National Fuel Gas Company
Q3 2017 Earnings Call Transcript

Published: 3 Nov 2017

[Operator:]

Good morning. My name is Kelly, and I will be your conference operator today. At this time, I would like to welcome everyone to the Fourth Quarter 2017 National Fuel Gas Company Earnings Conference Call. All participants are in a listen-only mode. After the presentation there will be a question and answer session [Operator Instructions]. Thank you. Mr. Brian Welsch, Director of Investor Relations, you may begin your conference.

[Brian Welsch:]

Thank you, Kelly, and good morning. We appreciate you 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 Ron Tanski, President and Chief Executive Officer; Dave Bauer, Treasurer and Principal Financial Officer; and John McGinnis, President of Seneca Resources Corporation. At the end of the prepared remarks, we will open the discussion to questions. The fourth quarter fiscal 2017 earnings release and November Investor Presentation have been posted on our Investor Relations website. We may refer to these materials during today's call. 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. National Fuel will be presenting in the Jefferies Energy Conference later this month in Houston. If you plan on attending, please contact me or the conference planners to schedule a meeting with the management team. And with that, I'll turn it over to Ron Tanski.

[Ronald Tanski:]

Thank you, Brian and good morning everyone. Thanks for joining us today. Our 2017 fiscal year was another strong year for National Fuel both earnings wise and operationally. Each of our main operating segments posted strong earnings that were in line with our projections, and Dave Bauer and John McGinnis will give more details about segment earnings drivers later in the call. As we noted in the guidance section of the release, earnings for 2018 fiscal year a forecast to be down slightly, a large part a decrease results from the lower realized commodity prices in our exploration and production segment, where the higher price financial hedges that we had in place have rolled off. Forward strip prices remain relatively flat and a $3 per MMBtu strip price and a $2.40 per MMBtu stock price for our natural gas production have been built into our forecast for next year. While this flat pricing appears to be the new normal and resets the base of our pricing assumptions moving forward, we illustrate in our Investor Relation slide deck, that our drilling program remains economic in this environment. Unfortunately, we will be missing the booster earnings that we had expected from our Northern Access project which is being delayed. And our second circuit litigation again for New York TEC although argument for our case is being schedule for November 16. If we are already - to use the constitutional lawsuit as an indicator of the timeline, we may not get a decision from the court until August. Remember that the facts on our case are different from the facts in constitution and we are not discouraged by the outcome in that case. As you know we are also awaiting FERC action on a request for the hearing with respect to our waiver argument regarding New York action on more appropriately inaction, on our water quality permit application. It's hard to project the timeline for enhance on that re-hearings since FERC seems to busy clearing after certificate application backlog that built up when they had quorum. Add to that, the additional litigation that the New York DEC is piling on in the Millennium Valley lateral proceeding, and it's anyone's guess when we might get an answer. We are encouraged however that FERC will have a full complement of commissioners with yesterday's senate confirmation of the last two commissioners. I believe that FERC's staff never really slowed down on the standard work load during the administration turnover, but it will be a good to have a complete slate of commissioners so that major policy issues can be addressed. In the meantime, Tanaka [ph] continues this plan to delineate our Utica shale region in the western development area. We have also resumed drilling and our Eastern development area in order to have plenty production available that flowing into TransCanada Atlantic Sunrise project. As we noted in our guidance section in the release, we project that Seneca's production next year would be in the range of 185 to 200 billion cubic feet equivalent, approximately a 10% increase in production over fiscal 2017. And we have accomplished this well generally living within our projected cash-flow. We continue to have discussion with others regarding joint projects that could provide an outlet from our seller's gas of Seneca and others, where the project we take a path that avoids the permitting pitfalls presented by New York. Nothing is for enough long on this front for me to be in a position to provide any substantive comments today. We are however in the process of preparing our FERC application for our Empire North project, well this project does provide for additional volumes of get natural gas to flow into New York, we have design the project to primarily be a compression project. We believe at the construction activity is involved for Empire North won't require a water quality certificate from the state, since the project is designed to increase two feet on our existing Empire pipeline system. As a reminder, this project will add 205,000 dekatherms per day of throughput, have a capital cost of $135 million and is expected to come on line in November of 2019. We expect fiscal 2018 to be another year where we will be living within cash-flow of $535 million to $645 million capital expenditure program that we have summarized in the release, we are continuing to focus on growth across the company. Our ongoing system modernization program in the regulated segments will continue to increase rate base in those segments and will continue to increase Seneca's production to the ongoing development of Seneca reserves, both in the Utica shale and in the Marcellus shale. The Utica development will have the add-on effect of providing additional growth in our gathering segment. The Marcellus development in the Eastern development area will utilize existing gathering facilities and will be used to fill our Atlantic Sunrise capacity when that comes online in mid-2018. In summary, we are busy in each of operating segments and each one is moving in the right direction for fiscal 2018. Now John McGinnis will give an update on Seneca activity.

