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Edited Transcript of NFG earnings conference call or presentation 3-May-19 3:00pm GMT

Q2 2019 National Fuel Gas Co Earnings Call

WILLIAMSVILLE May 9, 2019 (Thomson StreetEvents) -- Edited Transcript of National Fuel Gas Co earnings conference call or presentation Friday, May 3, 2019 at 3:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* David P. Bauer

National Fuel Gas Company - Treasurer & Principal Financial Officer

* John P. McGinnis

Seneca Resources Corporation - President & COO

* Kenneth E. Webster

National Fuel Gas Company - Director of IR

* Ronald J. Tanski

National Fuel Gas Company - President, CEO & Director

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Conference Call Participants

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* Christopher Paul Sighinolfi

Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships

* Holly Meredith Barrett Stewart

Scotia Howard Weil, Research Division - Analyst

* Rebecca Gill Followill

U.S. Capital Advisors LLC, Research Division - Senior MD & Head of Research

* Ryan Michael Levine

Citigroup Inc, Research Division - Equity Analyst

* Szu-Ying Loy

Raymond James & Associates, Inc., Research Division - Research Associate

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Presentation

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Operator [1]

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Good morning. My name is Carol, and I will be your operator today. At this time, I would like to welcome everyone to the National Fuel Gas Company Second Quarter 2019 Earnings Call. (Operator Instructions) At this time, I would like to turn the call over to Ken Webster, Director of Investor Relations. Mr. Webster, please go ahead.

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Kenneth E. Webster, National Fuel Gas Company - Director of IR [2]

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Thank you, Carol, 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.

At the end of the prepared remarks, we will open the discussion to questions. The second quarter fiscal 2019 earnings release and May 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 participating in the AGA Financial Forum later this month in Fort Lauderdale. If you plan on attending, please contact me to schedule a meeting with the management team.

With that, I'll turn it over to Ron Tanski.

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Ronald J. Tanski, National Fuel Gas Company - President, CEO & Director [3]

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Thanks, Ken, and good morning, everyone. Thanks for joining us. As we highlighted in last evening's release, earnings for the second fiscal quarter of 2019 were fairly consistent with last year and in line with our expectations.

Emerging from the winter heating season that was slightly colder than last year in our New York jurisdiction, we saw a slight uptick in earnings in the Utility business, where throughput was 1.7 billion cubic feet higher than last year's second quarter. Because our weather normalization mechanism offsets most of the impact of colder weather, the increase in Utility earnings came largely from higher margin, lower interest expense and other minor rate adjustments. The higher earnings in the Utility helped to offset an expected decrease in the Pipeline & Storage segment's earnings that was caused by the expiration of a shipper's transportation contract on our Empire Pipeline system.

As we've talked about before, KeySpan had used that capacity to import Canadian gas and transport it to its downstate service territory. The proliferation of Pennsylvania shale production closer to KeySpan service territory ultimately made the Canadian gas uneconomic, and KeySpan let the contract expire at the end of its term. Today, the capacity on the pipeline is fully contracted to move gas in the opposite direction, and that capacity will be further expanded next year.

In our Exploration and Production business, even though we achieved our highest ever average daily production rate this past quarter, we were expecting more. It's a slight disappointment that we've modestly lowered the midpoint of our production guidance to the low end of the range that we established last August. Operationally, we've experienced longer drilling and completion times on our Utica wells, which will shift production that we had planned for this year into fiscal 2020. The delay in well turn-on dates is not expected to materially change the economics of our Utica drilling program. Later in the call, John McGinnis will get into more details of Seneca's operations and plans.

In our pipeline business, all of our development projects continue to move along on schedule. In March, the Federal Energy Regulatory Commission, or FERC, issued a certificate for our Empire North project. This is the project that will add the capacity that I talked about earlier, and we plan to have it in service during the second half of fiscal 2020. With the certificate in hand, we've placed orders from -- for some of the items that have longer lead times, and we've requested a limited notice to proceed from FERC to begin preliminary construction activities during the current fiscal year. Actually, last evening, we filed for a full notice to proceed from FERC. Now this will lead to some spending on the project this year and will have a steady ramp-up in construction activities and spending through fiscal 2020. As a reminder, this project will add $25 million per year in annual revenues to the system.

