National Fuel Gas Company (NFG) CEO Dave Bauer on Q2 2020 Results - Earnings Call Transcript
National Fuel Gas Company (NYSE:NFG) Q2 2020 Earnings Conference Call May 1, 2020 8:30 AM ET
Ken Webster - Director IR
Dave Bauer - President & CEO
John McGinnis - President, Seneca Resources
Karen Camiolo - Treasurer, Principal Financial Officer
Conference Call Participants
Tim Winter - Gabelli
Chris Sighinolfi - Jefferies
Gordon Loy - Raymond James
Holly Stewart - Scotia Howard Weil
Ryan Levine - Citi
Ladies and gentlemen, thank you for standing by, and welcome to the 2020 Q2 National Fuel Gas Company Earnings Conference Call. [Operator Instructions]
I would now like to turn the call over to your speaker today, Ken Webster, Director of Investor Relations. Please go ahead.
Thank you, Amy, 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 second quarter fiscal 2020 earnings release and April 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 Citi Global Energy and Utilities Conference later this month. If you plan on attending, 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.
Thanks, Ken. Good morning, everyone. Past few months have been anything but ordinary for National Fuel as we adapted our operations to address the COVID-19 pandemic. From an earnings perspective, the continued drop in commodity prices weighed on our results, leading to the noncash write-down of our oil and gas properties and lower realizations on our production. Warmer weather in our Pennsylvania service territory also impacted the utilities earnings for the quarter.
On the positive side, our midstream businesses had a great quarter on the strength of Supply Corporation's recent rate settlement and solid operational execution and well results at Seneca drove record throughput on our gathering system. In short, other than pricing and weather, the quarter was right in line with our expectations and was another great example of the benefits of our integrated diversified business model. The COVID-19 pandemic has obviously impacted the way in which we operate. Each of our businesses has been deemed an essential service and continues to operate as such. But we've taken considerable steps to limit the potential exposure of our workforce, customers and communities in which we operate.
The safety of our employees and customers is our top priority. Any employee who can work from home is currently doing so. Those who cannot work from home, and given the nature of our business, there's a large number who can't. We're employing both social distancing and personal protective equipment to make sure they stay safe. We're committed to our employee group and have not implemented any furloughs or workforce reductions. Our employees have really stepped up to the challenge. And because of their exceptional efforts, the business is running smoothly, all things considered. I'm very proud of our employee group and say thank you to them for everything that they're doing during this crisis. Our regulated businesses haven't seen any meaningful financial impact from the pandemic. Day-to-day operations of the utility business have been perhaps the most impacted by the pandemic, given that it's the part of the business that has the greatest interaction with customers. We've suspended all non-emergency customer-facing work; we're still making reasonable progress on our annual modernization program in both states.
Overall, we expect capital spending will be lower by about $10 million at the utility as a result of the pandemic. At this point, we haven't seen a major change in throughput. Industrial volumes are down modestly due to plant shutdowns, but at this point, we're not overly concerned. We're very focused on uncollectible expense given the economic backdrop in our service territories. Thankfully, customer bills are relatively small as a result of the warm winter and low gas prices and should get lower as we move into the spring and summer. At this point, there isn't a discernible downward trend in customer payments, but this is an area we'll continue to monitor. Our pipeline and storage operations haven't been significantly impacted by the crisis. Our pipeline facilities and projects are generally located in pretty remote locations, and between social distancing and proper PPE, the workforce and construction crews on-site are able to stay efficient. Construction is well underway on the Empire North project and should be completed by the end of our fiscal year.
As a reminder, that project will add $25 million in annual revenues. You'll note in last night's release that our capital spending guidance at the pipeline is down $12.5 million at the midpoint. Now this is largely due to delays in some smaller modernization projects at Supply Corp. Supply Corporation had a good outcome in its rate case proceeding. You'll recall, we filed the case last summer to satisfy the comeback requirements of our previous rate settlement. In early February, parties reached a black-box settlement that provides for a 2-phase increase in supplies rates. First phase, which was effective February 1, 2020, increases supply's annual transportation and storage rates by approximately $35 million. This increase was driven in large part by higher plant balances from supplies modernization program and higher operating costs. In addition, supplies rates reflect higher depreciation and negative salvage rates, which accounted for approximately $10 million of the $35 million rate increase.
