Thank you, Mike, 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 Dave Bauer, President and Chief Executive Officer; Karen Camiolo, 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 fourth quarter fiscal 2020 earnings release and November investor presentation have been posted on our Investor Relations website. We will 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 Bank of America Global Energy Conference next week. Please contact me or the conference planners to schedule a meeting with the management team. With that, I'll turn it over to Dave Bauer.

Thank you, Ken. Good morning, everyone. As we reported in last night's release, National Fuel's fourth quarter operating results were $0.40 per share. Consistent with earlier quarters, lower commodity prices were the main driver, contributing to the $0.14 per share drop in operating results and triggering the noncash ceiling test impairment charge. Despite the drop in earnings, the quarter went as planned, with operating results right in line with our expectations. Fiscal 2020 was a remarkable year for National Fuel. Against the backdrop of a pandemic, we completed a highly accretive Appalachian acquisition and brought online a significant pipeline expansion project, all while continuing to safely and reliably operate our businesses across the natural gas value chain. Looking ahead, the outlook for natural gas has improved significantly, and National Fuel is well positioned for meaningful earnings and cash flow growth. We continue to see success with our expansion projects at our FERC-regulated pipeline businesses. We placed our Empire North project in service on September 15. As a reminder, this project is fully contracted with the bulk of the commitments extending for 15 years. The project is expected to add about $27 million in annual revenues. It looks like the final capital cost will come in around $129 million, which is more than 10% below our initial cost estimate. Constructing and placing this project into service safely, on schedule, and under budget in the midst of a pandemic was quite an accomplishment. Thank you to all our employees and contractors for the exceptional effort it took to complete it. We continue to make progress on our FM100 Project. And Transco's Companion Leidy South expansion is also on track. As a reminder, all of the facilities for both projects are in Pennsylvania. There are a few permits still outstanding, and we expect to receive them this winter. We have started to order longer lead time items, and once we receive the remaining permits, we'll file for our notice to proceed. All of this keeps us on pace to be in service near the end of calendar 2021. And again as a reminder, FM100 will add approximately $50 million in annual revenues between the $35 million expansion component and the additional $15 million modernization rate step-up agreed to in our February rate case settlement. Moving to our upstream and gathering operations. We closed the acquisition of Shell's Appalachian assets back in July and now have a few months of operations under our belt. The transition could not have gone more smoothly, and we're very excited about the long-term benefits of this acquisition. It added significant scale, lowered our per-unit cost structure, and added hundreds of highly economic development locations in Tioga County, which are supported by company-owned gathering systems and valuable firm transportation, including on National Fuel's Empire pipeline. In addition, production and reserves continue to be in line with our initial expectations. As we spend more time operating the assets, we're finding additional efficiencies and revenue enhancement opportunities. Seneca is currently operating a single rig that moves between our eastern and western development areas. On last quarter's call, we discussed the possibility of adding a second rig prior to the start date of Leidy South. Given both the meaningful improvement in natural gas prices for fiscal '22 and our expectations on the timing of the FM100 and Leidy South projects, we've decided to move up the rig addition to January. This will allow us to line up first production with the in-service date of Seneca's new capacity. It will also allow us to capture the benefits of higher winter pricing. As you can see from last night's release, we've already hedged the fiscal '22 production expected from the wells that will be drilled by the second rig. Because we won't see production from these wells until late in calendar 2021, there is no impact on our fiscal '21 production or earnings guidance. Nevertheless, in spite of the incremental $60 million in capital associated with this rig, we still expect to generate in excess of $100 million of free cash flow from our upstream and gathering businesses. While the increase in activity level differs from the approach taken by many of our peers, the strength of our balance sheet, our methodical approach to hedging, and our significant depth of high-quality inventory allows us to take this step to accelerate value while still generating significant free cash flow. Over time, the second rig is expected to focus principally in our eastern development area, where we have some of the most economic development opportunities in Appalachia. If you recall, our valuation of the Tioga County acquisition was based solely on PDPs and the related gathering assets. We did not attribute any value to the highly economic undeveloped locations. By adding a rig, we are now able to pull forward the development of these properties, further enhancing the value of the assets, including growing throughput on our gathering facilities. Our utility business continues to run smoothly in spite of the pandemic. Our team has done a terrific job adapting to the new reality. Because of the economic backdrop in our service territory, we've seen a drop in large volume commercial and industrial throughput. But thanks to our rig tracking mechanisms in New York, the impact to margin has been manageable. In spite of the pandemic, we had a very successful construction season, replacing over 150 miles of older pipe on the system. More than two-thirds of the spending associated with the program will be captured in our system modernization tracking mechanism. Taking all this together, our outlook for earnings and cash flow growth is strong. As a result of the improved outlook for natural gas prices, we're revising our earnings guidance up to $3.70 at the midpoint, an increase of more than 25% over our fiscal 2020 results. Despite the backwardation of the natural gas curve, as we look to fiscal '22, the increased activity at Seneca combined with the expected in-service date of the FM100 project and the continued growth in our utility segment are all expected to drive further earnings growth. Switching gears, in September we published our initial corporate responsibility report. This was an important step in furthering our ESG disclosures and highlighting our ongoing initiatives, continuing the course we've been on for a number of years. Over the past two decades, we've made significant investments to modernize our natural gas distribution, transportation, and storage facilities. This has significantly reduced emissions across our system. For example, relative to 1990 levels, our utilities EPA sub part W emissions are down by over 60%. We recognize the importance of reducing the global carbon footprint, and we continue to find ways to further reduce our own emissions profile as we grow our business. This is perhaps most evident on the Empire North Project where we installed our first electric motor drive compressor station, which virtually eliminates combustion emissions from those operations. We also continue to look for ways to incorporate renewable natural gas into our transportation and distribution systems. This past year, we built our systems' first interconnect with an anaerobic digester facility. All of these initiatives highlight how natural gas will continue to be part of the long-term energy solution. In closing, I'm excited about the future for National Fuel. 2020 was a year of challenges, but also one of opportunity. We've taken several critical steps that have strengthened the company and positioned it for near-term growth. When we look to fiscal '22 and beyond, we expect to generate consistent, meaningful cash flow at current strip pricing. This should more than cover our growing dividend and further improve our already strong balance sheet, giving us the flexibility to pursue additional growth opportunities as they arise. With that, I'll turn it over to John for an update on our upstream operations.

