National Fuel Gas Company (NFG) Q2 2016 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen and welcome to the National Fuel Gas Company second-quarter 2016 earnings conference call. [Operator Instructions] I would now like to introduce your host for today’s conference, Mr. Brian Welsch, Director of Investor Relations. Please go ahead, sir.

Thank you, Christie 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, Chief Operating Officer of Seneca Resources Corporation. At the end of the prepared remarks, we will open the discussion to questions. The second-quarter fiscal 2016 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 also like to remind you that today's teleconference will contain forward-looking statements. While National Fuel's expectations, beliefs and projections are made in good faith, and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made and you may refer to last evening's earnings release for a listing of certain specific risk factors. With that I will turn it over to Ron Tanski.

Thanks, Brian and good morning everyone. Thanks for joining us for today’s call. As you saw in our earnings release last evening, we had a pretty steady second quarter although earnings were slightly down from last year. Earnings in our utility segment were lower due to warmer than normal weather and the lower commodity prices decreased earnings in our Exploration and Production segment. Dave Bauer will go into the details of the major earnings drivers later in the call. Overall, activities in the field for each of our operating segments moved right along as planned. We are just gearing up for the construction season for our regular pipeline renewal projects in our utility and our Pipeline and Storage segments. At the same time, we’ve slowed the drilling activities at Seneca Resources by moving to a single rig drilling program. Our reduced drilling level combined with getting a partner to fund a large portion of this year’s drilling program has cut our spending to allow us to leave within cash flow for the year. Our current plans allow us to stay to single drilling rig for at least a year before we need to ramp up drilling and completion activities again in order to have enough production to fill the pipeline capacity that will come online in November of 2017, the targeted completion date of our Northern Access pipeline. With respect to our Northern Access project, we received some good news from the Federal Energy Regulatory Commission. At April 14th, FERC issued its notices schedule for environmental review for the project and it confirmed their intention to develop an environmental assessment or EA for the project and announced the July 27, 2016 target date for the EA. Now that fits within our timeline for November 2017 in-service date. The other recent news on the regulatory front is the denial by the New York DEC of the Federal Water Quality Certification for the Constitution Pipeline project in Southeastern New York. We submitted our own permit filings to the New York DEC, the Pennsylvania Department of Environmental Protection and the U.S. Army Corps of Engineers for our project just last month. We delayed our filing by three months after a number of pre-filing meetings with the staff of the DEC in order to make sure that our application was complete and address their stated concerns. Based on those pre-filing meetings and gleaning what information we can from the Constitution denial letter, we feel our application is in pretty good shape. A big plus for our project is that more than 75% of the pipeline route will be co-located along existing utility corridors. We also believe that we worked well with the DEC in the past. We already owned and operated thousands of miles of pipeline assets in the state and during our ongoing maintenance and renewal of those lines we've dealt with them on a regular basis, addressing many project specific issues. Suffice it to say that we are confident that our project will continue to move along. On the federal rate regulatory front, our team has been busy filing the required cost and revenue study for our Empire Pipeline and answering interrogatories from FERC staff regarding the filing. The schedule is set out by the administrative law judge is a target completion date for the proceeding is set for February of 2017. So, we will keep you posted in future calls if anything major happens in that case. Switching to our utility and state rate regulation, our utility rate team filed a request for a rate increase in New York yesterday. This is the first rate increase request the utility has made since early 2007. The filing supports a $41.7 million increase in base rates, an increase of approximately $5.75 per month for an average residential customer. As is typical in the New York rate proceeding, any new rates would not become effective for 11 months. So, we wouldn’t expect any earnings impact until the second half of next fiscal year. We have a pretty clear line of sight through the end of this fiscal year with respect to our earnings projections and you can see that we've tightened up our earnings guidance range. With respect to our oil and gas production, we are well hedged for the remainder of this fiscal year and next fiscal year. And as you can see in the back pages of our earnings release, we are continuing our normal practice of layering in hedges for our oil and gas production as commodity prices in the futures market for our fiscal 2018 and beyond have begun to firm up. We see the market getting more bullish on commodity prices in the out years as production volumes have started to level off and the rig count stays low. For the foreseeable future, we will continue to watch our spending, protect our balance sheet and work to get our Northern Access pipeline build that will deliver Seneca’s production to an attractive pricing point. Now, I will turn the call over to John McGinnis, who will be stepping into the role of President at Seneca, when Matt Cabell's retirement becomes effective next week.

