National Fuel Gas Co (NFG) 2008 Q4 法說會逐字稿

Good day ladies and gentlemen. (OPERATOR INSTRUCTIONS). I will turn the presentation to your host, Jim Welch, Director of Investor Relations.

Thank you, 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 call, 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 believe to have a reasonable basis actual results may differ materially. These statements speak only as of date which they made and you may refer to last evening's earnings release for a listing of certain risk factors.

With that we will begin with Dave Smith.

Good morning.

The past several months have been challenging es for the financial markets. The constant barrage of bad economic news and dramatic drop in equity share prices including our own, tend to obscure the fact that fiscal 2008 was the best year in National Fuels 106 year history. On an operating results basis, it was a record year. With $3.17 per share of consolidated earnings, up 40% over the prior year. Importantly, the growth in earnings was spread across the system with each of our three major segments posting double digit increases in earnings.

Financially National Fuel is in excellent shape and large part as a result of our diverse asset base. Despite the turmoil in the markets, we intend to continue to execute on our integrated business model. Certainly lower commodity prices and tighter credit markets will present challenges to the industry. And as a result, we have re-examined the Cap Ex budget in each of our business segments and made modest adjustments.

But, unlike many other companies, because of the focus on long-term sustainable shareholder value because of the quality and the diversity of our earnings and because of our long-standing commitment to fiscal discipline, we do not expect any wholesale changes in our business plans for 2009 and beyond. I should also note that we do not expect any change in our dividend policy, which has seen 106 years of uninterrupted dividend payments and 38 consecutive years of dividend increases. Last night's release provides details of earnings for the quarter and the fiscal year so I won't repeat them here. Instead, I along with Matt and Ron will review a few of the year's accomplishments and discuss some of our plans for the future.

In the E&P segment, we are very pleased with the results in each of our Divisions. In the East Division, the continued development of nearly one million acres of mineral rights in Appalachia was a top priority. Regarding our upper Devonian program which we continue to expand, the results exceeded our expectations. Due to a considerable increase in per well EURs we added 28 Bcf of proved reserves. Exceeding our reserve replacement target with fewer wells and less drilling capital thanwas originally planned. Fiscal 2008 production for the division was up 25% to 7.9 Bcfe. Looking to 2009, the aggressive development of Appalachia will continue to be a top priority with an upper Devonian well drilling target of 300 wells.

In the Marcellus, we will continue to move forward with our previously announced plans pursuant to our joint venture with our partner EOG. EOG will drill at least 10 development wells in the Marcellus in 2009 and as we indicated on the last call we anticipate drilling a number of additional Seneca wells in that play. In addition, a modification of our joint venture agreement with EOG which Matt will discuss provides more flexibility with regard to the bulk of the acreage. As a result we have the ability to further accelerate development of the Marcellus alone or with other partners. As our bids on the Marcellus blocks in the Pennsylvania state forward suggests where we were the successful bidder on four large blocks totaling approximately 24,000 acres that carry a 10 year term we are very much believers in the Marcellus play and have developed our plans accordingly.

Turning to the Gulf, the initial capital budget we announced in August contemplated drilling six wells in that region with the drop in commodity prices, three of the prospects we had identified are only marginal economic and have as a consequence had to remove them from our budget. We will re-evaluate that decision should commodity prices rebound.As we said in the past, we will only commit capital to the Gulf if we see an opportunity to earn an attractive return. In the west, things will pretty much business as usual. That division produces a steady two million plus barrels of oil per year and even at current prices fully supports the dollars we were investing there. As $70 oil prices the West Division generates over $100 million of pre CapEx cash flow.

Switching to the Pipeline and Storage segment, construction of the Empire Connector Project is nearing completion. We had been on track for November 1 in service date, but when it became clear that the Millennium project would not be finished by that date, we slowed the pace of our construction to avoid incremental overtime. As of today, the full 77 miles of the pipeline is in the ground and our contractor is finishing the wiring and other control systems at our compressor station. Commissioning of the project should be completed by the first week of December and that's when we will put it in service. Because of some project change orders and contractor overages the estimated cost of the project has increased slightly from $180 million previously announced, to $187 million.