Thanks, Dave, and good morning, everyone. Seneca had a strong fourth quarter. We produced 67.3 Bcfe, an increase of around 14% compared to last year's fourth quarter. Despite low in-basin natural gas prices, which led us to voluntarily curtail about 6 Bcf, we achieved our largest quarterly production ever. For the year, we curtailed 17 Bcf, and annual net production came in just over 241 Bcfe. This new fiscal year high for Seneca was supported by our development program and the impact of our recent acquisition. For the year, capital expenditures excluding the acquisition ended up at around $384 million, a reduction of approximately $108 million or 22% from the prior year. Expenses on a per unit basis were down 8% from last year and were all within our fiscal 2020 guidance ranges. Proved reserves increased by 359 Bcfe or 12% and to just under 3.5 Bcfe, with the increase largely driven by our acquisition during the fourth quarter. Proved developed reserves now make up approximately 84% of total reserves. As we discussed last quarter, we have updated our Marcellus and Utica development type curves and consolidated economics by producing area, and these are included in our Q4 investor presentation. As a result of our recent acquisition, we now have substantial inventory of both Utica and Marcellus drill locations in Tioga, and our inventory has expanded to approximately 300 locations in the EDA. Moving to the WDA, our near-term development is expected to shift towards the Rich Valley Beachwood development area, which is located immediately to the south of our CRB area where we have focused over the past few years. In the Rich Valley Beachwood area, we have around 100 Utica drill locations, and we'll be able to utilize our existing gathering trunk line. Based on results to date, we believe the economics will be superior to those related to our WDA Utica return trips. As shown on Slide 25 of our investor presentation, we have five pads with 19 wells currently producing in this area. These pads are performing at or above our previously posted Utica type curve. In California, we produced around 555,000 barrels of oil during the fourth quarter, a decrease of around 9% from last year's fourth quarter. Year-over-year oil production was largely flat, with a slight increase of 26,000 barrels. Earlier this year, in order to cut costs as a result of low oil prices, we significantly reduced well work and steam volumes across most of our heavy oil fields. This modestly impacted our production decline rates in these fields during our third and fourth quarters. However, we have recently increased steam volumes to previous levels in some of these fields, and we will continue to permit new wells to allow for a return to drilling in the event oil prices improve. As we are currently planning to defer much of our fiscal '21 development program in California, we have budgeted only $10 million in CapEx. But again if prices rebound, our intention is to increase our activity in California to return to our development programs in Midway Sunset and Coalinga. So moving to our fiscal '21 guidance. As Dave mentioned earlier, in connection with the continued development of the Leidy South and FM100 projects and the deep inventory of highly economic Utica development locations in Tioga as a result of our recent acquisition, we intend to add a second rig early in 2021. This additional rig will focus on our EDA assets in both Lycoming and Tioga. And longer term, we would expect relatively balanced activity between the EDA and the WDA. As part of our recent acquisition, we secured 100 million a day on Dominion with access to Transco's Leidy line and the Leidy South project, providing us with optionality to utilize this capacity from Tioga, in addition to Lycoming and the WDA. First production from the additional rig is expected in early fiscal 2022 to align with the expected Leidy South in-service date, allowing Seneca to utilize this 330 million a day of incremental pipeline capacity to reach premium markets during winter heating season. As a result of adding the second rig for approximately nine months of the fiscal year, we are increasing our fiscal '21 CapEx by around $60 million from our previous guidance for a total of $370 million at the mid-point. Even with the second rig, we’re forecasting a decrease in capital expenditures of around $15 million year-over-year. Most of our production growth in fiscal '21 is forecasted to be up over 30% at the midpoint, which should occur during the first half of the year, with a moderate decline during the back half as we defer completion and flowback activity until the winter season when our new capacity is targeted to be in service. Moving forward, we have 234 Bcf, around 77% of our fiscal '21 East division gas production, locked in physically and financially. We have another 41 Bcf of firm sales providing basis production. So about 90% of our forecasted gas production is already sold. We currently estimate that we'll have around 30 Bcf of gas exposed to the spot market. So as always, these volumes are potentially at risk for curtailment. And finally in California, around 50% of our oil production is hedged at an average price of just over $58 per barrel. And with that, I'll turn it over to Karen.

