better than the impressive $0.68 per Mcf realized in 2013. The 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 tenth year of development, the Fayetteville shale reached 4 trillion cubic feet of cumulative gas production and also delivered 24 of its best 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 the 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 have gotten 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 vigour in investing is 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 these 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. I'll begin with northeast Appalachia. Our production in 2014 grew to 254 billion 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 proved 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 gross reserves per well for our producing locations increased to 9.8 billion cubic feet in 2014, while the average gross reserves per well of our undeveloped locations grew to 9.6 billion cubic feet. This compares to 2013 averages, reserves of 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 costs.

In 2014, our average completed well costs for our operated wells was $6.1 million, which is down from the $7 million average in 2013. We've made additional progress in our testing of steering targets and profit loading, and we've completed 18 wells with over 2,500 pounds per foot of sand. These wells have had initial productivity increase of 50% versus prior wells. Our early tests indicate that we can achieve productivity gains by pumping more proppant per stage, over 1 million pounds, and optimizing stage spacing to approximately 500 feet on average, which allows us to place more profit at a reduced cost. Through the upcoming year we will advance these efforts and hope to decrease well costs 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 border. Both of these wells displayed strong results and are very encouraging for the northern portion of this acreage, which includes the 47,000 net acres from WPX acquisition which Jeff will speak to in a few minutes. We are developing the north part of our Susquehanna acreage further in 2015 and we expect first sales later in the year.

In addition to the success we are having in lower Marcellus, we have also advanced our upper Marcellus testing in 2014 and early this year. We've 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 have achieved promising results. We drilled a well in Wyoming county where we completed and tested only a portion of a 5,600-foot lateral. The well flow tested 7.5 million cubic feet of per day with a flowing tubing pressure of 1,000-psi.

Another example is Tioga County where we drilled and tested our first well in late 2014. We completed a portion of the lateral to determine flow characteristics within the Marcellus area. During a short-term test, we produced a 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 differentiating success, we have been able to realize in northeastern 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 the 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 indices. In addition to the progress made with our firm transport portfolio, the team also was able to finalize an agreement that provides the additional gathering capabilities needed to further develop our prolific Susquehanna acreage. For 2015 we are expecting another record year in this asset. We're are 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 four wells in the Lycoming County area, along with five in Wyoming, Sullivan and Tioga areas. Our plans have us exiting 2015 with a 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 rate 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 a 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 Hall, Darrell leased wells where the initial production rates averaged 5.9 million cubic feet a day for the three wells.

Our vertical integration in Fayetteville, which includes drilling rigs, a sand plant, two frac spreads, and other field services, once again created exceptional 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 seven new rigs into the fleet, which will bring increased efficiency to drilling operations for years to come. We have moved two of these new rigs to our operations in the northeast already.

As of December 31st, our gas gathering business in the Fayetteville was gathering and transporting approximately 2.4 billion cubic feet of natural gas per day, through over 2,000 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 drilled between 225 and 235 gross wells and deliver production of 448 billion to 453 billion cubic feet. The Fayetteville shale remains a key component of the portfolio and its resource size and close 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've 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 a bipartisan bill allowing drilling permits to be transferred between operators, avoiding re-permitting the 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 revolved, our initial activity was focused in Washington County, Pennsylvania. We completed drilling operations on our first well, the Robert Shorts 5H, which included an approximately 8,150-foot horizontal lateral. The lateral portion of the well was drilled in less than three days. We plan to complete the well in the first quarter. We have also recently completed two additional wells in the county, which will return to sales later this quarter.

We are leveraging our experience in the Marcellus, in northeast Pennsylvania, into our southwest Apalachicola operations, in both our drilling and completion designs. 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 are rigging up as we speak to drill our first well in Ohio County, West Virginia.

Our 2015 plan in southwest Appalachia includes investing approximately $520 million, and participating in 50 to 55 wells almost exclusively in the Marcellus. We plan to drill approximately five wells from Washington County, Pennsylvania, and four wells in Brook County, 15 wells in Ohio County, 18 wells in Marshall County and nine wells in Wetzel County, West Virginia. Additionally we have 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're 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 the 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 the call over to Jeff Sherrick for an update to business development and exploration activities.