To date we spent about $162 million on the project and we expect to incur another $25 million by the time the project is finished. As I said before, when Millennium is ready we will be ready. Looking beyond the connector project we continue to pursue growth in our pipeline and storage and mid-stream businesses. Much of this proposed expansion is tied to the development of Appalachia and the Marcellus. While it's likely the tight credit markets may delay the pace at which the Marcellus is developed, as I said earlier in the long run, we believe this will be a major play and are continuing to actively pursue a number of initiatives in this area.

With respect to the West to East project late in the summer, Supply Corporation held two simultaneous open seasons for new service. First was for 8.5 Bcf of new storage service from the proposed expansion of East Branch, Gailbraith and Tuscarora storage facilities. The second related was for capacity on a modified West to East project, including the new Appalachian lateral which is routed through the Marcellus fairway. Combined, the focus is on moving Marcellus and other Appalachian production, Rockies Express Gas from Clarington and new storage volumes.

Request for both the open seasons were strong with more than a Bcf a day of transportation request received. We are currently confirming the details of requested capacity and optimizing the design of the proposed facilities. If all goes well we hope to sign precedent agreements with potential shippers in early 2009. After that, we will begin the FERC application process including engineering and environmental studies. These are obviously longer term projects with proposed in service dates in 2011 or 2012 thus we don't expect it to spend any significant dollars on them in 2009.

But we will keep you up to date as the projects progress.

The current market environment is challenging for our new mid-stream business but we are still optimistic. As you know, lower commodity prices, tighter credit markets have caused many E&P operators in our region to announce spending cuts. On the one hand those spending cuts to the extent they impact drilling make it harder for us to grow this segment of our business. On the other hand producers that had planned to install their own gathering systems are now likely to redirect that capital to the drill bit and are looking to third parties like National Fuel to develop the needed infrastructure.

As I said, we were optimistic about this business forging full speed ahead and our development team continues to pursue opportunities in this area. Turning to our Horizon business as we continue to pursue the sale of our landfill gas related operations and our 50% interest in the energy systems northeast, or ENSE,power plant. Turmoil in the financial markets that certainly slowed the process down somewhat, but we were cautiously optimistic that we can close on these transactions by the end of this calendar year. In closing, we are proud of our 2008 accomplishments and look forward to building upon them. Earnings are robust. Our dividend is firm and our balance sheet is strong.

The current market environment will be challenging but we believe that National Fuel was well positioned financially and geographically to take advantage of opportunities and to weather the trying times ahead of us.

With that I will turn the call to Matt.

Thanks, Dave.

Good morning, everyone. Fiscal 2008 was a great year for Seneca. We grew reserves in production, substantially improved our finding and development costs. Drilled three new discovers in the Gulf of Mexico and increased our per well reserves in Appalachia. Fiscal 2009 should be another exciting year as we continue to grow our Appalachian production, bring on new discoveries in the Gulf of Mexico and increase our activity in the Marcellus shale. At oil and gas prices at $70 per barrel and $7 per Mcf we expect to fully fund our drilling and development plans with our internal cash flow.

Now let me focus on our results in Appalachia. For fiscal 2008, In our East Division we grew production by 25% and replaced 361% of our production at a finding and development cost of $2.33 per Mcfe. In addition, we continue to increase our per well reserves such that our average well in fiscal '08 with an EUR of 113 million cubic feet at approximately double the reserves of our average well three years ago. The extensive regional analysis and thorough geologic mapping by our talented eploration and development team are paying off.

