National Fuel Gas Co (NFG) 2012 Q2 法說會逐字稿

Good day, ladies and gentlemen. And welcome to the second-quarter 2012 National Fuel Gas Company earnings conference call. My name is Jeff, and I will be your coordinator for today. At this time, all participants are in a listen-only mode. Later, we will facilitate a question-and-answer session. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Tim Silverstein, Director of Investor Relations. And you have the floor, Mr. Silverstein.

Thank you, Jeff, and good morning, everyone. Thank you for joining us on today's conference call for a discussion of last evening's earnings release. With us on the call from National Fuel Gas Company are -- Dave Smith, Chairman and Chief Executive Officer; Ron Tanski, President and Chief Operating Officer; and Dave Bauer, Treasurer and Principal Financial Officer. Joining us from Seneca Resources Corporation is Matt Cabell, President. At the end of the prepared remarks, we will open the discussion to questions.

We would like to remind you that today's teleconference will contain forward-looking statements. While National Fuel's expectations, beliefs, and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last evening's earnings release for a listing of certain specific risk factors. With that, we will begin with Dave Smith.

Thank you, Tim, and good morning. As you read in last night's release, National Fuel's earnings for the second quarter were $0.81 per share. Excluding the $0.08 per share charge related to the new Marcellus impact fee in Pennsylvania, most of which relates to Marcellus wells drilled in prior quarters, operating results for the quarter were $0.89 per share, which is $0.11 less than last year's second quarter. This drop was largely due to three factors -- first, the winter of 2011 and '12 was unseasonably warm -- in fact, it was the warmest on record in our service territory. The mild weather impacted earnings by $0.05 per share in the Pennsylvania service territory of our Utility, and was a significant contributor to the $0.03 per share drop in earnings at National Fuel Resources, our non-regulated energy marketing subsidiary.

Second, and as you all know, natural gas prices continued to decline throughout the second quarter. While our hedging program did help, our actually realized natural gas price still decreased by $0.68 per Mcf, quarter over quarter. That decrease, and the sale of our offshore Gulf of Mexico properties last April, which is the third factor, were the largest contributors to the $0.05 per share drop in operating results at Seneca. Of the three, only the sale of the Gulf -- which, incidentally, we believe was the right decision, was within our control. Since we can't control gas prices, much less the weather, we focused on managing our businesses, and put particular emphasis on controlling our budgets.

We also continued to execute on our plans to grow our Midstream assets, all with a view to maintaining our strong balance sheet and creating long-term shareholder value. In the Pipeline and Storage segment, our ongoing expansion efforts are progressing according to plan. Construction has actually commenced on the Northern Access and Line N 2012 projects, with both projects still scheduled to be in service by November 1, 2012. When these projects ramp up to their fully contracted volumes, they will add just about $20 million in annual revenues. At our National Fuel Midstream subsidiary, construction of the Trout Run project was completed last week, and will go in service once Seneca's Tract 100 wells are connected, which should be in the next few weeks, and Matt will address that in his remarks.

In the E&P segment, excluding the impact of last year's sale of our offshore Gulf of Mexico properties, Seneca's consolidated production grew by 18%. In the East, Seneca's natural gas production increased by 2.4 Bcf, or 22%. While that is an impressive rate of increase, it actually understates what could have been produced. As we announced at the end of March, low spot natural gas prices on the Tennessee 300 Line led us to curtail an average of $15 million a day of production into the Covington Gathering System for most of the month. That impacted production for the quarter by more than 0.4 of a Bcf.

Looking forward to the third quarter, we expect a significant jump in production when we bring on our first four wells at Tract 100. That production will be delivered by our Trout Run system into the Transco system to the south, where pricing is stronger. In addition, should gas prices rise, we have the ability to immediately resume full production into the Tennessee 300 Line.

In California, crude oil production was up 11.5% from the prior year, largely due to our drilling programs at South Midway Sunset -- which, as you know, we acquired from Ivanhoe in 2009, and at Sespe. Our California folks continue to do a great job; and at these oil prices, we will look to be as aggressive as we can be with our development program in Pennsylvania -- in California.