Second phase, which will be effective the later of the in-service date of the FM100 project for April 1, 2022, that will increase supplies rates by another $15 million to reflect the modernization component of that project. Under the settlement, we agreed to a four year moratorium on new rate filings, and it will come back after year five if no rate case is filed. Overall, I think this is a good settlement and that it balances our need to recover the cost of system modernization with our customers' desire for predictable rates. The FERC settlement Judge has certified the rate agreement, and we're now waiting on final approval from the FERC commissioners, which should come in the next month or two.
Switching to the E&P business, Seneca's drilling and completion crews continue to operate in Pennsylvania. Seneca is currently at two rigs, but will drop one this summer and remain at that level through fiscal 2021. We're reducing production guidance by five Bcf to reflect recent pricing related curtailments, our capital spending is also coming in lower, which mitigates the impact on Seneca's cash flows. Oil prices are a concern, but we're well hedged at prices above $60 a barrel for 2020.
Our drilling program in California is complete for the year. And looking to fiscal 2021, absent a major recovery in prices, we expect a significant cut in capital and O&M spending in California next year. Overall, the business continues to be in good shape. Our regulated businesses continue to perform well, and thanks to projects, like Empire North, are positioned for growth into fiscal 2021. Commodity prices have weighed on Seneca's results, but looking at the NYMEX futures curve, there's cause for optimism in fiscal 2021 and beyond.
With that, I'll turn the call over to John for more on Seneca's program.
Thanks, Dave, and good morning, everyone. While pricing-related curtailments put a damper on Seneca's results, operationally, we're very pleased with our business and where gas prices appear to be heading. Seneca produced 59.8 Bcfe during the second quarter, an increase of 23% compared to last year's second quarter. And even though we voluntarily curtailed almost three Bcf this quarter as a result of low natural gas prices, we still saw an increase in production quarter-over-quarter with solid results across all of our operating areas.
We are currently operating two rigs in Pennsylvania but as discussed last quarter, in an effort to moderate capital spending given current commodity prices, we will drop to a single rig this summer. We're currently drilling a 10-well pad in the WDA and will drop this rig once we're complete. In terms of our WDA Utica development program, we brought online our second pad located in the Beechwood Rich Valley area this quarter. We drilled six wells off this pad, and the results are outperforming the type curve by about 30% and are comparable to our first pad in this area. It's interesting to note that as we move further south and deeper into the basin, we have brought online our two best-performing Utica pads in the WDA.
As we move forward with our development program, production from this area is expected to be utilized to fill our Leidy South firm capacity, which is still on target for an in-service date in early fiscal '22. The next pad that will be brought online in this area is a four well pad scheduled for late in our fiscal fourth quarter. In California, we produced around 605,000 barrels of oil during the second quarter, an increase of 7% over last year's second quarter. This increase is primarily driven by our recent drill activity at our Pioneer and 17N properties located within Midway Sunset in Kern County and Coalinga and Fresno County. As a result of the recent collapse in oil prices, however, we have implemented measures to reduce our operating expenses without negatively impacting the long-term performances of each field. Fortunately, with approximately 72% of our oil production hedged for the remainder of the year at an average price of around $62 per barrel, we are in good shape to weather this recent downturn in oil prices.
As we look out to the remainder of fiscal 2020, we expect oil production to be flat to modestly lower when compared to our second quarter results. In terms of guidance, we are now lowering our production forecast to range between 230 to 240 Bcfe, down around five Bcf at the midpoint, due entirely to our second quarter curtailments of 2.7 Bcf and additional curtailments of around two Bcf in April. As usual, we forecast no additional curtailments for the remainder of the fiscal year. We're also lowering our CapEx guidance to range between $375 million to $395 million, a decrease of $7.5 million at the midpoint.
We continue to see reductions in service costs associated with the decline in industry activity as well as continued efficiency gains in the drilling of our Marcellus and Utica wells in the East. We are well positioned for the rest of the year with approximately 76 Bcf or about 70% of our remaining fiscal 2020 East division gas production locked in physically and financially at a realized price of $2.16 per Mcf. We have another 25 Bcf of firm sales providing basis protection, so over 90% of our remaining forecasted gas production is already sold. Interestingly, the recent collapse in oil prices have been a huge lift for natural gas prices moving into the next two years. And as a result, we have significantly increased our hedge position over the next couple of years, the details of which are reflected on Page 57 of our investor presentation.
And finally, I'm very pleased with how our Seneca team has conducted business through the impact of the coronavirus. We have been able to work effectively from home since our offices are closed, and our operations team has done a great job continuing to operate successfully and safely in the field during this period.