We also received another favorable ruling from FERC on our Northern Access project. As you may recall, last August, FERC issued an order finding that the New York Department of Environmental Conservation effectively waived its water quality certification authority under the Federal Clean Water Act. The DEC and the Sierra Club subsequently requested rehearing from FERC, and FERC denied those requests in April.

In addition, in February, the U.S. Second Circuit Court of Appeals issued an order vacating and remanding the DEC's denial of the water quality certification. While we're certainly pleased with the progress that has been made on the legal and regulatory fronts and remain hard at work securing the remaining approvals necessary to seek a notice to proceed from FERC, we expect the construction is still a few years off.

Construction is underway however along our Line N pipeline system in Pennsylvania where we're installing a lateral to connect our system to the new Shell petrochemical plant that is also under construction. We expect our pipeline lateral to be finished by the end of the summer, and transportation services to -- provided Shell will add approximately $5 million in revenue on an annual basis. We've included more detail for those projects and our FM100 project in our quarterly slide deck that we have online.

Entering into the summer construction season, we're pretty well lined up with all our pipeline modernization projects in both the interstate Pipeline business and the Utility business. We're pleased that the New York Public Service Commission approved an extension of our system modernization tracker through March 2021. This extension allows us to continue to make significant investments in the safety and reliability of our distribution system and provides line of sight on continued albeit modest growth in the Utility for the next couple of years.

As you may recall, this tracking mechanism was part of our last rate case and kicked in last December when we exceeded established mileage and plant-related targets. It allows us timely rate recovery of incremental investments in pipeline modernization across our New York service territory and was originally scheduled to sunset in March 2020.

On a personal note, you may have seen my retirement announcement for this July. You've all gotten to know Dave Bauer over the years, and he will become President and CEO effective July 1. The Board and I have full confidence in Dave and the entire management team, and we expect that it will be a seamless transition. Our succession plan for other management moves on July 1 will likewise consist of the internal shifting of our experienced homegrown talent.

We're pleased with where our business is headed. We have investment plans and operating procedures to keep both our regulated and gathering pipeline systems safe. We believe that our oil and gas development strategy continues to work and needs no major retooling, and we remain confident that we will meet our targeted 15% to 20% average annual growth production or -- production growth over the next few years.

And now I'll turn the call over to John McGinnis and Dave Bauer to cover some more of the operational and financial details for the quarter.

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John P. McGinnis, Seneca Resources Corporation - President & COO [4]

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Thanks, Ron. Good morning, everyone. Seneca experienced mixed results in the second quarter. On a positive note, we saw some really nice well results. We brought to production 4 Utica development wells at DCNR 007, the first 2 -- the first new wells since 2016. These wells are looking great, and this tract is now producing over 60 million a day. Three of the wells are producing at rates of around 15 million a day and our fourth well, which is still cleaning up is currently at just over 10 million a day.

Our 2 new Marcellus wells at DCNR 100 came on as expected as did our most recent Utica pad in the WDA. However, the quarter was not without its challenges. Though we achieved record daily production levels this quarter, we fell short of our expectations. The shortfall relative to our expectations was mostly a result of some operational curtailments, the impact of our continued testing efforts to optimize our Utica drilling and completion design in the WDA and to a lesser extent, drilling and completion delays at Tract 007 in the EDA. While these operational delays have the effect of pushing production out to future periods, they are not expected to have a material impact on our ultimate well recoveries or program economics.

Looking to the full year, we are lowering our fiscal '19 production forecast by around 5% or 10 Bcf at the midpoint to a range of 205 to 215 Bcf. In addition to the items I discussed pertaining to the second quarter, our revised guidance range reflects the expected impact of drilling and completion delays in the EDA on production for the remainder of the year and builds in additional production downtime to reflect the operational realities we experienced in the first half of the fiscal year.