Thank you, John, and good morning, everyone. As Dave stated at the beginning of the call, National Fuel's operating results for the quarter came in at $0.40 per share, adjusting for items impacting comparability, which was in line with our expectations. Although our upstream business continued to face significant commodity price headwinds, each of our businesses performed well during the quarter, setting the company up for a strong fiscal 2021. One item of note during the fourth quarter was our effective tax rate, which at approximately 15% was much lower than expectations and the prior year. Periodically, we're required to assess the appropriate tax rate to use for recording deferred tax assets and liabilities. Our recently closed acquisition included significant additional firm transportation capacity to market outside of Pennsylvania, which resulted in the forecasted percentage of total revenues allocable to Pennsylvania to be lower in the future. As a result, we were required to remeasure the deferred taxes on our balance sheet to reflect the lower expected state tax rate. Since we are in a net liability position, we recorded the difference as a benefit to deferred income tax expense, reducing our effective tax rate for the quarter. Looking to fiscal '21, we revised our earnings guidance higher to a range of $3.55 to $3.85 per share, or $3.70 at the midpoint. There are a couple of major drivers behind that increase. First, we've increased our NYMEX assumption to $3 per MMBtu and correspondingly increased our in-basin pricing forecast to $2.50 in the winter months and $2.10 in the summer and shoulder months. Second, as a result of the ceiling test impairment charge recorded during the quarter, we now expect DD&A at Seneca to be in the range of $0.60 to $0.65 per Mcfe. This does not include any future impairments at Seneca. Going in the other direction reflecting recent changes in forward crude oil prices, we've reduced our WTI assumption to $37.50 per barrel and made a slight adjustment to our California basis differential, moving it down from 95% to 94% as a result of recent trends we are experiencing in the region. Additionally, while the increase in natural gas prices is a significant benefit to earnings, there are a few natural offsets to this. First, in Pennsylvania, we are subject to the state impact fee. This shows up in our other taxes line item on the income statement and is calculated based upon the age of each well and the average NYMEX gas price for the year. There is a tipping point into a higher tier as we hit the $3 per MMBtu mark. So our updated forecast reflects this increased fee, which is approximately $3 million higher for the fiscal year. Additionally, as John mentioned, we're forecasting a return to normal steam volumes in California. One of the key inputs in our steam generation is natural gas, and with the increase in pricing, we expect modestly higher LOE in the region, which is reflected in the slight widening of our guidance range, now forecast between $0.83 and $0.86 per Mcfe. Overall these adjustments on the cost side are more than offset by the benefit of expected higher realizations on our natural gas production. Further production, as John mentioned, we continue to actively hedge as the forward curve moves up, and now have price protection on 77% of our natural gas volumes. We also have 50% of our crude oil production hedged at $58 per barrel. Moving to the regulated businesses. As a reminder, we are forecasting a return to normal weather at the utility, which will drive a $5 million increase in margin year-over-year. Combining this with $3 million of incremental revenue related to our New York system modernization tracker, we expect to see margin growth of approximately 2% for the year. Going in the opposite direction, we now project O&M to increase approximately 3% to 4%, which is modestly higher than our previous guidance. As a result, we now expect operating income to be relatively flat year-over-year. At our pipeline and storage business, our assumptions remain unchanged for the year. We still expect revenues to be in the range of $330 million to $340 million and O&M expense to increase approximately 4% for the year. Turning to capital. On a consolidated basis, we are in line with our expectations for fiscal '20. Looking to this year, as Dave and John both mentioned, we expect Seneca's capital to increase by approximately $60 million as a result of the increased Appalachian activity level. All of our other guidance ranges remain unchanged. So at the midpoint of our range, we expect spending to be $775 million. Tying everything together, we now forecast our funds from operations to exceed capital spending by $50 million to $75 million on a consolidated basis. This was a great outcome when considering our expectation that we will be constructing a large portion of the FM100 project in fiscal '21, which is the most capital-intensive pipeline project in the company's history. Combining this free cash flow with the proceeds from our timber sale, which we expect to close next month, we don't expect any external financing needs after some seasonal working capital changes. With that, I'll close and ask the operator to open the line for questions.