And with that, I'll turn it over to Karen.
Thank you, John, and good morning, everyone. As you read in our release, we reported a GAAP loss of $1.23 per share, a decrease of $2.27 per share from last year's second quarter. This was primarily driven by $1.49 per share charge related to a ceiling test impairment on our oil and gas properties as well as a $0.66 per share charge tied to a state deferred tax asset valuation allowance in our non-regulated segments.
After adjusting for these charges and another small unrealized loss on certain benefit plan investments, we reported operating results of $0.97 for the quarter. This was a decrease of $0.10 per share from the prior year. The impact of lower commodity prices realized on our oil and gas production and warmer weather in our utility more than offset the impact of higher Seneca natural gas production, throughput at the gathering segment and the successful settlement of our Supply Corporation rate proceeding.
The earnings release does a good job describing all of the other drivers, so please refer to that for more details. Turning to our forecast, we are revising our fiscal 2020 earnings guidance to a range of $2.75 to $2.95 per share, representing a $0.20 decrease at the midpoint. It's important to note that our updated guidance excludes items impacting comparability, including the valuation allowance and ceiling test impairment recorded this quarter as well as future impairments we expect in the coming quarters. Our forecast also does not assume any impact of future price-related production curtailments. In addition to incorporating results from the second quarter, we've made other changes to our assumptions.
We continue to assume NYMEX natural gas prices averaged $2.05 per MMBtu and now project Appalachian spot pricing averages $1.65 per MMBtu for the remainder of the year. On the oil side, we've made steeper reductions to our forecast with WTI assumed to average $22.5 per barrel for the remaining six months. We've also reduced our California oil differential at Midway Sunset from 104% to 90%. As it relates to Seneca's per unit DD&A rate, our current guidance reflects the impact of the ceiling test impairment recorded this quarter, but does not incorporate any future ceiling test charges. We will revise this rate each quarter if and when we record additional impairments.
There are two other changes related to items from this quarter that need to be extrapolated out for the remainder of the year. First, the settlement of our supply rate case is leading to higher forecasted revenues for the fiscal year. We now assume revenues will be approximately $305 million in the pipeline and storage segment. However, this will not all flow through to the bottom line as we also agreed to higher depreciation rates as part of the settlement. With the higher depreciation rates, we now expect our underlying depreciation expense in this segment to increase approximately $2.5 million per quarter relative to our prior forecast.
Lastly, as it relates to guidance, the assessment of the state deferred tax assets that led to a valuation allowance this quarter will also drive a higher effective tax rate. Additional state NOLs and tax credits generated during the year are subject to the same evidentiary test as those that are on the balance sheet. Given the evidence as of today, we will not be able to record the benefit of the newly generated NOLs and credits until the evidence supports utilization of these tax benefits. This will lead to an increase in our effective tax rate, which we now expect to be 26% for the full year.
Let me touch briefly on the impact of COVID-19. Outside of the decrease in oil prices, there were no major effects during the quarter. As we look forward, however, we expect a modest impact in our utility segment as it relates to operating costs and uncollectible expense. On the operating expense side, the principal driver is the slowdown in construction activity, which is typically ramping up at this point in the year as the weather breaks. Our workforce shifts from operating expense activities in the winter months to capital-related work in the summer. But given the slowdown in customer-facing capital work and our commitment to not furloughing any employees, we are expecting more of our labor costs to be expensed over the next several months.
In addition, we are projecting higher uncollectible expenses as a result of larger unemployment and the temporary help in customer collections. While we are forecasting higher uncollectible expense, we have not experienced any discernible trend in customer payments that might indicate significantly larger-than-normal write-off. We will continue to closely monitor customer payment trends over the coming quarters. With respect to capital, we are reducing the midpoint of our capital guidance range by $30 million to a new range of $680 million to $740 million.
While the impact of COVID-19 on customer-facing capital work is driving the $10 million decrease at the utility segment, the other three segments are flat to lower for the year as a result of continued focus on cost control and updated timing on certain pipeline modernization projects. With our revised earnings projections and lower capital spending planned for the year, we continue to expect our funds from operations and capital expenditures to be roughly in line with each other.
Adding on our dividend, we expect a financing need of approximately $150 million for the full year. We started the year with nearly $700 million available of liquidity under our revolving credit facility, and we plan to use that as the first source of financing.
