Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

National Fuel Gas Company (NYSE:NFG)

Analyst Day

September 9, 2011

Executives

Dave Smith – Chairman and CEO

Matt Cabell – President, Seneca Resources Corporation

John McGinnis – SVP, Seneca Resources Corporation

Barry McMahan – SVP and Secretary, Seneca Resources Corporation

Ron Tanski – President and COO

Anna Marie Cellino – President, National Fuel Gas Distribution Corporation

Dave Bauer – Treasurer, National Fuel Gas Supply Corporation

Dave Smith

Good morning. Thanks for being here. We appreciate it. I know you’re busy, so thanks for taking the time to be with us today. Welcome to our Annual Analyst Day with a new fiscal (ph) number years. And you know, in the past, generally we took the opportunity to review the past year. Last two years we looked at, look forward a year or so and previewing the next year. This year we’re going to take a step further and we’re going to spend some time really looking over the next three years where we expect to be in three years from now. And really, obviously we’re going to spend a lot of time talking about our plans in the Marcellus.

Now, this is the agenda. I’ll provide a quick overview and really set the stage for the growth discussion. Matt who’s the President of Seneca, now he’s going to give an overview of the E&P Segment, John McGinnis, who many of you know, appears he’s the Head of our Exploration program, he’s Senior Vice President. And he’s really going to look at how we delineate our Marcellus acreage, what we’re looking at ring, for example, Utica Shale and the Geneseo Shale. Our new players, Barry McMahon, the Senior Vice President at Seneca, In-Charge of Operations, and he’s going to talk about our drilling operations. But in particular, he’s going to spend some time talking about costs and what we’re doing on the cost side to bring the cost. He’s also going to spend time talking about the environment and our commitment to the environment.

Ron Tanski, is going to do double duty today, and I know almost all of you know Ron, Ron’s the President and COO at National Fuel Gas Company. And he’s going to really update us on the pipeline in storage segment and also the Midstream segment and really emphasize the number of projects that we have in that arena, where we’re building infrastructure to move gas to growing markets in the east into Canada. Anna Marie Cellino, is going to talk about the utility and in particular the contribution of the utility, the financial contribution of the utility to National Fuel. And then Dave Bauer is going to wrap it all up. We are going to tell you how we plan to pay for this, over the next three years and increase our CapEx significantly but yet maintain a strong balance sheet.

Now, before I do that, I’m compelled to discuss our Safe Harbor slide. And by the way, for anybody who’s listening and you want to follow along with the slide, you have to refresh if you login before I think 7:45, so you have to refresh in order to follow along on the slides.

Now our presentations today are going to contain forward-looking statements that may vary from actual results. And they also contain non-GAAP financial measures. For more information, please refer to our 10-Q.

Now, most, probably all know that National Fuel Gas Company is an integrated gas company. We’re in regulated businesses, we’re on unregulated businesses. We’re from the well head to the burner tip, one of the few companies left. Seneca Resources, our NT subsidiary, well, it’s focused right now on growth and appellation. And our emphasis obviously is on our 745 acres in the Marcellus. And that should be overlooked as great oil assets that we have in California and frequently there over, we’ll talk about those a little bit today.

Pipeline and Storage segment which is Empire and Supply, they’re both FERC regulated. And they’ve been very busy building infrastructure and planning infrastructure to move Marcellus gas to market. And in the meantime transforming their system, I mean, there are a number of projects on the horizon. But really, probably more importantly we’ve been transforming our system from a north to a south system, where gas came in from the north and went south to a bi-directional system where it can go both ways. And we started doing that, we started looking at doing that a few years back, in part to take advantage of the strong market in Canada and that has very long term implications for National Fuel Gas and Ron Tanski is going to spend time talking about that today.

The Midstream is much as the same although it’s on a non-regulator ground. They’re putting in gather systems, primarily now for Seneca, they’re focused on Seneca but working with other producers as well, and we see that as a great business moving forward.

On the utility side, we have 728 or so customers, perhaps just the most underappreciated in our system from the financial perspective. But they’re really focused on customer service and safety and we won’t spend much time today at this seminar on because, this is a financial seminar essentially. But there in terms of their contribution or stable predictable cash flow, in order to do that, they are focused on cost controls they are focused on protection of revenue.

Now, we’d like these businesses and we like the standalone businesses. But we really like the way they fit together and we have for a long time, we very much like the model, we now have. And it’s taken us some time to achieve that. Some of you will remember way back when we were professionally a utility company. And then we had a work to grow the pipeline and storage and grow the E&P, and we moved through that. Then, you know, we sold our assets, our international assets, some of you may remember we had international assets and we sold those and we sold our Canadian properties, because they just didn’t fit. And more recently in the past 12 months, really past 15 to 12 months, most of them in the last year, we sold these companies. In fact that they wanted good companies, they were good companies but they were relatively small with relatively limited upside, the Gulf was relatively high risk for National Fuel Gas particularly compared to the Marcellus into California. And most importantly we’re able to focus our attention, our management attention and our financial resources, this has freed up some $200 million of capital to put into the other businesses. So, we like this model. And these are the companies we intend on continuing into the future with, obviously as the company changes its nature and it will, because we’re putting so much money into E&P, we’ll re-visit this down the road. But right now, this is the model that works for us.

It works and we know everybody doesn’t agree with this model but we see the advantage of it on a day to day basis. You know, how these subsidiaries work together to strengthen each other, to help each other. I mean, neither just some examples from an operations perspective where the pipeline to storage network, they did bring assets, and more importantly the capabilities in those arenas, greatly if Seneca can bring its production to market. You know, we have a very few wells shut in because of lack of infrastructure and as many of you know, that’s not typical when the Marcellus. And that’s because we’re able to work together with our subsidiaries.

NFR, our gas marketing company, which by the way, it doesn’t really speculate at all, the kind of market around that sense, it packs everything up. It sells gas to retail customers and pass that up. Our gas marketer, our utility, our two are two of the largest customers on our pipeline to storage system, in capacity and in storage. But perhaps, more importantly it’s the shared resources. I mean, we share facilities, we share rights away, we share systems, we share employees and allocate them across the subsidiaries. And this provides us with a terrific efficiency and an advantage, not only for our shareholders to company, our National Fuel Gas Company but for our customers as well. And there are numerous financial benefits to the model, we think that this diversity of earnings, this mix has allowed us to outperform, markets outperform our peers over the long term. In large part, it’s due to the mix of the regulated earnings which are very predictable, not commodity sensitive we pretty much know what we’re going to get on the regulated side. That provides some downside protection, but that mix with the opportunistic, upside opportunity, particularly in E&P, we think has helped us in the long run.

And, you know, I’ve talked about the pipeline and storage, and how that works together from Seneca’s perspective because of the rates in the pipeline and storage and Midstream perspective, because they know they have a good customer. If Seneca hand up for capacity, they can put the pipe in, and they know they can put the pipe in. And perhaps most importantly this mix, this diversity has really allowed us to have a low cost to capital for all of our company and that’s very helpful for our growing companies in particular.

So, let’s see just some of the advantages, needless to say, we like the model and more committed to it moving forward. As I said, we’ll spend most of our time and these speakers will moving forward. I just want to take a few moments to talk about the joint venture process that we just went through and really why we’re just starting up and move forward with this. There were a variety of considerations involved obviously, potentially a very large deal and it was certainly a very large deal and it was certainly a very large National Fuel Gas Company and we have a number of moving parts, all of those were important and these are some of the most important up here and, you know, that it concludes the price, the carrier, the operational control, who was going to control the operations, that was very important to National Fuel Gas. It didn’t include Utica if it did it, with the Utica excluded. The footprint, what was beside across what acreage position, it wasn’t across all the acreage, it wasn’t across the portion of the acreage. And what we call risk allocation, and that could include a lot of things. But in particular, there were just a lot of discussions about exit graphs. And we wanted to make sure that any joint venture partner was equally sharing the risk with National Fuel Gas.

And so, many I think, I think a focus of many analyst was on the price, was on the evaluation, the price on the carrier and in some speculation that we really didn’t receive the price per acre that we expected to receive. And the fact of the matter is what we talked about is, we talked about two deals where we are relatively close that we almost, that we’re very close to doing a deal twice. And with respect to those evaluations, we’re, you know, we wouldn’t have gotten to their point if we weren’t comfortable with evaluation. And I expect our, our expectation of evaluation higher than many of the write-offs that I read. I mean, we expected a very good price per acreage, why? We think we have great acreage. You know, we have compelling growth plans. We knew that. And perhaps, most importantly, we knew we can do this without doing the joint venture. We have a pretty good plan moving forward, we found to joint ventures. So, that essentially allowed us to trade hard, it allowed us to basically look for a very good price per acre. And frankly, allowed to say no and to move forward.

But also there were some other, it wasn’t valuation and knows to deals as the deal breaker, there were some other things, things like extra graph and thing of that nature that caused us more problems in terms of moving forward with. But, you know, I’m sure you will have some questions on the joint venture later but, quite, that’s pretty much why we didn’t move forward. We got in those two phases, evaluations, we were happy about.

Now, we talked about our plans for growth and obviously those revolve around to Marcellus, you know, in pipeline and storage and Midstream and E&P. So, which kind of growth we’re talking about, what are we looking at, what are our expectations, what do we expect of it?

Well, we’re looking at a significant increase in our CapEx, 18% a year over the next three years to about $1.6 billion, 95% of that will be spent in appellation. And to put that in some perspective, just 3 or 4 years ago, our total CapEx budget across the whole company was about $250 million and almost none of it was spent in the Marcellus. So, moving ahead with CapEx, production we’re looking at 40% per year growth on the production side and that’s generic growth by beyond 2014, we expect to be up to 200 Bcf a year.

Pipeline and storage, we’re looking at same kind of growth, 20% increase a year in throughput, I think last year we were maybe 305 Bcf, we’re looking at about 600 Bcf in 2014. And frankly the bigger volumes come after than when east or west comes on but that would be after 2014. So, we just think the pipeline and storage segment is really going to provide us with some good long-term opportunities. Now we can also do all of this without doing violence to our balance sheet, you know, we expect to maintain a 55 to 65 capitalization ratio, we expect to be there, we will tell you how we’re going to get there and yet spend all the money that we’re talking about spending here. And we expect to double cash from operations over the next three years from where we are now. So, those are just some pretty aggressive lofty expectations, it’s easy for me to get up here and say that’s what we’re going to do. Now the rest of the speakers are going to tell you how we’re actually going to achieve that. So, thank you.

And with that, I turn it over to Matt.

Matt Cabell

Thanks Dave. By most measures Seneca is a relatively small E&P company, except when you measure us by acreage or resource addition. We have one of the largest positions in any company and what is arguably the most important natural gas plant in the world today. We also have resource potential, risk potential to 10 to 20 times, offered reserve base. So, it makes for a very compelling growth story. Then we’ve put together a talented and experienced team to execute our growth plans and we’re going to hear from to the leaders of that team today, and they’ll handle the bulk of the Seneca presentation.