Looking to fiscal 2013 -- with the decline in natural gas prices, we expect to allocate less capital to the development of our Marcellus acreage. As you read in last night's release, we plan to move to a three-rig program by the summer. At current gas prices, the returns don't justify an aggressive development program, at least not as aggressive as we previously outlined. Fortunately, we are under no pressure to drill our acreage. Most of our natural gas rights are held in fee, and most of our non-fee acreage is held either by production or has a number of years remaining on its lease term.

Given these and a variety of other factors, we think the best answer for our shareholders is to pull back on our Appalachian drilling program and focus on three areas -- first, is the Utica. Given the depth and the pressure of the Utica, and given the size of our acreage position, we are optimistic it will be a significant opportunity, though assessing its potential is a top priority. Evaluating our Marcellus wet gas potential is another important initiative. Should the price uplift from liquids remain, the Owl's Nest area could be an attractive area to pursue, particularly if gas prices improve. We expect one rig will be dedicated to these delineation efforts.

In the Eastern Development Area, two rigs will be devoted to a scaled-down development program at Tracts 100 and 595. Wells on this acreage currently generate our highest returns in Appalachia. Overall, even with this reduced three-rig program, we still expect Appalachian production to grow by 25% in fiscal 2013. Moving from a four- to a three-rig program will have little effect on our 2012 capital budget, but the impact on fiscal 2013 is more substantial, about $75 million. Our new E&P capital budget for fiscal 2013 is $450 million to $550 million, which is roughly half the amount we set forth at our Analyst Day meeting last September, when we anticipated a very robust six and a half rig drilling program.

Some of the reduction in CapEx was simply a function of lower cash from operations, caused by the drop in gas prices, and a desire to maintain our strong balance sheet. Some represents capital that we plan to redeploy to Midstream opportunities -- that is, both our FERC-regulated Pipeline and Storage projects, and the non-regulated gathering projects of our NFG Midstream subsidiary. Since its formation in 2008, Midstream's primary mission has been to build the gathering infrastructure needed to get Seneca's production to market. Despite that limited objective, it has been quite successful, as evidenced by the Covington and Trout Run systems.

Along the way, we have had discussions with numerous third-party producers who are interested in having Covington and Trout Run expanded for their use, or in having NFG Midstream build their infrastructure. While we were certainly open to the idea in a higher gas price environment, capital allocation was the issue; the returns on third-party gathering projects really could not compete with the returns from our drilling program. In today's gas price environment, the returns on Midstream projects are much more competitive with our E&P returns, and we think that it makes sense to allocate additional capital for projects with unrelated producers, particularly given Seneca's more modest program.

Given our relationships with most of the major producers in Appalachia, all of whom have worked with one of National Fuel subsidiary companies; given our existing assets, particularly Trout Run and Covington, both of which can be expanded to other producers; and given our over 100 years of experience in putting pipe in the ground, we believe we are well-positioned to take advantage of opportunities with other producers in addition to Seneca, in the unregulated midstream space. In addition, we will also continue our ongoing project development efforts in our FERC-regulated business. Over the past several quarters, Ron and I have reviewed a long list of projects that are currently on the drawing board, and Ron will update you on some of those later in the call.

Needless to say, as we always have, we will aggressively pursue those initiatives and seek out new opportunities. Our FERC-regulated system is located in the heart of the Marcellus and the Utica, and I am confident our development team will continue to conceive many new additional projects in the years to come. In closing, the natural gas price environment will present challenges, particularly for independent natural gas producers. It will present challenges for National Fuel, as well. But relative to most, we are well-positioned. Our balance sheet is strong, and our regulated businesses provide a stable base of earnings and cash flows, without regard to commodity prices. Our midstream businesses should continue to grow, and we have great oil assets, which generate significant cash flow. We have a diverse business mix, and importantly, an expertise in our employee base that allows us the flexibility to redeploy capital, as we see fit, to the best opportunities. With that, I thank you for your attention, and I will turn the call over to Ron.