Our updated guidance range also reflects expected production impacts from our WDA Utica drilling and completion optimization efforts for the remainder of the year as well as the company's continued trend of drilling longer laterals in both the EDA and WDA. These longer laterals are expected to benefit our overall program economics, however, the longer drilling completion times will defer the online dates related to future development pads beyond the prior plan.

Even with this decrease, we still expect production growth to range between 15% to 20% year-over-year and to continue to grow at that rate for the next several years within our -- with our 3-rig program. We continue to make excellent progress with our Utica program in the WDA. We brought online a total of 11 wells over the past 2 quarters, 3 at the end of November, another 4 the last week of December and 4 new wells in March.

As we continue to focus on optimizing our drilling completion design in this area, we are testing landing target and several completion design variations that so far have included stage spacing, proppant loading and produced fluid blend. Due to this ongoing testing, we expect to see some variability within our program, as we fine-tune our well design.

We experienced some of this variability last quarter, where 2 of our Utica wells underperformed compared to the remaining wells brought to production. Our early assessment of these 2 wells indicate that the poor performance is attributable to a high produced fluid blend percent used during the completion operations. Of the 21 CRV Utica wells brought online to date, our poorest performers were either brought online too aggressively or were completed with a 95% or greater produce fluid blend. Though a limited dataset, our results so far suggest that the percent produced fluid blend maybe nearly as impactful to well performance as our restricted drawdown management practice. Therefore, based on our learnings, going forward, we will employ a lower produced fluid blend in our completion design on future WDA Utica wells. Our most recent Utica pad brought online in March utilized a fluid blend ranging between 75% to 85% on all 4 wells and are producing consistent with our type curve.

With 21 WDA Utica wells now online, we continue to be encouraged by overall results. Our type curve remains at 1.7 Bcf per 1,000-foot. We have -- and we have another 6 Utica wells scheduled to come online late in fiscal '19, and as stated last quarter, once all 27 wells have been producing for a few months, we'll provide an updated type curve and additional insight related to our drilling completion design optimization. WDA Utica has tremendous potential for our company and combined with the co-development of our Marcellus and full ownership of the Midstream gathering, we envision strong integrated returns from our WDA assets for many years to come.

For the remainder of the year, we plan to bring to production 6 additional Utica wells and 6 Marcellus wells in the WDA and 10 Marcellus wells in the EDA. Five of the EDA wells however, are scheduled to come online very late in the fourth quarter. Our fiscal '19 CapEx guidance remains the same with capital expenditures ranging from $460 million to $495 million.

Moving forward, we have locked in approximately 79 Bcf of firm sales in Pennsylvania at an average realized price of $2.42 per Mcf and another 14 Bcf of production with basis protection through our firm sales portfolio. Therefore, we have locked in physical sales for almost 90% of our remaining fiscal '19 production. We currently estimate around 11 Bcf available for sale into the spot market, but as we see opportunities, we will continue to layer in additional sales. Spot prices remained stronger during the second quarter but have recently fallen into the plus or minus $2 range at each of our 3 receipt points. Fortunately, we have minimal spot exposure but please recall, our production forecast assumes no marketing curtailments for the remainder of the year.

Moving to California, we produced 644,000 BOE of oil during the second quarter, a decrease of around 17% from last year's second quarter. This decrease was largely driven by the sale of our Sespe oilfield last year. Having finally received the necessary permits last quarter, we have now begun drilling both production and steam injection wells in Pioneer adjacent to our South Midway field. We should begin to see production growth related to this property in fiscal '20 as our steaming operations begin to heat the reservoir.

I know we continue to wait for an aquifer exemption permit of 17N, we have recently drilled 13 new wells, and early results look quite promising. This property is now producing over 500 barrels a day compared to around 200 a day at the end of our last fiscal year.

And with that, I'll turn it over to Dave.

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David P. Bauer, National Fuel Gas Company - Treasurer & Principal Financial Officer [5]

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Thank you, John. Good morning, everyone. National Fuel second quarter GAAP earnings were $1.04 per share. Similar to last quarter, we had items impacting comparability relating to hedging and effectiveness and the marking to market of investments in a nonqualified benefit plan.