A few points upfront, we are not at all the same company that we were just a few years ago. Our production reserves are expected to triple or quadruple from 2010 to 2014. We’ve held over 700,000 acres in the Marcellus before the play really received any attention. And since then, we’ve added another 40,000 acres in the quarter to play. In addition, the Marcellus, we have potential in both the Geneseo Shale and the Utica Shale, John will talk about both of those later today. And to balance our potential on the National Gas side, we have the outstanding old properties in California that provides steady production and cash flow.

Okay, if you look at where we were a few years ago and where we are today, I mean, in 2006, 70% of our capital went to exploration drilling and the Gulf of Mexico in Canada. Since then, we’ve sold Gulf of Mexico, we sold Canada, and in 2011, 90% of our capital has gone to the Marcellus Shale.

Production in ‘06 to ‘09 was declining and from 2010 to 2013, we expect that production to triple. Our three year F&D cost from 2006 to 2008 was $7.63 per mcfe from ‘08 to ‘10 it was $2.37 mcfe.

We have a relatively modest reserve base at this time. But, our resource potential is huge, we have 8 to 15 tcf of potential in the Marcellus, and we haven’t quantified the resource potential and the Geneseo or the Utica, I guess the way I would look at the Geneseo is we have 300,000 acres that will likely be open up a developed with shared infrastructure with the Marcellus, it’s probably lower a priority around Marcellus but it’s still likely to be developed over the long term. The Utica Shale, we’re still in a very early stages of exploring the Utica, we’re not prepared to provide any resource potential numbers there yet but John, is going to be talking about what we’re doing there.

And our finding and development costs has dropped pretty dramatically over the last several, this is three year F&D costs, those of you who have seen the recent Herald’s performance metrics that just came out, the 2008, 2010 numbers for the entire universe the companies was something in order of $3.80 and for gas waited the companies it was $2.43. So, we’re, at this point, we’re a little better than average on the gas waited in that universe, I expect that will continue to improve as we dedicate more of our efforts to the Marcellus.

If you look back at the past decade, the first decade of this century, we had a steady, slow decline in our production. And you could see that tract back all the way but it was greatly a steady slow decline throughout that decade. If you look at this decade, we’re looking at very, very rapid growth, probably in excess of any other company, our sites are bigger that you could pick from. Of course, with that comes increased capital spending. This captures what we know today, what this resale is spending and actually the pre-tractly that as well, spending and production that may come from the Unica for other new employees.

We’ve talked about this before, it’s important to understand the economic benefit we get from our mineral ownership, we own the minerals on about 80% of our acreage. This tract would represent the greater return for a typical well on our western acreage. You know, western acreage that’s where we own most of the minerals, this would be a $6.2 million well with say, 15 to 18 tract stages on our 4,500 collateral. From what you can see is that even at 3 bcf, we’re looking at 16% greater return. In addition to the economic benefit we derived from the fact that we pay no royalty, we also have minimal cost in acquiring that acreage and of course in addition to that, we’re not in the position that many of our competitors are in where they’re drilling wells, scattered wells all the acreage, they’re not getting them online. We’re able to develop this very efficiently. We pad drill all of it. And we could create economies of scale by doing that and Barry will talk about that some more, later.

These two graphs show our rig count and our well count for the next several years as we see it today. Our Marcellus point is relatively simple. We’ll aggressively develop our Tioga and Lycoming acreage. We’ll systematically evaluate our western acreage which we’ve been doing for the last year, we’ve identified areas that we will be developing and we identify more areas while going to the development mode. And of course, in addition to that we will participate with EOG in a joint venture as we happen.

And with that, I’m going to turn in over to John to begin with the details of Seneca’s finance.

John McGinnis

Thanks Matt. Good morning. All right, what I’d like to do today over the next 20 minutes is touch a little bit on our results to date on our plan forward within the Marcellus. Then I’d like to introduce to you, I think really for the first time, a little bit, our view point of some of the technical issues, the geotechnical issues that we’d run into within the Marcellus and how we think about that. And then finish up with just a quick snapshot of both the Geneseo play and finish with a couple of slides on the Utica.

With that, this is our leaseholds which were on the slide many times, it’s really broken into two pieces, one, we call the eastern development area which is really, almost entirely leasehold and really dominantly 10 year leasehold and then our core acreage which we call the western development area and it’s essentially mostly T acreage or held by production and what leases we do actually have there and within the Marcellus itself about 745,000 750,000 acres.

Here is a snapshot I’d like to talk a little bit about our results today within the eastern development area and then our plan forward. I’m going to go through each of these areas sort of to give you a sense for where we’re headed our Covington is essentially developed. We have 47 wells there. We have drilled out 47, 44 of them have been completed we’re in the process of completing our last three. Our gross production there is north of $100 million a day. And EUR average that we’re seeing here is about 5.5 bcf per well.

DCNR Tract 595 to the track that we picked up a couple of years ago, that’s now also in full development. I think at this stage, we actually have four rigs there. But really through fiscal year 2012, we’ll average anywhere from 2 to 3 rigs. We drilled that we have 6 wells drilled, 3 are actually producing and we’re currently doing $8 a day, once you get that shut, that shut down will back be about anywhere from $10 million to $12 million a day. But we’re in the full development mode on this track now.

DCNR Tract 100 again, full development mode. As you guys probably remember, about a year ago, we drilled our first well there and tested that I think it was like a five day test. Test had almost $16 million a day. For our fiscal year 2012, we will have at least one rig within this block level, a rig currently there. We are planning on shooting some 3D seismic there because there are some major fall through there and I think once that is completed, we may even add a second rig at that stage.

DCNR Tract 007, we’re in the delineation phase here. We have drilled one well, and honestly it was a disappointing well, and I’ll actually talk a little bit more about that later in the talk. We have just finished acquiring seismic this summer. And in our fiscal year 2012, we’re going to be drilling three verticals and then four additional horizontal wells in that track.

And let’s finish up with the Potter, DCNR Tract 001, the cost on the delineation phase, we drilled two wells there, one was in the Marcellus, it tested about $4 million and the other one was in the Geneseo that had a peak rate at almost $3 million a day. We have also just acquired 3D there, this summer as well. And going into next year, we’ll be drilling at least two horizontal wells in this area. Currently we’re waiting for pipeline hookup which should happen either this month or next month to get those wells producing.

I’d like to touch a little bit now on our decline curves that we’re seeing in the EDA. And really this is driven by Covington considering that’s our most, the bulk of our wells have been drilled. This is a part that shows all of our wells are greater than 3,500 foot lateral and going forward both in the EDA and the WDA that’s going to be pretty much, we’re looking at minimum 3,500 preferable 4,000 to 5,000 feet. We have a 6.7 bcf EUR there and I’d like to go a little bit to the history here. About six months ago, I think we announced that we’re seeing 6 bcf, type curve there I think that’s at a little bit higher, just a little bit over $7 million a day with a 72% decline. Since then, we’ve done much more I guess longer production on there. And we’ve added compression to the field and that’s changed our type curve, we’re bringing these wells on a little bit less aggressively they’re coming out about $5 million, $6 million a day, but the decline is less rapid, we’re only seeing about 65% decline, then once we add compression about 6 months in, we get another production bump, we’re now actually seeing an increase EUR with respect to these wells, so pretty nice. But, one surprising thing for me is, see if this works, no that doesn’t work, all right, now I’ve messed it up.

All right, well, let’s see if we can, I may need some help here, in a second. And I’m the technical guy. The thing that surprises the most to tell you the truth is that is the very ability that we saw across Covington. We saw a range, you know, we’re thinking in area here that’s maybe 4 miles to 5 miles and we saw a range of anywhere from a little over $2 million a day IP to as high as $10 million to $12 million a day IP. And that’s one of the things we’re going to be looking at over the next few months here when we do our Covington look back and what’s driving that range in results in our wells. So, we’re going to be looking at the geologic both completion designs, change in geology, but that’s something that we’re going to be looking at pretty hard to actually understand why do we see that variability. And honestly we see that variability across most of the basin. So, it’s not just going to be in Covington we’re going to see it in many different areas as well.

Okay, the next slide, we’ll jump over into the western demonian area, again to talk a little bit about the results and our plan forward going into the next fiscal year. As everyone here knows, we have a JV with EOG covers about 200,000 gross acres. There we have a 30% working interest and roughly a 60% net revenue just on that. UGs and the full development within the Pun City, which is in the southern area, so you can see down to the south, they’ve built 45 wells to date, 25 of them are producing. Through our next fiscal year, they plan on having a couple of rigs and they’re looking to drill about 30 to 35 wells within the Pun City area. They’re also in the delineation phase and what we call west branch which is further to the north. And then Boone Mountain which is also further to the south. In Owl’s Nest, that is, these are properties that Seneca is operator on. And we’re now moving them to the full development mode on that and I’ll get into a little bit more detail about this in a bit. We’ve drilled three wells, and really those three we’re looking at optimizing the target zone, we’ll have anywhere from one to two rigs in Owl’s Nest throughout next year. We’re looking to drill 15 to 20 wells. Our expected IPs are going to be between $4 million and $5 million a day. And we’re in the process of acquiring 3D as we speak.

Mount Juliet, an area we’re still delineating, we’ve just finished up three horizontal wells, and we will be completing those both this month and next month. Boone Mountain, we also just completed three horizontal wells and we’ll be completing those in October and November, that rig will be moving to Rich Valley, we’ll be drilling two wells, this would be a new area for us up in that part of Cameron County. And we also drilled three wells in Beachwood and we actually had poor results there. And based on what we’re seeing in terms of the completions, we think there is an essence of natural fractures, whether this is a local or regional phenomenon, we’re going to, the next step for us to get in there and shoot some 3D seismic. We’ve seen that there are quite a few localized areas where you can missing these natural fractures and that definitely makes a difference in how you develop these wells.

So, let’s talk about some of the geotechnical tees that we view key to success. Really the first four, I’m going to talk about for the next few minutes. We have found at least over the last three years that each of these are becoming more and more important. The 3D seismic data, four years ago, I would have said, you know, it’ll help us with the structure but we’re finding that has more and more importance as we go forward. It impacts when we got our surface locations, how our lateral lines and our target zones. In many cases we found the holes in structure, we can’t image on the 2D data, so 3D is necessary. In addition we’re doing quite a bit now of attributing fracture analysis to determine whether we can actually see the natural fractures and predict stress regime and I’ll show you some evidence for that going forward as well, pretty interesting slide actually. Natural fractures are key, if you don’t have your natural fractures, it’s very difficult not only to get a good track of but then you, it certainly impacts your initial production and your ultimate reserves per well. And we do see a lot of variation both locally and regionally with respect to natural fractures.

