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National Fuel Gas Co. (NYSE:NFG)

Q1 2009 Earnings Call

February 06, 2009 11:00 AM ET

Executives

James C. Welch - Director, Investor Relations

David F. Smith - President and Chief Executive Officer

Matthew D. Cabell - President of Seneca Resources Corporation

Ronald J. Tanski - Treasurer and Principal Financial Officer

Analysts

Carl Kirst - BMO Capital Markets

Shneur Gershuni - UBS

Rebecca Followill - Tudor Pickering &Co.

Operator

Good day, ladies and gentlemen, and welcome to the First Quarter 2009 National Fuel Gas Company Earnings Conference Call. My name is Shannon and I'll be your coordinator for today. At this time, all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the presentation over to your host for today's call, Mr. Jim Welch, Director of Investor Relations. Please proceed.

James C. Welch

Thank you 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, President and Chief Executive Officer; and Ron Tanski, Treasurer and Principal Financial Officer. Joining us from Seneca Resources Corporation is Matt Cabell, President. At the end of the prepared remarks, we'll open the discussion for questions.

We'd 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 day 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'll begin with Dave Smith.

David F. Smith

Thank you, Jim, and good morning to everyone. Last night, we reported a net loss for our first fiscal quarter of $0.07 per share. A sharp drop in crude oil and natural gas prices required us to take a $108 million after tax charge, to write down the book value of our exploration and production assets. While disappointing, it was expected, its non-cash, and it's important to realize this impairment was entirely price driven, with no significant loss reserves. Our reserves are still in place, and as they are produced, they will contribute to future earnings.

As we've said in the past, diversity of assets is a defining characteristics of National Fuel's long-term strategy. Our regulated operations, which are not greatly impacted by short-term swings in commodity prices, act as a natural hedge to our more price sensitive E&P operations. The benefit of our diversified and balanced portfolio of assets was readily evident in this quarter's results. While lower crude oil prices and hurricane related production shut-ins Gulf, our Seneca's recurring operating results to drop by $0.08 per share.

Our utility and our pipeline and storage operations posted strong results; results that largely offset the reduction at Seneca. Consequently, consolidated operating results were down only $0.02 per share, compared to the prior year's record first quarter.

The past several months have been characterized by declining commodity prices, and tighter access to credit, conditions which may exist for some time. Since there is little we can do to influence commodity prices or credit markets, we have focused on effectively managing our assets, and prudently allocating our capital.

In the E&P segment, we continue to prioritize the development of our nearly 1 million acres of mineral rights in Appalachia.

In the Marcellus, our partnership with EOG is proceeding at the pace called for in our joint venture agreement. And it's fair to say that EOG and National Fuel are encouraged by the results achieved this past quarter. At the same time, we are eager to initiate our own Marcellus drilling program, which we are only now able to do, as a result of a modification to the joint venture agreement, and expect to have a rig in place next week.

With regard to our Upper Devonian program, we are pleased with the progress of our drilling in that region. Presently, we are ahead of last year's pace, which at year's end resulted in 254 wells being drilled. Our attention is also focused on infrastructure. We've identified several pipeline, compressor and gathering projects that when completed, will help provide an outlet for incremental Appalachian production.

As you would expect, the lower commodity price environment in tighter credit markets have caused us to take another look at our E&P capital spending plans. In summary, one, we do not anticipate making any major changes, to our projected capital budget in the East, that's just down slightly.

In the Gulf, we are significantly reducing our exploration program. In fact, there are no true wildcat exploration wells, and as we said in the past, we'll only commit capital to the Gulf, if we see a solid opportunity to earn a very attractive return.

In the West, the incremental capital that has been earmarked to accelerate crude oil production, which was about $90 million, which made perfect economic sense at $100 a barrel, was cut from this year's capital budget. And Matt will provide in his presentation more detail on our E&P operations, and also on those CapEx reductions.

Turning to the regulated segments, frequent and bitter cold snaps are experienced throughout the quarter and in January, the cost increased throughput across our entire system. Operationally, it's been a real test. When we haven't had in some time and our system performed impeccably, which is a testament to our employees, whose efforts make possible the safe and reliable service our customers expect.

With today's energy prices, which are still relatively high historically, colder weather, and current economic conditions are more concern than ever about our customers managing this winter season bill. As a result, we continue to strongly promote the programs that provide them with both long and short-term assistance.

