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PNM Resources’ (PNM) CEO Patricia Collawn on Q1 2016 Results – Earnings Call Transcript

PNM Resources, Inc. (NYSE: PNM ) Q1 2016 Earnings Conference Call April 29, 2016 11:00 am ET Executives Jimmie Blotter – IR Patricia K. Collawn – Chairman, President and CEO Charles Eldred – EVP and CFO Analysts Ali Agha – SunTrust Robinson Humphrey Anthony Crowdell – Jefferies & Co. John Barta – KeyBanc Capital Markets Lasan Johong – Auvila Research Consulting Operator Good morning and welcome to the PNM Resources First Quarter Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Jimmie Blotter, Director of Investor Relations. Please go ahead. Jimmie Blotter Thank you, Rocco, and thank you everyone for joining us this morning for the PNM Resources First Quarter 2016 Earnings Conference Call. Please note that the presentation for this conference call and other supporting documents are available on our Web-site at pnmresources.com. Joining me today are PNM Resources’ Chairman, President and CEO, Pat Vincent-Collawn, and Chuck Eldred, our Executive Vice President and Chief Financial Officer, as well as several other members of our executive management team. Before I turn the call over to Pat, I need to remind you that some of the information provided this morning should be considered forward-looking statements, pursuant to the Private Securities Litigation Reform Act of 1995. We caution you that all of the forward looking statements are based upon current expectations and estimates and that PNM Resources assumes no obligation to update this information. For a detailed discussion of factors affecting PNM Resources’ results, please refer to our current and future annual reports on Form 10-K, quarterly reports on Form 10-Q, as well as reports on Form 8-K, filed with the SEC. And with that, Pat, I will turn the call over to you. Patricia K. Collawn Thank you, Jimmie. Good morning, everyone, and happy Arbor Day. Thank you all for joining us this morning as we report on the Company’s first quarter performance and take a quick look ahead. I’ll start on Slide 4 with a look at the numbers and our achievements from the first quarter. First quarter earnings were lower than last year but consistent with our expectations. Consolidated ongoing earnings were $0.13 per diluted share, compared with $0.21 per diluted share in the first quarter of 2015. In addition, today we are reaffirming our 2016 consolidated ongoing earnings guidance of $1.55 to $1.76 per diluted share. At PNM, concerted efforts to create a more favorable customer experience continue to pay off despite the challenges associated with high-profile filings such as our current rate proposal. J.D. Power reported the overall Customer Satisfaction Index reached a high point for PNM. I’m particularly proud of our customer service results which came in among the highest in our benchmark peer group. This achievement is the result of the effort and dedication of our employees from departments all across the Company who are focused on being responsive to and meeting the needs of our customers. Our Company has stayed the course, proactively communicating and sharing information that customers need the most. I’m proud of the work we have done. We know there is no silver bullet. It takes countless decisions being made every day on behalf of our customers. I’m confident our strategy is on target and we are doing the right things for our customers. I’m also pleased to say that TNMP has again been recognized by ENERGY STAR for the Company’s successful energy efficiency efforts. TNMP received the Partner of the Year Energy Efficiency Delivery Award for its high-performance Homes Program. The initiative promotes the construction of new ENERGY STAR certified homes and provides financial incentives and other assistance to homebuilders. This honor is on top of receiving ENERGY STAR’s Market Leader Award for the 11th consecutive year. So now let’s turn to Slide 5. Throughout the first quarter, we were preparing for the hearing of the New Mexico Public Regulation Commission regarding our $123 million general rate case. The hearing began on April 11 and after three full weeks of testimony it is scheduled to end today. As you all know, this filing is primarily driven by capital, the more than $650 million of investments we have made since our last rate increase to improve the electric service and better serve our customers. Our top priority is to achieve timely cost recovery to support strong credit metrics. I’m not going to speculate about the outcome. However, thanks to the knowledge and endless hours of preparation of our employees and our witnesses, we are confident that we presented a strong case. At this point, we anticipate a recommended decision by the Hearing Examiner in June with a final ruling by the Commission in July. We expect to implement new rates August 1. Part of our replacement power plant for BART includes adding a natural