National Fuel Gas Company's CEO Discusses F1Q13 Results - Earnings Call Transcript

Feb. 8.13 | About: National Fuel (NFG)

National Fuel Gas Company (NYSE:NFG)

F1Q13 Earnings Call

February 8, 2013 11:00 AM ET

Executives

Tim Silverstein

Dave Smith – Chairman and CEO

Ron Tanski – President and COO

Matt Cabell – SVP; President of Seneca Resources Corporation

Dave Bauer – Principal Financial Officer and Treasurer

Analysts

Andrea Sharkey – Gabelli

Kevin Smith – Raymond James

Mark Barnett – Morningstar

Timm Schneider – Citigroup

Operator

Good day, ladies and gentlemen, and welcome to the First Quarter 2013 National Fuel Gas Company Earnings Conference Call. My name is Shequanna and I’ll be your coordinator for today. At this time, all participants are in a listen-only mode. We will facilitate a question-and-answer session towards the end of this conference.

(Operator Instructions)

I would now like to turn the presentation over to your host for today’s call, Mr. Tim Silverstein, Director of Investor Relations. Please proceed, sir.

Tim Silverstein

Thank you, Shequanna, 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.

Dave Smith

Thank you, Tim, and good morning to everyone. First quarter was an excellent quarter for National Fuel. Earnings were $0.81, an increase of $0.08 per share or 11% over the prior year’s first quarter. Excluding the one-time charge at Seneca, earnings would have been 15% above last year and that’s in spite of a $0.69 per Mcf drop in after-hedging natural gas prices.

The Pipeline And Storage segment had a particularly strong quarter. Both the Line N 2012 and Northern Access Projects were placed in service this past fall. Those projects combined with a full quarter revenues from the Tioga Extension project that was placed in service in the fall of 2011 caused earnings in this segment to increase by about 70% over the prior year. As you know, this is a business that we’ve been excited about for a long time, and given the central location of our pipeline, gathering and storage assets in and around the prolific Marcellus and in between the Marcellus and growing markets in Canada and the Northeastern United States, and given our proven track record of bringing projects in on time and on budget, we expect continuing significant growth from these midsteam businesses.

In fact, I’m happy to report that we’ve recently received the customer commitments necessary to move forward on three different projects that combined our design to add another 230 million cubic feet per day of capacity to our system. Ron will provide more detailed information regarding these projects in the midsteam segment in his remarks.

In our Utility business, earnings rebounded nicely from the prior year thanks in large part to weather in our Pennsylvania service territory that was 10% colder than last year. While it was colder than last year, it was still warmer than normal, which is what our rates are based on. Thus, our employees continue to do a great job of focusing on efficiencies and on controlling O&M cost, which not only contributes to improved earnings, but rebounds to the benefit of our retail customers as well.

In the E&P segment, Seneca’s production continues to grow at an impressive rate. Consolidated production for the quarter increased by 6.3 Bcfe, or by more than a third, largely on the strength of Seneca’s successful drilling program in our Eastern Development Area. It’s important to note that that increase does not include any production at all from the exceptional wells we announced last month on PAD-M and Lycoming County. Those wells were tied into sales in late January and obviously will have a big impact on second quarter volumes.

Seneca’s GAAP earnings were down $0.04 per share, largely due to lower natural gas prices and a $3.7 million, what I’ll call termination charge, which was related to a rig that we idled last summer when we reduced operations to a three rig program. However, on a cash flow basis, excluding the termination charge, Seneca’s EBITDA was up $11 million or 11% over the prior year, even after the significant drop in after-hedging natural gas prices. This, of course, was due primarily to our success in the field.

Our Lycoming County acreage in the Eastern Development Area continues to produce some of the best results in the Marcellus. The PAD-M wells, which as I noted will impact the second quarter, contain six of the best wells Seneca has drilled today. Thanks to the coordinated efforts of Seneca and our midsteam subsidiary, all seven wells at PAD-M were producing into sales within days of being completed. The strong results from these wells let us to raise our production guidance for the year to a range of 102 Bcfe to 112 Bcfe, which at the midpoint is a nearly 30% increase over last year. And remember that’s on the heels of last year’s 23% increase in production.

In the Western Development Area, the early results of recent delineation efforts make us increasingly optimistic about this acreage. Several new prospect wells have been added to our program and we will maintain at least one rig focused on these efforts for the remainder of the year.