One in particular is our Conservation Incentive Program, established in our New York division's last rate case, which gave us the tools to aggressively promote conservation. Since implementation more than 18,000 customers have taken advantage of the program. Nearly $5 million has been provided in the form of cash rebates, and free weatherization services. And our efforts are beginning to pay-off in the context of throughput. Since implementing the Conservation Incentive Program and our Revenue Decoupling Program, average normalized residential usage has declined by about 1%.

In addition, we continue to aggressively promote the availability of the systems programs. In particular, changes to the federally funded Home Energy Assistant programs, offered in both New York and in Pennsylvania are making it possible for more families than ever before to qualify for health with Heating Bills. As of the end of the first quarter, we have collected $30 million HEAP on behalf of our customers, compared to the $20 million collected over last year's first quarter.

Turning to the pipeline and storage segment. In distribution, we placed the Empire Connector project in service. Nearly five years of development went into that project, which is the largest organic project completed in the history of the company. I applaud the efforts of the many individuals who made it a reality. Complementing the Connector project, Supply Corporation has been busily marketing its system, as a source of supply from Millennium shippers.

I am happy to report that Supply Corporation recently secured a 10 year contract to transport 75 million cubic feet per day into Millennium and Independence. The project required only modest incremental capital investment, and is expected to generate over $3 million of revenue per year for the company. We will continue to invest in this segment, and to that end we continue to pursue the development of our West to East project, and it's accompanying Appalachian Lateral.

Interest remains very strong, especially with Appalachian producers. We recently completed our revised capital cost estimates, and are drafting precedent agreements that we expect to sent to perspective shippers in the second quarter. However, as a producer driven project, the ultimate timing largely dependent on drilling activity in the region, and particularly in the Marcellus. Given the lower commodity price environment and tight credit markets, it's quite possible that pace of drilling may slow in the coming months, which could push completion of the project into fiscal 2012. And that's not to suggest that related projects will not be developed and put into service sooner.

Remember that, we believe for some time that it was likely that this and other projects would develop in sequential stages in conjunction with the development of the Marcellus, and the development of the market. And that's proven to be the case, for example, Supply Corporation is pursuing a pipeline of compression project, at the Southwestern end of our system, that would move about a 150 million a day to market constraint... of the market constraint Marcellus production to an interconnection with Texas Eastern at Bristoria, and ultimately off system.

In the long run, it very well may tie into the West to East project. This project is moving along at a rapid pace at least by pipeline standards, and we're hopeful to have signed precedent agreements by the end of this quarter. If all goes well, the Bristoria project should be in service by December 2010.

In closing, we continue to be optimistic about the future. No doubt, the coming months will be challenging. But National Fuel has endured many boom and bust cycles, over the course of its 107 year history.

We're a conservative company. We have been a conservative company; we are a conservative company, and we will be a conservative company. And I firmly believe our fiscal discipline and balanced portfolio of assets position us to meet the challenges that may lie ahead.

With that, I'll turn the call over to Matt.

Matthew D. Cabell

Thanks Dave. Good morning, everyone. Let me start by addressing Seneca's first quarter production. Although Hurricane Ike caused overall production to be down 10.5% versus first quarter last year, I expect that we will make up most, if not all of that shortfall over the remainder of the fiscal year, as Gulf of Mexico development projects come on line, and Appalachian infrastructure constraints are relieved.

Due to Hurricane Ike, first quarter Gulf of Mexico production was 1.2 Bcfe lower than first quarter of last year. While much of our production returned very fairly quickly after the hurricane, two of our major fields remained shut-in the entire quarter, and are just coming back on line this month.

In addition to the resumption of shut-in production, we expect to have first production from the Cyclops field within the next few weeks, bringing overall Gulf of Mexico net production up to 45 million cubic feet equivalent per day. We have one more discovery from last year, Eugene Island 383 that is still being developed, with first production expected in the fourth quarter.

In California, quarterly production is up 7% versus a year ago, due to the net production increase from last year's Ventura area property trade. The production increase resulting from our modified steaming (ph) operations, and the production added from our new Maverick wells at Midway Sunset, and our Monterey Shale wells at Lost Hills.

While our goal in California is to keep production flat for the next several years, our West division team is doing a great job finding ways to actually increase production, in each of our three field areas.

In Appalachia, we continue to aggressively develop our Upper Devonian type gas sands. However, our production for the first quarter was disappointingly low, due to gathering system constraints and compressor station shutdowns. To solve these constraints, we installed three compressors last month, and several new projects are underway. January production is up, and we expect a substantial production increase within the next few months. And ultimately, full year production of 10 to 15%... production growth of 10 to 15% for East division.