[John McGinnis:]

Thanks Ron, and good morning everyone. Seneca produced 40.4 Bcfe during the fourth quarter, compared to 39.8 Bcfe in last year's fourth quarter. The 100 Bcfe this year. The new - increase year-over-year and a total of 10% over the past two years, even while dropping to one rig from much of that time, and entering into a joint development agreement for Seneca working interest was reduced to 20%. Additionally, Seneca has generated significant positive cash flow each of the last two years. All in spite of weathering a tough commodity price environment. We achieve this through a combination of best-in-class Marcellus well costs, the joint development agreement with IOG and continuing to follow a discipline risk management approach our locking in prices physically and financially when opportunities arrives. Moving forward, we should continue to be cash flow neutral deposit over the next few years, even with our forecasted 10% plus average annual production growth as we execute on our long-term development plans. Our product growth for the year, was largely driven by stronger than expected Marcellus well performance, including better than projected flush production rates as we have brought on previously curtailed wells and minimal curtailments due to the improved strength in the spot market. For the year we curtail the total of 6.2 Bcf net compared to 34.6 Bcf last year. Much of these curtailed volumes actually occurred very early and very late in the fiscal year. Our capital expenditure totaled $246 million an increase of a $147 million compared to last year. The key drivers for this increase included lower year-over-year upfront and working interest proceeds associated with the IOG joint development agreement, bringing on a second rig in May and drilling and completing a greater number of a 100% working interest wells. In Pennsylvania, we have now drilled all 75 Marcellus wells and our IOG joint development, and we are currently completing the final 12 well pad. This final pad should be online in sometime during our second quarter. For the year approved reserved increased by 305 Bcfe or 17% for a total of around 2.15 Tcfe. This increase was primarily due to two key factors, reserves added from our Pennsylvania development program and positive reserve revisions as a result of the improved pricing. Only 28% of our approved reserves are currently categorized as approved undeveloped. Utica reserves now count for nearly 10% of our total and as we move forward with full development in both the Western development area and on our Tioga 007 track, this percentage will grow quickly. And finally, we continue to reduce our three-year average F&D costs, a three-year average is now at $0.98 per Mcfe and this reduction was driven by a combination of improved drill bit F&D and positive price revisions given higher prices both in Pennsylvania and California. Going forward this number should continue to decrease as Pennsylvania becomes a greater overall percentage of our capital program. We now have eight Utica wells on production in the WDA and we will be shifting to a 100% WDA Utica development program by the end of this fiscal year. Our three new wells have been online for less than 30 days and they have not yet reached peak production as a result of our conservative drop down management program bringing these wells online slowly. Early indication suggest however that they will be similar on a per foot basis to our previous appraisal wells and therefore we have now generated an initial WDA Utica type curve based on the first five wells. This type curve was included in our IR deck last night along with our CRV Marcellus type curve. Our Utica type curve assumes an EUR of 1.7 Bcf per 1,000 feet compared to 1.1 Bcf per 1,000 feet related to our CRV Marcellus wells. To-date all of our WDA Utica wells exhibit very shallow declines as compared to our Marcellus wells and so far, we have been very pleased with the results. In California, we produced 674,000 barrels of oil during the fourth quarter, up very slightly from the third quarter. Annual net production in California was down about 5% year-over-year to 3.2 MMBOEs. As I stated last quarter, this decrease is primarily due to changes in our steam operations and the significant reduction in well workover activity as a result of low oil prices. During the fourth quarter however, our oil production has increased by around 300 BOEs per day as we ramp up our workover activity. In - Total LOE also increased $4.6 million this quarter or $0.10 per Mcfe on a per unit basis driven mainly by this increased in workover basis and due to increased steam fuel cost. We will see higher LOE through the remainder of the first half of the year as we continue to bring on ideal wells in California. And these costs however should return to more typical numbers by the end of our second quarter. For fiscal 2018, we are forecasting capital expenditures to range between $275 million to $325 million. California ranges between $30 million to $40 million and Pennsylvania between $245 million to $285 million. We will remain at a two-rig pace in Pennsylvania with one rig active drilling both Marcellus and Utica wells in the WDA and the other rig drilling Marcellus wells in Lycoming and Utica wells in Tioga. For much of the year we will remain at a single completion crew but at time we will need to bring in a second crew. Net production is expected to range between 185 to 200 Bcfe, a forecasted increase of around 10% year-over-year. And our fiscal '18 production forecast however assumes a minimal curtailment through the remainder of the year. We enter fiscal 2018 with the pricing for 96 Bcf or 55% of our production locked in physically and financially at a realized price of $2.59 per Mcf. We currently estimate that we'll sale around 32 Bcf into the spot market that obviously depending on pricing these volumes are at risk for curtailment and would reduce the forecasted production range just discussed. Finally, in California we're forecasting production to be around 3.3 Mmboes 60% of our oil production is hedged at an average price of $54.30 per barrel and much of our development activity this year will continue to focus in Midway Sunset both on our legacy properties and on our new farm-in opportunities at Pioneer and South Midway and 17 and in North Midway. The key risk related to the startup of these programs is obtaining - exemption approval to allow us to begin injecting steam into these reservoirs. The approval process has been slow but once we obtain the necessary permits we'll move forward quickly. And with that, I'll turn it over to Dave.

