National Fuel Gas Company (NFG) Q4 2008 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen and welcome to the Fourth Quarter 2008 National Fuel Gas Company Earnings Conference Call. My name is Eric, and I'll be your coordinator for today. At this time, all participants are in a listen-only mode. We'll facilitate the question-and-answer session towards the end of the conference. [Operator Instructions]. I would now like to turn your presentation over to your host, Mr. Jim Welch, Director of Investor Relations. Please proceed.

Thank you, Eric 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 a discussion to 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 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'll begin with Dave Smith.

Thank you, Jim and good morning. The past several months have certainly been challenging sometimes for the financial markets. The constant barrage of bad economic news and the dramatic drop in equity share prices including our own, tend to obscure the fact that fiscal 2008 was the best year in National Fuel's 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 is a result our diverse asset base and despite the turmoil in the markets, we intent to continue to execute on our integrated business model. Certainly, lower commodity prices and tighter credit market will present challenges to the industry. And as a result, we have reexamined the CapEx budgets in each of our business segments and have made modest adjustments. But unlike many other companies, because of our 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 the details of our earnings for the quarter and for 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 E&P segment, we're very pleased with the results in each of our divisions. In the East division, the continued development of nearly 1 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 crude reserves, exceeding our reserve replacement target with fewer wells and less drilling capital than was 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 us with more flexibility with regard to the bulk of our 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 and 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 a drop in commodity prices. Three of the prospects we had identified are only marginally economic. And we have as a consequence to remove them from our budget. We'll re-evaluate that decision should commodity prices rebound. As we've said in the past we'll only commit capital to the Gulf if we see an opportunity to earn an attractive return. In the West, things will be pretty much business as usual. That division produces a steady 2 million plus barrels of oil per year, and even at current prices fully supports the dollars we're investing there. At $70 oil prices the West division generates over $100 million in pre-CapEx cash flow. Switching to the pipeline of storage segment, construction of the Empire Connector project is nearing completion. We had been on track for November 1st 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 in order 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. Machining of the project that should be completed by the first week of December and that's when we'll 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 spend 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 continued to pursue growth on our pipeline and storage, and midstream businesses. Much of this proposed expansion is tied to the development of Appalachia and the Marcellus, while slightly 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 and East project late in the summer, supply corporation held two simultaneous open seasons for new service. The first was for 8.5 bcf of new storage service from the proposed expansion of East branch Gilbreth and Tuscarora storage facilities. The second related was for capacity on a modified West to East project, including the new Appalachian ladder which is rather 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're currently confirming the details of the request to 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'll begin 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 to spend any significant dollars on them in 2009. But we'll keep you up-to-date is the projects progress. The current market environment is challenging for our new midstream businesses, but we're still optimistic. As you know, lower commodity prices, tighter credit markets have caused many E&P operators in our region to announced spending cuts. On the one hand, those expending 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 bid and are looking to third-parties like National Fuel to develop the needed infrastructure. As I said, we're optimistic about this business, we're forging full speed ahead and our development team continues to pursue opportunities in this area. Turning to our horizon businesses, we continue to pursue the sale of our landfill gas related operations and our 50% interest in the energy systems Northeast ESNE power plant. The turmoil in the financial markets, that's certainly slowed the process down somewhat but we're still cautiously optimistic that we can close on these transactions by the end of this calendar year. In closing, we're 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 is well positioned financially and geographically to take advantage of opportunities and to weather the trying times that may be ahead of us. With that, I'll turn the call over to Matt.