Excluding those items, our operating results were $1.07 per share, which, though a little below Street consensus, were right in line with our own expectations. This was a quarter where the benefits of our integrated diversified business model were particularly evident. Our regulated businesses, Utility in particular, had strong quarters relative to forecast, which helped offset the near-term challenges in Appalachia, that John described earlier.

Looking at the results of our operating segments. The Utility had a really nice quarter, driven in large part by improved operating margins, which excluding the refund provision for Income Tax Reform were up $0.02 per share. This was the result of 2 main factors: first, we're seeing a modest amount of customer and industrial usage growth, which can be attributed to the continued strong economic backdrop in our service territories and the cost advantages of natural gas. The second, the system modernization tracking mechanism Ron described earlier contributed a little less than $1 million of additional margin.

We expect this tracker will provide about another $2 million for the remainder of the year as the weather breaks and our level of construction activity ramps up. The surcharge is accrued volumetrically so similar to most rate-making items, there will be some seasonality to the cash flows and earnings related to this mechanism.

As expected, the earnings of our FERC-regulated pipeline businesses were down relative to last year, largely due to the loss of the KeySpan time track on the Empire system, which Ron described earlier. This reduced revenue by about $6 million in the quarter and will reduce full year fiscal '19 revenue by about $14 million. The benefit from Tax Reform and the new rates from Empire's rate case settlement partially offset the loss of that contract. Pipelines & Storage revenues for the quarter were in line with our forecast, and we don't expect any major changes in the second half of the fiscal year. Therefore, we're keeping fiscal '19 revenue guidance for the pipeline segment at approximately $285 million. As I mentioned on prior calls, fiscal '19 is a cyclically higher year for compressor maintenance and pipeline integrity work, which will likely drive a 5% to 10% increase in O&M expense. Most of that increased spending was weighted to the first half of the fiscal year.

As you can see from last night's release, Pipeline & Storage O&M was up $7.1 million or 19% for the 6 months.

Looking to the second half of the year, I expect the pipeline O&M will be pretty much flat to fiscal '18 levels.

Turning to our nonregulated businesses. As John discussed earlier, Seneca's production with the quarter was below our expectations, which weighed on the earnings of both our E&P and Gathering segments. Pricing was generally in line with our expectations. Gas was a couple cents lower and oil a couple dollars higher but the net impact was very small.

With respect to Seneca's operating expenses, there were a few items worth noting. Seneca's LOE for the quarter was $0.94 per Mcfe, above the range of our guidance. This was not unexpected. As I said on last quarter's call, elevated natural gas prices in Southern California caused a spike in steaming costs. Prices have since moderated and at the same time, we've made changes to our supply portfolio and outsourced almost all our steam fuel at indices that are more closely tied to Rockies pricing.

Looking to the back half of the fiscal year, more moderate steam fuel cost combined with the expected increase in Seneca's Appalachian production should cause third and fourth quarter LOE to trend towards the middle of our full year to $0.85 to $0.90 per Mcfe guidance range. Quarter-over-quarter, DD&A expense increased from $0.70 to $0.74 per Mcfe due to the timing of capital spending and reserve additions.

We still expect the year to be in a range of $0.70 to $0.75 per Mcfe, which approximates our long-term expected F&D costs. One further note on Gathering. The shift in timing of Seneca's production has a corresponding impact on fiscal '19 Gathering revenues, which we now expect will be in the range of $125 million to $130 million.

Bringing it all together, we're keeping our fiscal '19 earnings guidance at a range of $3.45 to $3.65 per share. Though our E&P and Gathering earnings projections were impacted by the drop in Seneca's forecasted production, as several items offset that impact including our updated commodity price assumptions, additional firm sales contracts and our rate reduction on a portion of Seneca's upstream transportation capacity.

Our Appalachian spot price for the remainder of the year is $2.10 per MMBtu. With only about 10 Bcf spot exposure for the remainder of the year, changes in spot prices should not have a material impact on earnings. But that being said, should we see a severe drop in local pricing, we may look to curtail production until the higher priced winter months.