[David Bauer:]

Thanks John and good morning everyone. Last night, National Fuel reported fourth quarter earnings per share of $0.53. While this was lower than the $0.66 per share in the last year's fourth quarters, earnings were right in line with our projections. For the full fiscal year operating results were $3.33 per share an increase of 7%. The earnings for the quarter at the regulated subsidiaries were pretty straight forward. The only item of note was O&M expense in the pipeline and storage segment which was up $3.4 million over the last year. During the quarter we incurred about $1.5 million in cost to overhaul to major compressor units. Our overhaul themselves aren't unusual. We typically don't have two on one quarter. We also saw an increase in project development cost mostly related to the Empire North project. As you recall we take a conservative approach with respect to these costs and expense them in the early stages of development. At Seneca production for the year was a little below the midpoint of our guidance. In the later part of the quarter spot pricing in Appalachia dropped significant from levels we saw earlier in the year. Not only to this reduced-price realization relative to forecast, but it also let us to curtail 2.5 Bcf of production during the quarter which in addition to impacting Seneca's production at a follow-on effect on our gathering business. Spot prices have remained depressed throughout October. But as cold weather returns, and as new infrastructure is added in the basin, we expect prices will recover. There were couple of unusual expense items during the quarter at Seneca that we don't expect to repeat. First LOE came into the $1.07 per Mcfe which was meaningfully higher than in prior quarters. And which generally in line with our projections. As John mentioned earlier, this increase was largely due to the timing of workover activity in California which was back weighted to third and fourth quarters. Looking to next year, we expect the LOE to return to the $0.90 to $1 per Mcfe range. Second, is other operating expense for the quarter reflects the $2.4 million payment to reimburse the Canadian pipeline operator the cost related to our project to develop new capacity downstream with Northern Access. That payment essentially puts the development of the Canadian capacity on hold pending the approval of Northern Access. Once that happens, development of that capacity will recommence, and Seneca will recoup the $2.4 million payment. Lastly, our consolidated effective tax rate was significantly lower than prior quarters. This was driven by two main factors. First is an adjustment to Seneca's Pennsylvania deferred income tax liability. It is related to a capacity on Atlantic Sunrise. As a result of that project more Seneca's production is expected to be transported out of Appalachia and therefore less of its income will be taxed in Pennsylvania. This allows us to reduce Seneca's PA deferred tax liability, which benefited Seneca's effective tax rate for the quarter. We had a similar adjustment a few years back related to our Northern Access 2015 capacity. Second, with oil prices at current levels we're able to take advantage of tax credits related to enhanced oil recovery activities at our California operations. These credits are available on a year-to-year basis depending on historical oil prices. This credit will apply again in 2018, but if oil prices rise in the future it will phase out. Our fiscal 2018 guidance assumes an effective tax rate in the range of 38% to 38.5%. On the tax reform front yesterday, the Chairman of the House Ways and Means Committee released the 429-page ex-cuts in jobs act. This bill includes a substantial tax rate reduction from 35% to 20% as well as many other changes to the tax code. Our initial take on the proposal is positive as obviously as a long waited go before becoming law. There are two other items of note that occurred during the quarter. First, we refinanced $300 million or 6.5% interest rate notes that have been scheduled to mature in April 2018. To do this we issued $300 million of new 10-year notes to carry a rate of 3.95% and executed the make whole option on our 2018 maturity. This transaction was well received in the market and will translate in the meaningful interest savings. However, because the two components of the refinancing startled fiscal years at September 30th both cash and long-term debt on the balance sheet are temporarily inflated by $300 million. The call of the 2018 bond settled in middle October so as of today our long-term debt is back to $2.1 billion. In the pipeline in the storage segment FERC recently approved a surcharge related to new pipeline safety