With that, I'll close and ask the operator to open the line for questions.
Thank you. [Operator Instructions] Your first question comes from the line of Tim Winter with Gabelli Funds. Your line is open.
Good morning, gentlemen. I was wondering if you could talk a little bit about how you think about the dividend as we go into, I think in the press release, you're talking about maybe some more oil and gas write-offs, given prices and the lower production guidance. How do you guys think about the dividend?
Yes. Tim, we generally view the dividend in light of our regulated earnings. So if you look at the utility and the pipeline, there, we're not we're actually expecting an increase in earnings in the years to come because of projects like Empire North and the continued modernization of our system. So I feel good about the dividend that the regulated earnings will be there today and, in the future, to cover it.
Do you expect much of an impact from what you can see now in the future write-offs as far as the equity ratio on the balance sheet?
Yes. Well, if we have continued impairments, which will be dependent on pricing, we'd expect the equity component to drop into the, call it, mid- low 40s potentially, but all that's going to be dependent on commodity prices and how big the impairments end up being.
Okay, thank you guys.
Your next question comes from the line of Chris Sighinolfi with Jefferies. Your line is open.
All right. Good morning, everyone. Thanks, guys, thanks for the update. I do have a couple of questions, Dave. I think first, if I could just pivot to John. John, I think you've talked obviously, we saw a deceleration of planned Seneca activity over the winter. It was a different pricing environment then. I know you've talked historically about certain price points at which you'd contemplate reaccelerating activity. If I look at your fiscal 2021 strip, I think it's now about $2.75, but then faces a backwardation in subsequent follow-on year.
So, I guess I'm just wondering how you're thinking about both on the completion side and perhaps a resumption of drilling activity? What that change in pricing dynamics between the last call and this call means? What the backwardation means? And what FM100 capacity means?
Yes. Thanks, Chris. It's funny you asked that because I've been talking to Dave quite a bit about it. As I think we've said before, we would certainly consider adding back in a rig another rig, if we see prices get to about that $2.75 plus range. But we also have to be able to lock in acceptable hedges over multiple years in order to support that increased activity level. Right now, we don't see that in fiscal '22 or fiscal '23. But certainly, in the $2.70 price range that starts to we begin at least to have a conversation around it. But right now, the out years are just not there; we have around 25 DUCs currently.
And again, if prices get to a point where we're comfortable going into next year and in the out years, we can certainly accelerate some of those completions as well.
Okay, that's helpful. And when you had mentioned in the release and I think you mentioned earlier on the call, curtailments, I think it was 2.7 in the last quarter. And I think you said two Bcf in April. Just curious, is that spread across the acreage? Or is that concentrated in a particular area of your development?
Yes. Most of our curtailments, Chris, are in the EDA, both the Lycoming and in Tioga. Typically, the CRV area has a little bit better pricing. It's just been less curtailments there.
Okay. I have a couple more questions. I'm going to ask one more and then I'll hop back in the queue and finish up with others go. But I was just curious, Dave, you mentioned the settlement on Supply Corp. Obviously, pipeline had strong results in the quarter, which you attributed to the settlement. And I saw pipeline revenue, expectation for the year is up versus your prior guidance. Is it sort of safe to assume based on that that the outcome was better than you had maybe thought that it would be? Could you just talk a little bit about that?
Yes. I would say it was within the range of expected outcomes, but maybe towards the higher end of the range. The increase in depreciation rates was likely the area that we hadn't necessarily counted on, but when you consider the overall environment in New York and the lives we have been using in the past and update, we're able to convince FERC staff and the parties that an increase in rates was warranted.
All right, thanks a lot for the time guys.
[Operator Instructions] Your next question comes from the line of Gordon Loy with Raymond James. Your line is open.
Good morning and thanks for taking my questions. I just had a I just want to get an idea of what the thresholds for the Appalachia prices would be kind of before wells are setting? I know that the current strip, obviously, is more optimistic than it was some time ago. But I guess I see on Slide 35 that the cash costs all in for Seneca are about $1.26 per Mcfe, and I'm assuming that, that's Appalachia will be a little lower than that. But I guess, is that a decent assumption?
Yes, absolutely. I don't like to speak exactly to what prices we could curtail to. But essentially, we focus on a price where we'll continue to generate positive earnings on a consolidated basis, and essentially, that's in the $1 something range. And beyond that, I just don't want to get into too much detail on that.