In California our activities are proceeding according to plan. In late December we closed on our farm-in agreement with Chevron and expect to commence operations there shortly. I’m confident that our Bakersfield team will be able to replicate the success they’ve achieved at Midway Sunset and will extract incremental revenue from the East Coalinga Field. California continues to deliver the results we have come to expect and maintains a key role in our portfolio. Matt will have a full insight in Seneca later on the call.

In closing, our opportunistic efforts to grow the company in a disciplined way continue to gain momentum, and the strong first quarter, along with recent positive developments early in the second quarter are compelling evidence of our ongoing success in creating shareholder value.

And with that, I’ll now turn the call over to Ron.

Ron Tanski

Thanks, Dave and good morning, everyone. As Dave mentioned we’re off to a great start for our fiscal 2013 with every one of our operating segments performing at the high end or above our forecast. Having ramped up the Northern Access and Line N pipeline projects to full capacity, we expect that we’ll be busy blocking and tackling in our regulated segments for the remainder of this year and coordinating our midstream gathering activities in Appalachia with the well completion schedule of Seneca in order to get production flowing to market as efficiently as possible.

For 2013 the bulk of our spending in the Utility segment and the Pipeline And Storage segment will be for pipeline upgrades and integrity management programs. We’ve also got a budget in the $43 million range for finishing work in the Northern Access and Line N projects and for some new pipeline projects. Those new projects include our Line N 2013 and Mercer expansion projects, and we’re working on precedent agreements with customers for both.

The Line N 2013 project, which will have a capital cost of about $6 million is designed to add 30 million cubic feet per day of capacity and should add $1.5 million in annual revenues starting in November of 2013. The Mercer project will add 105 million cubic feet per day of capacity and add $5 million in annual revenue. The cost of the Mercer project, which we expect will be in service by November of 2014, will be approximately $20 million.

We also completed an open season for our West side expansion project, which would be the fifth expansion of our system in the Line N corridor. We were very pleased with the results of the open season and received bids for all of the capacity that we had offered. A total of 95 million cubic feet a day of capacity has been awarded and we’ll be working on precedent agreements for that business also. Since the completion of that open season, we’ve received additional inquiries for capacity and we have our engineers looking at how we can accommodate that interest.

In addition to our efforts along the Line N section of our system, we continue to pursue opportunities to move additional Marcellus production volumes into Canada. Both Empire’s Tioga Extension Project and Supply Corporation’s Northern Access project can be expanded to accommodate an increased throughput. Our project development team is marketing this concept to potential customers and we’re optimistic that we’ll have additional – have an additional project, or projects, in the 2015 to 2016 timeframe. Like I said continued blocking and tackling in the regulated segments.

The largest portion of our capital spending in 2013 will again be in the exploration and production segment for development and delineation drilling.

I’ll turn the call over to Matt to cover all the details for that segment.

Matt Cabell

Thanks, Ron, and good morning everyone. Ron, I appreciate your successful blocking and tackling in the regulated segments and if I can expand on your football analogy a bit, you’ve given Seneca enough time in the pocket to complete another long pass and we’re now first and 10 in the red zone.

Seneca produced 24.5 Bcfe in the first quarter of fiscal 2013, a 34% increase over last year’s first quarter. Production was fairly flat from August through mid-January as no new wells came on in that time period. However, new Marcellus wells have a big impact on monthly production beginning this month; more specifically, we brought on seven wells of tract 100 PAD-M. In our January 22 press release, we detailed the rates for six of these wells. Since that time, we brought on the seventh well and increased the rate on another.

These are truly remarkable wells with average IP rates of 18.2 million cubic feet per day. Four of the wells produced at rates over 20 cubic feet million a day and all seven wells are currently flowing at a combined rate of approximately 85 cubic feet million a day. It’s a bit early to estimate ultimate recovery for these wells, but I’m confident the EURs will be higher than the 11.5 Bcf we estimated for the previous two pads. Finding and development costs here will be in the $0.50 to $0.80 per Mcf range, making for attractive economics even at a gas price of $3.

Also at tract 100 we have now – we now have a couple of months production data from our well that we completed using reduced cluster spacing, or RCS. Using our best well-to-well comparison, the RCS well has a much flatter decline and an estimated 15% to 20% higher EUR than a comparable well with a standard completion design. Therefore, we are planning to complete the remainder of our tract 100 wells and many of our other Marcellus wells using RCS.