Thanks, Ron, and good morning everyone. For the fiscal second quarter, Seneca produced 39.2 Bcfe, which suggest over a Bcf more than we produced in our first quarter. In Pennsylvania, we curtailed approximately 9.1 Bcf of potential spot sales due to low prices and as a result, no spot gas was sold during the first half of our fiscal year. In April, however, prices have actually improved to the point but we have intermittently produced into the spot market at both our Tennessee and Transco receipt points. Though not a large volume totaling just over a Bcf, this was the first time we have sold meaningful spot volumes since December of 2014. In Pennsylvania after beginning the year with three rigs, we have now dropped to a single rig as of March. We plan on keeping this rig active for the remainder of the year to ensure we have sufficient inventory of DUCs to help fill Northern Access now scheduled to be online late next year. We have also reduced the activity level related to our completions crew to daylight-only operations. At this reduced pace, we typically complete five to six stages per day, which allows us to continue to recycle all of our produced water and avoid costly water disposal. Even with our frac crew operating at half pace, we continued to drop our well costs. For the first half of 2016, our development program has averaged under $5 million per well for a 7,400 foot lateral, which equates to costs of around $675 per foot. The key drivers for this continued drop in costs include the impact of the new frac contract executed in September of 2015 and a significant reduction in water costs. We now average less than a dollar per barrel in water costs, compared to about $3 per pad early in our development program. Moving now to the Utica/Point Pleasant, we have drilled and completed our first Clermont area at Utica horizontal at an estimated cost of just over $7 million. This well was drilled with a relatively short lateral length of 4,500 feet to better understand productivity on a per foot basis. Once we have completed all of 11 wells on this pad, 10 of which are in the Marcellus, we will bring this pad into production later this summer. The rig has recently moved to a new pad also in the Clermont area where we are currently drilling our second Utica well. This well is scheduled to be tested early in 2017. On the marketing front, when the opportunity arises, we continue to layer in fixed price sales and firm sales tied to financial hedges. This has allowed us to slowly grow production and realize acceptable pricing during an exceedingly difficult period for commodity prices. For the remainder of our fiscal 2016, the vast majority of our natural gas production forecast around 64 Bcf is locked in both physically and financially at an average realized price of $3.20. This $3.20 is net of firm transportation. We also have an additional 4 Bcf of basis protection and with the recent improvement in futures pricing, we are actively pursuing additional opportunities to add to our physical sales portfolio and hedge book. In California, production was nearly flat quarter-over-quarter, even though we have significantly cut our spending in California this year. We're targeting to spend just under $40 million in 2016, almost a 30% reduction in compared to last year and half of what we spent just two years ago. All of our development activity is focused in Midway Sunset and will remain so until prices rebound. As a result of our recent farm-ins, however, we believe we can keep production flat to slightly growing over the next couple of years, even with these capital cuts. Thus far in 2016, we have cut E&P capital expenditures by almost 70% compared to 2015 levels to a forecasted range of $150 million to $200 million. Even with these cuts, we expect to grow our production slightly this year and maintain our DUC count ahead of Northern Access in-service date. The key drivers in achieving this result include our recent joint development agreement with IOG, dropping to a single rig and moving to daylight-only frac operations in Appalachia, combined with again, a significant reduction in our California capital expenditures. I’d like to now turn the call over to Dave Bauer.