Target zone that also varies by area and when we go through these delineation phases, that’s one of the things we’re looking at, we’re testing each, we’re putting, our geologists are putting force a number of candidates and we’re drilling those three wells and we’ll drill each well in a different zone based on some of the parameters that we’re looking at. And then stress regime, that also impacts our completion efficiency, it’s something that we haven’t had that big of an issue out in Tioga but looking at closure stress is key in order to drill and bring wells on at decent rates in the western area.

So, let’s start with the 3D seismic data, we have completed almost 200,000 acres to date over the last couple of years. Pennsylvania is interesting as three or four years ago, that was essentially almost no 3D data and honestly by the end of the decade, within the next 10 years, probably the entire state will be covered. We have a number of surveys in progress, three of them and that will add another 130,000 acres. And as I said before, it’s key to, as we move in to the full development mode in each of these areas, these 3Ds are key for us in order to accurately land, understand the pressures being, understand the natural fractures and so on. And I’ll show you an example of that here.

So, let’s go back to the DCNR Tract 007, we drilled this about a year ago, maybe less. And this is a block that’s in Tioga. It has the Tennessee gas pipeline goes right through the middle of it, you can see that across. We drilled the first well and really what drove our surface location here as we wanted to be pretty close to the Tennessee pipeline access, it’d be a lot cheaper to get pipeline into that line. We drilled it and it was a difficult tract which surprised us, we hadn’t seen that in Tioga before. And it tested at only $2 million a day. So, a bit of a surprise, so we took a step back and we said, let’s get some 3D across this. And so we did. And the major question was were we lacking fractures, natural fractures across this area. So, our first look when we got this, we got the 3D, we did the fracture analysis that we do in-house and sure enough it appears that actually the tract is quite dense with natural fractures all over it and that’s what we’re looking at these discontinuities that are in grey and blue. We see these in Covington, and that we’ve seen, we’ve tied them this to some of our wells in terms of production. So I think they’re a legitimate but time will tell, we’re going to be testing this to make sure that what we’re imaging is truly discontinuity is across this tract.

But what surprised me the most is the one area we’ve put our well was an area where we saw minimum or no natural fractures. So, we’re going to come back in here this summer. We’re going to be drilling three verticals. And basically the other portions of this tract and we’ll be looking to drill at least four horizontals going into next year in this tract, so I think we’ll see a different picture there but anyways, interesting learning curve here.

Now let’s jump back to the western area, this is Owl’s Nest, and we talked a little bit about closure stress and target zone in our delineation areas out west but we focused on this a lot, this has been a key point. Our early history has shown that if we land a well in a very high closure stress regime, the tracts are very difficult to initiate, you get very little width and rather than saying in zone, most of the energy were just run out, they just go shallow very quickly. So, we touch very little source rock at all. So, closure stress is key in terms of avoiding it and now you can.

And then, in terms of target zones, we’re identifying based on rock quality and brittleness and avoiding the high stress regimes. And this is a perfect example, this is in Owl’s Nest, we had two different targets, one was in what we call the Walker Creek with the upper Marcellus and the other was in the Union Springs in the lower Marcellus. And there were also those wells the 3H was the one that was within the Union Springs and it was by far our best well. And so, we think that, we feel pretty comfortable that the Union Springs is definitely where we need to target within the green zone that you see in this slide. We had to treat a lateral length of the 4,400 feet, this peak rate of about $4.5 million a day, a three day average of $4 million, just a little bit over $4 million a day. And compared to the other wells that with the Walker Creek, this well is anywhere from 15% to over 30% better than the other two wells. So, we’re pretty confident here that this is where we’re going to go.

The other thing is and you can see why we’re going to acquire seismic data, you see there is a little sync line in the middle of this line that was difficult to image on 2D data. So, as we move into the full development mode, we’ll be acquiring 3D across the entire area before we do that. And this will dictate a little bit of where we put our surface locations, as well actually put it right on top of that so we can avoid it. So, we’ll get many more stages within the correct sound at that stage.

All right, this is a snapshot and a table form of how, our current view of our acreage position. I’m not going to go through all of this. I’m just going to touch on, as I said before, Covington, we’ve essentially developed we finished development on that. We’re in full development in four different areas and that’s DCNR Tract 595 and 100. We’re moving into full development in our western area that’s Owl’s Nest, Ridgeway, it’s a huge area, about 90,000 acres. We have identified potential locations of almost 700, somewhere 650 and 700 locations. So, this can handle quite a few rigs. And then, finally the EUG operator during the full development down in the Pun City block, we built 45 wells there to date, and I think have bought 120 to 130 wells.

So, moving forward into fiscal year 2012, DCNR 100 and 595 are going to have a lot of our attention a lot of our CapEx is going to be going into these two blocks. We’re going to continue to drill delineation wells and 007 and 001. In the western development area, Owl’s Nest is moving into full development as I said before. And we’ll continue to do the delineation in the rest of the WDA, hopefully, Mount Juliet and Boone Mountain will give the results that we need to go under full development there as well.

And then finally, the EUG, operated you know, we continue to participate with them, it’s a great deal for us with our 60% NRI and 50% working interest and they’ve been quite successful and very active. And then, 2013 I can go through that you guys can rewind.

Finally, I’d like to sort of touch a little bit on the Geneseo and finish up with the Utica. Geneseo has seen lease in our areas, we’ve seen some activity. Each resources, now Shell and PGE have been permitting and have drilled some of the wells, I don’t think they’ve announced those results yet or well, I haven’t seen them. We drilled two wells, we drilled in a vertical in Mount Juliet, we didn’t test it, as more just take a look at the rock quality and do some core and log analysis. And then we drilled a horizontal over in Potter County, just to take a look at it as well. You can see what kind of depths, from 5,000 to 6,000 feet, thickness is ranging from about 75 feet north of a 100, the organic content looks really good that’s what attracted us. And we tested the one in Potter it had a peak rate of about $3 million a day and a seven day average of about $2 million a day. And as Matt mentioned before that we see this is potentially being developed as we move in and begin to develop on Marcellus. But as a standalone, I just don’t think at least early on I don’t think it’s going to be a $4 shale price, so we’ll see. That was our first well, I think we have a little bit of analysis to move forward there.

Moving to the Utica, here is the thermal maceration rock or source rock maceration math that I see everywhere nowadays. We put on all the recent vertical well permits and horizontal well permits, you can see most of the activity has been over in Ohio, approaching the wet gas oil window. Our acreage position as we view it currently lies entirely within the dry gas window. And so I’d be surprised if we that we’ll see the drilling will obviously let us know. We’ve drilled one well already in the Mount Juliet area, I’ve done quite a bit of log analysis on that some core analysis as well. We’re currently drilling our second well in the Henderson area, we just plugged out about a week ago. And then we’ll finish up within the next few months moving to Thimest (ph) and drilling a vertical there.

Actually, interesting results on our first Mount Juliet well, we saw about 400 feet of gross reservoir, it’s pretty deep about 10,000 feet so one of the deepest wells that we’ve seen at least with respect to the Utica within the field to date. Potential pay actually spans in the lower portion of the Utica throughout the point pleasant and into the top of the trend. We see reservoir quality with somewhere to the Marcellus, a little bit lower organic content. But in terms of process and permit abilities quite similar, we’re pleased to see that but the mineralogy was very different. And really the biggest difference is the presence of carbonates. So, I think we’ve seen enough here that we’re actually now talking about the possibly going in within the first half of our fiscal year next year and drilling the horizontal within the Mount Juliet area, just to test the Utica and get a feel for it.

And with that, I’ll turn it over to Barry, thanks.

Barry McMahan

Hello everybody. Today what I’m going to do, talk about our drilling and completion cost. And it’s from the learning we’ve had at the Covington field. It’s basically bracketed around the 4,500 foot well drilled in that area. First thing I want to talk about is our drilling rate, you can see that the drilling rate costs about 22% of the well. We are in the growth phase, we’re bringing in rigs that are specialized for location drilling, the walk from well to well and they’re very expensive but they fit this purpose.

And then, one thing I want to talk about extra prices, if you look at the second most costly thing is our cutting handling and disposal. We first moved in the area, we did not expect to try our cuttings, hall them to a disposal area, we do that. No cuttings hit the ground we’re going to see that just going forward. So, it’s an expense we have to incur but it will be there for the long term.

The other ones are fairly simple. Let’s click, and let’s just talk about where we think we’re headed with our drilling. Our estimated 2011 drilling cost of about $2.5 million, our last location at Covington, we think we drilled them for $2.2 million with about 18 days. So, we already started to see improvement. We’ve set a target for 6 to 8 well pad of 15 days and $1.7 million. And how we’re going to get there, we’re going to focus on drilling efficiency through use of mud motors and bit and trying to make one trip for every well. In other words, we’re not wanting to make multiple trips to get the well drilled.

How we do that? Also as we increase drilling efficiency and you can see the plot on the far side, you can see we’ve been continuing improving our daily footage per well. When you increase that footage per well, then you can start reducing your best days drilling. And if you look at the blue bars, you can see that we have steadily increased that with a goal of 12 days completely drill the well. We have achieved that one time, the goal as to make that repeatable.

Onto completion, stimulation that’s our fragmentally we talk about, that represents 55% of the cost that includes the equipment to people, the sand and the chemicals we use to frac a well and it’s the bulk of our completion cost. We’ve been working very hard to improve our completion costs. You can see through the winter of this year we’ve had some mechanical problems, some fishing problems, that related to our plug and per designs, we’ve since approved that in April, we renegotiation our frac contract, that was a significant step for us. What it allowed us to do work longer hours, our frac contractor was required to basically double its staff so that we can work 18 to 19 hours a day fracing. You can see the results through May and June, we lowered our frac cost significantly. I would expect that to continue to drop over time. Our guys think that Winner, you can crack to Winner as long as it is minus 15 or higher and if there is not five or six personal on the ground. Winner should not bother us except for last nose hops.

Okay, putting that all together we already have proved that we can lower out cost through growing efficiency and frac cost improvement. But for the long term we see this as important as we grow in concentrated areas so that we can focus all our efforts in that area and you can see us we have concentrated in Covington and now we are now moving to Tract 595, 100 and Owl’s Nest. The idea is to keep everything in one place so that we are not spending a lot of money mobbing, demobbing and mobbing equipment in and out. The other thing we are looking at really hard is buying our own province at Sand and our own Tract chemicals. We think there is a significant savings there. Long term Tract contract as we grow our rig fleet what we are looking to do is either sponsor a frac fleet or somehow get out of the bid for discount type of frac fleet contracts. We all like, in the operations department we like to drill more wells prepared our completion guys like six, our drilling guys like eight. So we may end up with some kind of multiple of those two so that we can take care of the efficiencies of drilling multiple wells.