Moving on the Marcellus Shale, our first long lateral well from the EOG joint venture, loading an average of 1.4 million cubic feet per day over a 25 day period. This appears to be an economically viable well with an EUR of approximately 2 Bcf.

There are three more horizontal wells waiting to be fracked and another is currently being drilled. These recent wells have lateral lengths of 3,800 feet to 5,700 feet, as compared to the previous well at 3,500 feet. The next frac job is planned for March, but should have flow test results by our next earnings call.

Within the next six months, I expect that we'll have four or five more joint venture wells completed and tested. Regarding EOG's acreage selection, they have chosen the first 50,000 net earnable acres that they will pursue. Their final 50,000 net acres will be selected by March 1st.

Our Seneca operated vertical drilling program will commence next week. With our initial wells planned for Tioga County. We have a total of 10 vertical well locations planned in six different Pennsylvanian Counties. These vertical wells are intended as assessment wells, to help us evaluate our extensive acreage position.

Most will be cord, and all maybe used as monitor (ph) wells for future horizontal fracture treatments. To execute our horizontal program, contracted with HWD for a new rig which will arrive in July. This is a very noble, highly automated, super single with 1000 horsepower pumps. It is nearly identical to the rig that EOG has used very effectively for the last several joint venture wells, but it is enhanced to accommodate higher anticipated frac volumes.

Let me conclude with an update of our planned E&P capital spending. Due to low oil and gas prices, we have cut our fiscal 2009 budget. Our current plan is to spend 19 million in the Gulf of Mexico, primarily for developing last year's discoveries. 35 million in California which as Dave said is a $90 million cut and 190 million in the East including 74 million for the Marcellus leases we picked up at September state resale. We are also taking a hard look at Upper Devonian program and may cut that back some if natural gas prices remain low or trend lower.

This brings our new total forecasted E&P capital spending to $244 million absence of 74 million that we are spending on the Pennsylvania leases. Our spending would be completely covered by our E&P cash flow at $45 oil and 550 gas. Our planned CapEx reduction will have minimal impact to our fiscal 2009 production. And we are maintaining our production guidance of 38 to 44 Bcfe.

With that, I will turn over to Ron.

Ronald J. Tanski

Thanks Matt and good morning everyone. Although variability in commodity prices has provided a challenge for all the financial analysts, trying to keep their forecast models updated. Back in August, when we gave our preliminary fiscal 2009 earnings guidance of $3.20 to $3.40 per share, we based our forecast on NYMEX prices of $9.50 per MMBtu for gas and $115 per barrel of oil.

When we reported earnings in November, we revised 2009 earnings guidance to a range of $2.60 to $2.80 per share based on NYMEX prices of $7 per MMBtu for gas and $70 per barrel of oil.

In last evening's release, we revised our guidance once again, including $1.35 per share reduction in earnings from our ceiling test impairment and began reducing commodity prices to $5.50 per MMBtu for gas and $45 per barrel of oil for our un-hedged production over the remaining nine months of fiscal year. We have a new earnings guidance range of $1.10 to $1.30 per share or $2.45 to $2.65 per share excluding the impairment. Continuing our usual practice, we've included an earnings per share sensitivity due to changes in commodity prices at page 21 of last evening's release.

In addition to that table, our first quarter 10-Q that we'll be filing later today have some additional calculations regarding a hypothetical impairment if lower prices have been used in the ceiling test calculation at the end of November. Matt mentioned a cut back in CapEx for the exploration and production segment. With that reduction, planned CapEx for the fiscal year will be $244 million for the E&P segment, for the consolidated company our CapEx is now targeted at $376 million.

From a cash flow perspective, factoring in $376 million in capital spending for the year and using the middle of our earnings guidance range, we expect to be cash flow negative for the entire year by approximately $87 million. We've plenty of credit capacity to cover our working capital needs and to handle this extra $87 million cash requirement.

In addition to the impairment there were two other items recorded in the first quarter of fiscal 2009 that impact the comparability of our first quarter to last year's first quarter earnings. The first was a receipt of a debt benefit payment under corporate owned life insurance policies due to the untimely death of a retired officer. A former friend and colleague Bruce Hale who retired in 2005, passed away in November at the age of 59.

The second item was an impairment charge to write down the value of our 50% interest in our Energy Systems Northeast combined cycle turbine that we own with Connector. Based on a joint review by the partners and our expectation of reduced dispatch time into the New York ISO, we determine to write down the book value of the turbine. After the impairment we now have an investment of approximately $2 million for our 50% ownership share reflected on our books.