Our capital spending guidance is unchanged at a range of $725 million to $810 million. Since we aren't changing earnings or capital guidance, it follows that our financing needs are also unchanged. We still expect our funds from operations should cover substantially all of our capital expenditures this year, with our financing needs tied primarily to our dividend and any changes in working capital.

In conclusion, all things considered, the second quarter was a good one for National Fuel with positive developments across the system, including improved margins at the Utility, continued progress on our pipeline projects and good well results at Seneca.

Production guidance is modestly lower, but at the end of the day, our program is still well positioned to deliver solid returns and consistent production growth. Looking forward, I'm excited for the future of National Fuel. We have great assets that span the natural gas value chain. The economics for our drilling program remains strong. We have a great backlog of pipeline projects, and the current state regulatory backdrop supports the accelerated modernization of our Utility system.

Our balance sheet is solid, and we fully expect to continue our long-standing practice of returning capital to shareholders through our dividend.

All of this should translate to growth in shareholder value in the years to come. With that, I'll turn it over to the operator to open the line for questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question today comes from Holly Stewart from Scotia Howard Weil.

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Holly Meredith Barrett Stewart, Scotia Howard Weil, Research Division - Analyst [2]

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Congratulations, Ron. May we all be so lucky.

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Ronald J. Tanski, National Fuel Gas Company - President, CEO & Director [3]

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Gets here faster than you think, Holly.

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Holly Meredith Barrett Stewart, Scotia Howard Weil, Research Division - Analyst [4]

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Maybe I'll start off, one for John, just you mentioned the minimal curtailments in the guidance. Just maybe high level, how are you all viewing the market right now in EDA? Is this temporary, maybe due to just shoulder season patterns in demand? Or are we seeing pipes backfill post-Atlantic Sunrise and the widening maybe to continue here?

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John P. McGinnis, Seneca Resources Corporation - President & COO [5]

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Holly, obviously during the shoulder months, we always see this kind of decrease in spot prices across the basin to tell you the truth. Honestly, I hope it's temporary, but we're expecting maybe a little bit lower prices through summer. But as always, it depends a little bit on how hot the summer is. But as -- we've locked in quite a bit, so we do have some exposure, but if it stays in just above at $2 and above, we're -- I think we're actually fine with that.

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Holly Meredith Barrett Stewart, Scotia Howard Weil, Research Division - Analyst [6]

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Okay. That's good color. Maybe I guess on that note, recognizing you are pretty locked in on the firm sales for 2019. But given pricing overall for NYMEX is kind of trending toward multiyear lows here. How are you thinking about that 3-rig program, as we move into the back half of 2019 and beyond?

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John P. McGinnis, Seneca Resources Corporation - President & COO [7]

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Yes, well, we've committed to firm capacity on pipe. And so we have -- we'll stay at 3 rigs. We've committed to Leidy South. It's 330 million a day, and so our goal in the short term, at least over the next couple of years is to make sure that when that pipe comes online that we can fill it.

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Holly Meredith Barrett Stewart, Scotia Howard Weil, Research Division - Analyst [8]

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Okay. Great. And then maybe just one other one. We've heard a lot I think this quarter about just water in general, whether it's impacting the LOE or whether it's actually water infrastructure assets for sale. So it's been pretty topical. Can you maybe help us think through just your water handling, both in the EDA and the WDA, and if there is an opportunity for your Midstream business, I guess it would be particularly in the EDA on third quarter water volumes?

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John P. McGinnis, Seneca Resources Corporation - President & COO [9]

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Yes, it's actually a tough question. We have a very large central water facility in the WDA. In the EDA, it's a -- it's much smaller because the volumes that we see being produced in the east are just not what we see in the West. So we do -- we have a very large water facility. We typically do bring in third-party produced water when it's necessary, when we need the water. But we also will supply water to other operators when they need it. I'm not sure it's a business I want to get into. We view it as a means in which to drive down our water cost.

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Operator [10]

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Our next question comes from Ryan Levine from Citi.

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Ryan Michael Levine, Citigroup Inc, Research Division - Equity Analyst [11]

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What percentage of your California production is urban? And how do you view the exposure to some of the protocol commentary coming out of the state?