gas peaker on the San Juan site. On April 26, PNM filed an application for a CCN for an 87 million 80 MW facility. We hope to receive a procedural schedule in the next few weeks with the goal to have the facility online by June 2018 before the summer peak season. I’m also very pleased to say that on March 17, FERC issued an order approving the settlement in the PNM formula transmission rate case, which includes a 10% return on equity. On April 15, the Company made the final compliance filing for the rates that have already been in place. Going forward, rates will be updated annually on June 1, including this year. Over in Texas, on March 23, the PUCT approved TNMP’s most recent TCOS filing and new rates went into effect totaling $4.3 million annually. We plan to make our next TCOS filing in July with rates expected to go into effect in September. Now I’ll turn it over to our Chief Financial Officer, Chuck Eldred, for a more detailed look at the numbers. Charles Eldred Thank you, Pat, and good morning, everyone. I’d also like to say happy admin week for all the administrative assistance that help all of us in our daily work. So beginning on Slide 7, as Pat said earlier, we are reiterating our 2016 guidance of $1.55 to $1.76. As you know, this is a broader range than we typically provide because of our pending rate case at PNM. I want to remind you of the quarterly distribution of earnings that we provided to you when we issued the 2016 guidance. We have provided that information here for your reference. Because of the third quarter rate case implementation, we expect the second half of the year to have a higher percentage of our earnings than we normally see. With Q1 being 8% to 9% of our earnings for the year, our first quarter results of $0.13 is inside the guidance range for the quarter. Turning to Slide 8, let’s review the PNM’s load details. Load at PNM was down 1% compared to the first quarter of 2015. Residential was down but growth in the small commercial sector helps to offset that decrease. Industrial, although only a small portion of overall load, was down 7.2% between the periods. In this group, Intel is a large customer and they continued to show a decline on a year-over-year basis. As many of you are aware, they announced a major restructuring in their business during the first quarter earnings call. We are carefully monitoring the situation. We have received no communication from Intel that they plan to close this site. Our 2016 guidance range for the load of flat to down 2% considers sensitivities for changes to Intel’s load. We continue to see overall improved economic development efforts locally. This resulted in the Albuquerque Metro area having the best month for job creation in March on a year-over-year basis since May of 2007 at 1.6%. The bulk of that job growth was in private sector jobs. We anticipate that the increased focus on growing the private sector jobs will result in a more diverse and resilient economic base. We see some of the results of these efforts in our continued customer growth which is above forecast at 0.7%. Now moving to TNMP’s load on Slide 9, volumetric load for the first quarter of 2016 was down 1.6% compared to the first quarter of last year, but demand-based load was up 1.5% for the same period. Most of TNMP’s commercial and industrial customers are billed based on their peak demand, which is not reflected in the volumetric based load figures. This offsetting impact causes load in total to have a slightly positive financial impact for the quarter of about $0.005. Both volumetric and demand-based load were used to create a load forecast. We continue to expect load for the year to be at an increase of 2% to 3% compared to 2015. As you read in many publications, this has been a warmer and drier winter than normal in Texas. As a result, the quarter to quarter load comparison has likely been skewed by this, particularly in the residential customers as this group is more sensitive to weather. This has been more than an offset in our results by the demand-based customers which are much less sensitive to weather changes. Turning to Texas economy, as we talked about on our last earnings call, it continues to be strong due to its diversified base. While Houston is feeling the impact of the low oil and natural gas prices, the state overall is diversified and this helps to compensate for the weakness in the energy sector. The Permian Basin which TNMP serves a portion of continues to show the most strength in the oil market. We saw that Chevron made an announcement this week that it plans to invest more heavily in this area even though they’ll be cutting costs in other areas. Several other economic factors in the state also continue to show strength, including increases in building permits and existing home sales to name a couple. We see the impact of the strong economy by way of continued higher than forecasted customer growth at 1.6% for the first quarter 2016. Now