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 three transactions in the Sand Wash basin in western Colorado. We kicked off our testing of that acreage in the second half of the year by drilling four vertical wells and one horizontal well. For well [692 H11]. Which we reported initial production rate of about 408 barrels of oil per day, 448,000 cubic feet of gas per day and 1,193 barrels of completion water from a 4,663-foot lateral in late December. This well is located in the black oil window of the play and is currently shut-in for a pressure build up test.

Three of the four verticals have been completed and are testing various prospective intervals, predominantly in the gas condensate window of the 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 in the gas condensate window for long-term testing, and one additional vertical well on the east side of the acreage position.

We then announced the West Virginia and southwest Pennsylvania acquisition from Chesapeake in October, acquiring 413,000 net acres and approximately 336 million cubic foot equivalent a day of net production. This transaction closed on December 22, 2014, and as Bill mentioned a few moments ago, we've hit the ground running in the area and we are excited to be starting the process of extracting the value identified when we made the purchase.

In a 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 Virginia and southwest Pennsylvania. And this transaction closed 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 a small gathering system. The transaction was announced in December of 2014 was closed on January 30 2015. The WPX deal is our eighth bolt-on acquisition in northeast Pennsylvania, and one of the exciting things about this transaction is it brought significant value to the Company in multiple ways. The EPA for existing production fit seamlessly into our current Susquehanna operations and justified the purchase. When you add the value of the current transportation capacity to move additional gas out of the region on the millennium pipeline system, the deal easily pays for itself very quickly.

2015's begun with the same quick pace in which 2014 ended. While we're in the process of closing the Statoil and WPX transactions, we have been very focused on making good progress on the assets divestitures that we announced as part of the acquisition financing. For each of the assets identified for divestiture, which are the East Texas and Arkoma E&P operations, along with the gathering system in northeast Pennsylvania, we have been actively marketing the assets during the first quarter.

We have received a very high level of 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 will occur in the second quarter, as previously discussed. With that, I will now turn it over to Craig Owen to discuss the financial results from 2014.

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 noncash 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 liabilities, 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 to $879 million in 2013. This increase was primarily due to higher volumes and realized prices, partially offset by higher operating costs and expenses due to increased activity levels. For the year, we realized an average gas price, including hedges of $3.72 per Mcf, which was up from $3.65 per Mcf in 2013. Excluding 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 through fixed price swaps at a weighted average price of $4.40 per MMBtu. Our hedge position, combined with 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 have approximately 310 Bcf of our 2015 expected gas production protected, from the potential of widening basis differentials through hedging activities and sales arrangements, at an average basis differential to NYMEX gas prices of approximately minus $0.17 per Mcf.

Through 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 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 costs low in 2014, and our cost structure continues to be one of the lowest in the industry.

With all in, cash operating costs of approximately $1.32 per Mcfe in 2014, compared to $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 compression costs associated with our growth in the Fayetteville shale and 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 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 2014, 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 loan that we took out in place to initially finance the Chesapeake transaction.

As Jeff mentioned last month, we closed the two other large transactions that were announced 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 have 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, or discount of $0.70 to $0.85 per Mcf in 2015. Which, when combined with our estimated actual discounts of about zero for February year to date in northeast Appalachia and southwest Appalachia, results in average natural gas discount for March through December of $1.20 to $1.30 per Mcf in these areas.

We currently expect our total debt to 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 we'll turn it back to the operator who will explain the procedure for asking questions.

(Operator Instructions)

Doug Leggate with Bank of America Merrill Lynch.

Good morning everybody. Steve, I don't know who you want to direct this one to, 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?

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 [core] high grade you see? I've got a follow-up please.

As far as a ratio, what we've been concentrating on is the 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. Our goal is by 2017 to get it 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 would be potential disposition candidates. That would be at earliest, late this year and probably more like a 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 into a lot of details there, I'll 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 until about June of this year. You might see us sell that one, and like I said, some other small assets. Stay tuned on that one and we'll watch the year as it plays out.