Thanks, Dave. Good morning everyone. Fiscal 2008 was a great year for Seneca. We grew reserves and production, substantially improved our finding and development cost, drilled three new discoveries in the Gulf of Mexico and increased our per well reserves in Appalachia. Fiscal 2009 should be another exciting year as we continued to grow our Appalachian production, bring on our new discoveries in the Gulf of Mexico and increase our activity in the Marcellus Shale. At oil and gas prices of $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 continued to increase our per oil 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 exploration and development team are paying off as we continued to develop our assets efficiently and cost effectively. As Dave mentioned, our drilling target for fiscal 2009 is 300 upper Devonian wells with activities somewhat dependent on natural gas prices. In the Marcellus, in partnership with EOG, we've drilled three new horizontal wells with a new purpose build drawing rig. These three wells have lateral lanes in excess of 3,000 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 the flow rate soon. Many of you may recall that our joint venture with EOG required EOG to choose 10 Prospect Boxes covering 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. Additional in the Marcellus play, we were the high bidder on four of our six bids at the Pennsylvania State lease sale, adding 24,000 acres in a highly perspective area where the Marcellus is relatively thick. Between the lease sale and the amended joint agreement with EOG, Seneca will become a major Marcellus Shale operator with over 0.5 million operated acreage to evaluate. As a result, we are modifying our fiscal 2009 drilling plans. We will initiate our Seneca operated drilling program in the second quarter and plan to drill eight 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 on our new state leases; also allowing us a bit more time for permitting. In preparation for our first operated horizontal wells, we have been negotiating with several rig companies and anticipate having a rig capable of drilling 4,000 foot laterals arriving by June. Needless to say, things will be moving forward quickly for our Marcellus play in 2009. At our next turnings 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 a result of our successful drilling programs with the moderate Shale of lost hills in the Maverick Sand and Midway Sunset as well as the impact of our Sespe, Ohio property exchange. We've additional drilling plant for fiscal 2009 and we are also beginning to see a good response to a modified steam-injection plant 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 fiscal '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 remained shut-in due to repair work on third-party pipelines and onshore processing facilities. For fiscal 2008, we lost a total of approximately 1 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 on line. On a positive production note, Ohio Inland 23L Discovery came on line last week and is currently producing at 14 million cubic feet per day and 1,800 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 in 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 cost for fiscal year 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 risk and economic value of our future projects. With that in mind, we have chosen to cut our Gulf CapEx for fiscal '09 by $15 million to 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 are still anticipating production between 38 Bcfe and 44 Bcfe, even with the first quarter of hiccup resulting from the hurricanes. Perhaps most importantly in today's environment, our drilling and CapEx... our drilling and development CapEx program can be fully funded by our forecasted E&P cash flow at $7 per Mcf and $70 per barrel. And now, I'll turn it over to Ron.

Thanks, Matt and good morning everyone. Since Dave and Matt already covered most of the highlights for the year, I'll be brief so we can get right to your questions. We were quite pleased that our earnings for the quarter and the entire 2008 fiscal year were at the upper end of our guidance range. And looking forward to fiscal 2009, we revised earning's 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 in 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 the 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 as a preliminary 2009 capital expenditure budgets that I gave out during our August call. As Dave and Matt, said we've 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 of the production segment, our total capital budget including the leases for Seneca was the high bidder in the recent Pennsylvania State lease sale is $285 million. For all other areas, the budget's totaled $1 million and that gives us a grand total of $417 million of plan capital spending for fiscal 2009. Our budgets and projects are flexible enough, so we can slide our 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 17th in order to conserve our cash reserves. We did complete the acquisition of the 8 million shares as 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 $1 million shares under the new Board authorization at an average price of $44.70 per share. As we will report in our 10-K, we have remaining Board authorization to buyback approximately $7 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. In addition, we'll 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 question. Question And Answer

Thank you. [Operators Instructions]. Your first question comes from the line Shneur Gershuni with UBS. Please proceed.

Hi. Good morning, guys.

Hey Shneur.

Hi Shneur.

Just had a question with respect to the Marcellus, we know performance coming out of a year-to-year is favorable in this year?

Shneur, you are really braking up. We can only one in every four or five words.

Sorry. So, can you hear me better now?

Yes.

Yes.

Okay, great. My comments are with respect to Marcellus, specifically with EOGs talk this favorably as it has for some of its other place. I was wondering if you can comment with respect to your thoughts on the play on being potential horizontal play versus being vertical play and is that potentially a reason why it is attractive to other player like EOG rather than versus you guys and so forth.

You broke up a little there Shneur but I'll 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 maybe areas that lend it South well to a vertical program but I think the majority of the play will be horizontal.

Shneur, the second part of the question, I think I heard most of it seems to suggest that the implication that EOG has moved ahead with other acreage as opposed to our acreage. That implies that our acreage is favorable as the other acreage. And I just don't think that's true. I think in part EOG was just further along in on the acreage that they recently made the announcement with respect to. That's where they took the rig and they were drilling prior to the drilling with the new rig on the acreage in the AMI. Matt that was.

Yeah.

Did that was your question Shneur?

Yes. If I can 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 forecast as a result out there, because I would have anticipated if you take your commodity forecast down the taxes associated with it or the royalties would come down as well too, so just wanted to know if there had been any other adjustments on the cost side?

Yes, the original guidance we put out back in August and there is been 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 and we were also using the $9.50 gas price that we had in the forecast for the steaming cost. We also had more hedges in place as of the end of the fiscal year than we did back in August. There are couple of other minor things, but that gets the bulk of the difference.

Okay, great. Thank you very much.

Thanks Shneur.

Your next question comes from the line of with Tim Schneider [ph] Citigroup please proceed.

Hey guys. Just a quick question, on the Gulf of Mexico what kind of commodity prices do you need to put up play to be more economic?

Well I'm not sure I'm fallowing your questions. In other words it's either our results from 2008 are very economic at today's commodity prices.

Yes, but I mean you said your are not going ahead with three other wells just given the marginal economic right now don't make sense. So my question is would you need to commodity prices to get in order for those wells to become more economic, so that you'd actually go ahead with those?