Slide 10, let’s review the drivers for PNM. We purchased 64 MW of Palo Verde Unit 2 leases in January of this year. The savings from the lease purchase offset by the additional depreciation results in a $0.03 improvement to earnings in the quarter. Outage costs were $0.02 higher. While San Juan had outages in the first quarter 2015 for the SNCR installation, which were not experienced in the first quarter this year, Four Corners had an extensive outage this year. In addition to the planned outages at Four Corners, San Juan Unit 3 had a 12 day unplanned outage. We had higher depreciation and property tax expense of $0.02 due to increased investments. Lower market prices for Palo Verde Unit 3 sales caused results to be $0.02 lower this quarter and interest expense also reduced earnings by $0.02 because of the additional long-term debt that PNM entered into in August of 2015. Load, AFUDC and Navopache FERC Generation contract, each caused results to be $0.01 lower than Q1 of 2015. We also recorded $0.01 in Q1 of 2015 for the cumulative reimbursement of prior year’s Palo Verde spent fuel storage cost that did not repeat in 2016. Now moving to Slide 11, we’ll review TNMP and Corporate drivers. At TNMP, rate relief in the TCOS filings was up $0.01 compared to the first quarter of 2015. Weather was down $0.01 and depreciation and property tax expenses were also higher by $0.01. At Corporate, we were up $0.02 compared to the first quarter of 2015. This change was driven by less interest expense because of the repayment of the 9.25% debt in May of last year and the incremental interest associated with a financing agreement with Westmoreland, offset by additional interest expense from higher short-term debt balances. On a side note, since Westmoreland took over the San Juan Mine on February 1, we have been very pleased with the operational performance of the mine. Thing are running smoothly and the transition has gone very well. Westmoreland taking over the mine has proven to be a great benefit to our customers as well and the associated cost savings helped to offset the rate request that we have before the Commission now. In conclusion, I want to reiterate that we are pleased with the progress so far in the rate case. As Pat indicated, we believe that we have presented a strong case during the hearings. We expect to receive the Hearing Examiner’s recommended decision in June and ultimately to implement new rates at PNM on August 1. As a result, we plan to update our current year guidance to potential earnings power schedules and capital spending forecast during our second quarter earnings call. This concludes my comments and I’ll turn it back over to Pat. Patricia K. Collawn Thanks, Chuck. We are pleased to say that the Company continues to perform well. Customer satisfaction is up. We are confident we presented a strong case to support our rate increase. We continue to execute our plan and manage our businesses effectively and responsibly, and at all times the focus is on our efforts to serve our customers with safe, reliable and environmentally sensitive energy at low prices. I’m also pleased to say that as Chairman of the New Mexico Economic Development Partnership, I’m in a position to see the fruits of all of the policy changes that Governor has made to make New Mexico a more business friendly state. Our pipeline is as robust as I’ve seen it in many years. Thank you for joining us today. Operator, let’s now open it up for questions. Question-and-Answer Session Operator [Operator Instructions] Our first question comes from Ali Agha of SunTrust. Please go ahead. Ali Agha As per the call, Chuck, you mentioned that in your guidance you’ve assumed that new rates go into effect August 1 of this year. Can you remind me, is there some flexibility for the Commission to delay that or push it back, and if so, remind me what the sensitivity is for every month in delay? Charles Eldred I don’t think we have provided that in the guidance of the sensitivity. While Jimmie is taking a look to see what the numbers are, legally they could delay the rate case, the Hearing Examiner or the Commission, up to October 1 of this year. But we’ve seen that the Hearing Examiner, although the one month of lag that you are aware of, has been very disciplined towards trying to stay to this current schedule. So if you looked at the sensitivities, the implementation on August 1, we dropped the earnings about $0.08, and then September 1 it drops down about $0.07, and then $0.06 in October of one implementation of those rates. So you can see that. Jimmie can lead you to the guidance information to give you more detail if you need to reference some of the previous slides that we’ve prepared on that. Ali Agha Right. And then secondly, so if this comes into effect August 1, I recall, I mean if the timeline is not that the San Juan retrofit rate increase should go into effect beginning in 2018, historically has there been any precedents when