Thanks, Dave, and good morning, everyone. As a result of the warmer weather, we expected, and saw, a decrease in our year-over-year throughput in our utility segment and in the legacy contracts in our pipeline and storage segment. Simply stated, because of the space heating needs were lower in our own utility service territory and in the service territories of other utilities that ship gas through our interstate pipeline system, related throughput was lower. Offsetting those decreases from our traditional utility customers, we saw an increase in throughput from shippers moving gas out of the Marcellus production areas, through our system, and off to East Coast and New England markets.

In addition, because of the lower price of natural gas, the Sithe gas-fired electrical cogeneration plant near Syracuse was running quite a bit during the quarter, and we saw increased throughput on our Empire pipeline, as a result. When the producers get all their gathering lines tied into the Tioga County extension, we should see a very slight increase in throughput on the Empire Pipeline system, and it will only be slight because the producers have temporarily released their capacity to replacement shippers who actually use the capacity during the quarter.

With respect to field operations, the mild winter weather allowed our construction and maintenance crews to work pretty steadily on all of our maintenance and system upgrade projects, and we are right on target with our capital spending for our ongoing pipeline integrity field work. We are also moving along with our spending on a couple of near-term, new infrastructure projects. For Supply Corporation, we have begun construction of a compressor station for our Northern Access project, and we expect to have all the metering changes and other bits and pieces of that project complete this November, so that we can provide service as originally scheduled.

On our Line N 2012 project, which is the second expansion of this legacy pipeline, there is more compression being added, along with some pipeline upgrades, to increase capacity on that line by an additional 164,000 Dth per day. We also expect to have this new compression capacity operational in the fall. In our unregulated midstream gathering operations, as Dave said, we are expecting to place Trout Run System in operation to coincide with Seneca's completion of its initial well pad on Tract 100 in Lycoming County, later this month. Remember that the Trout Run pipeline will deliver Seneca's production from Tract 100 to Transco, and has a design capacity of 466 Mcf per day.

Currently, realized pricing on the Transco System is about $0.30 per Mcf higher than on the Tennessee System for term deals, and $0.15 to $0.17 higher for spot deals. On the regulatory front, I am pleased to report that Supply Corporation has reached a Settlement in Principle with the parties in its rate case that it filed last October. We put the new, settled rates into effect on May 1 on a temporary basis, until the settlement is finalized. There is still a lot of work to be done in putting a complete settlement agreement together, and it could take four or five months to reach final agreement and have that agreement approved by the Federal Energy Regulatory Commission.

Before I turn the call over to Matt for an update on Seneca's operations, I will point out that Seneca, as part of the Appalachian Shale Recommended Practices Group, recently published a list of operations standards for drilling in Appalachia that were developed by the group to address safety and certain environmental and health concerns, the development of oil and gas properties in Appalachia.

National Fuel and all its operating subsidiaries believe that the responsible development of domestic, clean-burning natural gas can be an economic benefit to the communities where the development is occurring and to the energy security of the nation. Seneca is pleased to be a part of the group in the forefront of that responsible development. Now, I will turn over the call to Matt to update us on Seneca.

Thanks, Ron. Good morning, everyone. East division production was 13.3 Bcfe, up 22%; while West production was 5.1 Bcfe, up 9%. Overall production was 18.4 Bcfe, up only slightly due to the sale of the Gulf of Mexico assets last year. Focusing on California first, we are continuing to grow production with significant increases at both South Midway Sunset and at Sespe. We plan to drill a total of 23 new wells at South Midway Sunset this year.

Recent drilling has extended the size of the two primary Antelope Sand reservoirs, and allowed us to increase production from about 700 barrels of oil per day last year to 1,050 barrels of oil per day now. At Sespe, four wells were drilled in fiscal 2011 that are producing at a combined rate of about 300 BOE per day. We have six wells planned for this year, including two more five-acre infill wells, two Coldwater Formation wells, and two wells on our new Oak Flat Lease. Also in California, our non-operated Monterey well at the Belridge Field is producing about 50 barrels of oil per day. Three to four delineation wells are planned there, including at least one horizontal. While we only have a 12.5% interest, if the delineation drilling is successful, there could be hundreds of additional locations.