I would had if we had... we have forward strip that would say above 8 box and wells that we pulled out would look pretty good.

Okay.

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

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

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

Okay. That's it for me. Thanks guys.

Your next question comes from the line of Jim Harmon with Barclays. Please proceed.

Hey, good morning, guys.

Good morning, Jim.

Hi, Jim.

First, kudos to Matt for what he has done to me in E&P. I have been following the company for 15 years that was great to see some progress going on to that segment.

Thanks Jim.

And hopefully you'll answer my next two questions. But... what?

I said oh oh.

Now is there two on E&P and one on the forgotten timber. First you said that the average EURs in Appalachia were 113. I was just curious as to what maybe the some of the higher EUR you are seeing and what are you doing differently now in moving towards the higher EURs? Is it a technique? Is it a region that you are concentrating on?

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

Okay. And maybe an example of some of the higher EURs, I mean could do the basic math, but are you seeing anything in like the 130, 140 range?

Much higher than that. I would say the best wells might be 300.

Okay.

But the overall average is 113.

Okay. 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? And then, as a part to that, what's the timing of the three wells that are currently on the projects play?

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, but we expect it'll be about six months from now. Another one we have a lot of control over and it will probably be in the summer. So I guess the short answer, Jim would be most of that drilling is later in the fiscal year.

Okay.

And at least two of the three wells look pretty good even with a further fall in oil and gas prices.

Okay. We still have winter ahead of us so anything can happen.

Yes.

On the timber segment, which is I know nearing gear, it looks like you used to get a nickel to a dime earnings and we are tracking a nickel through a dime of losses. And so how do we stem the losses? It looks like you've cut costs. Is that something which you see for the rest of the year?

Yes, Jim, I don't know where you came with the nickel to the dime in losses. We're certainly not forecasting that and no we don't forecast by segment, but we're not forecasting losses in the timber.

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

Well in large part, you cut costs.

Okay.

And we would just be tied way back at the operations of the mills, we just wouldn't cut the timber and processes. So it will just continue to grow off the field.

Yes, one of the mills is I don't know Jim, we've cut back significantly. I think the guys have also done a pretty good job. In part, the last quarter was due to this just high inventory cost associated with obligations they've had on federal lands. I think it was federal estate land to cut timber. So, in part that was kind of an out of the ordinary forward. We will be able to cut back costs significantly.

Okay, great. Thank you.

The 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 just picked up some more acreage in the Marcellus and Lycoming County and you had mentioned that your original wells will go little bit on the water usage, and Pennsylvania is kind of going through re-haul system. Have you guys have to re-file your water usage plans or do you feel you're all set on the permitting side on the Marcellus there?

We have to permit them individually. So, as we developed locations we have to get them permitted. So, I guess the short answer to your question is no we're not all set but yes we're doing everything to get those permits as quickly as possible and we don't anticipate that being an issue for getting the wells that we've got in the fiscal '09 plant drilled.

Got you. And then, in California the governor has talked about maybe increasing taxes in oils and severance tax going up to potentially at 9%. Just want to see, are you guys hearing that and sort of how you would handle that? Would that impact sort of the drilling plans at all or is it still too early to figure out what's going to happen?

Unlikely that it would 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 '09 could easily be delayed into fiscal 2010 if we found ourselves in a cash flow issue that we want to preserve our cash flow.

Got you, great. Thank you so much.

Your next question comes from the line of John Hampston [ph] with Prestige [ph]. Please proceed.

Good morning.

Hi John.

Good morning.

Just a follow up on the Gulf of Mexico a bit, you've got a new well on; what kind of decline rates do we have on those if it we're might see a year out or something like that just so we can know how kind shape goes?

You're breaking up. I heard a question about decline rate.

Yes. What kind of decline rates do we have there?

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

Alright. Thank you very much.

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

Hi. Good morning guys.

Good morning.

Good morning.

Just a quick question, did I hear you say you're new estimates 2009 production be the same as 2008 or is that a regional thing?

Our guidance is the same as it was from fiscal 2008.

Okay. Good, that's it from me.

[Operator Instructions]. It appears we have no more audio questions. Thank you. I'd like to turn the call to Mr. Jim Welch for closing remarks.

Thank you, Eric. We'd like to thank you everyone for taking the time to be with us today. A replay of this call will be available in about one hour on both our website and by telephone and a run through the close of business on Friday, November 14th. To access the replay online, visit our Investor Relations website at investors.nationalfuelgas.com. And to access by telephone, call 1-888-286-8010 and enter passcode 13507417. We'd also like to mention that on Tuesday, November 18th at approximately 12:30 PM Eastern Time, National Field will be making a webcast presentation of year-end financial and operational results that can be accessed through our Investor Relations website. We'll issue a press release to remind everyone of the details of this event. This concludes our conference call for today. Thank you and goodbye.

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