you’ve had two rate increases in New Mexico so close to each other and is that a concern from a regulatory approval process with two back-to-back rate increases? Patricia K. Collawn Ali, everybody understands that the next one on the primary drivers of that are the San Juan to BART settlement. And so that will have some normal capital spending into it. But I think everybody understands that these are special circumstances with the BART settlement here that state settle for regional haze and will help us with the clean power plant. So long answer, I don’t think it has any worries for us on that. Ali Agha Okay. And then last question, on the load trends, first in New Mexico, any sort of light at the end of the tunnel where we may reach an inflection point and start to see at least load flattening? There’s constant negative trends for the last several quarters, so let me start with that. Are you seeing anything that tells you we may have bottomed out here? Patricia K. Collawn I think I’ll kind of give you a high-level answer, Ali, and then I’ll let Chuck fill in. I think what we’re seeing is the economy is starting to turn around. Chuck mentioned we’ve seen the best job growth since 2007. And I think that you’re seeing most utilities are having negative usage per customer growth on the residential side. They just haven’t seen the customer growth. The job growth here is going to help us bring back the customer growth on that. And as I mentioned, our economic development pipeline looks very strong right now. So we are starting to see some of those turn around. Charles Eldred I mean the trends are beginning to reflect more of a flattening indication on load because what we are benefiting from in the small commercial and some of the growth is being offset by still some of the economic hardship in the area of Albuquerque. But again, we are beginning to see some flattening, hopefully not much of a decrease, but certainly even the sensitivities I mentioned with Intel are still within that zero to negative 2% guidance range that we gave you. Ali Agha Right. And Texas, I think it’s the first time, at least in the recent past, you’ve broken out this demand side and volumetric load trends, but you put them together and you come up to a negative number. I know you mentioned that weather normalization may have been a challenge here, but anything else that concerns you on Texas? I mean we haven’t seen a negative load number there forever I think as far as I can go. Charles Eldred A lot of it, and we mentioned a little bit about the weather being unusual that first quarter that we’re a little sensitive on the weather normalization in that calculation because it was a drier period in Texas, it created a little different kind of adjustment as you think about weather modernization, but we added the demand-based load because we consider that. We could see that with the AMI implementation, we’re getting more readings and shifting customers more to that demand based to be more reflective of the type of customers that they are and providing that tariff. So as we go forward, we’ll continue to incorporate the demand-based load and be more reflective of the expectations of the entire load projections with that consideration. But as I mentioned, the end result even this last quarter was about $0.5 million, so $500,000 benefit on an earnings basis as a result of the load in first quarter. Patricia K. Collawn Ali, I think a key number to look at on that Slide 9 is, our customer growth forecast is 1% and we are at 1.6%. So our territories in Texas are still growing. We don’t see anything and a quarter does not a trend make, just as we kind of good quarter we don’t call it an upswing on the low growth for just one quarter, especially when it was a leap year normalized and a weather normalized and heaven only knows what else in there, it kind of tops out. We’re not changing our forecast on Texas. Ali Agha Understood. Thank you. Operator Our next question comes from Ben [Budis] [ph] of Jefferies. Please go ahead. Anthony Crowdell It’s Anthony Crowdell. I don’t know how it came in as Ben, but that’s okay. I’ve been called worse. On Slide 11 you have $0.01 benefit for the Westmoreland financing agreement for the quarter. Is that something we can annualize and make it $0.04 to $0.05? And when I compare it to the Slide 14, potential earnings power, shouldn’t that offset some of the Corporate and Other because that looks like it has not changed, it’s still at a $0.06 to $0.04 loss? Charles Eldred I think I’ve talked about it even on the last call. The Westmoreland would be about $0.04 benefit to eastern Corporate and Other. So that’s a good indication of what you can expect going forward. We haven’t updated potential earnings power slide to reflect any incorporation of the Westmoreland loan. So we are really intending to wait to the rate case that we have all the information necessary to update the slide. In that point in time, we’ll include