Not to belabor the point, but obviously what one price of a view 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. The 2017 timeline?

I think the target for you to think about, is we will get under 2 by 2017. We will manage our business to do that. Our goal though is to be well under 2, and that mid 1.5 range. If gas price is $2.50 for three or four years, you're going to see us just under 2, rather than close to 1.5. If it is more like $3.50 you're going to see us in the 1.5 range.

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.

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.

Just to 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 the things we'd run across and the issues we might hit along the way. As Bill said, right now, we're a little bit ahead of schedule. Remember, we're only about 60 days into this.

But the other kind of restriction we had on it was, we knew for the 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 we thought was available to us. 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 built really 2015 and 2016 all the growth, all the upside is basically built around that northeast Pennsylvania. And we, as you mentioned, we have more than enough capacity there today, and our marketing group is actively, what we're not using today is actively marketing that. You'll see, just like you have in some of the other quarters, a little bit higher marketing value as you go forward through the next few quarters.

By the time we get towards the end of the year into 2016 we'll have grown into that overall firm. And from 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 what Craig said in 2016 was a low-double digit growth, low-high single digit growth, we think we can achieve that.

Thanks Steve. I appreciate the answers.

Drew Venker with Morgan Stanley.

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 2016 and 2017 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.

You know, obviously 2016 budget depends on what the gas price is and what the oil price is as you look out into the future. So 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 mean that we had pretty severe gas price in 2016 as well.

If you project that out to 2017 and invest $2 billion again, and you have another difficult year from a pricing standpoint, we're still in high-single digit growth range. We've kind of done the book ends. We're comfortable that we can give good delivery on the low side of gas price, and the other side of gas price comes back during that period time you'll see us go faster.

Thanks Steve. Just as a follow-up on the budget for 2015. The CapEx cut was pretty significant, even in just your main drilling programs. Fayetteville and Marcellus. 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?

There were three places where, in general, we made some cuts. We had some discretionary capital. By discretionary it's important, but you can do it this year or last year, and that was part of it. And that discretionary capital had no production with it.

There was re-looking at our new assets in West Virginia, and really, we just revised some things because we had some guesses going in and we know more now, and that actually revised down a little bit.

Then in the Fayetteville shale, from the original $2.6 billion capital budget, we draw from a six rigged program to a four rigged program. You can see the corresponding decrease there, that's the only place where there was any production decrease in the system. That's why the production in general could stay high where the capital was going down, as you go through. So that's the basic answer on that.

Thanks Steve.

Charles Meade with Johnson Rice.

Good morning everyone. Steve, I'm wondering, you addressed a this a bit already with an earlier question, but I wonder 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, you probably inherited some of that TETCO M-3 exposure from Chesapeake that's helping you out here in the beginning of the year.

Some of your other operators, particularly up in the northeast, have talked about projecting some price related curtailments, you know, 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?

Yes. As you said, a lot of what we have in the new acquisition is M-3 type pricing. But you know, as far as some kind of pricing that would make us shut-in wells or do something, we factored that all in to our capital budgets. I don't see anything on the horizon there.

Okay. Okay. That's helpful. And then going back to your guidance, there's a, you guys bumped up the, the oil component of our volume guidance a bit and you actually, you know, looked like you beat 4Q on that front as well. Wonder if you could talk about maybe what's changed in the last two months that led to you increase those oil volumes and what's behind it.

I think we learned a lot more in the last two months, basically. We had -- most information we were 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 the well information. So it's just having more data in the last 60 days.

Okay, great. Thank you, Steve.

Will Green with Stephens.

Good morning everyone. A few years back you know, we were talking about how, you know, in the Fayetteville drilling times had reached technical limits, you know, 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?

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, the sorts of same step changes in, technology or experience with the rock in places like the Marcellus?