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John P. McGinnis, Seneca Resources Corporation - President & COO [12]

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Yes, it's -- California is a fun place to do business. Honestly, we don't see this bill -- I think it's Bill 345, which you're referring to. We don't believe the bill will survive. There's a lot of opposition already and not just from our own industry, but having said that, we have stepped back and taken a look at potential impact on our operations, and honestly, we think it would be minimal because almost all of our operations are very rural in the San Joaquin basin.

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Ryan Michael Levine, Citigroup Inc, Research Division - Equity Analyst [13]

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And is any of the rural near any hospitals or any infrastructure that's being proposed to be of concern?

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John P. McGinnis, Seneca Resources Corporation - President & COO [14]

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No.

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Operator [15]

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Our next question comes from Gordon Loy from Raymond James.

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Szu-Ying Loy, Raymond James & Associates, Inc., Research Division - Research Associate [16]

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So I just had 2 quick questions. The first one in the opening remarks, you guys mentioned that there is a continued trend towards drilling longer laterals. And I just wanted to get a sense of I guess what's the average lateral length that the company is drilling now? And where do you guys foresee that going to?

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John P. McGinnis, Seneca Resources Corporation - President & COO [17]

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Sure. Let's start in the WDA. 6 months, 9 months ago, we were drilling 6,000-foot roughly plus or minus the 1,000-foot appraisal wells in the Utica. Today, we're drilling 8,000-, 9,000-, even over 10,000-foot Utica wells. Our Marcellus wells, we just recently drilled a Marcellus pad. We typically average 6,000- to 7,000-foot. Most of those wells were 8,000-, 9,000-, 10,000-foot wells. So we're seeing an increase of anywhere from 2,000 to 3,000 feet per lateral at least in the WDA. A perfect example in the east is we're now at a pad in the Gamble, Lycoming area where we had assumed or expected that we'd be drilling 4,500-foot lateral. We just finished that well, and it ended up being I think north of 5,500, if I remember correctly. So just to give you a sense of perspective, if we're -- let's go to the west. For every 2,500-foot of lateral, it probably adds -- let's say we have 4 wells on a pad, it may add 4 or 5 days of drill time and it may add -- obviously it's going to add additional completion time because we're going to be having more stages. So every 4-, 5-, 6-well pad, if we're drilling that greater of a lateral, probably add anywhere from 3 to 4 weeks just to get that pad online.

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Szu-Ying Loy, Raymond James & Associates, Inc., Research Division - Research Associate [18]

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Got it, that makes sense. And then my follow-up is I'm looking on Slide 19 and you have kind of the well cost estimate for the Utica CRV, and it's currently at about $895 per lateral foot. Is that kind of the expected well cost when it's -- when you guys shift into more development mode or is that just what's it's kind of averaging right now?

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John P. McGinnis, Seneca Resources Corporation - President & COO [19]

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It's actually kind of what it's averaging right now. Early on, we tried to make forecasts on that, and then as we get more and more wells, then we tend to look at what the average is, our contracts obviously that are associated with it, so...

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Operator [20]

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Our next question comes from Chris Sighinolfi from Jefferies.

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Christopher Paul Sighinolfi, Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships [21]

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Ron, just wanted to -- like Holly, offering my congratulations on your long career with NFG and the retirement. I've personally learned a lot from our interactions and conversations and also enjoyed time spent traveling together. So thanks for all of that and wish you the best in retirement.

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Ronald J. Tanski, National Fuel Gas Company - President, CEO & Director [22]

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Thanks. I'll buy you a beer when I see you at AGA.

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Christopher Paul Sighinolfi, Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships [23]

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There you go. I think they're free, but I'll let you pay for it. I think also, Dave, congrats on your role. I think therein lies a question. Ron, you'd mentioned in your prepared remarks, the anticipated shift among the internal team, given Dave's pending move to the CEO role but just any further clarification on what we might expect as the CFO search process either internally, externally, takes shape, and we move towards July?

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Ronald J. Tanski, National Fuel Gas Company - President, CEO & Director [24]

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Yes, it's our typical practice to announce those as they're made. With all of the attendant pictures and releases, and we'll just keep to that and announce it then.