the Westmoreland loan. So we just don’t want to put pieces of information out there. We really want to give you more of a comprehensive view based on the major driver, which is the rate case at PNM, to give you a better reflection of how we see all these additional earnings and the impacts of the rate case to be incorporated into the earnings power slide. Anthony Crowdell Great. Thank you so much. Operator Our next question comes from John Barta of KeyBanc. Please go ahead. John Barta So I guess if we go back maybe a month ago, it seemed like ROE, PV2 and the Balanced Draft Technology were probably the most contentious pieces of that rate case. Just after three weeks of hearings, do you have a better feel on any of those items just from talking with the staff, et cetera? Charles Eldred John, we really don’t want to bring any color to the results of the discussions going on, but I think you’ve certainly pointed out some of the areas the intervenors have questioned, but we look at this as a capital rate case. It’s being litigated with the idea that we think we can build the right record on our capital investments as being prudent and reasonable for the utility to maintain the reliability of the business itself. So there is a lot of different factors, so ROE, depreciation, some of the capital items that you’ve mentioned that intervenors had questioned, but again we felt like our testimony and the record that we’ve built was very solid and well justified the Company’s position to recover those costs. John Barta Okay. And then just in Texas on the load growth, so it sounds like the volumetric percentage is going to transition more to the demand-based load over the coming years. Charles Eldred You see the split-out. We really have taken that in consideration because it’s becoming more of a driver as the automated meter reading gives us a more accurate indication of the type of customers, commercial, industrial and the type of demand that they have on the system. It’s more reflective of that now going forward. So you’ll see us evolve into adding that additional component to our load forecast. Again, no concerns about TNMP’s continued guidance in growth of 2% to 3%. Just want to give you another variable how we’re driving towards those numbers. Patricia K. Collawn It’s easier for us to split it out now that we have the data from the automatic meter reading because that’s how it’s billed, and so it just provides another level of transparency. John Barta Okay, thanks. And then have you disclosed how many megawatts in total is? Patricia K. Collawn No. John Barta All right, thank you. Operator Our next question comes from Lasan Johong of Auvila Research Consultants. Please go ahead. Lasan Johong Question on kind of looking forward, in your presentations you put out 2017, 2018, 2019 outlook, have you taken into consideration the changes in Texas potential ORDC regulations, shutting down of the coal plants, build up of solar, more wind power probably as well, and how does that affect – I mean has that all been taken into consideration in your kind of outlook, how are you incorporating that into your outlook? Patricia K. Collawn The nice thing for us now is that since we’re a T&D utility, that really only impact it would have is if energy prices get extremely high over there, I think you would see customers starting to conserve, so our volumetric load might fall. Customers in Texas have been pretty inelastic to price sensitivity there. Their rates for example in Texas are higher than in New Mexico but their usage is a lot more. On the solar side, we’re seeing some solar penetration in Texas but not a lot. Texas does not have net energy metering, and so the solar potential or the solar penetration in Texas has been low, we’re seeing more of it, but so far all of the growth we have seen has been able to overcome that. So the trends we pay more attention to in Texas are sort of the overall economy and particularly our service territory since we’re sort of around Dallas. We’re south and east of Houston in a petrochemical manufacturing area, refining area, and then more over kind of in West Texas. So the thing that drives our numbers is more those general economic positions. And in the outlook we’ve put forward in terms of earnings potential, we haven’t really seen anything that drives us to believe we’ll see a lot of macro changes in the economy. Lasan Johong And based on [indiscernible], any kind of mass migration in customer usage or patterns of switching for example, as prices go up and down, do you think there’s vulnerability with bigger players, such as yourselves relatively speaking, versus smaller players who are more nimble and take more market risk shall we say, you don’t see shifts in customer or switching? Patricia K. Collawn No, we don’t really see that impacting our piece of the business right now. I think obviously the Texas market is in a little bit of flux right now in terms of where they are going to go