I'll start with Fayetteville. You know, I think there was some discussion in the past about whether or not we reached the technical limit. I think when you've got a well portfolio, I've drilled wells that tops 4,000, you've got a lot of opportunities to learn. And our teams have just continued to better understand the rock, have better placement of the lateral's, and be much more accurate in those drilling plans and 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 latter time, technology is beginning to help us with increased capability on those rigs. And then it's just continuous learning.

We are moving a couple of rigs northeast, some in Marcellus, northeast Pennsylvania and some in southwest Appalachia. Already we've seen drilling improvement times in northwest Pennsylvania from our learnings in the rock, our learnings from what we picked up in the Fayetteville, and our drilling teams that are moving up into that region. So we've brought drilling days down and continue to bring those down in the northeast.

In southwest, a 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 you know, this is, again, leveraging some technology, leveraging some experience, and just getting better and better at the understanding of the 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. So you see in southwest Appalachia for example, we've changed the number of rigs, and it's more driven by the fact that we believe we can learn even faster than we projected, and we will drive those times down.

Great. And then I apologize if I missed it in the prepared remarks. But you know, when I'm thinking about the 50 to 55 wells you guys are looking at in southwest Appalachia, obviously there's 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?

I gave out the kind of counties. We're primarily targeting the Marcellus, and the wet areas of the Marcellus is the real objective at this point in time. You know, in the future, as we learn from industry, as we get ourselves up and running, up in that area, we'll obviously be looking at the Utica and some of the other areas. But right now for 2015, absent some, a couple of leasehold wells, we are targeting the wet portion of the Marcellus.

Let me add, I don't want anything to think we're bullish on the liquids. We're targeting the wet area, because that's where we have the gathering systems in place and the processing in place, and we'll 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 that, basically except for the conventional, little bit of conventional, is Marcellus. We only have one well total on our reserves that's Utica. So there's a bunch upside there in the future for all those horizons.

Great. I appreciate the color guys.

David Heikkinen with Heikkinen Energy Advisors.

Steve, you 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?

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's, there are four different gathering systems, one is with a conventional and there's three other gathering systems. They have gaps in them, they need to have kind of a strategic look on what's there, and then there's a significant amount of the 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 will look hard at using our midstream and our abilities to do part of that.

Okay. And then, on the same thought of updating type 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 internal new updates as far as your southwest region type curves?

That might be a little bit early, but maybe. Certainly in the second half of the year, the wells that we're drilling right now, they get put on in the second quarter, get put on basically right now. You barely can make that September timeframe. But by the end of the year you certainly could.

All right. Thanks guys.

Jeffrey Campbell with Tuohy Brothers Investment Research.

Good morning. You mentioned, 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 the 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?

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, we really can't tell you much about 2014.

Okay thanks. At least the well count, that's helpful. In your reserved areas, we talked about southwest Appalachia as 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 old acreage over the next several years?

About half the activity, I think in 2015, will hold acreage of some sort. About maybe a third of the activity. It's not that big on any given year, it's very manageable. We also have the ability to extend leases as we normally do lease extension provisions or leasing agreements.

Okay. Thanks very much. Appreciate it.

Michael Rowe with Tudor Pickering and Holt.

Hi, good morning, I just wanted to dive in a little bit more on liquids pricing. You all, I think previously said, you expected 33% realizations for NGLs relative to WTI. How has that really changed in terms of your updated guidance?

It hasn't. One component you make sure you include in that as well, there's a transportation deduct on the NGLs of about $6 that we'll include in that as well. As Steve said, it really hasn't changed.

Okay. I guess on the same note then, in terms of the drilling economics for your wet gas Marcellus and at $2.75 Mcf world, curious to see if you could talk about your anticipated returns, where the liquids prices are today?

You know, I'll make a general comment about every one of our areas. Not just there. What we will do is the same thing we did in 2012, where we, we high graded, and by high graded, when we moved on a pad we drilled the very best wells on 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'll do that in everyone of our areas.

So this year is a high grade program, there may be a little bit of inefficiencies in there, you may have to go back to a pad in the future. Every well we drill in this environment we'll do that.

Again, with that, you have to have some kind of assumption about costs. We're using this year, roughly $3.25 on the gas price, $3.75 next year and $4 flat forever after that. I think we're using $60, give or take average, over the next three year oil price.