Got it, that's helpful. And then my follow-up is a while back I think you guys had mentioned that your base declines in the Marcellus were probably in the upper teens range and the Utica was a little higher in the mid-20s to upper 20s. And with the decline in activity, I guess this mostly affects the Marcellus, but do you guys have an updated idea of kind of where those base declines are trending?
Yes. Our base declines are when you look at last year going into this year, overall, we're around 23% base declines in Pennsylvania.
That's helpful. Thank you.
Your next question comes from the line of Holly Stewart with Scotia Howard Weil. Your line is open.
Good morning, gentlemen. Karen, yes, good morning. Maybe, John, just to follow-up a little bit on Chris' question, just trying to get a sense for the program in 2021. Is there a sort of a general rule of thumb that we could use for just that kind of a 1-rig program throughout 2021?
Well, like I told Chris, $2.75, definitely gets our attention but until we see recovery in the out years, fiscal '22 and beyond and recovery in terms of volumes that we can effectively hedge, I think we're going to hold to a one-rig case. It's very expensive to add and add rigs and pull rigs off the table. And so I just don't I want to see some continuity before we start doing before, we start adding and continued dropping of rigs.
Yes. So, I was just trying to get a sense of if there was just a sort of a one-rig kind of capital number available?
Yes. It's tough for me to speak to what our CapEx guidance is going to be for next year, but it's going to be roughly in the, I'd say, plus or minus $350 million range. That's a little bit more than what a one-rig case will be because there's some other capital projects that we'll be continuing with, but we're looking at that $350 million plus or minus.
Okay, that's helpful. And then, maybe just thoughts around the California activity next year, just kind of given where we are on oil prices?
Yes. If oil prices stay where they are, California activity will be very low. We've already drilled our portfolio, our development program for this year. If prices stay where they are, we would defer that. We don't have to we're very fortunate in that our California production has very low decline rates. And so if we push out or can defer our capital program for a year, there's a modest increase in decline, but it's something that we can recover over time.
Okay, that's helpful. And then I know previously you'd given some color on just the kind of the cadence of production throughout the quarters of fiscal 2020. And given the shut-ins that happened in the second quarter and then what you're seeing right now for April? Is there any sort of update to that cadence that you could provide, maybe the exit rate higher as a result? I'm just trying to think through the next few quarters?
Yes, the next couple of quarters, the way we look at it right now, Holly, are pretty flat to maybe modestly, a little bit lower, but really, they should be pretty flat.
Okay, that's helpful. Thank you.
Thank you, Holly.
Your next question comes from the line of Ryan Levine with Citi. Your line is open.
Good morning. Can you speak to the regulatory mechanism to get recovery on bad debt expense in the Utility segment and how you're pursuing that?
We don't have a regulatory tracking mechanism, per se, on uncollectible. We have somewhat of a tracker for the impact of gas prices in New York and their impact on uncollectibles. But there isn't a true tracking mechanism, per...
Okay. And then, what are you seeing in terms of load dynamics in the Utility segment since the quarter end? And what are your expectations for your business?
Yes. I mean it's been interesting in that. On the residential side, it was a pretty cold April in Western New York and Northwestern Pennsylvania. So our volumes have actually been up on the residential side. On the large industrial side, we have seen a fall off, call it, in the 5% to 10% range on volumes. So if you put that in perspective, industrial margin is about 10% of the total margin of the company; so on an overall basis, not a dramatic impact on the utility. At least at this point, we'll see as we go through the rest of the quarter and months ahead.
And then can you comment also in terms of how you're managing the expense profile in that segment? It looks like personnel costs ticked up in the quarter. Do you envisioning any type of initiatives to reduce the expense profile?
Well, with the basic shelter in place and lockdown, expenses generally tend to come in, at least the discretionary part, things like travel and other types of material purchases tend to naturally drift down. With respect to managing personnel costs, we do have a business to run, right? So we've got all of our people are working. And obviously, we're charging and collecting rates that are covering those costs.
So we're certainly managing our cost to excuse me, managing our expenses, but the business hasn't had a wholesale change, right, as an essential service.
That's all from me. Thank you.
Your next question comes from the line of Chris Sighinolfi with Jefferies. Your line is open.