First question comes from Holly Stewart from Scotia Capital. Please go ahead.

Maybe the first for John, John, I think we've always sort of thought of the maintenance level being like a rig and a half for Seneca, understanding right now there's a higher level of duck inventory. With your larger production base, with the Shell acquisition now being closed, has that moved our assumptions move higher? And then sort of bridging that, should we think about that two rigs in 22 keeping production flat? Or would you expect some growth with that activity?

That's correct. We haven't altered our maintenance level at 1.5 due to the Shell acquisition. It still generally stays within the range of 1.5 to 2. If we were operating consistently at two rigs, we could see annual growth of about 5% to 9%, depending on where those rigs are deployed. The maintenance capital might vary slightly once Leidy South is operational, but for now, we are still maintaining that 1.5 to 2 rig pace.

Maybe it sounds like from Williams' conference call that Leidy South, at least part of that project was coming on a little bit early. Is any of that capacity going to be allocated to Seneca?

Our goal is to target the winter heating season. If it begins earlier than expected, we will need to collaborate closely with Williams to fully understand the implications. Currently, our aim is to ensure that we have adequate production to supply Leidy South as winter approaches next year.

And maybe just one final question for me if I could. It appears that as of yesterday, the cash market remains very weak in the basin. Is there any production that is currently shut in today?

Yes. Actually, October, our spot volumes were pretty much entirely shut in. And you're right. November has started the same way. So spot volumes remain curtailed in Appalachia. At least with respect to us. We are voluntarily curtailing production.

Your next question comes from Brian Singer from Goldman Sachs.

To follow-up on Holly's question with regards to the upstream, can you talk about how the updated economics and type curves across the portfolio impacts your thought process on where within the eastern and western development areas, you place your rigs? And as you bring on a second rig next year, how long does that stay in the east? You mentioned I think it's initially in the east. So I just wondered if you could add any color there.

Yes, absolutely. To address the second part first, it will mainly stay in the east. Occasionally, it may drill one pad or a few wells in the west, but over 90% of the time, it will be in the eastern development areas. We acknowledge that our highest returns come from this region, particularly in Tioga and Lycoming. However, our annual capital allocation is based on our firm transportation portfolio. We will not grow our production base just to supply the local market. Ultimately, our capital allocation is focused on fulfilling our uptick commitments and ensuring our gas reaches the appropriate markets.

Great. And then my follow-up, I think at the end of Dave Bauer's opening comments, you made the point that especially when you look out into 2022, there's more free cash flow and balance sheet flexibility to consider additional growth opportunities as they arise. And I just wondered whether you see those opportunities more organically versus inorganically, and upstream versus midstream?

Yes, we have a substantial amount of acreage that we can develop on our own. However, we also have a strong history of expanding our interstate pipeline network. We remain open to other opportunities that may present themselves. In short, we are capable of growing organically while also being ready to pursue strategic acquisitions if they are sensible.

Your next question comes from Asit Sen from Bank of America.

Thank you for the CapEx guidance for fiscal 2021. Wondering if we could get directionally your comments on fiscal 2022. I know it's early days, but how should we think about the broader contour, the moving pieces by segments? Clear E&P with the addition of rigs, you would have three months of additional drilling capital, but how should we think about completions, and any comments on 2022 directionally?

John, do you want to take the E&P side?

In 2022, as we approach the online date for Leidy South, we anticipate some increased costs related to completing and bringing those wells online. Therefore, 2022 may see a rise in expenses, but we expect that to decrease going forward. We plan to maintain a pace of 1.5 to 2 rigs, which should keep us consistently within the range of 350 to 400.