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 declining service costs, high grading or both?

It's a function of better wells than even we projected when we did the budget. We did take, included in the capital budget for northeast Pennsylvania was some additional land and other nonproductive bearing type capital that we just pushed out. And so, you had better wells that raised the production, the capital changes were really not drilling and completion related.

I think, somebody else has mentioned something about service costs, we really have not adjusted anything based on guessing on future service costs. 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, future drops in them.

Okay great. That's helpful. Thank you.

Bob Brackett with Bernstein Research.

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 dropped out.

Was that an oversight? Or are you going to bring that back? Because I miss it.

You'll see it next week. What happened was the release is getting so large. We had one for the northeast Appalachia and we had one for Fayetteville. When we put out our new IR material next week, you'll see both of those tables in there, and it will have the quarterly data in that overall. So stay tuned on that part.

Great. I applaud you for that disclosure. The other quick one, BHP was selling their Fayetteville. Looks like no one wanted it. What kept you from being interested in that asset?

I think the biggest thing that kept us from being interested is that we just about a $5 billion acquisition. It was really the balance sheet more than it was the asset itself.

Okay. Thanks.

Neil Dingmann with SunTrust Robinson Humphrey.

Most of mine have been hit. A couple of things very quick. On slide 8 and I think Doug was talking about this earlier, where you guys talked about sort of the take away and what's going on. I guess just two things I had.

What's your thoughts about the take away in some of the newer areas, especially as you look down south around Upshire and Lewis county. Will it be more than, are you bringing more infrastructure and take away in that area as well. Just try to get an idea of where the infrastructure. I understand the lines coming on, but I'm just not quite certain on how they're going to, or what regions they are going to tie up to.

You're talking about our gathering infrastructure?

Yes, sir. Yes, sir.

Yes. I think we'll talk in more detail about that. But there's going to have to be some kind of a backbone run north south across our acreage and around our acreage. Where exactly it goes I don't know. But we'll -- it'll certainly head that direction toward those southern counties.

There is a small gathering system there already. But it certainly doesn't have the capacity to do what we want to do. And 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 a north south line that kind of runs across to four or five counties there.

Okay and then just lastly, on that slide 26 it shows the northeast Appalachian just the type curves there, what do you guys kind of, I guess now if you had to sort of estimate curves? Is it still trending? To me it still looks like they're trending pretty close to that, I don't know the 12 [D's] or so.

It does look a little bit different, I guess in this slide deck versus looking like September and some of the back drops maybe, if you could just comment on some sort of how you forecast some of these northeast Appalachian type curves this days.

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 drilled a lot of the Susquehanna wells. But other than that mix and the discussion that Bill had about the fact that we're getting very good wells, there isn't anything fundamentally changed. The EURs are up a little bit, because we know more about the wells is really what's happening.

We have upgraded the completions as I talked about before, and our landing, the quality of our landing end zone in our village has improved quite a bit as well, so we've optimized where we land, staying in zone the whole way and profit [loading] as we talked about earlier.

That helps, that's a great point. Thank you.

Dan McSpirit with BMO Capital Markets.

If you could clarify the 1.4 Bcf a day in Appalachian firm transportation includes capacity on constitution, correct? If so, can you remind me of that amount, as well as the overall cost of the capacity in place?

It does not include it in 2015 and 2016. We've had nearly 1.4 today. But in late 2016, we assumed constitution will come on, and that's 150 million a day to us. What actually happens, some capacity we have today falls off as you go through 2016 and constitution comes on, and it's basically kind of flattens out about 1.4 once you're there.

Great. Then just the overall cost of that, of that capacity?

Our weighted average costs for all of our portfolio up there is right about $0.36.

Okay great. And then a follow-up, if I may? And maybe a more theoretical question on capital efficiency, however much that may be an over used term these days.

If the Company, like other producers, drills the best locations today in light of low commodity prices, what does that mean for capital efficiency in the out periods? That is, would it naturally decrease as the remaining locations and inventory are say of lesser quality, holding all else constant?