In the Utica, we flow tested our Mount Jewett well. As you may recall we had an operational issue with this well and only pumped three stages, one of which was not effectively fraced. The well flowed at a 24-hour rate of 1.6 million cubic feet per day. We are pleased with this rate given the limited treated lateral of 500 feet and only two effective stages. I expect a typical well here would have approximately 5,000 feet of treatable plant and 17 frac stages, assuming it was not an RCS well. Therefore, we expect that we could achieve IP rates of 10 million cubic feet to 15 million cubic feet per day with a typical fully stimulated horizontal well. Our plan is to return to this area later this year.

Looking at our overall drilling plans for the rest of this year, we plan to continue to develop tract 100 with two rigs. By fiscal year-end, we expect to have a total of 36 wells drilled at tract 100 and at least 25 online producing into the Trout Run System. We will keep a third rig drilling on our Western acreage. Following the current seven-well delineation program, this third rig will begin a pilot development program in the Rich Valley Claremont area. As you may recall, our first well at Rich Valley IPed at 6.3 million cubic feet per day and in development mode with economies of scale from multi-well pads and shared water handling facilities we believe we can drill and complete 5.5 Bcf to 6 Bcf wells here for about $7 million, resulting in attractive returns at $4 per Mcf.

In California, we finalized our farm-in agreement with Chevron and we’ll begin redevelopment activities at East Coalinga soon. 2013 plans include reactivating some idle wells and drilling the first few evaluation wells across the acreage block. I anticipate spending $30 million to $50 million at East Coalinga over the next three years.

In Kansas, we’re closely monitoring offset activity in our neighborhood as we plan for a Seneca-operated well in the fiscal third quarter. Drilling plans on our non-operated acreage are proceeding more slowly than we expected and we no longer anticipate a well in the current quarter.

At our last earnings call in November, I mentioned that production would be relatively flat for our first and second fiscal quarters. Since PAD-M has come on ahead of forecast and at rates in excess of forecast, we are now expecting a decent increase in production for the current quarter and are revising our overall annual production guidance upward by 6 Bcfe to a new range of 102 Bcfe to 112 Bcfe.

We are also revising our CapEx guidance up to a range of $480 million to $560 million. This increase reflects the increased cost of RCS completions of about a $1 million per well and a slight increase to overall activity as we are drilling and completing our wells faster than originally forecasted.

Also at our last earnings call, I reviewed our fiscal year-end reserves replacement. For comparison to our peers, who are just reporting reserves now, I think it’s worthwhile to repeat our replacement ratio of 473% and our overall funding and development cost of $1.74 per Mcfe. We’ve maintained a relatively conservative proved undeveloped percentage of about 33%. Because of this, we avoided the large negative reserve revisions that some of our peers have been reporting.

Let me close by pointing out that we recently achieved a new production milestone by exceeding 300 million cubic feet equivalent of companywide daily net production. We’ve more than doubled production over the past three years, and while we have cut back our spending this year, we’re having outstanding results from our drilling program, so I expect our rapid growth to continue.

With that, I’ll turn it over to Dave Bauer.

Dave Bauer

Thank you, Matt, and good morning, everyone. To reiterate what Dave said earlier, first quarter was a great one for National Fuel. Dave hit on all the high points and the release does a good job describing the year-over-year variances, so I won’t repeat them all there. I would, however, like to expand on the charge we recorded during the quarter to terminate a drilling contract, which was pretty much the only unusual item in the quarter.

As you recall, about a year ago Seneca was operating six rigs in the Marcellus. With the drop in gas prices, in the spring of 2012 we decided to lay down three of those rigs. Two of them were beyond their initial contract term, so we released them. The third was under contract through the summer of 2014, so it was temporarily idle, and we continued to pay a reduced day rate for it under the assumption that we would reactivate it when gas prices improved. Under the accounting rules, we’re allowed to capitalize those standby payments.

This past fall we identified another operator who is willing to take the rig at the current market rate, which is somewhat lower than Seneca’s day rate. To get out of our contract, we have to make the owner of the rig hold for the difference between the old and new day rates. We also agreed to fund a portion of the cost to relocate the rig. Total amount accrued in the quarter was $3.7 million before tax or $0.03 per share.