Equipment, we have rent a lot of equipment that I consider has high rate return with low risk. We are going to be looking at purchasing that equipment to see if that helps us lower our cost, take that profit away from the vendors. Pad reductions, we are working a lot to reduce the cost of the containment within our pad. And the natural gas power grid is a big thing. That is not really good for the environment but also good for our price in historical, all right.

Let me just finish down at the bottom, pin up your paper boats close and put them together, you can see that we are drilling for 2.5 million today. We have experience with a $2.2 million pad. Fracing, I just use $800 a foot, I think we can beat that for a total cost of $6.1 million that is really close to what we think we can do. Our target, we have set an aggressive target of 1.7 to drill the well and 3.15 to frac it for a total cost of 4.85. I think that is it, the bulk of our acreage and the only thing we have to deal with are areas where we have deeper zones and higher fetcher.

This is another thing I want to talk about all day. We don’t have chase acreage at Seneca we own the bulk of our acreage. So we are very interested in pad drilling. If we were to move around and drill one well, versus our pad drilling you can see the cost difference. We are very interested in keeping operations at a six or eight well package and you can see the savings have been significant, over a million dollars per well. Another thing I am going to do is get this to fill out, I just want to show you a timeline, this is a timeline of a what a well package would look like. It is about a 199 days from the time we move the drilling radian, drill six wells, complete them and put them back on. That’s why you sometimes you see our production, share staff, all look a little lump. Okay.

So I want to talk a little bit about our water program. Matt talked a lot about our cold mine run off, you have seen that a lot. Permitted fresh water sources, we have abundant fresh water sources available to us and then recycled water. We recycle 100% of frac water that we generate.

We have a zero discharge policy within the company. That means we discharge no water to the surface, no water goes through any treatment plant. We recycle all our upper Devonian water and all upper, all of our Marcellus water. We have built centralized water systems at Covington. We are going to utilize the centralized water system that we built for Covington for 595. We are building a centralized water system at Tract 100 and we are building a centralized water system at Owl’s Nest for our new development. We are also installing, some of you guys saw our field trip where you, we tested a evaporative system to evaporate our waste water. What it really does it takes, excuse me, it takes the salt out of the water, creates a solid that can be taken to a landfill and you end up with a pure H2O vapor that eliminates any deposable make.

The other thing in our acreage position, we are looking at underground injection like we do in California. We have, in California we inject about 20000 barrels a day of waste water into to the ground, so we are very good in understanding waste water injection.

Okay, just to talk a little about zero discharge, we tested, I told you we tested this system for the last six months, we have purchased two. We are going to build centralized systems, one in EDA, one in the WDA. They will collect all the water. They could collect water from our competitors that we sold to. Clean the water and either distill it and release it or recycle it back into our frac programs. And the bottom line, if you use this system you get clean water vapor coming out the have you.

Also I want to make sure that everybody understands that we have disclosed our frac crude, you know, that was a big deal at one time in New York times. We have full disclosure. It is on this website, fracfocus.org. We are testing frac foods, we would like to be greener. We would like to proceed as a green company. We have burn a lot of diesel also out in the field and the frac trotted to about 22000 gallons an hour. We need to make sure that we are not spilling that diesel on the ground. So we have created standards to make sure that doesn’t happen. In a word that is practice as company, we do everything as good as we can do it.

California, I would like to talk just a little bit about California. We have had our position there since 1987. We are the 7th largest producers in California with about 12000 acres of property. We, our oil grabby ranges from 12 to 37 degrees. When you see 12 degree oil that means it is a steam plant. And with high prices that we have say in crude oil and low prices that we have on natural gas is perfect environment to have a steam plant.

Here is the location. Most of our properties are located in fairly large fields. And Midway-Sunset is a filling and barrel field. Los Telez is a filling and barrel field. And Winter Properties are heart of what we call the Winter Structure. It’s one of the largest in California also. And this is the most important side I want you to understand. Our cash flow is tremendous out at California. If you add that to DDNA we get about $52 a barrel cash coming out of California properties.

With that I will turn it over to Ron. Thank you.

Ron Tanski

Thank you Barry. Matt, John and Barry have been talking about the new technology and efficiency that Seneca has been achieving. You might notice that Barry walked a little bit gingerly off the steps from the stage, he just had a couple of new knees put in and that new technology is working quite well for Barry. And he actually managed to kind of hang in there and keep control over all of Seneca’s operations during that whole process. So our hats off to Barry’s yeomen work. One of the more important features of power integrated model is that each segment can actually focus their time on their individual projects. And then when we take those projects together and combine them and coordinate them we can generate consolidated earnings for the company.

Seneca, as we have seen is focused on proving up reserves in the Marcellus today. In the future, we are looking at improving up reserves in the Geneseo and Utica. And booking reserves is great but arguably what is even more important are getting those reserves produced and getting that production to market. Our unregulated Midstream Pipeline Company is immediately focused on getting Seneca’s production to market. We are building pipe and compression and getting that into the interstate market which we think is essential for the Marcellus’ gas.

And Seneca is eastern development area in Tioga and Lycoming County. Midstream is building gathering systems to connect Seneca’s production in the Tioga County up to the Tennessee 300 line. And in Lycoming County down to the Transco line. We have dedicated people to this effort who are familiar with the area, who have grown up in Western Pennsylvania, who know what is important in dealing and construction techniques through rural area, through forest plants. And who know how to keep the local landowners whose property we cross with our pipelines content.

In Covington Midstream was build its 10 mile $16 million gathering system to get Seneca’s production flowing into Tennessee’s 300 line pretty much when each well pad, each individual well pad was completed and the wells and metering equipment were available. As a matter of fact, I think for pretty much all of the wells drilled in the Covington area, the average time to completion of fracing and completion of the wells themselves and cleaning up after fracing, the turning into production was an average of 34 days per well. And that’s pretty good as a lot of that was due to the, we knew we were going to develop the area and Midstream got out and started building early on.

Now as production in Covington is ramped up, Midstream is adding addition compression and dehydration facility to boost capacity on that system to 220 dekatherms per day.

What we have shown on this map, get this to work here, addition well. These maroon or purple lines permitted by other operators in the area. And we expect that and Midstream has been in contact with them to the extent that they haven’t found an outlet for their production and many of them have, you can see they have also done some pipeline geology and gotten their wells pretty close to the Tennessee 300 line to the extent they are a little bit further away from the line, little bit further south adjoining Seneca’s production. As Seneca’s production starts to decline along its normal path, we expect to backfill the space or the open space in our Midstream line with production from those producers.

Likewise in Lycoming County and Midstream is currently in the process of building an 18 mile 20 inch pipeline and associated compression at a cost of around $51 million to provide about 466 dekatherms per day of capacity down to the Transville pipeline. Seneca has already committed to 360 dekatherms per day at this space and Midstream again is talking to other producers to fill out the design capacity. Here again, we have highlighted the permitted locations of other producers in the area and Seneca has been talking to those folks also. I am sorry, the Midstream has been talking to those folks also.

While Midstream’s main focus would be to continue to build out high pressure smaller diameter trunk line systems to get Seneca’s production to market. The revenue growth that we see in this chart here at the bottom right is made up primarily of inter company revenues in the early years. And so as I mentioned as Seneca’s production continues along its normal decline we fully expect third party revenues to replace the inter company revenues provided by Seneca right now. And while focused on Seneca’s production, Midstream as Dave mentioned is always looking for opportunities to build systems for third parties.

Moving from the smaller diameter unregulated pipeline business over to the first regulated pipeline and storage segment. You can see that our regulated pipelines are in a great location in the Marcellus Shale fairway. And they can provide an outlet to the interstate markets for the Marcellus Shale Gas. As Dave mentioned, this business is always been integrated with regulated utility business. And more recently with our unregulated marketing business and most companies are taking advantage of approximately half of the extremely flexible services and capacity that the interstate market and the interstate system has to offer. That system is inter connective with a number of interstate systems and provides a utility and marketing company with access to a number of producing reasons and it also provides Seneca access to a number of markets for its production.

Taking that previous line, let me show you the footprint here and plotted the number of new wells, new Marcellus wells permitted so far just during 2011. That growing, drilling and production activity has already provided support for incremental true foot projects for the national fuel gas supply in our Empire Pipeline Systems.

We are getting more and more producers attached to our Legacy Pipeline System and we now have eight producers in addition to Seneca to flow Marcellus Gas into the pipeline system through multiple pipeline taps and meters. And that’s up from just two producers in 2009. And in addition to these producers that are already flowing gas into the system, we have got requests for an additional 30 taps and meters into the system from 19 different producers for new Marcellus Gas production and our engineers are already working on design plans.

On this chart, you can see that in terms of and this is just local production, where it will called production that’s produced in the area within the footprint of our pipeline system, Marcellus Shale Gas is becoming a larger and larger portion of that local production. As the producers on the system turn their attention towards Marcellus Shale new wells rather than the historical Devonian sandstone wells that have been the main stay of local producers in our system for years and years. And we believe, since we are not exactly sure how many wells are attached to the system behind some of producers meters and we pretty much lost Tract of that since first that wasn’t important for us to know, we just needed to know the quality of the gas. We believe there are still approximately 24000 shallow Devonian wells still attached to the system and producing into the interstate system. In addition to that we think there is approximately 15000 shallow wells attached directly to our utility lower pressure system.

Now because of the decreasing bases advantage, the Canadian gas supply had at the Niagara import point compared to supplies priced off of Dominion self point, we have seen declining throughput of Canadian gas entering our system at the Niagara border crossing. Now here we have graphed the differential between the cost of supplies priced at the Niagara border versus those priced at the Dominion self point. Up until the end of 2008 it was generally cheaper to buy supplies of Canadian gas and move it across our system to downstream point than it was to buy supplies priced off of Dominion self point. Now you can get gas cheaper at Dominion self point and as a result throughput of Canadian supplies across our system it started to decline as early as 2009 because of our straight fixed variable tariffs and the fact that our customers continued to pay demand charge for that capacity the decline or throughput wasn’t immediately problematic. But our interstate marketing team could see where things were heading. So they began to plan for the eventuality that the customers would end, would be ending their contracts when they could, turn back to capacity and stop paying those demand charges.

Now their resulting plan was to reverse the flow on a few of our major systems and eventually turn our system inside out. Now Marcellus Gas Supply has far surpassed the ability of the local markets to consume those supplies. And that gas needs to get to the interstate system. So the projects that we have talked about for the past few years are moving along, some faster than others. We have included the interstate project and the Midstream projects all on this slide for convenience. A number of you who were around the field trip last month saw the construction operations on the Tioga extension project along from the Conning down to the state line where we are boring under a couple of roadways, rail road grade and a river all in one shot. And you were also able to see the pretty much completed operation in the Covington gathering system where Seneca’s wells are already tied in and producing.