Yes. Certainly it would. You know? And part of the reason we did the acquisition is that, that acquisition has a large amount of running room with a large amount of high quality wells in them. But certainly if you drill your very best well first, the other ones are going to be a little less than that well. So you will see that, whether it's for the industry, or for our Company, or for an area, you'll see that happen all the time.

Got it. Thank you.

Brian Singer with Goldman Sachs.

Thank you. Good morning. Wanted to follow-up on the impact of commodity prices and costs on your longer term growth strategy. In late December you showed production in 2017 being up about 1 bcfe a day versus 2015, I believe that was run at $4 for a couple of years and then and $4.50 in 2017.

You mentioned you're not ready to make a statement on costs. But can you just talk to whether you feel like you could still achieve these targets? And what gas price you would need to meet those objectives?

Well, I think to hit those exact numbers, we need about the gas price we put in that sheet, actually. And I'm not sure about the $4.50 in 2017. Whatever you hit in 2017 was really based on 2016 wells and early 2017 wells.

But, you know, long-term, we said this several times, we think we are in a $4 world. And in a high $3 low $4 world we think we can hit those targets and all the stuff we talked about before, if it's a low $3 world, what do we do in that world.

Got it. And then, assuming the bulk of that incremental production comes from Appalachia, I know not all of it is natural gas, how much additional firm transport do you need to achieve those targets? How much do you expect to use the local market? Because it seems like, incrementally, there is only a couple hundred million a day you have locked in right now.

Yes, I think between now and, end of 2016, we will, when you say local markets, I won't quite describe it, what we will do is work with other operators who have excess capacity, and use their capacity. And so, I think on a percentage basis selling into what you call a daily market, isn't going to be that high a percentage. And we think there is plenty of excess capacity we can work on between now and 2016. You will see us in the near future commit to probably close to 1 bcf a day, that would be the 2017, 2018, 2019 type time frames.

Then really, we believe the market's changing a little bit, and historically we've talked about the fact you have to have firm. There's some point we believe in the not too distant future, the northeast will have more than enough capacity from a take away standpoint, and then firm isn't as important.

So one of the things you'll see us doing, whether it's the 1 Bcf that I'm talking about, or any other firm that we might think about adding on top of that, we'll be looking at the shorter contract term life, not necessarily the 15s and 20s but more like the 10s, and we'll certainly be watching very closely the cost and where that's going to as we go through. Because once you do have all the capacity you need, then the firm isn't as important, and it actually becomes an issue if you paid a lot for it or you have a long-term timeframe on it.

So, we know we need 1 Bcf a day, we know somewhere around 2020 we could certainly be produced 2.5 plus Bcf a day out of that new acquisition. So there's 1 Bcf we need, and we'll kind of sort through what else we need after that.

Just since the acquisition closed we picked up another $175 million a day on a three-year term. So we're, our guys are out, opportunistically picking these up. So we're very comfortable with -- we can continue to do that.

Sorry asking a last follow-up. Can you talk what the cost of those incremental projects are, relative to say that the cost of underwriting a new pipeline out of the region? Or reversal?

I won't talk a lot about it, just to say that since these are committed by other companies, and it's available today, their price was low. So you're talking $0.30 type numbers or $0.40 numbers, you're not talking $0.50s or $0.60s.

Thank you.

Ladies and gentlemen we have reached the end of our allotted time for questions. I would like to turn the floor back over to Mr. Mueller for closing comments.

Thank you. When I started the call today, I talked about the differences that happened between this time last year and today. You know, while there's a lot of differences, I also talked about the consistencies that make us a premiere company.

We've talked about it. We've got world class assets and advantageous geographic areas, operated by a 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 you know, we don't just plan, we prepare. And we prepare for what might occur when the plan doesn't work. And really, when the plan doesn't work.

If change is required, we know what 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's high volatility. And I think what you see in 2014 with our records, what you've seen over the last three years with what we've been able to do, has proven that ability of planning and staying prepared as we go through.

More proof of 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.

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 good day.