Thanks, John. Good morning, everyone. Excluding the ceiling test charge, earnings for the quarter were $0.97 per share, down $0.05 from last year. The unseasonably warm weather in our service territory relative to last year's record cold, lowered earnings by a combined $0.11 in our utility and Pipeline and Storage businesses. Meanwhile, our ongoing focus on cost control across the system helped to offset the continued weakness in oil and gas prices, which lowered earnings by about $0.25 per share. All told, considering the twin headwinds of weather and commodity pricing, both of which are largely beyond our control, the second quarter was a good one for National Fuel. Seneca's production was up nearly 10% over last year's quarter and 3% on a sequential basis. This increase is largely attributable to Seneca's firm transportation capacity and associated firm sales related to the Northern Access 2015 project, which was placed in service late in calendar 2015. As a reminder, this was a joint project between our NFG Supply Corporation subsidiary and Tennessee Gas Pipeline designed to move a 140,000 dekatherms per day from our WDA acreage to the Canadian border at Niagara. For the quarter, this project contributed over $3 million in revenues to our Pipeline and Storage segment. In addition to benefiting Seneca and Supply Corp, the increase in Seneca's production combined with our partner IOG's share of the volumes from the joint development wells also helped our gathering business where revenues were up by $4.2 million or nearly 25%. Controlling operating costs was a focus across the system and we saw excellent results during the quarter. At Seneca, per unit LOE was $0.96 per Mcfe, down $0.07 from the first quarter. Most of this decrease was attributable to our California operations. In light of lower oil prices, our team has kept a tight lid on expenses, limiting our spending to only highly economic work-over activity and to areas that are critical to the safety and integrity of our assets. Also, lower natural gas prices caused steam fuel cost to be lower than we expected. In Appalachia, lower water disposal costs were also a factor. As John said, Seneca is now reusing almost 100% of our produced water. Road maintenance expense was also lower due to the relatively mild winter. Given all of these factors, we now expect our full-year per unit LOE rate will be in the range of $0.95 to a $1.05 per Mcfe, down $0.05 from our previous guidance. Seneca’s per unit G&A expense was $0.49 per Mcfe. During the quarter, Seneca implemented a reduction in force that trimmed our staffing complement by about 10%. As part of that effort, we paid out severance costs of about $1.5 million, which caused Seneca's per unit G&A to be about $0.04 higher than it otherwise would've been. We'll start to see lower personnel costs in the second half of the year. Per unit G&A for the rest of the fiscal year should be in the range of $0.35 to $0.40 per Mcfe. At utility, O&M costs were down over $5 million from last year. About a third of this decrease was caused by lower bad debt expense. A combination of historically warm weather and exceptionally low natural gas prices caused our customers winter heating bills to be the lowest they've seen in decades and has had a meaningful impact on our bad debt expense. The remainder of the decrease was caused by a variety of factors, including lower maintenance expense that was the result of the mild winter and lower pension and personnel-related expenses. In the Pipeline and Storage segment, revenues were up just about a $1 million from last year. While this may seem light, given the projects that were placed in service in the first quarter of the fiscal year, the swinging weather year-over-year had a significant impact on revenues from short-term firm services which decreased by approximately $5 million from last year. We expect larger favorable variances in revenue for the last two quarters of the year and still expect revenues in the segment to total between $300 million and $310 million for the full year. Looking to the remainder of the year, we are tightening our earnings and production guidance ranges. Our new earnings guidance while unchanged at the midpoint is a little tighter at $2.80 to $2.95, excluding ceiling test charges. Seneca's updated production forecast is now a 158 to a 175 Bcfe. We up the low end of our previous guidance range of 150 to a 180 Bcfe to reflect new firm sales that were done this quarter, as well as some minor changes in our operations schedule. We lower the high end to reflect curtailments from the second quarter. As in prior quarters, the difference between the high and low end of our production range is driven entirely by curtailments. The low-end assumes we curtail a 100% percent of our spot production while the high-end assumes we have no curtailments. While we didn’t have any spot sales during the first six months of the year, as John mentioned we’ve sold about a Bcf spot sales in April which is encouraging. We have also made a modest change to our NYMEX natural gas price assumption which is now $2.15, down $0.10 from our previous guidance. Our oil price assumption is unchanged at $40 a barrel. We are well hedged for fiscal ‘16 for the remainder of the fiscal year and assuming the midpoint of our production guidance, we are about 80% hedged for natural gas and 55% for crude oil. Therefore, any changes in commodity prices should have a relatively modest impact on our cash flows. We continue to actively pursue incremental hedges in firm sales to lock in the economics of our program, as we grow into the volumes that are required to fill the Northern Access and Atlantic Sunrise projects. Just recently, we added a modest layer of Dawn and NYMEX-based hedges for 2018 to 2021 time period at about $3 per MMbtu. Consolidated capital spending for fiscal ‘16 is expected to be in the range of $445 million to $545 million, down $20 million from our previous range. Substantially, all of the change is related to the timing of spending between 2016 and 2017. Details of capital spending plans by segment are included in the new IR deck on our website. From a liquidity standpoint, we continued to be in great shape. Assuming the midpoint of our earnings and capital spending guidance, we expect we are very close within cash flows for the fiscal year. With that I will close and ask the operator to open the line for questions.

Thank you. [Operator Instructions] Our first question comes from the line of Kevin Smith of Raymond James. Your line is open.

Thank you and good morning, gentlemen.

Hi, Kevin.

John, congrats first on joining the earnings call but with that, I will kick off the question. Can you discuss current shut-in volumes in the Marcellus and maybe how much you’ve been able to sell to spot since differentials have been tightening?

Say that again. I’m sorry, you are breaking up.

I apologize about that. Can you discuss current shut-in volumes in the Marcellus and then maybe how much you’ve been able to sell into spot and what that’s looked like over the last month?

Yes. We’ve sold essentially nothing in spot for the second quarter, a little over a Bcf in April because prices had improved upon we could, both on Tennessee and Transco sell into the spot market. But recently though pricing has dropped off again so we are shut-in. But I think we are about $40 million to $50 million of available spot in our Tioga area and a little over 100, 120 in Lycoming if I remember correctly.