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Christopher Paul Sighinolfi, Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships [25]

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Okay. But it's not something where we would see an interim notification. Your intention is before July to have fully staffed CFO position.

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Ronald J. Tanski, National Fuel Gas Company - President, CEO & Director [26]

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Yes, yes.

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Christopher Paul Sighinolfi, Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships [27]

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Okay. Great. And then if I could just pivot and follow up on some of the other questions, John, for you. You mentioned in your release last night and obviously on call this morning, multiple factors, the longer laterals, the testing on well and completion design and the delays that you cited in the DCNR Tracts in east, some of that seems to be more impactful on fiscal 2Q and some of it seems to be more impactful towards on the program on a go-forward, I was just wondering in terms of fiscal 2Q, how -- if we thought of maybe as a percentage of the impact, how much of that was just the DCNR issues and are those resolved at this point?

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John P. McGinnis, Seneca Resources Corporation - President & COO [28]

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Yes, I would say, at least for a specific to Q2, it was probably a small amount. Maybe a half would be -- was related to some delays there. The larger impact will occur going into the next couple of quarters. We had 1 well that we had to sidetrack and redrill. That put us back about 30 days, and then at 007, we actually had 1 well that had some collapsed tubing, which was a bit strange that took us a couple weeks, 2 to 3 weeks, to sort of get that fixed, and so that sort of postponed the online date for 3 wells.

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Christopher Paul Sighinolfi, Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships [29]

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Okay. And I guess the way that those -- that reads issues you see as very much at -- sort of specific issues to those wells and not something that speaks to larger problems in that program. Is that right?

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John P. McGinnis, Seneca Resources Corporation - President & COO [30]

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No, that's, that's exactly correct, Chris. But we view these as one-off issues, and we don't foresee this being a consistent trend.

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Christopher Paul Sighinolfi, Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships [31]

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Okay. And then you also had noted I guess in the prepared remarks, John, that the produced fluid percentage being problematic about 95%, better in the 75% to 85% range. But just wondering, any variability in ranges other than 75% to 85%? Or are you indicating that, that's a sweet spot your team believes is optimal for your program?

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John P. McGinnis, Seneca Resources Corporation - President & COO [32]

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Yes, actually that's a great question, Chris. We've had a lot of debate on this. Our ranges will typically go as -- at least in the West to as below 50% and to as high as 100%. And so we're not sure -- after only 21 wells, we're not sure what that sweet spot is yet, but we do know that once we get to that 90% plus, really 95% plus that we are seeing an impact on these wells. It wouldn't surprise me that the fresher the blend, the better the well, but there's --- it's going to, how we manage that going forward is going to depend a little bit on the impact on the economics and the well results.

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Christopher Paul Sighinolfi, Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships [33]

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Okay. I guess then as it relates, Boone Mountain has been a standout for you guys, the appraisal there. Can you just remind me was that -- is that simply the resource opportunity in that area? Or did you do something different with that well and completion design versus the others that...

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John P. McGinnis, Seneca Resources Corporation - President & COO [34]

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No, that is just the resource potential within that area. We actually think in our appraisal drilling over the next few years, we'll try to lock it down, but there's -- we think there's a corridor between our Rich Valley 214 well and our Boone Mountain well that will be fairly productive. Again, that's just something we're going to have to lock down over the next couple of years.

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Christopher Paul Sighinolfi, Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships [35]

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Okay. And I guess this is all very helpful. The final question for me would be then, you mentioned I think in the WDA, 6 Utica, 6 Marcellus and then the EDA, 10 Marcellus for the remainder of the year. I'm just curious given the program so the time profile with longer laterals, et cetera, what sort of DUC inventory do you envision at the end of your fiscal year, setting up for next year?

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John P. McGinnis, Seneca Resources Corporation - President & COO [36]

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Yes, any DUCs that we have -- DUC inventory -- the only DUC inventory we really have that's significant will be in the WDA, where we have 2 rigs running. In the EDA, as soon as we're done drilling on a pad, we have a spot crew moving in to get that pad completed.