Aside from that charge, our consolidated earnings were a little ahead of our internal forecasts. Seneca’s earnings were a few cents better than forecast, mostly because of lower expenses. Production and revenues were right in line with our expectations. Realized gas prices were a little lower than our base forecast of 350 per MMBTU, but that was offset by higher than expected crude oil prices.

Per unit DD&A expense was towards the low end of our range of expectations, largely due to the timing of our capital spending. Going forward we’re still comfortable with our fiscal year DD&A guidance of $2.10 to $2.25 per Mcfe. Other taxes were $0.13 per Mcfe in the quarter, which is below our guidance range of $0.15 to $0.25 per Mcfe.

During the quarter, we received an approximately $800,000 research and development credit against our Pennsylvania capital stock tax, which reduced our other tax expense. While I’m hopeful this credit will recur in the first quarter of fiscal 2014, I expect our other tax expense for the last nine months of the year will return to the $0.15 to $0.25 per Mcfe range.

Going in the other direction, Seneca’s $1.05 per Mcfe of LOE expense for the quarter was a bit higher than our $0.96 per Mcfe rate from the fourth quarter of fiscal 2012. This increase is largely a timing issue related to our California oil properties where a good portion of the well workovers we had planned for fiscal 2013 were frontloaded into the first quarter. Looking forward, I expect our per unit LOE will be closer to the middle of the range of our $0.90 to $1.10 per Mcfe guidance.

Turning to the regulated companies, earnings of the Pipeline And Storage and Utility segments were also a little ahead of our forecast. As Ron indicated earlier, both the Northern Access and Line N 2012 projects are fully in service, so we’re still comfortable with our full year Pipeline And Storage revenue guidance of $255 million to $265 million. At the Utility, weather in Pennsylvania, in spite of being colder than last year was still warmer than normal by about 7%, and our forecast assumes normal weather. However, O&M expense came in a little lower than planned, partially due to the warmer weather, but mostly due to our employees’ continued focus on controlling costs.

As you saw in last night’s release, we’re increasing and narrowing our fiscal 2013 earnings expectations to the range of $2.75 to $3 per share. At the midpoint, a $0.075 per share increase. This increase reflects our strong first quarter results and assumes Seneca’s updated production guidance of 102 Bcfe to 112 Bcfe. It also assumes normal weather at the Utility. Our commodity price assumptions of $3.50 per MMBTU for gas and $85 per barrel for oil has not changed.

With regard to capital spending, our consolidated capital budget for 2013 is now a range of $665 million to $795 million, which reflects the new Seneca budget that Matt described earlier. Our spending plans for the other segments have not changed from our previous guidance. In terms of cash flow, we expect the incremental net revenues from Seneca’s increased production forecast should fund most of its increased capital budget. Therefore, assuming the midpoint of our earnings and capital spending guidance, we still expect our fiscal 2013 capital spending will just about equal our cash from operations.

With regard to our hedging program, as gas prices rallied last month, we added positions to our hedge book for fiscal 2013 and 2014. For the remainder of fiscal 2013 we’re hedged in the low 60% area for both gas and oil at prices of $4.68 for gas and $94.92 for oil. And these hedges give us a good deal of certainty with respect to our cash flow projections for the year. For fiscal 2014, we now have just under 50 Bcf of gas hedged at $4.24 per Mcf. At these hedge prices, our development drilling program in the Marcellus is highly economic.

Our next long-term debt maturity is for $250 million on March 1, and we expect to be in the market in the near-term to refinance that maturity. Given the current interest rate environment, we’ll likely term out a significant portion of our short-term debt balance, so you can expect an issuance of at least $400 million.

With that, I’ll close and ask the operator to open the line for questions.

Question-and-Answer Session

Operator

(Operator Instruction) And your first question comes from the line of Andrea Sharkey representing Gabelli. Please proceed.

Andrea Sharkey – Gabelli

Hi. Good morning.

Tim Silverstein

Hi, Andrea.

Ron Tanski

Good morning.

Dave Smith

Hey, Andrea.

Andrea Sharkey – Gabelli

So, I’m going to focus on the pipeline a little bit, because that was – well it better than what I was expecting. The $0.20 for the quarter, now that includes Northern Access, N Line and one in November, so I would assume it’s not even really accounting for the whole impact of – the whole quarterly impact of those projects. So I’m just kind of trying to get a sense of, is $0.20 sort of a good run rate going forward? Could it be a little bit better? Or are there are things coming up that we should be mindful of that would make it come down a little bit?