Looking forward to remainder of the fiscal year, it's really only the volatility in commodity prices and variations in weather that are expected to cause variations in our projected earnings. As we reported in the back pages of last evening's release; weather for the first quarter was 10.5% colder than last year. During the quarter however, we saw daily temperature swings in our service territory from a level that was 60% warmer than normal on one day to a 30% colder than normal, two days later. That variability requires our dispatchers to be own your toes and our field operating people do a great job keeping gas flowing to all our customers despite those wide variations.

In addition to the impact on the utility system, those wide temperatures swings can have an impact on Seneca's well production that cease into the lower pressure pipelines. As the pressure in those lines has increased to assure delivery to customers in cold weather, production from Seneca's wells gets choked back. There is a positive note that arose from the weather variations, due to a combination of extremely cold weather in January and system constraints on other pipelines we were able to sell some short-term firm and interruptible capacity on the Empire Pipeline and our Empire Connector.

Our goal is to get customers to take more long-term firm capacity on the Empire system but after just starting up the connector pipeline, it's not uncommon to have to fill up the space with short-term contracts here and there.

I'll make one final comment regarding another tweak that analysts can make in their financial forecast models. Due to the impairment charge and the effect that Seneca's depletable base is now lower by $183 million, Seneca's DD&A rate for the remaining nine months of the year will drop in a range between $2.10 to $2.20 per MMcfe. With all this variability, we'll do our best to keep you updated in future earnings releases and through other reports that we developed for industry conferences from time-to-time, and make available on the Investor Relations section of our website.

Now operator, we'll open up the line for questions.

Question-and-Answer Session

Operator

(Operator Instructions). The first question comes from the line of Carl Kirst of BMO Capital.

Carl Kirst - BMO Capital Markets

Hey, good morning everybody and a nice way to start off here. Just a few E&P questions if I could, Matt just... I guess the EOG JV horizontal well that's drilling now, is that number seven or number eight, I am losing track.

David Smith

The one that it's drilling now would be our seventh horizontal.

Carl Kirst - BMO Capital Markets

Would be seventh. And are you seeing previously I guess we've talked about well cost in the range of $3.5 million sort of on a run rate basis, understanding we're doing a lot of science in the early days here. But, are you seeing costs beginning to come off on that, as far as your drilling incompletion estimate for this well here?

Matthew Cabell

Maybe a little bit Carl. It's not a substantial change at this point. I think what we're really seeing is, we'll probably be able to drill wells at that same cost, and get much longer laterals. So, on a cost per foot basis, yeah we're seeing an improvement.

Carl Kirst - BMO Capital Markets

Could you repeat what the lateral lines of these of the three wells that are going be fracked and I guess the anticipated laterals the well that's being drilled?

Matthew Cabell

They range from 3,800 feet to 5,700 feet.

Carl Kirst - BMO Capital Markets

Okay. And then, just last question I had on that, you had mentioned a possible flow test in March, and then maybe having a data point on the next earnings release. Since we have three wells waiting to be fracked is that some thing where all three wells can kind of be fracked kind of back-to-back i.e. we might have three data points, or is the timing such that there going to be space enough on part where we really are going to have that sort of first flow test by the next call.

David Smith

Carl, I guess I would expect that we'll only have one by the next call. Two, that are waiting are in a fairly remote location that we think is better or I should sat EOG thinks is better to wait until, after the spring fall. So those two wells would be further down the line.

Carl Kirst - BMO Capital Markets

Okay. Thank you.

David Smith

You're welcome.

Operator

(Operator Instructions). Your next question comes from the line of Shneur Gershuni of UBS.

Shneur Gershuni - UBS

Actually Shneur Gershuni, but okay.

Ronald Tanski

We know its Shneur.

Shneur Gershuni - UBS

Just a couple of quick questions here. I was wondering if you can give us a little color on the ceiling test, what areas were more impaired, and so forth. Kind of how you evolve with the numbers?

Ronald Tanski

I am sorry, Shneur. You need to repeat that.

Shneur Gershuni - UBS

The ceiling test. I was just wondering, if you can sort of, if you can walk us through which areas were more susceptible to.... to the test versus others? Whether it was more in California, or whether it's in the Gulf of Mexico and so forth?

Ronald Tanski

Well. Keep in mind it's a full cost pool. So really, you like at the total value of all your reserves, and compare that to what's on your books. And you calculate that total value, based on year-end pricing.

Now, another way to look at it is oil prices took a substantial dive, particularly when you apply a California basis differential. So, one could argue that California had more of an influence on it. But it's really an aggregation to do the calculation.