and greenhouse emissions regulations. As far as supply corporations 2015 settlement with our shippers our parties agreed to recovery mechanism that became available of cost related to new regulation exceeded the certain threshold. We reached that threshold and therefore filed and received approval for a surcharge that will add about $4 million in additional revenue next year. We're taking this into account when we establish initial guidance as a result there isn't any change to our pipeline and storage revenue forecast which remains at $295 million. Turning to guidance aside from the items I touched on earlier not much has changed since our initial fiscal 2018 projections we provided last quarter. We're modestly tightening our earnings guidance to a range of $2.75 to $3.05 per share this increase is largely the results of lower expected interest expense as a result of the bond refinancing. Detailed assumptions are included on page seven of last night's earnings release as well as in the Appendix of the Investor Relations deck. Our NYMEX assumptions of $3 for natural gas and $50 for oil are unchanged. We're starting the new fiscal year 60% hedge for oil and 55% for gas. This is right in line with our policy and we'll continue to look for opportunities to layer in additional hedges as the year progresses. A fair amount of our un-hedged production or volumes that will flow into our Atlantic Sunrise capacity, construction of that project has begun and as we get more clarity on the exact in-service day we'll look to layer in additional trade. The midpoint of our 185 to 200 Bcf production guidance range assumes we sell about 32 Bcf of spot volumes in Appalachia an average price of $2.40 per MMBtu. This is higher than the prices we have seen over the past few shoulder months. As I mentioned earlier we expect the colder weather and additional pipeline capacity will benefit prices in the basin. So, for now, we're going to keep that spot price assumption the same. To give you a sense of the potential impact on earnings with actual spot pricing differs from our assumptions, we would expect earnings to be lower by about $0.055 per share for every $0.25 per MMBtu change in average spot prices. Looking on capital spending, our guidance of $535 million to $645 million is unchanged. For the year, we expect cash from operations to exceed capital spending by about $50 million at the midpoint of our guidance. This is consistent with our goals within cash flows for the next three to five years. In conclusion, National Fuel's in a very good positioned, and the two-rig program, we expect to grow our upstream and gathering businesses by 10% a year or at least the next three years, all are living within cash flows. On the regulated side of the business five-point development opportunities combined with the ongoing need to modernize our system will contribute to long-term growth and rate base. Our balance sheet is strong and should continue to strengthen providing flexibility to pursue additional opportunities as they arise. With that, I'll turn it over to the operator to open the line for questions.

[Operator:]

[Operator Instructions] Your first question comes from the line of Holly Stewart of Scotia Howard Weil. Your line is open.

[Holly Stewart:]

Good morning, gentlemen.

[Ronald Tanski:]

Good morning.

[John McGinnis:]

Good morning, Holly.

[Holly Stewart:]

Maybe first for John, if you could just give us a sense of I think you said in 2019 the WDA would be just specific to Utica development but give us a sense on this year in 2018 and toward the WDA and ADA have the spilt there between Marcellus and Utica and if you start well account numbers that would be great?

[John McGinnis:]

Sure, as I mentioned in the discussion just now we still have three wells that are currently coming on and we will be drilling three more wells I think for the at least bringing three more wells online during 2018 in the WDA area. So, we'll be doing some drilling and now I have that drill account now, but I know will be bringing on three additional wells. Our east, once we done and gamble we will move into tailored on our first pad there and I believe it's seven wells that will be drilling on that pad and that will all take place during this fiscal year we want to see production from that until 2019. I believe we have there in the second quarter.

[Holly Stewart:]

Thank you, okay. And then another one just on Atlantic Sunrise, if you could maybe help us just understand how you in the vision on that project selling up, is it a 100% full on day one, but is that existing production versus incremental production to trying to think about how you utilize that project from the detail?