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Christopher Paul Sighinolfi, Jefferies LLC, Research Division - Senior Equity Research Analyst, Master Limited Partnerships [37]

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Okay. So the delay in the timing didn't meaningfully change I guess that year-on-year cadence in terms of where your inventory to complete in the west might be? Is that how I am reading it?

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John P. McGinnis, Seneca Resources Corporation - President & COO [38]

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Yes. No. It just pushes us back a month, 1.5 months, is really what the delays do.

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Operator [39]

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(Operator Instructions) Our next question comes from Becca Followill from U.S. Capital Advisors.

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Rebecca Gill Followill, U.S. Capital Advisors LLC, Research Division - Senior MD & Head of Research [40]

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Following up on Chris' question. The third part of the rationale for the lower guidance, that trending towards drilling longer laterals, what has changed from the prior guidance. I mean are you -- was the prior guidance ex lateral and now it's ex or what's different?

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John P. McGinnis, Seneca Resources Corporation - President & COO [41]

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Yes, we've set our guidance, our range very early, obviously before -- back in August is I think is when we set it. And as we move forward and begin to better understand some of these areas, we'll permit them along, and if we have the opportunity to continue to drill them longer, we'll do so. Historically, when we drilled Marcellus wells, we permitted them long and it always ended up being maybe 1,000, 2,000 feet shorter than what we had permitted because the structural complications, and we're not just finding that in the Utica. So in terms of our forecast, and we've tended to under forecast what our final laterals will be based on what we've done to date. Does that make sense?

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Rebecca Gill Followill, U.S. Capital Advisors LLC, Research Division - Senior MD & Head of Research [42]

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That makes sense. And then you also mentioned in -- the reason for the 2 wells that underperformed, it was the combination of the produced fluid blend and choke management. Are you doing that?

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John P. McGinnis, Seneca Resources Corporation - President & COO [43]

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No. Yes. We choke manage all of our wells in the Utica, under WDA Utica, and that's a positive. They don't come on as strongly, but they're much better wells. The reason those 2 wells underperformed was because of produced fluid blend. It was just too high.

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Rebecca Gill Followill, U.S. Capital Advisors LLC, Research Division - Senior MD & Head of Research [44]

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So it's not choke management.

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John P. McGinnis, Seneca Resources Corporation - President & COO [45]

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Exactly.

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Rebecca Gill Followill, U.S. Capital Advisors LLC, Research Division - Senior MD & Head of Research [46]

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And then because it's still, I mean you're still really early in the development at this play, with a number of wells you've drilled compared to how many you plan to. So when you do your forecast for 15% to 20% growth, how much do you factor into there the fact that the mix is going to change, and some wells are not going to work, and you're still kind of in science. So how do you risk-adjust that 15% to 20%?

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John P. McGinnis, Seneca Resources Corporation - President & COO [47]

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That's a great question. We've drilled 350 Marcellus wells, and we've really gotten that -- we have fine-tuned our forecasting related to that program. The Utica, we drilled a whopping 26 wells, and so we're still learning as you've just mentioned, and we try to be a bit conservative on our forecasts, but having said that, maybe at least during this early period, as we're trying to understand and optimize our drilling and completion, it's going a little -- typically a little slower than we envisioned, but I think as we continue to drill these wells, we'll begin to lock down at least a more accurate forecast going forward. So there is a lot of noise early. We try to be conservative but I think because we've been drilling Marcellus wells for a long -- for such a long time, for pushing 10 years, we've underappreciated the learning curve related to some of these new areas.

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Operator [48]

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And we have no one left in queue at this time. I'll turn the call back to Mr. Webster for closing remarks.

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Kenneth E. Webster, National Fuel Gas Company - Director of IR [49]

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Thank you, Carol. We'd like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 3 p.m. Eastern Time on both our website and by telephone and will run through the close of business on Friday, May 10. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com, and to access by telephone, call 1 (800) 585-8367 and enter a conference ID #6683755. This concludes our conference call for today. Thank you, and goodbye.

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Operator [50]

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Thank you. This does indeed conclude today's conference, and you may now disconnect.