In Pennsylvania, we continue to develop our Eastern Marcellus acreage in Tioga and Lycoming Counties. Our combined Covington and Tract 595 wells in Tioga County are capable of about 140 Mcf per day, but we are currently curtailing production to about 130 Mcf per day, for which we have firm sales contracts. In Lycoming County, the Trout Run Gathering System is fully installed, and our first four-well pad has been frac'd. We are currently drilling out plugs and running production tubing, and expect to initiate production before the end of the month. We are a few weeks behind schedule, due to a delay in getting a 10,000 psi snubbing unit that could handle these higher-pressure wells. Once this pad is online, we expect overall Marcellus net production to be over 180 Mcf per day.

We completed our third well at Boone Mountain in the second quarter; it came on at 4.6 Mcf per day. We have de-risked this portion of our acreage, and will begin development when gas prices improve. Later this summer, we will be drilling three Marcellus wet gas tests to determine BTU content and potential EURs in Western Elk County. This data will help in designing the cryogenic processing facility and in determining minimum gas pricing needed for this development project. We are also closely watching NGL pricing. We do expect some downward pressure on C3+, and will consider this prior to a go-ahead decision on a processing plant.

In the EOG joint venture, the two most recent wells came on at rates of 3.5 Mcf and 4.5 Mcf per day. We are encouraged to see higher initial rates, as compared to last fall's disappointing IPs. However, we will be evaluating the economics of the EOG wells and considering non-participation until prices improve. As I have mentioned before, even if we do not participate, we will retain a 20% royalty interest on JV wells drilled on our fee acreage. In the Utica, we are drilling our second horizontal well. Our first Utica horizontal at Mt. Jewett will be frac'd in July. Our latest production guidance is 81 Bcfe to 90 Bcfe in fiscal 2012, and 100 Bcfe to 115 Bcfe for fiscal 2013.

Capital expenditures are expected to be $610 million to $690 million in fiscal year '12, and $450 million to $550 million in fiscal year '13. This assumes that we continue to curtail some production through the summer, and it also assumes we drop another Seneca-operated rig this summer, leaving only three Seneca-operated rigs for fiscal year '13. We are also assuming that we will not participate in some portion of the EOG joint venture program in fiscal year '13. Note that we have cut our spending considerably; we expect to reduce it further in fiscal '13; and at the midpoint of our guidance, we still expect production growth of 25%, both this year and next year.

On the cost side, we are currently in the process of negotiating to lower our pressure pumping charges and sand acquisition cost. We have succeeded in gaining substantial reductions to our chemical and wireline costs, and continue to move forward with the purchase of some items, such as frac tanks and rig mats, that we once leased. We have slowed our hiring substantially and are currently at a head count of about 40 less than what we had budgeted. As production grows this quarter, we will see a substantial drop in our G&A per Mcfe, such that 2012 will be lower than 2011.

In conclusion, we have responded to the current commodity price environment by expanding in California and reducing our spending in Pennsylvania. California production is up, and we expect to increase our spending there in fiscal 2013. Our Marcellus program has great momentum; even as we temper our activity there, production will continue to grow. When gas prices improve, we will be well-positioned for further growth. With that, I will turn it over to Dave Bauer.

Thank you, Matt. And good morning, everyone. Overall, our operating results for the quarter, while lower than last year, had a number of bright spots. In the Utility, if you put aside the effect of an unseasonably warm winter, earnings in that segment were actually ahead of forecast, due to lower than anticipated O&M expenses. In the Pipeline and Storage segment, this was the first quarter to reflect the full impact of the Tioga Extension and Line N expansion projects that were placed in service last fall. For the quarter, the two projects added $7.8 million in revenues.

At Seneca, operating results fell short of our previous projections, mostly because of lower natural gas prices. But production growth and strong oil prices led to improved results from our California properties, which mitigated some of this impact. All of the specific drivers of the quarter's results are covered in last night's release, so I won't repeat them all here. However, I would like to expand on Seneca's per-unit operating expenses for the quarter, which were a little higher than we anticipated, but which we expect to trend downward over the remainder of the fiscal year. On a sequential basis, Seneca's $1.14 per Mcfe of LOE expense for the quarter was higher than the $1.02 rate for the quarter ended December 31, 2011.