So further to the south, you also took a trip to Tract 100 and you saw the early development of a well pad drilling and the pipeline construction operations from Midstream down there. We are going through some final commissioning of the additional compression that we have added at the Lamont Compression stations and that pretty, almost ready to go. And we are finishing up on our line and expansion into the Texas Eastern System in South Western Pennsylvania. Those will be completed this fall.

All of those are being driven by the development of the Marcellus Shale both by Seneca and others. On slide 61 here we have depicted the relative and very rough timeline of all these projects. The further you move to the right of the slide the less certain the exact timing of these projects become. And while we have shown fiscal years along the bottom of the slides, the timing of the west to east in Central Tioga Extension projects might are likely not to fall within, a list of throughput is likely not to fall within fiscal 2014. So those of you who have been following us for sometime you will remember that when we began talking about the west to east project, we projected that project having some throughput as early as 2009 because of the slower development in the market, they have obviously been pushed back further than that.

We still believe that with respect to west to east, it’s not a question of if but only a when in additional producers will step up to the capacity commitments and it will take to get that project completed. One other note on this page, if you add up all the capacities along the left side of the arrows they won’t add up to the total firm capacity of the 1.8 billon dekatherms on the bottom of the page. And that’s because we did not list 150000 dekatherms of capacity from the Central Tioga Project that is only going from the inlet of the out, inlet of the pipeline to the millennium pipeline. But if you add that then it gets up to the 1.8 Bcf.

So on the next two slides we have shown some more of the details of both the Tioga County Extension Project and the Line N Expansion Projects but I really don’t need to spend much more time discussing the details of those right here. If there is any questions, you can give those in the question and answer session. Now this slide 64 is another slide that we have put together to show the relative increase in throughput from all of these projects. But again the timing of the west to east and the Central Tioga Project are not necessarily tied to the timeframes that we have shown here. Again we don’t expect that that will hit our system until fiscal 2015. Now the scale on the graph is shown in thousands of cubic feet per day. And it also assumes a relatively conservative 80% load factor for throughput into that new capacity. Because we are showing a bunch of standing and these projects and the later project I wanted you to be able to see it graphically what that, those projects will do to the throughput on our system at least to give you a visual impact. But again they are not likely to hit the system until fiscal 2015.

For cash flow planning purposes we do expect and as Dave already mentioned we do expect to see a significant increase in the throughput on our systems more than doubling the annual 300 Bcf of production that we saw in 2010 totaling 741 Bcf of throughput across the system in fiscal 2014.

Now my segment wrap up slide combines all the pipeline and storage capital expenditures for five years and our projected revenues over the same timeframes. The large capital expenditures again that we have in fiscal 2014 will begin generating corresponding revenues in fiscal 2015. As we have pointed out in the past, we believe our forecasts are conservative, they are achievable and we assume that the returns that we will achieve on our investments. At least in the regulated high point and storage segment will be in line with the returns that have been allowed in recent frac perceiving. Through the years the projections that we have made we think have always been based on reality and more often than not as we have moved along we have been able to either achieve or exceed those projections. Now I will turn it over to Anna Marie to give us outlook for the utility segment.

Anna Marie Cellino

Thank you Ron and good morning everyone. I would really like to continue to the theme of growth with my talks and unfortunately I can’t operate a utility in a non growth area. However, I can continue the theme of great performance and that is with utility and all the other segments that we have talked about today. Third thing I want to talk about is safety. Safety has always been our number one priority and that’s the safety of our employees and the safety of our customers. This year we appointed a chief safety officer who actually has oversight over all segments of the company. Utility, pipeline, storage and the exploration in production. And his name is Jim Ramsell. Has over 30 years of experience and he will keep all of us focused on our safety. And what I have here is the slide of our capital project and you can see that we have pretty consistent spending over the years dating back to 2006. It is basically in the range of $55 to $60 million and I have highlighted in green the amount of money that we spend for safety. And that runs for about 76 to 80% of our dollars each year.

The majority of that is to take care of the replacement of our various field pipes and services. So our system is in good shape, we are going to continue spending money along their brains right looking into 2014 in the ranges of 76 to 80% of our capital budget on safety.

Next I am going to talk about, a little about our gas supply and our capacity. Ron has already talked about how the gas flows are changing and yes even the utility is seeing the change in gas flow. As you can see our dependence on gas and capacity has really been for the majority in the Gulf Coast. And looking to the future with the development of all the Shale place, we are going to see a difference in our gas flows and that is the result of the increase in the Marcellus production. So you can see the difference here the drop in the Gulf Coast supplies in capacity in an increase in more of the local Marcellus.

You have heard me talk before, again we are in the non growth area and we always focus on cost control. And we really have a pretty impressive record when you look at this chart. To think that we have salary increases each year and yet we are able to keep our OEM cost down and actually decreasing. What I have highlighted this year is the uncollectible expense. I thought I would keep it with the Marcellus theme today. And as the price of gas has gone down our customer bills have gone down, so that has resulted in our uncollectible expense going down. And you can see the trends here and how that has helped certainly our OEM spending. And it is great for our customer. Our bills are more affordable, customers can you know, feel more comfortable picking up FERC using more of our products and they can pay the bill. So it’s a win-win for all of us really with the Marcellus development.

Thought I would mix up a little picture here with the foundation. And I always talk about the utility and Dave has mentioned it today, it is the foundation of earning stable predictable earnings year after year. And that’s what we feel the company is built on these stable predictable earnings. And you can see here that we have had pretty predictable earnings year after year. Back in 2006 we started our rate case in Pennsylvania, it concluded in early 2007. And then in 2007 we started and concluded our rate case in New York. And after those two rate cases you can see there was an increase in earnings which we have been able to maintain.

Looking at this chart in the top corner, I am focusing in more on return on equity and I have identified there are targets. In New York it is 9.1% and in Pennsylvania it is between 10 and 11%. We had a negotiated case in Pennsylvania. And you can see we have achieved those numbers and it has exceeded those numbers. So because of that we don’t anticipate filing a rate case in either of the jurisdiction within the next 12 months. Again this is great for our customers, keeping our rates as low as possible yet achieving our ROEs. What we have in sight for our number of rate mechanisms. And if you look at New York we have those rate mechanisms in place to basically assure us a certain level revenue even though our throughput may go down. So that is very key to maintaining our stable earnings in New York. In both jurisdictions we have choice programs, so customers think they are paying too much for the utility they can always go to a marketer and sign up with the marketer. So we do have active choice programs in each jurisdiction Pennsylvania’s bid just starts this year as far as our residential and small commercial customers and we have about 17000 customers now in choice in Pennsylvania. So basically these rate mechanisms do allow us to maintain our stable outlook on our earnings.

Moving forward, we are always going to have that strong commitment to safety, controlling our cost, making sure we have the gas available for our customers, providing great customer service. And when you do that you make sure you take care of the customer, you always have good rate relations and we will continue to do that. We run a great utility and we are going to do that in the future. Thank you. And I will turn it over now to Dave Bauer.

Dave Bauer

Thanks Anna and good morning everyone. The speakers who have come before me certainly laid out some impressive plans to grow our company and my job this morning is to tell you how we are going to pay for it.

This slide shows on a consolidated basis the level of CapEx that Matt and Anna and Ron had revealed. And as you can see, we are looking at making a very substantial investment in the company over the next several years. With most of the growth and spending coming in the E&P segment but also in orange a fairly substantial investment in the high point and storage segment as well. Also from when you go out to 2014 we are expecting our level of CapEx on a consolidated basis to be nearly double of what it is today.

So let’s look at how we are going to pay for this. The next several slides will compare our CapEx from this slide with our expected cash in operations starting on a segment basis and then aggregating to a consolidated look at our overall financing picture. In years passed we have had a similar discussion but limited really to just one year given the scope of the opportunities for us we thought taking a three year look gives you a better appreciation for just how different our company will be going forward. So let’s start with the utility and to set up the slide the blue bars on the right are CapEx numbers from the previous slide and the green bars on the left are expected cash from operations. And these line this, these amounts would correspond with the cash in operation going on in on our cash flow statement so they are after interest expense taxes and alike. And over the years we have consistently said that the utility is a stable and reliable source of cash flows and I think without a doubt that comes true in the slide here for our CapEx over this time period will be level in that 55 to 60 million dollar level. Again for maintenance, mostly for maintenance CapEx being an area where our customer base is not growing, our focus is as Anna said is on maintaining a safe and reliable system.

Cash flows will be pretty steady in that 115 to 125 million dollar area. But if you look closely you can see ever so slight downward trend in our expected cash flows. And this is really driven by two reasons. First, in Pennsylvania we see continued declines in consumption due to conservation and we don’t have a revenue decoupling mechanism there. So as conservation occurs it does impact our margin. And second we are assuming that OEM does increase slightly due to inflation. We do our best to control those faux but inflation at times is inevitable. So over time it would expect a slight down turn in our returns in this business but overall and each of the periods we are forecasting that will achieve a very reasonable rate of return. And as Anna said wouldn’t expect to file our rate takes in any of these periods.

Turning to the pipeline and storage segment. If you focus on the green bars, you can see that as the expansion projects that Ron referred come into service we will see a steady growth in cash and operations in this business. The trend gets lost a little bit in the scale of the graph but if you look closely at the numbers we are expecting some good growth here. To get that though, we will have a relatively modest financing need in 2012 and then a more significant one in 13 and in 14. In 2012, we will be building the Northern Access Project and the Line N 2012 Project, both of which are about $100 million in total. So we would expect our CapEx to outpace our cash flows by a relatively modest amount in 2012. Looking forward to 13 and 14 our financing needs pick up quite a bit. The West to East Project and Central Tioga Extension Project combined are about $425 million in capital. Construction will start in the summer of 2013 and then continue through all of fiscal 14. And for forecasting purposes we are assuming that the projects don’t go into service until our fiscal, early in our fiscal 2015. So we have a lot of capital without a lot of revenues.

But over the long haul we see this segment as being a significant generator of free cash flow. You know, if you take 2014, it’s an example and back out to roughly $300 million of expansion related to CapEx. You’ll see that we’ll be generating about $100 million per year on free cash flow from this segment. And as you would go out further and watch and east and central Tioga come in online with only increase.

Turning to the E&P segment, here is where we see the bulk of our growth recurring. The blue bars are assumed the CapEx levels that Matt reviewed earlier and the revenue, the cash lines assumed the production forecast that was earlier on the presentation. We have some fairly conservative well cost assumptions built into the capital numbers. And as Gary said earlier, we’d expect, it’s our hope that we’re able to drive those costs down into the future.