As we continue to develop our assets efficiently and cost effectively. As Dave mentioned, our drilling target for fiscal 2009 is 300 upper Devonian wells with activity somewhat dependent on natural gas prices. In the Marcellus, in partnership with EOG we drilled three new horizontal wells with the new purpose built drilling rig. These three wells have lateral lengths in excess of 3000 feet and were drilled but not yet completed at a cost of approximately $2 million each. Due to water usage issues completion of the first well was delayed several weeks. We are just finishing up the frac job on that well.

We expect to have a flow rate soon.

Many of you may recall our joint venture with EOG require EOG to choose 10 prospect boxes to cover 100,000 gross acres, by the end of this year and another 10 by the end of 2011. This arrangement left the majority of our acreage available for EOG to choose from for another three years and consequently restricted our ability to accelerate the development of our acreage position. As Dave mentioned, we have recently amended this joint venture agreement such that EOG will now pick their second 10 prospects by March of 2009. This is a very significant change for Seneca,

as we will now have complete control of our remaining 100% working acreage. Working interest acreage beginning in March. Additionally in the Marcellus play we are the high bidder on four of our six bids of the Pennsylvania state lease sale adding 24,000 acres in a highly prospective area where the Marcellus is relatively thick. Between the lease sale and the amended joint venture agreement with EOG, Seneca will become a major Marcellus shale operator with over 0.5 million operated acres to evaluate.

As a result, we were modifying our fiscal 2009 drilling plans. We will initiate our Seneca operated drilling program in the second quarter and plan to drill 8 to 10 vertical wells and two to four horizontal wells this fiscal year. This slight delay in our vertical program will allow us to position wells in areas previously operated by EOG as well as on our new state leases. Also allowing us a bit more time for permitting. In preparing for our first operated horizontal wells, we have been negotiating with several rig companies and anticipate adding a rig capable of drilling 4000 foot laterals arriving by June. Needless to say, things will be moving forward quickly for our Marcellus play in 2009.

At our next earnings call, I expect to have some frac results from the recent EOG horizontal wells and more information concerning our long-term plans and expectations. Moving on to California, we finished the year with annual production approximately 3% higher than last year and a year end production rate approximately 500 barrels of oil per day higher than last year. This increase is result of our successful drilling programs for the Monterey shale at Lost Hills and the Marvic Sand at Midway-Sunset as well as the impact of Sespe-Ojai property exchange.

We have additional drilling planned for fiscal 2009 and we are also beginning to see a good response to a modified steam injection plan at Midway-Sunset. If all goes well, we could see production increase again in fiscal '09, and in the worst case I expect '09 production to be roughly equal to '08.

In the Gulf of Mexico, production was down this quarter due to hurricanes Gustav and Ike. While damage to our production facilities was mostly superficial, approximately 50% of our production remains shut in due to repair work on third party pipelines and onshore processing facilities. For fiscal 2008, we lost a total of approximately one Bcfe.

First quarter fiscal 2009 will also be impacted by 0.5 to 1.0 Bcfe of shut ins as production is gradually brought back online. On a positive production note, Highland 23L discovery came online last week and is currently producing at 14 million cubic feet per day and 1800 barrels of condensate per day. As you know from previous updates we had an outstanding exploration year in the Gulf of Mexico. Since the last call, we drilled a second well at our Cyclops discovery encountering over 200 feet of high quality pay. We anticipate first production from the two well Cyclops project by January. For the year, our exploration discoveries added 14 Bcfe proved and 24 Bcfe of 2P reserves. Finding and development costs for fiscal 2008 were $4.44 per Mcfe proved and $2.61 per Mcfe on a 2P basis.