with their regional haze plans and their clean power plants in terms of where the generation mix is, but we don’t see anything to incorporate into our numbers. Lasan Johong And lastly, Texas has experienced some really bad weather as of late, tornadoes, hurricanes, hailstorms and such. Any impact? Patricia K. Collawn No. The really bad weather that you saw kind of missed our service territories. It was more in the Houston Metro which is center point. So we’ve had some outages and some impacts but nothing major for us. Lasan Johong Great, that’s fantastic. Thank you very much for your time. Operator This concludes our question-and-answer session. I’d like to turn the conference back over to Pat Vincent-Collawn for any closing remarks. Patricia K. Collawn Thank you. And again, thank you all for joining us today. We hope you have a wonderful rest of your day and a wonderful spring and we look forward to talking to you again on the second quarter call. Have a great day. Operator And thank you. Today’s conference has now concluded and we thank you all for attending today’s presentation. You may now disconnect your lines and have a wonderful day. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. 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National Fuel Gas Company’s (NFG) CEO Ron Tanski on Q2 2016 Results – Earnings Call Transcript

National Fuel Gas Company (NYSE: NFG ) Q2 2016 Results Earnings Conference Call April 29, 2016 11:00 AM ET Executives Brian Welsch – Director of Investor Relations Ron Tanski – President and Chief Executive Officer Dave Bauer – Treasurer and Principal Financial Officer John McGinnis – Chief Operating Officer Analysts Kevin Smith – Raymond James Holly Stewart – Scotia Howard Becca Followill – U.S. Capital Advisors Operator 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. Brian Welsch 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. 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. John McGinnis 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. 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. Question-and-Answer Session Operator Thank you. [Operator Instructions] Our first question comes from the line of Kevin Smith of Raymond James. Your line is open. Kevin Smith Thank you and good morning, gentlemen. John McGinnis Hi, Kevin. Kevin Smith 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? John McGinnis Say that again. I’m sorry, you are breaking up. Kevin Smith 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? John McGinnis 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. Kevin Smith 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? Dave Bauer 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. Kevin Smith Okay. Great. That’s extremely helpful. That’s all I had. Thanks. Dave Bauer Sure. Operator Thank you. [Operator Instructions] And we do have a question from the line of Holly Stewart of Scotia Howard. Your line is open. Holly Stewart Good morning, gentlemen. John McGinnis Hi, Holly. Holly Stewart 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? John McGinnis 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. Holly Stewart 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? John McGinnis 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. Holly Stewart Okay. Great. Thanks, John. John McGinnis Yes. Operator Thank you. And our next question is from Becca Followill of U.S. Capital Advisors. Your line is open. Becca Followill Hi guys. John McGinnis Hi Becca. Becca Followill 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? John McGinnis 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. Becca Followill Thank you. And then on the water permit, what is the timing you’re expecting to get that permit from the DEC? John McGinnis Well, assuming that it takes the full year, Becca, it would be the beginning of March of 2017. Are you getting that? Becca Followill Do you think it will take the full year? John McGinnis 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. Becca Followill 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? John McGinnis 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. Becca Followill Okay. Thank you. Operator Thank you. And our next question is from Chris Sighinolfi of Jefferies. Your line is open. Unidentified Analyst Hey guys. Good morning. This is actually Chris Dillon [ph] on for Sighinolfi. How are you? John McGinnis Hi, Chris. Dave Bauer Good, Chris. Unidentified Analyst 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? John McGinnis 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. Unidentified Analyst Okay. That’s fair. That was it for me. Thanks guys. Operator 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. Brian Welsch 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. Operator 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. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. 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