Everyone, I have mentioned I had some follow-ups, and I do. John, I appreciate all the thoughts on the development activities at Seneca. I had also wanted to get your thoughts on M&A just given the pricing dislocations and the stress, some of your peers might be feeling you sold Sespe, for example, a couple of years ago, I think. But are investments in California oil of interest if the prices were right and if you continue alternatively on the gas side, you continue to see a backward dated curve that doesn't give you confidence to ramp up activities. Are there any properties that might be of interest aside as you think about filling F100 volume?
Let's start in California. We are definitely interested in adding to our California properties out there. 17N, Coalinga, Pioneer are all examples of that are sort of bolt-ons that we've been able to bring into the fold. And between those, they're producing 800,000 barrels a day. So they've been great adds to our production profile out there. We continue to look. It's tough. Oil has only been down for a very short period of time. So I think there's going to be a bit a hesitancy to move forward with anything very quickly that I think we could agree to, but we're certainly keeping an eye on what's going on out there. And we'd love to be able to get some more assets.
And moving to Pennsylvania, we've talked about this before. We're always looking for opportunities to expand our position in the EDA. And really specifically, those that are near our current operations, and honestly, that we want both the upstream piece and the midstream piece associated with that. So we continue to work that, and we will continue to do that going forward. I know that is a very big answer, but that's where we are.
Well, no, it's still helpful just to get a sense of if you had no interest, you'd say so. So it's I know that opportunities come along and but it takes a willing seller. So that's been one of the struggles.
Yes. I guess as it pertains to that, Karen, Tim asked you earlier about the capitalization structure, given some of the write-downs, what they do to the book equity position. And I know there was a debt covenant back in the day that I think pertain more to total company losses and restrictions on incremental borrowings after, I think it was an annual period or multiple annual periods of loss. But you had written in last night's release about Seneca's specifically having multiple years potentially of losses and that affecting what you were doing with your deferred tax asset. I was just curious if there's any ramification on either one of those items with regard to your capacity for incremental leverage?
And maybe as it pertains to that, can you remind me just where any of the I think the covenants are predicated on debt-to-cap, can you just remind me where those reside?
So, I think the one you might be talking about is the restriction under our 74 indenture where we have to be at a two times interest coverage in order to be able to issue incremental long-term debt. So the ceiling test impairments definitely get into that calculation because it's a book it's based on book operating income. So having said that, we are expecting these ceiling test impairments. They're certainly not going to be the magnitude that we saw back in 2015, 2016 when we kind of were closed out of issuing incremental long-term debt for a period of time.
So having said that, there could be some impact on that, but we're not expecting that in the near term, certainly. So I don't know if that answers your question.
It answers yes, you're right about what I was referencing. I was, frankly, a little confused as to what bond indenture I was referring to, but I remember it being something that was quite some time ago. So as I guess, as we roll forward on a 12-month look back on the strip and as we incorporate new prices, you're going to get ceiling tests, which reduce this down. And I guess my question is, if it triggers what it did in 2015, what is the stay out period of time in which you'd not be able to raise any long-term debt?
So, it depends the magnitude of those and how long we continue to have them, but we'd expect that if there's any impact, it's not in this fiscal year. And if we kind of project out maybe a quarter or two in next fiscal year, that could be have an impact. But I mean, like you said, prices are running up, we've been able to put on some incremental hedges. So that could change what our forecast is on the ceiling test impairments that we're expecting. So if we are out, it's not for a long period, it's not for an extended period of time. We don't have an upcoming maturity. And even under that provident, we're able to refinance any refinancing needs that we have, and that's not until December of 2021.
And I mean, if we're anticipating to be closed out in a couple of quarters of next year, we do still have the remainder of this fiscal year to do something if we felt we needed to.
Yes, for sure. Okay. I appreciate the color. I was remembering that there were certain things that loomed out there that had cropped up a couple of years ago, and I didn't want to lose sight on them, so I appreciate all the color.
Yes. First, the way the covenant works is you look back on a trailing 12-month basis, and you basically have to show positive GAAP earnings. So as you roll through time, if the ceiling test charges were really large, like they were in 2015 and 2016, that can kick us out for an extended period of time. But if they're more modest, like the one we saw this quarter and may see in the future, they roll off pretty quickly.
Okay, that's very helpful. Thanks, everyone.
This concludes our question-and-answer session. I will now turn the call back over to Ken Webster for closing remarks.
Thank you, Amy. 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 3:00 p.m. Eastern Time on both our website and by telephone and will run through the close of business on Friday, May 8. 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 a conference ID number 9439819. This concludes our conference call for today. Thank you, and goodbye.
Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect.
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