Most of that increase is attributable to higher LOE on our non-operated joint venture wells, including an out of period adjustment from EOG that by itself increased our LOE rate for the quarter by $0.04 per Mcfe. We have updated our forecast, and expect our LOE rate for the last six months of the year will be in the range of $0.95 to $1.10. Seneca's DD&A rate for the quarter was $2.30, up $0.03 per Mcfe for the quarter ended December 31. Much of this increase is due to the timing of our reserve additions, relative to our capital spending. As our wells on Tract 100 come online, we expect meaningful reserve additions in the upcoming quarters, which should cause our DD&A rate to come down. Thus, we are still comfortable with our $2.20 to $2.30 per Mcfe guidance for DD&A expense.

G&A expense is on pace to be within our guidance of $54 million to $58 million for the fiscal year. As Matt said earlier, we expect a significant jump in production in the third and fourth quarters, which should cause the per-unit rate to come down. As we said in last night's release, property, franchise, and other taxes increased due to a $9.8 million accrual for the Marcellus Shale Impact Fee. $5.9 million of that accrual related to prior fiscal years. Going forward, assuming a three-rig program and current gas prices, our impact fee accrual should be approximately $2 million per quarter for the last six months of fiscal 2012. Assuming current gas prices and a three-rig program, we expect the impact fee will trend upward in 2013 and average about $2.5 million per quarter. However, changes in gas prices and the timing of when we spud our wells could impact the ultimate amount we incur.

Turning to our earnings guidance -- we are lowering our GAAP earnings expectations for fiscal 2012 to a range of $2.30 to $2.45 per share. Our previous guidance was $2.40 to $2.65 per share. The change in our guidance is mostly attributable to the Marcellus impact fee and a further reduction in our NYMEX natural gas pricing assumption, which is now $2.25 per MMBtu for the remaining six months of the year. On a positive note, we are seeing higher than expected firm transportation revenues in the Pipeline and Storage segment, and lower than expected O&M expense across both regulated segments. We expect those trends to continue into the second half of the fiscal year, which should add a few cents to earnings, and this has been reflected in our new range.

Our earnings guidance also reflects the terms of the settlement of Supply Corporation's rate case, but that settlement should not have a material effect on this year's results. In terms of our capital budget, our spending plans for 2012 are unchanged from the $900 million to $1.045 billion range we included in our most recent IR slide deck. With respect to 2013, as Dave said earlier, we have lowered Seneca's spending forecast by $75 million, to reflect the new three-rig program. The forecasts for the other segments have not changed.

A recap of 2013 spending by segment is as follows -- $55 million to $60 million in the Utility; $30 million to $50 million in Pipeline and Storage; $450 million to $550 million in E&P; and $75 million to $125 million in Midstream and All Other. Our consolidated financing needs for fiscal '12 are essentially unchanged. Seneca's operating cash flows are expected to be a bit lower at our new $2.25 natural gas price assumption, but that will be offset by a lower cash need at the Utility for purchases of stored gas inventory. At March 31, we had $172 million of net cash on our balance sheet.

Over the next six months, we will incur significant expenditures at Seneca for its drilling program, at Supply Corporation for the construction of the Northern Access and Line N 2012 projects, and at the Utility for the purchase of gas inventory. As a result, by fiscal year-end, I expect we will be in a net short-term borrowing position of around $50 million. Before closing, I would like to highlight a change we have made to our hedging program. As you saw in last night's release, we added a modest layer of natural gas hedges that extend through fiscal 2017.

This is a bit of a shift from our historical hedging strategy, which generally had gone out only two years beyond the current fiscal year. Given the slope of the NYMEX futures curve, we intend to establish a meaningful long-term hedge position to lock in the economics of our drilling program. We started layering in these positions this past week, and would expect them to build in the quarters to come. With that, I will ask the Operator to open the line for questions.