The 2008 programs full life rate of return is estimated to be 44% at a gas price of only $7 per Mcf. Although we had great success in fiscal '08, we will always thoroughly evaluate the the risk and economic value of our future projects. With that in mind, we have chosen to cut our gulf Cap Ex for fiscal '09 by $15 million to it a revised total of $35 million. Due to the marginal economics of certain exploration projects under reduced oil and gas prices. To sum it up, in fiscal 2008 we grew overall production by 4% and replaced 130% of our production. Overall finding and development costs were $3.82 per Mcfe. Appalachian production and reserves grew substantially and we made progress toward a full scale Marcellus exploration and development program,including an amendment to our joint venture that gives us far more control of our path forward. For fiscal 2009, we were still anticipating production between 38 and 44 Bcfe even with the first quarter hiccup resulting from the hurricanes. Perhaps most importantly in today's environment, our drilling and development Cap Ex program can be fully funded by our forecasted E&P cash flow at $7 per Mcf and $70 per barrel.

And now I will turn it over to Ron.

Thanks, Matt and good morning, everyone.

Since Dave and Matt covered the highlights for the year, I will be brief so we can get to your questions. We were quite pleased that our earnings for the quarter and entire 2008 fiscal year were at the upper end of our guidance range. And looking forward to fiscal 2009, we revised earnings guidance based on flat NYMEX prices of $7 per MMBtu for natural gas and 70 per barrel of oil for our unhedged production. That pricing change had the effect of lowering our 2009 guidance to a range between $2.60 and $2.80 per diluted share.

From the perspective of the utility segment, even with those lower commodity prices, winter bills for our customers are still expected to be approximately 10% higher than they were last year. As we head into the heating season, our customer service representatives and field service people are prepared to assist our customers and setting up payment arrangements and any other service needs. With the expected higher gas bills, we will be carefully watching both our accounts receivable and the ability of our low income customers to keep current with their heating bills. One bit of good news, is that the level of federal funding for the Home Energy Assistance Program or HEAP has been expanded substantially for this heating season.

Another area that's worth reviewing and updating are the preliminary 2009 capital expenditure budgets that I gave out during our August call. As Dave and Matt said we gone through all of our spending budgets to make sure that we can live within cash flow if we have to. Here are our most current budgets for the fiscal year. In the utility segment, capital spending is budgeted at $58 million. For the Pipeline and Storage segment we have a budget of $73 million.

$40 million out of that $73 million is for the completion of the Empire Connector in this fiscal year. For the Exploration and Production segment our total capital budget including the leases were Seneca was the high bidder in the recent Pennsylvania state lease sale is $285 million. For all other areas the budget total $1 million and that gives us a grand total of $417 million of planned capital spending for fiscal 2009. Our budgets and projects are flexible enough that we can slide off projects to fiscal 2010 if necessary if we run into any cash flow concerns.

Because of the unsettled nature of the credit markets we stopped buying back shares after September 17 in order to conserve our cash reserves. We did complete the acquisition of the eight million shares that the board authorized in December 2005 for an all-in cost of approximately $324 million or $40.53 per share. We also acquired a little over one million shares under the new board authorization at an average price of $44.70 per share. As we will report in our 10K, we have remaining board authorization to buy back approximately seven million more shares depending on market conditions. As we mentioned in the earnings release, we have $420 million of bilateral credit lines in place plus a $300 million syndicated committed credit facility which is available through September 2010.

For our long-term debt, we will be refreshing our shelf registration statement at the SEC for a new three year period to take effect later this month or next month. And in addition, we will also be filing new registration statements for our direct stock purchase and dividend reinvestment plan and for the $300 million private placement debt that we issued in April. As Dave said, our balance sheet is solid, our projected earnings are firm, and we expect to have adequate cash flow and access to working capital over the next few fiscal years.

With that, operator, let's open it up for questions.

Thank you. (OPERATOR INSTRUCTIONS). Your first question comes from the line of Shneur Gershuni with UBS. Please proceed.

Good morning, guys. Just had a question with respect to the Marcellus. You know the comments coming out of EOG-- My comments are with respect to the Marcellus specifically with EOG hasn't talked as favorably as it has for some of its other plays. I was wondering if you could comment with respect to your thoughts on the play, either a potential horizontal play versus being a vertical play and is that potentially a reason why it isn't as attractive to other player like EOG rather than versus you guys and so forth?