From a pricing standpoint, we’re assuming that gas prices rise from 450 in 2012 to 550 in 2014 and the oil prices stay in the $95 to $100 range. So as you can see, we face a fairly significant financing requirement in 2012 and in 2013 as Seneca ramps up its drilling program from a 4.5 rig program in 2011 to 5.5 rig program in 2012 and then increasing to 6.5 in ‘13 and ultimately 7 in ‘14. But I think the takeaway from is this is that while we have that significant financing requirement in the near term, once the production from those wells come online, the cash from operations catches up pretty quickly to the 0.25 2014, we’re basically living within cash flows.

Before leaving the E&P segment, I thought I’d talk about our hedging program. As we said in the past, we have an active program in place to protect our cash flows and lock in our returns on our Marcellus drilling program. Our strategy is to generally layer in our hedge positions over a two year period, such that prior to the start of the fiscal year, we’d be about 40% to 70% hedged.

In the slide here shows our hedge positions on the left relative to those targets and then our positions by product on the right hand side. And overall, we’re very happy with our program, you know, in particular the gas prices on the right hand side are quite good. And if you think back the math side that showed the returns that we earn on our Marcellus wells, we’re locking in some awfully good returns at those price levels.

Lastly, from a segment standpoint is Midstream, our marketing company and other. Here we have much smaller dollars relatively to the other segments. But I think a pretty good growth story here, proven a large part by Midstream. I mean, if you look at the change from year-to-year in the green bars, those are largely dollars that Seneca would have paid to a third party but is not used Midstream to build its infrastructure. Now, so overall I think it’s a pretty good story relative to the dollars that we’re investing.

So, now let’s look at things on a consolidated basis. This slide here aggregates all of the individual segments into a consolidated picture. And I think that there are really three takeaways from this slide here. First, if you focus on the green bars, you can see that we’re basically doubling our cash from operations over a three year period from about $625 million this fiscal year to $1.3 billion in 2014, which I think is an impressive growth rate. Second, by the time we get to 2014, we’re very close to living within cash flows. In fact, if you back out the $300 million of spending for west to east in the central Tioga project, we’re solidly living within cash flows. And then, thirdly just looking at the difference between the blue and the green bars, you can see that we’ll have some financing needs in the coming year.

But before we can arrive at a total for our financing needs, we got to consider two additional items, the first is our dividend. As you know, we have an impressive dividend track record. This past June our board increased our annual dividend rate to $1.42 per share, which extends our streak of consecutive increases to 41 years. We’re proud of our dividend and are anxious to continue this streak. As we’ve said in the past, the regulated companies generally cover our dividend the earnings in the regulated companies generally cover our dividend. And as the pipeline of storage project that we talked about going to service, I think they’ll provide an ample source for future dividend increases. But as E&P becomes a larger share of our overall earnings picture, I’d expect our consolidated payout ratio to decline over this period.

The other thing we have to consider is our debt maturity schedule which is shown here. As you can see, we have $400 million of maturities in the near term, $150 million of which comes this November which is early in our fiscal 2012 and then $250 million in March of 2013. And after that period we go another five years before our next maturity. So, I think our overall long term debt schedule is pretty manageable.

This slide ties everything together. It layers in our debt maturities in red and an estimate of our dividend in green and then calculates a consolidated financing requirement in blue. And as you can see in 2012, we’re looking at our financing needs a bit more than $0.5 billion, about $400 million of which is incremental financing to the balance sheet. And I expect that over the next 12 months, we’ll be satisfying that with the combination of long term debt and short term debt based on market conditions. Going out in the 2013, we’d expect to do another $0.5 billion or so in financing about half of which is incremental to the balance sheet. And then another $0.25 billion or so in 2014 related to for the west to east in Tiogo, essential Tioga projects.

So, this is intended to give an overall look at the trend of where we think our financing needs will be. Obviously there are a lot of factors that as you go from left to right, we’ll influence our actual borrowing need at the time from commodity prices to drilling and completion costs to timing of our in-service states of our pipeline and storage imitative. Overall, I think our balance sheet can handle this incremental debt. If you look at our capital structure today, we’re about as 64% equity to GAAP ratio. Considering that $400 million of incremental debt, we’ll put our equity to GAAP in the high 50% area, you know, which I think given our mix of businesses is an achievable thing. Looking out into the future as the business grows, it’d be our expectation that our balance sheet would grow in such a way that our equity to GAAP would stay in about that vicinity.

Just a moment here on our capital structure targets, when we think of our capital structure targets, we take a bottom up approach to setting them. We start by setting targets for the individual business segments that you can see on the left. For our regulated businesses, that’s generally in the 45% to 50% area and largely reflects the amount that are, those businesses earned in their great structures. Our targets on the non-regulated sites are generally more equity rich which reflects the riskier nature of those businesses. After we set these targets, we take a look at the amount of capital that we’ve committed to each of the business segments and asking this to calculate a blended target that based on our business mix today and through the next two years, we think in the 55% to 60% range make sense. As we get to be more of an E&P company though, I’d expect that our equity requirements will drip north of that into the 60% to 65% range.

A comment on our credit rating and our short-term debt facilities; as you can see in the bottom, we maintain a good amount of credit facilities to fund any of our short-term needs. And from a credit rating perspective, we average to a BBB+. We’re committed to remaining an investment grade credit, and I think as we go through time, our leverage metrics and coverage metrics will support that.

So on closing, we got a tremendous opportunity ahead of us in the Marcellus. We have some financing needs, but I think our balance sheet should be able to handle it.

Analysts

And with that, I’ll – I guess we’ll open it up to questions.

Dave Smith

Yeah. I think the – just a few words. The (inaudible) of the growth properties from that, we’re setting reports here, 40% increase in the production and the doubling of pipeline and storage throughput, doubling of cash from operations, and I mean we think that’s a pretty compelling story, but more importantly it’s achievable. It’s what we expect and in many ways it’s the basic. That’s the case that reflects relatively conservative assumptions and to the instance that prices improve, particularly gas prices, to the extent that results improve, we certainly have the flexibility and the capability to grow at an even faster pace.

And so with that we’re open to your questions.

Question-and-Answer Session

Unidentified Analyst

From your Marcellus property say in part (inaudible) what would firm transportation likely cost to the Toronto city gates and how does that compared to the same haul of the New York?

Dave Smith

Getting it into the supply system, we’d be looking at an average system rate of around 11.7 cents to Niagara. I mean, we still – we get that rate across our system up to Niagara. Up to Toronto, I’m trying to think what the TransCanada hasn’t quite settled all and their new rate structures yet that they are going through, but I would – I would hazard to guess that at about another 70 cents to 80 cents, George (ph).

Unidentified Analyst

And how about the same haul to New York?

Dave Smith

If we get into the transport system, I know Seneca has got some capacity there. Matthew, do you know what Jim just got set up for the Transco capacity?

Matt Cabell

I don’t know off the top of my head. John?

John McGinnis

I don’t know (inaudible).

Matt Cabell

Right. I would think that would be somewhere in the neighborhood of 75 cents.

Dave Smith

Yeah. I think George at the end of today with the slide in there on the basis flip between and in the past, it was about $0.50 cheaper to source your gas in Canada at the border and that’s why we had a number of customers like (inaudible) for example. You know, essentially, (inaudible) are employer extender, because they were looking to source more gas in Canada in quite for operational reasons which they still achieve but in part the cost savings with the flip of the basis now with gas becoming more expensive at the border, at the end of the day, we’re able to deliver it into Canada.

Now TransCanada, that’s a differential, but delivering it into Canada at a better price than we can deliver it into New York now. And so that’s why we work so hard to flip our system around to be able to move gas in both directions. In the past they just came in from Canada, now it’s able to go south from the Marcellus north into Canada and it was essentially based on our projection that that basis would change that gas prices in Canada would get much stronger, because they were converting all of their coal plants to gas and it’s mandated in Ontario and that’s in large part is what caused the strengthening of gas prices, which provided us with this opportunity and frankly provides Marcellus producers with a great opportunity to get their gas into Canada and that’s what they are looking for.

Unidentified Analyst

Thank you.

Unidentified Analyst

Hi. Two questions; I guess piggybacking on the pipeline that George started with kind of (ph) already on your slide 69, I wonder if you can comment on what implications that has for when utilities such as yours stop contracting on some of the long haul pipes from the Gulf since you have so much more access in region and then – and from the west and then I had another question.

Anna Marie Cellino

We’ve talked to the commissions about this; especially Pennsylvania is very interested in the Marcellus and what they were going to source our gas from there. But, we will main – we will keep our capacity down to the southwest, means the Gulf Coast mainly they have reliability of gas, so we will add. So this pie chart show we’re going to decrease it, but we still will maintain a variety of capacity from all sources to make sure that we have that gas available for our customers.

Unidentified Analyst

So if I understand you, you’re going to maintain some firm capacity if the total size will decline meaningfully?

Anna Marie Cellino

It will decline in the southwest, but we will focus more and the increase will be in the Marcellus area. If you looked at that pie chart, we still have Canadian gas coming in and that is declining also. So the sources will be varied less than the Gulf Coast and more focused for the Marcellus gas.

Unidentified Analyst

Are there any particular years where you see a bit of a fair stop to reducing your firm contracting and surplus pipes?

Anna Marie Cellino

Well, we have contracts in place. Our capacity contracts usually are from five to six years. I don’t know the exact date, but we are starting to have a decline in come of their contracts, but the timing is varied and I don’t know the exact date.

Unidentified Company Representative

Yeah, I mean to really (inaudible) your question is I just add to what Anna Marie said, you know, how much our northeastern utilities going to drop their long haul capacity because of the Marcellus and certainly there are pressures at the commissions not only in the northeast – I mean not only in New York but in the rest of the northeast for utilities to in part shed storage, shed long haul capacity because of the prolific nature of the Marcellus region.

But, as we looked at and we looked at long-term studies, you’re going to still need to keep a good percentage of long haul of capacity. And for storages like ours which are legacy storages, which are essentially a $1 storages that’s not a bad news. For new storages, $3 and $4 storages and we thought this a couple of years ago so that’s why we stopped developing new storages, I think that’s – I won’t necessarily say the decimal but $3 or $4 storage is going to be very, very difficult and in environment where you make gas depending upon your view of what comes out of the Marcellus up to 15 million to 17 million a day coming out of the Marcellus. I mean it’s going to fundamentally change that business I think.

Unidentified Analyst

That’s great. Let’s see if I can follow-up with you. I guess more of a big picture question for the company. I mean, you all have laid out a terrific manageable growth plan maintaining the integration and control, which you’ve said is so important and you’re doing all this without requiring more equity, external equity.

So I guess you know the pressure for my question is not as great but from a long-term value issues maybe you can comment if the integration and control maintain say with an MLP IPO for the pipes and midstream would ultimately make sense. If you have a much better cost of capital there and you can as you said with more resources, higher gas prices as you can certainly charge even more than the 40% plus growth on E&P, would that makes sense over couple of years to consider even though you have a manageable plan right now?