(Operator Instructions) Andrea Sharkey, Gabelli & Co.

Hi. Good morning. I was wondering if you could give us some more guidance towards 2013 on California. You guys have done a great job increasing that oil production; I think it's up about 10% so far the first half of this year. You seem to be ramping up more drilling. Can we expect a similar type of growth rate in 2013 and beyond? Or is there a level where you tap out on the California area?

We have not given any guidance yet for specific -- by division for fiscal 2013. We will be spending a bit more in '13 in California than we did this year in '12. So, I think we would anticipate some growth in production between '12 and '13, but I don't think we are really prepared to quantify that yet, Andrea.

Okay, that is fair enough. The next question would be -- I think you guys have about $250 million in debt that is maturing in 2013. And you might be a little bit -- have a shortfall on your capital spending this year. How do you plan to address that? Will that just be new debt? Equity? What are you thinking there? And then, also looking at 2013, do you plan to stay within cash flow there?

In terms of the $250 million, at this point, I think we would plan on refinancing that with another long-term debt issuance. I would not see us needing to issue equity. That is not the plans. In terms of fiscal '13 spending versus cash flows, we have not initiated guidance yet. But I think it's safe to say that we will be much, much closer to be living within cash flows.

Okay. Good to hear. Last question for me, and I will give somebody else a chance -- you guys have significant hidden value in all of your assets. There is a lot of options out there for you to service that value -- for example, we've talked about before monetizing the pipeline by maybe an MLP structure. Where are you on evaluating any of that potential financial engineering options?

I think, at this point, Andrea, we are fairly comfortable with where we are. Certainly, as we move forward and look to devote more capital to the Pipeline and Storage segment and the Midstream segment, and we have a higher basis -- tax-basis assets there, we would be looking much more toward an MLP at that point. I think right now, we have some room to lever up a little bit, a couple hundred more million dollars. And certainly, that is very active in our thoughts and considerations as we move forward.

Okay, great. Thanks a lot.

Holly Stewart, Howard Weil.

Good morning, gentlemen. Just a couple follow-ups -- remind us, Matt, on the limitations in California. Because I think -- obviously, as you look out to the macro environment right now, people think great cash flows in California, so why wouldn't you be going faster? So, can you remind us of the limitations out there?

Well, let's think about our two biggest growth areas, which would be South Midway Sunset and Sespe. At South Midway Sunset, we are extending reservoirs as we drill those wells. So, really, if you tried to get ahead of yourself, you might outdrill the limit of the reservoir. So, you need to -- each well is dependent on the previous one. And at Sespe, the primary growth area at Sespe is the 5-acre infill program. We really want to get some production history before we determine how aggressive we want to get on that program. We have a little bit of production history from the 2011 drilling.

We will get some production -- some further history from those wells, plus some from our 2012 drilling. And then, we may be able to accelerate it a little in fiscal -- let's call it fiscal '14. But there is some limit, even if we felt like it was something we wanted to get more aggressive on, there are some limitations to how much we would drill at Sespe. We have a limited drilling window. That's a fairly environmentally sensitive area, so there would still be some limits based on that.

Two rigs running right now?

In California?

Yes.

No. One rig in California.

One rig, okay.

(inaudible)

Okay. Switching to the Marcellus -- talk about the decision to drop the rig. More specifically, was there a financial impact of that decision?

Oh, you mean --

In terms of rig contracts and services.

Yes, we fully expect that we will be able to have that rig placed in another basin, and that our costs will be minimal. We do have an obligation on the rig that would be on the order of $6.5 million a year, were it not placed.

Another basin?

Yes. Not for us.

Okay, okay. Just a reminder on -- I think Dave said now looking for a 25% growth rate in 2013 in the Marcellus. What was the previous announced growth rate there?

35% to 40%, I think, Holly, previously.

Okay, great. Thanks, guys.

Carl Kirst, BMO Capital.

Good morning guy, actually its Danilo. There was mention of other Niagara capacity turnbacks and pipelines, and those turnbacks offsetting revenues from the expansion project. I am just curious if this is something incremental to what we have been talking about.