[John McGinnis:]

Yes, it will be full on day one. But we have existing production there now could fill today. And we're projecting that it comes on to in July and if we see, there should be slip a little bit we may be out and the market time to fill that gap. But as of today, we can fill up from day one.

[Holly Stewart:]

Okay, great. And then just one final one from me and Dave reference business comments but just wanted to follow-up. I'm assuming at this point and given where we are in the spot market, we are still curtailing volumes through 1Q?

[David Bauer:]

Yes.

[Holly Stewart:]

Okay. Thanks, Dave.

[Operator:]

And your next question comes from the line of Graham Price of Raymond James. Your line is open.

[Graham Price:]

Good morning, guys. Just really quick on the unit to test wells just trying to get a sense of maybe how much testing those wells with regards to determining an optimal profit loads and stage basin. Things like that and then any potential uplift the EUR that we could see from that?

[Ronald Tanski:]

A quite a bit of testing is left to do. For example, and the three most recent wells, we actually tested three different targets. I now there're all within 30 - 40 feet of each other but we've actually seeing differences even with that that small of the change. As we move forward, it will be an ongoing I guess testing program, we will be changing at least into for the next year will be testing difference spaces, spacing will be testing different well spacing as well. So, there is still quite a bit of work to do. And then in terms of improving these well results significant, I don't think that will happen it's more towards fine tuning and cost saving.

[Graham Price:]

Okay. Got it. Thanks. That's great. And then real quick for my follow up. Just wondering about completed well costs for those Utica well have been drilled. I know that these costs will be coming down, but just kind wanted to get a sense of maybe where you're at today?

[Ronald Tanski:]

Well, overall there are about 20% higher and most of that is on the completion side. I don't know what they are today, but I know we're expecting on the completion side, there will be little north of $3 million once we move into full development.

[Graham Price:]

Okay. And you expect to move to full development 2018.

[Ronald Tanski:]

Yes, towards the end of 2018 moving into 2019 we will have fine-tuned our completion practices and be moving forward on that.

[Graham Price:]

Okay, perfect. Thanks guys. That's it from me.

[Operator:]

Your next question comes from the line of Becca Followill of US Capital Advisors. Your line is open.

[Becca Followill:]

Good morning, guys. Just following up on that question. So, I think you said it's $3 million for completed well cost or just the completions portion?

[Ronald Tanski:]

It will be little over between 3 and 3.5.

[Becca Followill:]

And then the drilling portion?

[Ronald Tanski:]

We're estimating a little over 2, between 2 and 2.5. So, in all in between 5.5 to 6.5. I think we're looking at 6-6.2.

[Becca Followill:]

And that's where you expect to be?

[Ronald Tanski:]

That's where we expect to be. That's a little more expensive now, because we do a lot of science on these pads, on these wells. Our stage spacing is tighter than I think it will end up. So, there is still a lot of work to do. But it will reduce as we go forward.

[Becca Followill:]

How long do you think to get to that level?

[Ronald Tanski:]

Within the year. 9 months to a year.

[Becca Followill:]

And targeted well spacing at this point?

[Ronald Tanski:]

Good question. Probably minimum a 1000 foot, but I think we'll probably start a little wider around that about 1200. But that something we are still working out.

[Becca Followill:]

Great. And then last question is can you tell us how much gas is curtailed during October?

[Ronald Tanski:]

About 1.5 Bcf.

[Becca Followill:]

Great. Thank you, guys.

[Operator:]

And your next question comes from the line of Tate Sullivan of Sidoti. Your line is open.

[Tate Sullivan:]

Great thank you for taking my question and good morning. And thanks for the details earlier on the lower tax rate and the higher debt at the end of the quarter too. Can you go into the more detail on your utility just in terms of the customer growth rates year-over-year I think it declined slightly in Pennsylvania and give some context for those rates growth?

[John McGinnis:]

Sure. Our as you know we've got a pretty high concentration of the customer base in both New York and PA at better than 95%. There is some population growth, but we don't count on large growth in customer account probably in the 0.5% area per year.

[Tate Sullivan:]

About 0.5% per year. Okay, great. And then the year-over-year decline in the quarter in the utility was some of that weather related in Pennsylvania. Or was it mostly the lower rate case coming through in New York in April.

[John McGinnis:]

So, you're saying the earnings of

[Tate Sullivan:]

Adjusted utilities peace.

[John McGinnis:]

Quarter-over-quarter?

[Tate Sullivan:]

Year-over-year if you can?