You broke up a little bit but I will respond to the first part of that question which is we think it's most likely going to be developed as a horizontal play. There may be areas that lend itself well to a vertical program, but I think the majority of the play will be horizontal.

The second part of your question, I think I heard most of seemed to suggest the implication that EOG has moved ahead with other acreage as opposed to our acreage. That implies that our acreage isn't as favorable as the other acreage. I don't think that's true. I think in part EOG was just further along in on the acreage that they reach -- recently made the announcement with respect to -- that's where they were drilling prior to the drilling with the new rig on the acreage in the AMI. That was the question was.

Yeah.

That was your question?

Yeah. Pretty much. If I could just follow up with one other question with respect to your earnings guidance. You took the numbers down and you effectively said it's related to your commodity forecast. Did you adjust any of your cost forecasts as a result either? I would have anticipated if you take your commodity forecast down then the taxes associated with it would have -- or the royalty would have come down as well, too. Wanted to know if there are any other adjustments on a cost side?

Yes. The original guidance we put out back in August and there is a number of things that have changed between then and now. In addition to the commodity sales price, the cost for steaming in California came down substantially. We were also using the $9.50 gas price that we had in the forecast for the steaming costs. We also had more hedges in place as of the end of the fiscal year than we did back in August. There are a couple of other minor things but that gets the bulk of the difference.

Great. Thank you very much.

Thanks.

Your next question comes from the line of Timm Schneider with Citigroup. Please proceed.

Hey, guys. Just a quick question. On the Gulf of Mexico, what kind of commodity prices do you need for that play to become more economic?

Well, I'm not sure that I'm following your question. In other words, it's -- our results from 2008 are very economic at today's commodity prices.

Yeah, but you said you weren't going ahead with three of the wells given the marginal economics right now don't make sense. My question is, what do you need commodity prices to get to in order for those wells to become more economic so that you would actually go ahead with those?

I would say if we had forward strip that was say above $8 then the wells we pulled out would look pretty good.

And it doesn't only relate in a vacuum. I think in part it's an allocation of capital between different -- between different divisions. That's relevant as well.

Okay. And then the only other question is a follow-up to the other question. Given the recent decline in gas prices, how far is that going to show up in lowered LOE expenses, if at all?

As I mentioned, substantially, there was about let's say a $0.5 per share pick up in earnings related to lower LOE just in the steaming out in California. So that is the primary expense directly related to commodity costs in Seneca's operation.

Okay. That does it for me. Thanks, guys.

Your next question comes from the line of Jim Harmon with Barclay's Capital.

Good morning, guys. Kudos to Matt with what he has done with E&P. I have been following the company for 15 years so it's great to see progress going on in that segment.

Thanks, Jim.

Hopefully, you'll answer my next two questions. These are two on E&P and one on the forgotten timber. First you said that the average EUR in Appalachia were 113, I was curious as to what may be some of the higher EUR's you seeing and what are you doing differently now in moving toward the higher EURs. Is it a technique? A region you are concentrating on?

I would say the primary difference is more thorough geologic mapping which allows us to avoid the lower EUR wells and allows us to because we are looking at more of our acreage with this new mapping we are able to identify the areas that you might have a whole program of 20 wells or so that are significantly better than with a we were drilling two or three years ago.

Okay. And maybe an example of some of the higher EURs, I could do the basic math but see anything in the 130 or 140 range.

Much higher than that. The best wells might be 300.

Okay.

But with an overall average of 113.

And then maybe a follow-up on the gulf question. What price deck do you need to sustain the economics on the three wells that you are pursuing. Then as a part to that, what is the timing of the three wells that are currently on the project slate.

One of them is a follow-up to our Cyclops discovery. And that well -- we don't really have that much control over the exact timing. We expect it will be about six months from now. Another one we have a lot of control over and it will probably be in the summer. I guess the short answer, Jim, would be most of that drilling is later in the fiscal year. And at least two of the three wells look pretty good even with a further fall in oil and gas prices.