Dave Smith

Andrea, I think it’s – it should be a decent run rate. The – we’ll have – we’ll also have a ramp up in the Empire Tioga Extension project that went in service, so that ramps up to its full volumes in May. But generally I – most all of the projects that we have for this year are in service and this should be a good quarter to benchmark off of.

Andrea Sharkey – Gabelli

Okay. Great. And then, the comment, I think that Ron made about there was another Line N expansion that you had the open season for that you received I guess full bid. When – what would be the timing and size of that project and the CapEx related to it?

Ron Tanski

Well we’re still working on the details of the CapEx, Andrea, but as I mentioned we’re looking at 95 million cubic feet a day for that. And again, that’s through the Line N quarter with more and more producers there looking to get the – some more of the, both Marcellus and Utica production in there. And that’s looking at some time in 2015 to be completed and in service.

Andrea Sharkey – Gabelli

Okay. Great. That’s really helpful. I’ll turn it back in and let somebody else have a chance. Thanks, guys.

Dave Smith

Yep.

Ron Tanski

Thanks.

Operator

Your next question comes from the line of Kevin Smith representing Raymond James. Please proceed.

Kevin Smith – Raymond James

Hi. Good morning, gentlemen.

Tim Silverstein

Hi, Kevin.

Kevin Smith – Raymond James

Solid quarter. Just had two questions. How’s Trout Run doing on excess gathering capacity, is there any potential for bottlenecks?.

Dave Smith

Kevin you broke up a little bit there, could..?

Kevin Smith – Raymond James

Sorry – how’s the Trout Run doing on excess gathering capacity?

Ron Tanski

Well. Let’s put it this way. We’ve built the line in anticipation of more and more pads coming on for Seneca. So it’s not ramped up to its full capacity yet. We don’t expect that there will be any problem in adding each new pad that comes as soon as it’s pretty much completed for Seneca. So that what’s – I mean, is that what you’re looking for?

Dave Bauer

That what you were looking for?

Kevin Smith – Raymond James

Absolutely. Yeah –

Dave Smith

We don’t expect a bottleneck, I guess was your question.

Ron Tanski

Yeah, no bottlenecks.

Kevin Smith – Raymond James

Okay. Great. And then Matt, can you walk me through the process, or the thought process here of moving that rig from the Utica development to Rich Valley? Are you more optimistic on rates of return? Or how should I think about that?

Matt Cabell

Well. I guess I would just say that that Rich Valley Claremont area is an area we have a lot more certainty on. We’ve drilled the Rich Valley well, we’ve drilled other wells in the area. We have a geologic interpretation that gives us a pretty clear path forward there for development. Utica, we really only have – I’d almost define it as one and a half well test, with the Tionesta well, which was a little disappointing and this Mt. Jewett well that was not so disappointing, but was only a test of two stages. So while we’re still excited about the Utica, there’s still a lot of uncertainty there, we need some more delineation work before we’re ready to go forward with the development there.

Kevin Smith – Raymond James

Got you. Do you plan on testing the Utica again this calendar this year? I think you mentioned that in your prepared remarks.

Matt Cabell

We have – we’ll definitely drill additional Utica wells this year and likely at the Mt. Jewett area again, but by the time we drill them, frac them, soak them, I don’t think we’ll see another rate on a Utica well in the fiscal year; it’ll more likely be in the fall.

Kevin Smith – Raymond James

Okay. Thank you.

Operator

Your next question comes from the line of Mark Barnett representing Morningstar. Please proceed.

Mark Barnett – Morningstar

Hey, good morning.

Tim Silverstein

Good morning, Mark.

Dave Smith

Hi.

Mark Barnett – Morningstar

Hi. Just a quick question. I know it’s a small thing, but I’m just wondering about the Kansas delays. Is that something that’s more operational or is that a geological challenge?

Matt Cabell

No. It’s more – it has more to do with our non-operated – with our operating partner and the timing around when they want to get the well drilled. It’s not a geological issue at all.

Mark Barnett – Morningstar

Okay. And then the second and this is also, I know, a pretty small business for you, but there’s been a little bit of activity around this space. With your retail marketing business, your retail energy marketing business, is there any chance you’d be interested in maybe monetizing that? It’s obviously a fairly small cash flow item, but just in general if your crew are ramping up a CapEx schedule in your other businesses that might be a good source of funds?