Unidentified Company Representative

Yeah, I think that’s – it’s a very good way you put it. We like the plan we have now, but there’s no question if something changed in terms of prices and we look to create by accelerate our program or if we look to move into another basin and we needed additional capital, I mean something that would cause us to want to increase our capital requirement at this point.

You know, certainly there are a variety of other things we might look to as well. Things like having our midstream – not putting the capital into the midstream, but having somebody else do it. I mean, they are, you know, partnering out our pipeline, our biggest drag if you will, the biggest lag in terms of cash flow is with respect to our pipelines and you know because they are just longer term and especially as you saw with east or west.

But, with respect to something like in MLP, we look at that all of the time and it’s not a structure that we have any difficulty with and we looked at it a couple of years ago, you know, and there were cash leakage issues there, cash basis issues. You know, there were future growth issues, what we’re going to be able to continue to see this. There were issues of use of the proceeds. We didn’t need it for example, but certainly that’s changed and we do review that structure on a regular basis.

I think, I kind of like that it’s a little more than an IPO of let’s say Seneca let’s say particularly one I think our acreage is significantly undervalued as it is right now, but yes, those are all options, those are all areas that we have in our clever that and frankly there were others. So, yes, we certainly would be willing to look at that and we certainly recognize that circumstances have changed a little bit over the last couple of years that move in the direction for example of an MLP particularly on the pipeline and storage and gathering side.

Unidentified Analyst

Thank you.

Unidentified Analyst

Hi. I got a question on the financials. And I think it was very helpful that you laid out 14 years of financials. So thank you very much for that. As your equity component of your balance sheet moves down, I think you said the high 80s from mid 60s now. Do you get a feeling for when the rating agencies become sensitive to that sort of leverage ratio?

Unidentified Company Representative

Well, it’s an area that certainly is focused on. At this point we haven’t had any expressions of concern, but we’re certainly – it’s certainly an area that we keep our eye on.

Unidentified Analyst

Okay. Thanks. And then one question from that; I mean as you increase E&P capital spending in the Marcellus side roughly 70% year-over-year, obviously your (inaudible) are increasing. Is there any reason to believe that your F&D this year is going to be fairly lower than last year?

Unidentified Company Representative

(inaudible) to go into the F&D calculation. One of them is how much are you adding puds and how much are we drilling puds. The nature of our program in fiscal 11, a lot of that was drilling up the puds at Covington rather than expanding puds. The other thing that comes into is imply the timing. So the way the (inaudible) look at it if we drill a new well but we don’t have that cash to be up, so we’ve got a new area where we’ve got a pad; we could even have a six well pad drilled but not fraced yet, we’re unlikely to book those reserves.

`So in a lot of cases we may have cost spent with no reserve adds, because we haven’t had those wells and haven’t got them flowing. So a long way of answering your question that I do not expect our one year F&D number in fiscal 11 to be lower than our one year F&D number was in fiscal 10. But, I think the trend; the three-year trend is going to continue to fall for probably the next several years. Does that make sense?

Unidentified Analyst

Yes.

Unidentified Analyst

Two questions; one on slide 80 you guys talk about cash flow and CapEx. To the extent the gas prices are at $5.50 in 2014, can you talk about the sensitivity out of your cash flow to changes in gas prices? And then if they are let’s say $4.50 for an extended period of time, do you have additional debt capacity just to be able to make us that delta was set or does it change your plans?

Unidentified Company Representative

Well, certainly on the pricing side, we don’t have a lot of hedges in place for fiscal 14 quite yet. So the low gas price would certainly have an impact in terms of the sensitivity for looking at 180 Bcf or so production, it could be a dollar change could have a meaningful impact on our cash flows. In terms of what it would do to our CapEx, I guess it would depend on the prospect for future prices. In other words if the strip suggested that it was $4 and lowering, I don’t know that we would be quite as anxious to spend as much money.

Unidentified Company Representative

Yeah, I mean there is two parts that go into that, one is simply we have the cash flow and the balance sheet to do it if gas prices a very low and the other is economics of the play. And I think you could see from the slide I showed earlier that the economics are still fairly robust at the current NYMEX curve, as Dave point out, if we are at kind of a $4 flat curve, I think it would affect our thoughts about how quickly you want to ramp up.

Unidentified Company Representative

And that is also related, if you had a prolonged period of $4 or $4.50 gas prices that is going to dramatically I think affect the likelihood of producers signing up for capacity. So projects like West to East are more likely under those kinds of circumstances to be pushed off which will have a dramatic on our CapEx in the Pipeline & Storage segment. So they all sit together and at a prolonged $4 price you’ll be able to turn it back if that’s what it calls for.

Unidentified Company Representative

Conversely if it’s a dollar up we might look at growing a whole lot faster.

Unidentified Analyst

That’s helpful. Second question on drilling cost, on your guidance on your goal to reduce the total drilling cost, is that just an status quo environment, are you also seeing that there is some cost creep over the next few years?

Dave Smith

Barry, you want to take that?

Barry McMahan

Cost creep from the vendors, yes I do expect that. And we have two offset that by efficiency of our operations.

Unidentified Analyst

So is that – that you’re going to get it down that level that assumes there is cost creeping there also.

Barry McMahan

Yes, yes, it does.

Unidentified Analyst

Okay, thank you.

Unidentified Analyst

Just one financial question and one oriented (ph) question. On the financial side when you show your cash flows after tax, are those booked taxes, are those real taxes. I can’t believe with the amount of drilling that your IDCs will shelter an awful lot of book taxes.

Unidentified Company Representative

Yes, that’s absolutely right. We don’t expect to pay federal taxes for the bulk of the period, that’s presented there.

Unidentified Analyst

So, when you were showing your after-tax cash flows all the matching bars, was that book or expected cash taxes?

Unidentified Company Representative

Cash.

Unidentified Analyst

Okay.

Unidentified Company Representative

Yes. I mean there is a small amount of state income taxes that gets paid, but.

Unidentified Analyst

I just want to make sure it wasn’t the net income number, okay.

Unidentified Company Representative

All right.

Unidentified Analyst

From the standpoint of hitting the target, I talk to a lot of people who ultimately would like to drill six wells per pad, they felt that the leasing situation makes it particularly difficult in various areas in optimally while they would really like to get the six, they can get to 2.4 et cetera. Can you give me a…

Unidentified Company Representative

We are in a – We are in a very different situation than most other operators because we have the large contiguous position which is one of the points we’re trying to make that this large contiguous mineral position that we own, where we own most of these minerals allows us to pad drill virtually everything. In the cases where we do have lease stake or just primarily held like Lycoming and Tioga (ph) counties, these are also very large contiguous blocks that we least from a state. And in some cases we’ve added acreage just immediately continuous to that. So that’s not a big issue for us.

Unidentified Analyst

Thanks.

Unidentified Company Representative

Hi, Murray (ph).

Unidentified Analyst

Dave, you talked about MLP having a tax issue before but you kind of said it’s not as relevant today, what’s changed?

Unidentified Company Representative

Well, I didn’t necessarily say it wasn’t as relevant, but we have a number of new projects and a number of more recent pipelines and we are growing at a much more rapid pace. We add up to a billion dollars of growth potentially over the next six or seven years in Pipeline Storage & Gathering. So, I mean that was really the more relevant.

Unidentified Analyst

So, let’s – just maybe Dave could put in some meat on bones on that. How much would be your tax, if you did it today on a cash basis to convert the – to an MLP status.

Unidentified Company Representative

Yeah, Murray, I don’t have that…

Unidentified Analyst

What would it take to get it?

Unidentified Company Representative

To calculate the number?

Unidentified Analyst

Yes. Well, it’s not complicated, you’ve done it already. Dave has already talked about it in fact leakage (ph).

Unidentified Company Representative

Yeah, I just don’t have the number on top of my head.

Unidentified Analyst

You think it’s relevant for us to know that, should we ask it on a next conference call, will you get by then. Let’s go to the next question, you have…

Unidentified Company Representative

We just want to make sure we understand. I mean I talked about last time we talked about this. When we look at it all the time, but we looked at it two or three years ago in connection with our discussions with New Mountain and when we looked at it at that point in time. National Fuel and our advisors had looked at it with us at that time, decided not to move forward with it. And one of the issues was saturated.

Unidentified Analyst

What was the cap rate them and cap rate to MLPs, I don’t know I will just try; I just want to get that later. Can you go through the next slide though on Seneca? You indicated that the Seneca was materially under value that you did an LPO you would lose part of that, did you assume a 5% LPO, you would lose part of that, did you assume a 5% LPO of the Seneca 10% and you considered in that calculation a spend of 10% that shows without an LPOs, it shows wouldn’t lose any leakage. How do you through that thinking?

Unidentified Company Representative

I wasn’t talking specifically about 5% or 10% LPO tuck in, generally about LPOs. I mean I think looking at the alternatives, I am not sure that would the alternative that would jump to the top of our list, I mean we’re certainly I mean I am not saying we would not consider it, I don’t think now we have to, I think now we have a plan that we like I think that we were looking at I think the word was turbo charging, what would do and there are variety of options I think one of the options is an LPO. I am just not sure that might be the number one option on our list Mario.

Unidentified Analyst

I mean you laid out the plant that includes cost for save you’ve said you wanted control the exit ramp and you want to have operating control and looking at alternatives to doing that, is that high priority in terms of surfacing the value and giving more financial flexibility particularly if something goes wrong and 9/11 could change dynamic somewhere, but...

Dave Smith

Yeah exit ramp was really more of reference to sometimes within these joint venture deal that was in the detail, they really have to look, you have to look very carefully at for example in exit ramp that would allow your joint venture partners who exited the joint venture. That could put on a very difficult position in that kind of third year and in factories else in my view at least in an option on the acreage. So that’s what I was referring to them, Mario. And the LPO, I am just not sure if it’s flexible, I mean it’s something that we certainly would consider, I am suggesting it might not be our best alternative it’s all same (ph).

Unidentified Company Representative

Mario, as we look at the – with the counter value nature of the view of the acreage that’s currently let’s say baked into the stock prices we see it. Simply doing an LIPO wouldn’t necessarily do anything to highlight the value of Seneca and Seneca’s acreage. As Dave mentioned one of the better avenues that we see is actually delineating the value of certainly the western development area to actually crew up the acreage so the market can see exactly what we have in terms of reserves for well bringing that to white, so the market can see an increase in the value of the overall stock rather than doing an LPO in an under value market right now.

Unidentified Company Representative

You missed my point, I mean if I own 100% NFG, you spent off 100%, I still have those, I don’t lose any value, if you give a investment bank at 6% and you think 10% or 50% discount, I am sure I can appreciate that, but that’s now what I’m talking about.