You are kind of breaking up there. Could you repeat that?

Yes. There is a mention of Niagara capacity turnbacks. I'm just curious if this was something that was incremental to what we have already been talking about?

No. Those were all planned. And then, as we move forward, by the end of this year, when we get the Northern Access project in place, that is all pretty much going to be offset by gas flows going the other way.

Okay. Thanks for that. Finally, on the Utility, can you please tell us what the pretax dollar impact from weather was for the quarter?

I am pretty sure it was $0.05.

Okay.

It's in the back of the press release.

The $0.05 is after tax, right?

Oh, I'm sorry, that is after tax. I don't have that number here. (multiple speakers)

We can get back to you on that.

Okay, great. That is it for me. Thanks.

Timm Schneider, Citigroup.

First question -- how many more wells are you planning to drill at Owl's Nest this year?

Let's see, we have two more Owl's Nest wells planned in the coming months. They won't necessarily fall in this fiscal year. If I had to guess, I would say one would be this fiscal year and one will be next fiscal year, just because the rig will be there at a time that overlaps the end of our fiscal year.

Got it. If possible, can we get an update on that Henderson well, or are you still doing the data on that?

We are still keeping that one tight, for now.

Okay. With respect to the down spacing at Sespe, what could the incremental locations be there, if it in fact works?

I'm going to put a range on it, and say 20 to 50.

Okay. Got it. That was it for me. Thank you.

Chris Sighinolfi, UBS.

Matt, when you were talking about curtailments in the East, due to take away limitations, do you think -- remind me how long will would be in place? How long are you going to be curtailed there?

Well, it's a function of pricing.

Okay.

So, if we got to the point where our spot pricing at TGP 300 was in excess of $2.30, we would probably stop curtailing there.

Okay. That is just discounting to get it into that line, essentially.

Yes.

Okay. Dave, switching gears a little bit, when you spoke about the impact of the Impact Fee of $2 million, I think was what you said, in the back two quarters of the year -- is that -- might I think about it in addition to what we saw as the run rate in 1Q? So, you had sort of a tax line, if you will, in E&P of $2.5 million in the first quarter. So, am I to think about the third quarter as being somewhere around $4.5 million, and incremental $2 million on what you had --

Well, we have some franchise and ad valorem taxes in California that would be in addition to the Impact Fee.

Right. So, you were talking only about the impact of -- okay.

Right. So, that $2 million -- if you were to go back to last year's third quarter, if that is what you are trying to do, that $2 million would be incremental to whatever that previous rate had been.

Okay, got it. And then, I appreciated the color on your hedging strategy change. I saw, incidentally, that wasn't employed on the oil side -- obviously, we have a backward[-dated] curve there. So, is this more of a -- if I thought about your hedging profile in the past or hedging behavior in the past -- it was around cash flow protection and making sure you guys could forecast accordingly. Now, it looks to me more of a -- I don't want to say commodity bet -- but maybe a viewpoint that that can tango on the natural gas curve makes it such that you guys can make attractive returns. So, you just opt to lock it in. Is that the way to think about what you are doing there?

Yes, I think that is right, where if you look at the upward slope, we can hedge at an average price of around $4 an Mcf. We can lock in a pretty good return at that level. And given the downside on commodity prices, thought that was the right thing to do.

Okay. There has been some questions about the out years of the curve, how liquid it is out there. Granted, you guys are starting small, you talk about adding a little bit on as time progresses. But any issues with regard to that, as you have seen it?

Yes, we heard the same things from our counterparties, where at times, the big producers may have been doing some good-sized trades that sopped up all the liquidity. But we were patient and like the levels that we got.

Okay, thanks, guys.

Craig Shere, Tuohy Brothers.

Matt, a couple quick questions -- on the EOG JV participation, I thought that was running maybe $150 million a year. Is that right? And do you have a rough proportion of that that you might choose not to participate for fiscal '13? And would any of that affect the second half of this year?