Shneur Gershuni - UBS

Okay, fair enough. You mentioned in your remarks that you were looking at potentially cutting the Upper Devonian program. Just kind of trying to look at where you believe the breakeven prices for the Upper Devonian program or breakeven plus cost to capital, kind of where do you need to see gas prices, you need to make sure that you're earnings your returns there?

Ronald Tanski

I think really the way we need to look at it is by discreet project. And some of the projects look good at $4. And others don't look good unless it's at least say 550. So, that's why I'd say we're looking at it hard. There will be certain projects that maybe, won't make the cut. That would have made the cut six or eight months ago. So that could potentially affect the number of wells that we drill for the year.

Shneur Gershuni - UBS

Is it kind of circular like if you see service costs come down in those numbers, you trying to change?

Ronald Tanski

Yes, and that's part of what we're factoring into our analysis is, how much can we assume well cost would be reduced.

Shneur Gershuni - UBS

Okay. And you've also noted that 50,000 acres have been chosen by EOG. Was that primarily on NFG's legacy acreage or is it on EOG's legacy acreage?

Ronald Tanski

That will be the selection process is entirely on an NFG's acreage, Seneca's acreage because the way the joint venture works, we have the right to earn 50% working interest in all of EOG's acreage that's with in the AMI. EOG has the right to earn 50% of 200,000 acres or 100,000 net on our acreage, so they need to select down to that amount where there is no selection process any of EOG's acreage.

Shneur Gershuni - UBS

Okay. And one last question with respect to share buyback program, is it currently suspended now or is it something that you're looking at now that, you're taking that expensive gas out of the ground and gas is much cheap as the liquidity is improving?

Ronald Tanski

Really Shneur this round tasking is really is going to depend more on the credit markets and the fuel for the credit markets. As Dave mentioned in his comments, we're just really watching our capital and there's a lot of acreage to be tested. And we want to do a lot more science or we're just being careful; managing what capital we have and don't want to assume necessarily that the credit markets are always going to be there. So, the share buyback is still extent. We haven't purchased any shares under at lately well.

Shneur Gershuni - UBS

Okay, great. Thank you very much.

Operator

Your next question comes from line of Rebecca Followill of Tudor Pickering.

Rebecca Followill - Tudor Pickering &Co.

Good morning. You guys mentioned that in your 10-Q to be filed later today, you had some hypotheticals on what would happen to reserves; had there been a lower oil price at September 30th, can you give us any color on that or do we need to wait?

David Smith

Well. No. its not reserves Becca, it's really the ceiling test calculation.

Rebecca Followill - Tudor Pickering &Co.

Okay.

David Smith

And what we did is, we did another sensitivity and we did the calculation with oil prices that were $5 a barrel lower and then we also did another run at gas prices that were a $1 lower at the end of December and then we combined them both together.

Rebecca Followill - Tudor Pickering &Co.

Okay. So if fuelling test not negative reserve additions?

David Smith

Ceiling test. So under each scenario we get round about another $50 million impairment, $50 million of gas prices were $1 lower or $50 million of oil prices were $5 a barrel lower and if you add them together round about $100 million, extra impairment but it didn't effect the reserves.

Rebecca Followill - Tudor Pickering &Co.

Any field force of you guys escape the pull of having a September 30th fiscal year-end. A lot of companies as you're seeing are facing big negative reserve provisions because of their really low oil price and the light basis at year end, any feel for what happened to reserves had a different oil price scenarios?

Ronald Tanski

Becca of course we look at our reserves quarterly, so we did take a small, very small negative reserve revision at the end of the quarter but its not substantial. And yeah, oil in California is what is most sensitive to that. Now, the vast majority of our oil production can handle a much lower oil price, so it's only going to effect tail end years out into the distant future.

Rebecca Followill - Tudor Pickering &Co.

So if September 30th of this year, if oil is at 50; we shouldn't expect a massive negative reserve revision?

Ronald Tanski

No.

Rebecca Followill - Tudor Pickering &Co.

Okay, great. Thank you.

Operator

I would now like to turn the call back over to the management.

James Welch

Thank you, Shannon. We would like to thank you 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 a run through the close of business on Friday, February 13, 2009. To access the replay online, visit our Investor Relations website at investor.nationalfuelgas.com and to access by telephone call 1888-286-8010 and enter pass code 64283323. This concludes our conference call for today. Thank you and good bye.

Operator

Ladies and gentlemen that concludes the presentation. Thank you for your participation. You may now disconnect. Have a wonderful weekend.

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