And I think when you consider the rest of the system, the gathering CapEx over time, I'd expect to be relatively flat. We've made a big investment in that over the years that we're now really able to monetize. As you know, we'll be building FM 100, which is a better than $200 million project. The bulk of that will be spent in 2021. So we'd expect a big drop in pipeline CapEx in 2022. And then on the utility, it's likely steady as she goes, kind of in that $90 million to $100 million area. So when you consider the big jump in revenues that we'll have on the pipeline side of the business and the big growth in Seneca's production, we'd expect to be meaningfully free cash flow positive in 2022 and beyond.

I appreciate the details. On just thinking to 2022, it looks like you have a very solid hedge book for fiscal '21. What does the hedge book look like or protection looks like for 2022? And given natural gas dynamic, what's your hedging philosophy and how you're thinking about sensitivity to gas prices in 2022?

Yes. We've been methodical in trying to build a book for 22. If you look at our release last night in the slide deck, you can see that we've added a fair number of positions there. Our philosophy is to layer in hedges over a 2 or 3 year period, with the goal of being in the two-thirds hedged area prior to the start of the fiscal year. So if you look where we are on fiscal '21, we're better than 75% hedged. We're less than that for fiscal '22. But as we go through fiscal '21, we'll grow that book to be again in that two-thirds area for that fiscal year.

Great, and if I could sneak one more in. Thanks for the color on where the second rig is going to go. But just wondering how you're operating or thinking about operating the recently acquired assets differently from the previous owner? What I'm thinking about is utilization of infrastructure in our supplier chain? Anything operationally that you're doing differently?

The primary advantage comes from water costs. We had access to several freshwater impoundments that we could use, allowing us to start early when we anticipate being active in that region. There was also a produced water storage facility. So far, in just a couple of months, we've noticed significant cost savings by reducing our water expenses. As we work on optimizing the situation, many wells require upgrades to meet our standards, and we will dedicate some time to that, which will also contribute positively. However, at this point, the reduction in water costs is the main factor driving our savings.

Your next question comes from Tim Winter from Gabelli Funds. Please go ahead.

Congratulations on the updated guidance. Could you discuss where the California oil patch aligns with your strategy in light of the changing U.S. energy policy? Additionally, can you expand on the significant free cash flow opportunities in 2022 and outline what you might be considering as the world shifts towards a net zero carbon economy?

I'm sure. John, you want to take the California piece?

California remains a key piece of our portfolio. It generates significant cash flow every year. Even at $40 heading into fiscal '21, we're anticipating free cash flow in the low 30s. As prices increase, that amount rises considerably. However, it continues to be an excellent cash flow generator for us. Hopefully, that answers your question, Tim.

In terms of 2022 and beyond, we will keep our options open. Management and the Board regularly review the strategic direction of the company and consider opportunities across the natural gas value chain. We acknowledge that the world is focused on decarbonization, which could create additional opportunities for us. We will remain vigilant for potential avenues that may enhance value for our shareholders.

Your next question comes from John Freeman from Raymond James. Please go ahead.

This is Gordon. I'm filling in for John. I have a quick question about Slide 54; I noticed that the average CapEx per lot has decreased significantly across the board. I'm trying to understand how much of this decline is due to service cost pricing and how much might be structural and longer-term.

Yes, that's a good point. Much of the decline has been driven by service costs, which have decreased by about 10% to 20% year-over-year. However, we are also seeing lower costs on a per well basis due to increased efficiencies in our Utica program, where we are drilling wells more quickly. This trend is expected to continue and will help us further reduce costs. Overall, the combination of these factors has led to significant improvements year-over-year, particularly on the Utica side, with service costs playing a notable role.

My follow-up question is about the 6 BCF that you curtailed this quarter. Can you provide the split between the EDA and WDA? Also, is this related to the amount of spot exposure you have across the different basins?

That's exactly right. I don't have the breakdown between our three key receipt points. However, we have experienced curtailments in both the WDA in Tioga and Lycoming. I don't know the specifics of how that is divided, but it is indeed related to pricing at each of those points based on our spot exposure. If the prices fall below a certain threshold, we will shut those wells in.

And that was our last question. At this time, I will turn the call back over to the presenters.

Thank you, Mike. We'd like to thank everyone for taking the time to be with us today. A replay of this call will be available this afternoon on both our website and by telephone and will run through the close of business on Friday, November 13. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com. And to access by telephone, call 1800-585-8367 and enter conference ID 5657046. This concludes our conference call for today. Thank you, and goodbye.

Ladies and gentlemen, this concludes today’s conference call. Thank you for participating. You may now disconnect.