Got you. That’s helpful. And would you mind providing some more details about the new firm sales agreements? Basically what’s the length of those contracts?

Yes. Sure, Kevin. This is Dave. We did -- well for fiscal ’16, we did about 5 Bcf of additional firm sales and then looking out into ’17, ’18, ’19, we did a bunch of fixed sales ranging, call it from 10 to 30 Bcf per year, kind of in the high but just under $2 range.

Okay. Great. That’s extremely helpful. That’s all I had. Thanks.

Sure.

Thank you. [Operator Instructions] And we do have a question from the line of Holly Stewart of Scotia Howard. Your line is open.

Good morning, gentlemen.

Hi, Holly.

Maybe just one on sort of what you see on the capacity market in Northeast PA. I mean the rig count, I think in Northeast PA has dropped to maybe three now. Just curious if you’ve seen a pickup in capacity being offered out there and sort of what you are looking at in terms of volume, maybe a pickup in order to bring some of that volume on -- some of your shut-in volume online?

I think it’s actually down to two rigs now. I was just looking at that the other day. It continues to fall. We haven't seen any help on the capacity side as of yet. Whether producers are bringing on wells as they had shut in, we just -- we haven't seen additional, at least significant additional capacity available in that part of the state.

Okay. Okay. Great. And then maybe you could just help us think about the progression of production for the next few quarters, give us your wells turned to sales during this past quarter and then sort of the remaining target for the year?

Yes. I can give you our target for the year. I can't tell you what the second quarter was. We are targeting for fiscal ‘16 about 50 wells to drilled, 45 to be completed. We will end the year with about 60 to 65 DUCs. And in terms of the well count, back half of the fiscal year, we are looking at bringing on an additional about 25 wells.

Okay. Great. Thanks, John.

Yes.

Thank you. And our next question is from Becca Followill of U.S. Capital Advisors. Your line is open.

Hi guys.

Hi Becca.

You talked a little bit. I know you’ve had the one-rig program. What does it take to start to ramp that back up again?

Well, part of why we want to keep a single rig going is that it keeps in the half, sort of the daylight-only or what I call a half frac crew is that it keep our DUC count relatively flat. And so really to ramp-up, it doesn't really -- we are not going to necessarily need to bring in an extra rig. What we will end up doing is we will go to 24-hour frac crew and potentially two frac crews, obviously -- depending on the ops and the in-service date related to Northern Access. So really it’s more to bring in an additional frac crews as opposed to a rig count.

Thank you. And then on the water permit, what is the timing you're expecting to get that permit from the DEC?

Well, assuming that it takes the full year, Becca, it would be the beginning of March of 2017. Are you getting that?

Do you think it will take the full year?

I think we've -- that's kind of what we have planned at the outside. We had the luxury of being on 98% of the route sites, so that we had what we think was a very, very complete application. Whether that state will move it along any faster, we can’t guarantee. We just know that there is a year timeframe from filing. So that’s what we are planning on.

Thank you. And then lastly on the Empire open season. I think there was something in the slide deck about precedent agreements were tendered in February. So, can you talk a little bit about that expansion?

Well, we are working through that. We did have a good open season for the Empire North project. It was -- to a certain degree it was oversubscribed because certain parties tried to put together different combinations of transportation routes and so that's really what we’re working through, Becca, in order to kind of rationalize the best flows and the best combination and get that worked in to precedent agreements. We don't have any of them signed just yet and we just continue to work away at that.

Okay. Thank you.

Thank you. And our next question is from Chris Sighinolfi of Jefferies. Your line is open.

Hey guys. Good morning. This is actually Chris Dillon [ph] on for Sighinolfi. How are you?

Hi, Chris.

Good, Chris.

I was just wondering if you could provide an update on the JV and whether or not you feel like the partner is likely to exercise the option there as we approach that date and what I guess, kind of conversations you are having and what might be under consideration from their side?

The relationship is great. We drilled 30 of the 42 wells. With those pads just -- they are early. They are just now coming online. Our costs have been about 10% or more down which they are pleased with. We have conversations around entering into the second tranche, but really that's a decision that they are going to make in July and that’s really all I can speak to right now on that.

Okay. That’s fair. That was it for me. Thanks guys.

Thank you. And that does conclude our Q&A session for today. I would like to turn the call back to Mr. Brian Welsch for any further remarks.

Thank you, Christie. We would 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 6, 2016. To access the replay online, please visit our investor relations website at investor.nationalfuelgas.com. And to access by telephone call 1-855-859-2056 and enter the conference ID number 84814628. This concludes our conference call for today. Thank you and goodbye.

Ladies and gentlemen, thank you for participating in today’s conference. This does conclude today’s program. You may all disconnect. Everyone have a great day.