Unidentified Company Representative

Any other questions.

Unidentified Analyst

(inaudible) I was just wondering if you could shed a little light on some of the geology?

Unidentified Company Representative

Well, it’s unrelated to the LPOs. LPOs is a two ten times away from us, the Midway Sunset are the thing that coming up and pitching of the basin middle so I don’t think there is going to be any deep play under that basin, that’s really what you’re asking.

Unidentified Analyst

Thank you.

Unidentified Company Representative

Hey Matt, I was wondering if you could talk a little bit more specifically about (inaudible), looking at the state, it doesn’t seem like the decline rates are shallower, but it was only couple of months worth of data I guess, what do you know about EURs there and can you talk about returns of 450 gas?

Matt Cabell

I guess maybe I would characterize that Ray is our expectation is that when we land laterals consistently in the zone that we expected to see 4 Bcf, that’s kind of an average EUR across that, a fairly broad area. And that’s based on the data we have from those wells. So we’re in – as John put full development mode there and next step is requiring 3D and then we’ll have to wait there for the rest of the fiscal year.

Unidentified Analyst

How many locations (inaudible) by the end of this year?

Unidentified Company Representative

The way we look at it, we’ve got over 600 locations in the what we call the greater Owl’s Nest bridge way area, a lot of things can change and we’ll be under developed area so that’s kind of broad location estimate across that leadership.

Unidentified Analyst

(inaudible)

Unidentified Company Representative

In fact you’re referring to the state I think probably the only well that would have following the state data is the first well drilled out there, which was not in the ideal land.

Unidentified Analyst

Matt, can you talk little bit about New York, if we have a relaxation of various stands and drilling fracing, would you intend to do anything out there?

Matt Cabell

Bob, it’s not an area where we have particularly large Marcellus position and in fact where we do have acreage in New York a lot of it is kind on the ridge (ph) is fair away. So it would probably be a long time before we drill wells in New York.

But we talk about our 745,000 perspective acres in the fairway, none of that’s in New York.

Unidentified Analyst

In Owl’s Nest, are you taking the thing EUR for these, do they come in a little bit lower in that say 3,5, did that hit you rate of return for the part and 4 Bcf are you getting somewhat like 30% rate of return announcement?

Unidentified Company Representative

I’m happy to address. Owl’s Nest would be an area that’s entirely see we don’t know the all the minerals there at 3 Bcf at 16% I don’t think we show 4 Bcf or 3.5 Bcf specifically on that graph, remembering the page for that, here it is, it’s page 18. But I think you can kind of interpolate there between 16% and 49% would be from 3 Bcf to 5 Bcf, it’s still attract rate of return.

Unidentified Analyst

When you drill well, what your kind of targeted rate of return, you need like 20% rate of return hurdle before try to drill it?

Unidentified Company Representative

Yeah, we would on likely to develop an area that we didn’t expect to have 20% rate of return. That said I think we have so much acreage with so much outstanding potential that it’s not necessarily looking at they cut off so much if it is what’s most attractive place for us to go.

Unidentified Analyst

Thank you.

Unidentified Analyst

We have to realize this is going to be while till we’re until development mode rest of the Owl’s Nest. So my understanding is your little more Liquids Rich going west. So you need off take and these pipeline about. So can you seek to the opportunity the liquid potentially as a percent of the volumes out there or the mix and what you would need to process that get to market and how perhaps some of the recent movements contracting in the northeast and ethane front with the ranges announcement may involve it.

Unidentified Company Representative

Let me start with a comment to sort of say that (inaudible) rest of that question, but if you look at where the Owl’s Nest wells are, they kind of the right on the border of needing to the process, that’s possible that even some portion of Owl’s Next we process as you go further west or almost certain they need to process that cash and there will be much more liquids rich.

Unidentified Analyst

I am sorry – what gives you is ultimate (inaudible).

Unidentified Company Representative

It’s right on 1,140 and there is ethane and butane and propane. So what we’ll do is we’ll try to have plants in that area, pull out the butane, propane and but the ethane is an overhead until redevelop the market.

Unidentified Analyst

And the other things about half of that move 7% or something?

Unidentified Company Representative

There is one over here.

Unidentified Analyst

Just had very quick question. Looking at your presentation slide. I like your chart on per ton acreage, but you consider right now if you your core acreage in Marcellus, you said some 55,000 I know you had 735,000 acres perspectives, you would say you had about 55,000 core acres. I think I missed this in the presentation, but what you consider your core acres now.

Unidentified Company Representative

I am not sure about the 55,000 core acres…

Unidentified Company Representative

(inaudible) not necessarily core or noncore, anything I’ve alluded are core development.

Unidentified Analyst

All right I appreciate it. Thank you.

Unidentified Analyst

In your communications with rating agencies, are you going to be able to both rate the debt level that you’re speaking off and maintain increasing the dividend whether it’s 5% to 1% a year. Would you reach point with cost of rating debt exceeds the ability to increase the dividend and still maintain the credit rating.

Unidentified Company Representative

At this time we’re confident that we can do both if our cash flow metrics will support our credit rating and that the cash that’s generated from our regulated statements will cover our dividend.

Unidentified Company Representative

Frac projections we put forth today so many increase in dividend, I mean we remain committed to that.

Unidentified Analyst

And what interest rate you’re expecting to pay on the incremental debt that you’re talking about taking on?

Unidentified Company Representative

Whatever market is there at the time and I guess I don’t really want to speculate as to what we would do in a deal I mean for the modeling purposes I think we’re in the high course, you’re asking what the interest rate puts in the P&L, we put together in the high 4% range.

Unidentified Analyst

And the last question at what point going forward you become cash flow positive on an operating cash-on-cash basis, but having to sell any operations without having to take an IPO or anything else to judge cash and through the business your CapEx, or your dividend et cetera that would then be able to say we are cash flow positive?

Unidentified Company Representative

A lot of that depends on pricing and whole bunch of other factors including the timing of our expansion projects, but as you could see from the graph that I had out there that we’re getting close in 14 and that included over the 13 and 14 period 400 million in CapEx for our pipeline projects. If you were continue those graphs, those trend lines out into 15 I’d expect this to be a whole lot closer what you’re described.

Unidentified Analyst

If he doesn’t answer the question, well question at what point that we’re talking 16, 17, 18 perpetuity?

Unidentified Company Representative

Well we gave projections through 14 and you can see that in 14. We included the west to east CapEx which was extremely significant, but no revenue for west to east because it’s not on line yet. So we were very close in 14, we expect significant revenue from cash from west to east in 15 that wasn’t reflected in the projections in the chart we put out.

Unidentified Company Representative

And then also in 15, we wouldn’t have 300 million in CapEx for west to east anymore our CapEx would be out in that segment. The gap I would suspect 15 if you just continue our trend, it wouldn’t be far off than 15.

Unidentified Analyst

Thank you

Unidentified Company Representative

Mario?

Unidentified Analyst

(inaudible) perfect job in the utility business and obviously you have some transactions take in place in the utilities are opening up for sale in the gas business. And maybe you might comment on that but also what you buy anymore merge the existing business with another one. But your other comment that you made which kind of treating these, you’ve done such a terrific job in the learning curve in E&P and you said you’re looking at new basin kind of can you flush that out?

Unidentified Company Representative

Sure, I will take the merge utility question. My expectation Mario is we would not put a significant capital throughout the acquisition of the utility, I mean we love the utility business but we have – I think better places to spend that growth capital. Certainly there might be opportunities to use other capital, other parties interested in acquiring utilities and having us work with those parties, but at this point I would not anticipate with DME (ph) and this with regard to large utility company.

I mean there are certainly smaller fill in acquisitions that make sense, if you look at our service territory even on our I think probably at our service territory, we have a little blocks where we have white spots in the middle of our service territory where there kind of Ireland’s small utilities. Those make sense because they’re very easily simulated and you can make up for the premium immediately by using your cruising your system. But to acquire a larger utility, I’ve always felt, it really almost has to be contiguous, very hard to work that premium off without adding fee contiguous where you can really take advantage of the synergies and service centers, facilities and all those kind of things I’ve talked about.

And even in that pace, it’s a tough acquisition and it certainly doesn’t – it’s less attractive than the opportunities we have in pipeline shortage and mid stream and E&P for capital.

So again likely that we’d be acquiring utility at least using our capital and with regard to – the second part of your question. Matt, why don’t you.

Matt Cabell

Mario, we have been and we’ll continue to be looking at opportunities in other basins. John and his team are particularly focused on oil resource plays, we’re expanding fast in the natural gas side, we would like to maintain our balance of oil and gas, we maintain as a little exaggerating. We’d like to keep from that balance deteriorating too fast so oil resource plays are very well focused. We go to day rooms, we look at deals, no we haven’t pulled the trigger on any of that, but we will continue to look probably relatively modest sense until we get footholds.

Unidentified Analyst

Last question about CapEx versus cash flow. Obviously cash flow influenced by price of gas. But I am just curious in the drilling plant, are you more like to anchor yourself to a pace of drilling or to the aggregate CapEx line that you said, if you’re well cautious or baking a conservative level of share, if you improve relative to that are they trying higher relative to that, are you more likely to keep the pace of development, are you more likely to cap yourself with the CapEx levels you saw?

Matt Cabell

If you consider several things if you go into what would influence a change in our – in the pace of our program. One is results so if we say delineate several new development areas very quickly we have very good that come on where the wells come on very high rates and have got EURS. That does two things, one we get more clarity about it and many of you are more willing to put additional rigs in those areas. And also if they’re coming on in the high rate that improves our cash flow position as well, makes it easier to do that. Of course pricing had an influence on that as well. Pricing influence is how does each of these areas look and also what our cash flow position is. Did that answer your question?

Unidentified Analyst

Yeah, in part, I mean I am just trying to think about we’ve talked a lot about the delta where you get to a sort of cash on neutral point of view, I am just wondering if let’s say in 2014 you do have taken that West to East project, but your cost structure is such that you wind up with at the current drilling plan the number of rigs that you’ve projected, you wind up with a considerably lower E&P CapEx, are we likely to see you to accelerate the drilling program in order to maintain the CapEx level we saw or if we likely just to say the drilling program that you have outlined is good, however, it’s going to shape out, right (ph).

Dave Smith

I would say in that scenario we are likely to accelerate bringing on another rigs over. And the function, the plan is kind of adding half a rig a year, but we could do more than that.

Unidentified Analyst

Okay, thanks.

Dave Smith

Okay. Well, thank you, thank you for coming today and we will be around the next half hour, an hour or so and well I guess we have to be out by 11:00, so until 11 o’ clock, so please feel free to – feel free to say and talk to whoever you like. Thanks for coming.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: National Fuel Gas Analyst Day - Transcript
This Transcript
All Transcripts