We still have winter ahead of us. So anything can happen. On the timber segment, which is near and dear, it looks like you used to get a $0.5 to a $.10 of earnings and we are tracking a $0.5 to a $0.10 of losses. How do we stem the losses? This looks like you cut costs. Is that something we should see for the rest of the year?

Yeah. Jim, I don't know where you came with the $0.5 to a $0.10 in losses. We are certainly not forecasting that. I know we don't forecast by segment. We aren't forecasting losses in the timber.

Let me ask it a different way. How would you offset the weakness in the product sales?

In large part you cut costs.

We just will be cutting way back at the operations at the mills. We wouldn't cut the timber and process it. It will just continue to grow out in the field.

One of the mills is idle now and we have cut back significantly. I think the guys have done a good job in part the last quarter was due to high inventory costs associated with obligations they had on federal lands and I think it was federal estate land to cut timber. In part, that was kind of out of the ordinary Going forward, we will be able it to cut back costs significantly.

Okay. Great. Thank you.

Next question comes from the line of Mark Caruso with Millennium. Please proceed.

Good morning, guys. Just two quick E&P questions. One is I know you recently picked up some more acreage in the Marcellus in Lycomingscounties and you had mentioned that your original wells were delayed on the water usage and Pennsylvania has been going through a rehaul of the system. Have you had to refile your water usage plans? Do you feel you are set on the permitting side on the Marcellus there?

We have to permit them individually. As we develop locations, we have to get them permitted. I guess the short answer to your question is no, we are not all set but we were doing everything to get those permits in as quickly as possible and we don't anticipate that being an issue for getting the wells that we've got in the fiscal 2009 plan drilled.

Okay.. And then in California the governor has talked about maybe increasing taxes and oil and severance tax going up to 9%. I want to see are you guys hearing that and sort of how you would handle that? Will that impact the drilling plans at all or is it too early to plan what's going to happen there?

It is unlikely it will impact our drilling plans. Most of the things we do in California are very economic even at more modest oil prices. Now that said, some of our capital plans for fiscal 2009 could easily be delayed into fiscal 2010 if we found ourselves in a cash flow issue that we want to preserve our cash flow.

Thank you so much.

Your next question comes from the line of John Hanson with Praesidis . Please

Good morning.

Good morning.

Just a follow up on the Gulf of Mexico a bit. You have a new well on. What kind of decline rates do we have on those that might see a year out or something like that so we can know how that shape goes.

You are breaking up. I heard a question about decline rate.

What kind of decline rates do we have there?

These wells tend to stay at a fairly even plateau for some period of time. When they get close to the end of their life they decline very, very rapidly. So it's really more a function of the reserves and the individual discovery than it is sort of forecasting a decline curve.

All right, thank you very much.

Your next question comes from the line of David Rewcastle with Argus Research. Please proceed.

Good morning. Quick question. Did I hear you say your US 2009 production will be the same as 2008? Or is that a regional thing?

Our our guidance is the same for fiscal 2008.

It appears we have no more audio questions in queue. I will turn the call over to Mr. Jim Welch for closing remarks.

Thank you. We like it to thank everyone for taking the time to be with us today. A replay of the call will be available in about one hour on both our website and by telephone and will run through the close of business on Friday November 14. To access the replay online visit our investor relations website at investor.nationalfuelgas.com and access by telephone call 1-888-286-8010 and enter pass code 13507417. We also like to mention that on Tuesday November 18 at approximately 12:30 P.M. Eastern Time National Fuel will be making a web cast presentation of year end financial and operational results that can be accessed through our investor relations website. We will issue a press release to remind everyone of the details of this event. This concludes our conference call for today, thank you and good-bye.

Thank you for your participation in today's conference. This concludes our presentation. You may now disconnect and have a good day.