Dave Smith

Yeah, we’re certainly not looking to sell that business. It’s a nice business, I think it provides options for our retail customers. And we have given thought to monetizing it, but it’s not something that’s at the top of our list.

Mark Barnett – Morningstar

Okay. Thanks.

Operator

(Operator Instructions) Your next question comes from the line of Timm Schneider representing Citigroup. Please proceed.

Timm Schneider – Citigroup

Hey, guys. First question on the updated production guidance, should we just assume all of that is from the Marcellus?

Matt Cabell

Yes.

Timm Schneider – Citigroup

Secondly, can you guys give us an update, I know you touched upon it on the last conference call, on that wet gas solution you’re were trying to work on? Has there anything – anything else kind of pushed to the fore here? Any updates there?

Ron Tanski

Yeah, I think probably – oh, well, I mean with respect to the pipeline project in terms of on the wet gas solution, no. We’ve – we continue to have discussions with producers there. And another partner to actually build the processing. But drilling has slowed down over there and nobody has committed to enough or a large enough drilling program to commit to any kind of capacity through any of the lines there. So, that’s going to be a little bit longer term project.

Timm Schneider – Citigroup

Got it. Then I guess strategically, can you discuss your opportunity set in a bit more detail? Kind of over the next couple years what you see panning out here? On the midstream side, are you just looking to build on to your existing footprint or would you be willing to kind of branch out into other areas of the Marcellus then compete with some of the other guys that are – historically have been active in those areas, to compete for projects?

Dave Smith

Yeah, well, I guess the good news is we have a lot of opportunity within our typical geographic service territory, especially as it extends out to Tioga and Lycoming and further east of our traditional service territories. So we have a lot of opportunity, we have a lot of projects that we’ll be able to focus on.

We will, however, look at doing projects for third parties. And obviously we’ve done some with range and Line N, and in the other areas. So, we will consider doing projects for other parties, but the first option, the first goal with respect to midstream is our own acreage.

Timm Schneider – Citigroup

Okay. And then just switching back to E&P real quick. Matt, in the Utica, those 10 million cubic feet to 15 million cubic feet a day IP wells, what kind of gas price do you think you guys would need to accelerate drilling there?

Matt Cabell

Well, I think the first thing we need a horizontal well with multiple stages and a test rate that is in that 10 million cubic feet to 15 million cubic feet a day range or better. But – so it’s – I mean, it’s a little hard to put a breakeven price on it when we don’t have that well test yet, and you need more than really just an IP rate, you need a sense for the climb, so...

Timm Schneider – Citigroup

Got it.

Matt Cabell

Hypothetically, $4 gas might be good for us for a well there, but maybe it’s lower than that.

Timm Schneider – Citigroup

Okay. And is there any update on Owl’s Nest?

Matt Cabell

Yeah, Owl’s Nest, we drilled two more wells in a rich gas area – it’s not the superrich, but it’s a rich gas area – we drilled two at Owl’s Nest, and one at an area we call Church Run which isn’t too far from Owl’s Nest. We’ll be fracing those and we’re actually going soak those wells too, and we’ll get tests probably sometime this summer. We’re still very interested in that area and in the potential of that wet gas development.

Frankly the two things that really happened here, one, we’re more excited about some of our dry gas than we had been, which is the Rich Valley Claremont area. And secondly as you’re well aware the NGL pricing has eroded and it’s the – the wet gas opportunity is not as compelling as it once was. So that’s a long-winded way of saying we’re still evaluating it. Certainly, it will be developed at some point, it’s just a matter of where it prioritizes in our overall portfolio.

Timm Schneider – Citigroup

All right. Got it. Thanks, guys.

Operator

At this time, I would like to turn the call back over to Mr. Tim Silverstein for closing remarks.

Tim Silverstein

Thank you, Shequanna. We’d 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 p.m. Eastern Time on both our website and by telephone, and will run through the close of business on Friday, February 15, 2013. 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 47931748. This concludes our conference call for today. Thank you and good bye.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect and have a great day.

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National Fuel Gas (NFG): Q4 EPS of $0.81 beats by $0.02. Revenue of $452.9M misses by $29.74M. (PR)