[John McGinnis:]

Year-over-year. Yeah, of the biggest chunk of that is going to be weather in Pennsylvania which was I think the winter was somewhere in the 10% warmer than normal area. On top that we had some cost create in the on the O&M side, but weather was by far the biggest factor.

[Tate Sullivan:]

Okay. Thank you very much for that. Thanks.

[John McGinnis:]

You bet.

[Operator:]

[Operator Instructions]. Your next question comes from the line of Chris Sighinolfi of Jefferies. Your line is open.

[Chris Sighinolfi:]

Hey, good morning, guys.

[Ronald Tanski:]

Good morning Chris.

[Chris Sighinolfi:]

Dave, I just had a question with regard to the timing of that deferred tax liability reassessment. Was that due to something within the regulatory approval process for Atlantic Sunrise or the fact you having in fiscal year or something else, just what may do you take the reassessment at this point?

[David Bauer:]

So, this is with respect to the Atlantic Sunrise adjustment,

[Chris Sighinolfi:]

Your PA tax going down.

[David Bauer:]

Yeah, you've got to pick the time when we make the adjustment, we have typically been pretty conservative and waited until we have seen shovels in the ground to make the adjustment, so with construction pretty much underway on Atlantic Sunrise the probability of that project being completed was high and are estimated and that let us to record the adjustment.

[Chris Sighinolfi:]

Okay, okay. That's helpful. And I guess what would be next steps for Empire and North, I did see some incremental personnel agreement volumes added I think since the last call, and you have had obviously mentioned in prepared remarks some additional fencing items associated with that project this past quarter, so, just wondering with milestones to look forward to through gauge progress on that and potential timeline for it.

[Ronald Tanski:]

The next steps would be the actual filing of the FERC application for the seven seas for their project Chris and that's basically yeah, the spending to-date has been preliminary engineering for the compressor sites and logistics for that, so we are looking to get that done pretty close to the end of the year and does may affect where starting out reach hearing or outreach meetings next week to cover any questions that locals might have with respect to deciding of those compressor side.

[Chris Sighinolfi:]

When you say the end of the year, you mean in this calendar year.

[Ronald Tanski:]

Yes, the calendar year. I am sorry.

[Chris Sighinolfi:]

Just being okay. And I guess with regard to the personnel agreements in place on that project, are there those third-parties for a Seneca representative on ...

[Ronald Tanski:]

Not, Seneca is not represented, so a portion of it however is our utility and I forget the exact portion of that Dave, could you.

[John McGinnis:]

Yeah, it's relatively small.

[Ronald Tanski:]

Yeah, it's a relatively small but it's a third-party production that would be utilizing that space.

[Chris Sighinolfi:]

Okay. Two more questions if I could, one was Dave if I heard you correctly with regard to the payment made, I guess that was to TransCanada just to keep on ice for some time the ability that can vary the Northern access volumes all the way in - is that right, is that sort of how do I understand it, Northern access does eventually go forward, they complete their portion of the build you get reimburse.

[David Bauer:]

That's exactly right, Chris. It basically suspends the project until we get approval on Northern access.

[Chris Sighinolfi:]

Okay. And then I guess a final question for me is just there was a shareholder proposal or idea uploaded about tracking stock potentially for your utility company and then I have my thoughts about it, but I was just curious if you guys had obviously considered that and thought about it either once the management team or conversation at the board level and what if any response or thought given to this?

[David Bauer:]

Yeah, it's a little tough to comment on that, right at this point in time Chris. We're in the process, - the lawyers are concerned about anything we say being considered proxy solicitation, so just prefer not to comment on it at this point.

[Chris Sighinolfi:]

Okay, fair enough. Well thanks again for the color and look forward to seeing you guys in Houston later this month.

[Ronald Tanski:]

Sounds good. Thanks.

[Operator:]

[Operator instructions]. And there seems to be no further questions at this time, I turn the call over back to the presenters for closing remarks.

[Ronald Tanski:]

Thank you, Kelly. We like to thank everyone for taking their time to be with us today. A replay of this call will be available at approximately 3 Pm, Eastern time, on both our website and by telephone. And we'll run through the close of business on Friday November 10. To access the replay online please visit our Investor Relations website at investor.nationalfuelgas.com. To access by telephone call 1800-585-8367 and enter a Conference ID number 960-83185. This concludes our conference call for today. Thank you and good bye.

[Operator:]

This does conclude today's call. You may now disconnect.