It's important to understand, when you think about our participation in a well that is spud today, that a whole lot of the cost -- well, let me rephrase that. If you look at 2013, a lot of what we will spend on the EOG program is completions of wells that are already drilled or are being drilled as we speak. So, even if we non-participated in everything, the impact of 2013 is probably only on the order of about $50 million.

I got you.

Now, if we continue to non-participate, it would have a -- you are probably right, it probably gets to be more like $150 million over time.

Okay. And then, on those Sespe questions, you were talking about the down spacing. But didn't you have a deeper delineation well you were working on, that is kind of separate from that?

Yes.

And what is the progress of that?

Well, we haven't drilled it yet.

When will that be done?

It will be in fiscal '13.

Okay. Any idea how early?

I'm sorry -- it will be in fiscal '12.

Okay. So, you will have results to report by the year-end, for the fiscal year?

I wouldn't count on having production results in '12, no. Probably more likely it would be '13 by the time we have completed it.

Okay. And Dave, you were talking about, at the lower commodity strip, about the competitiveness of Midstream expansion serving third-party producers versus CapEx to E&P. That makes a lot of sense, but could you put some additional color around just how much the Midstream could grow over time?

I think in large part, we have a number of projects right now on the drawing board, let's say, over the next three years. We have, probably, about $400 million right now. Now, the likelihood is, they won't all happen. And many of those coming from our actual Midstream subsidiary, the unregulated side, are devoted to Seneca. But I could see a scenario working with other producers, particularly expanding Trout Run, expanding Covington, and working with other producers. I could see us spending an incremental $200 million there, let's say, over the next two or three years.

Okay.

But there's a lot of moving parts to it. So, it will depend on how many of those projects, for example, we presently have on the drawing board we do, it will depend on our ability to work those relationships that I talked about. But certainly, we think those are very, very good projects, and a great opportunity for us to grow.

If I may dovetail that with the question about the MLP status -- do you think, if we fast forward, say, 24 months and you have an extra couple hundred million of Midstream CapEx well on its way, that you are getting close to the point of critical mass, to think about improving your cost of capital and some of the parts multiple with an MLP?

Yes, absolutely.

Great, thank you.

Kevin Smith, Raymond James.

Good morning, gentlemen. Most of my questions have already been answered, but I just have one and maybe two -- first, are you going to be able to produce everything out of Tract 100 at capacity? Where do you stand with firm capacity out of there?

We have about $30 million a day of firm sales now, it goes to $50 million in November. I would say there's a pretty big -- pretty high likelihood that we will be above that firm sales level. So, the spot market is okay there right now. No reason why we can't produce above our firm sales. And then, also, we are looking at potentially locking in additional --

I'm sorry, I think I lost you -- you said you are looking at additional firm capacity?

Yes. We may -- I wouldn't think of it as firm capacity, more as firm sales. But yes, we are looking at additional firm sales.

Got you. Lastly, when do think you are going to be able to talk about Utica well results and what that play means for you? Do you have it targeted a year from now or six months from now? What is your timetable and thinking on that?

Maybe the way to look at it, Kevin, is we'll two wells drilled and frac'd by the end of this fiscal year. And we may have some test results from them sometime in the fall. So, I would say, if you really want to -- if what you are trying to think about is -- when are we going to be talking about how significant this potential is to us, and what does it mean for our capital spending forward, I would target sometime in the fall.

Got you. And is anybody else drilling -- do you have any competitors that are drilling around that acreage?

We certainly have permitted wells around that acreage.

Okay. That is all I have. Thank you.

Ladies and gentlemen, that concludes the Q&A portion of our call. I would now like to turn the presentation over to Mr. Tim Silverstein for closing remarks.

Thank you, Jeff. We would like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 2.00 PM Eastern Time on both our website and by telephone, and will run through the close of business on Friday, May 11, 2012. To access the replay online, visit our Investor Relations website at investor.nationalfuelgas.com. And to access by telephone, call 1-888-286-8010 and enter passcode 11631131. This concludes our conference call for today. Thank you and goodbye.

Ladies and gentlemen, that concludes the call. Thank you for your participation. You may now disconnect. Have a wonderful day.