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Hawaiian Electric Industries’ (HE) CEO Constance Lau on Q2 2015 Results – Earnings Call Transcript

Hawaiian Electric Industries’ (NYSE: HE ) Q2 2015 Earnings Conference Call August 10, 2015, 1:00 PM ET Executives Clifford Chen – Manager, Investor Relations Constance Lau – President and Chief Executive Officer James Ajello – Executive Vice President and Chief Financial Officer Alan Oshima – President and Chief Executive Officer Tayne Sekimura – Senior Vice President and Chief Financial Officer Analysts Paul Patterson – Glenrock Associates Charles Fishman – Morningstar Michael Weinstein – UBS Nick Yuelys – Gabelli & Company Andy Levi – Avon Capital Sachin Shah – Albert Fried Operator Good day, ladies and gentlemen, and welcome to the Hawaiian Electric Industries, Incorporated Q2 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] I would now like to introduce your host for the conference call Mr. Cliff Chen. You may begin. Clifford Chen Thank you, and welcome everyone to Hawaiian Electric Industries second quarter 2015 earnings conference call. Joining me this morning are Connie Lau, HEI President and Chief Executive Officer; Jim Ajello, HEI Executive Vice President and Chief Financial Officer; Alan Oshima, Hawaiian Electric Company President and Chief Executive Officer as well as other members of senior management. Connie will provide an overview of followed by James, who will update you on Hawaii’s economy, our results for the quarter and outlook for the remainder of the year. Then we will conclude with questions-and-answers. In today’s presentation, management will be using non-GAAP financial measures to describe the company’s operating performance. Our press release and webcast presentation materials, which are posted on HEI’s Investor Relations website, contain additional disclosures regarding these non-GAAP measures, including reconciliations of those measures to the equivalent GAAP measures. Forward-looking statements will also be made on today’s call. Actual results could differ materially from what is described in those statements. Please refer to the forward-looking statements disclosure accompanying the webcast slides, which provides additional information on important factors that could cause results to differ. The company undertakes no obligation to publicly update or revise any forward-looking statements, including EPS guidance, whether as a result of new information, future events or otherwise. I’ll now turn the call over to our CEO, Connie Lau. Constance Lau Thank you, Cliff and aloha to everyone. Turning to our results announced earlier today, both our utility and bank are on track to meet our 2015 earnings guidance. At the utility, we have been working hard to advance the energy transformation plans that we filed with our commission last August, which would triple distributed generation including rooftop solar in Hawaii by 2030. Increased renewable energy to 65% by 2030 and also position us to achieve Hawaii’s new goal of 100% renewable energy by 2045. At the bank, we are working hard to deliver stable, profitable performance. Year-to-date deposit growth was strong and credit quality remained sound. On June 10, we achieved an important milestone for our pending banks spin and utility merger with HEI shareholders approving the merger with NextEra Energy with a 90% mandate from shares voted. In addition the process to obtain Hawaii’s Public Utilities Commission approvals and other approvals is underway. As many of you know the governor of Hawaii made public statements regarding the proposed merger following testimony that was filed on July 20 by interveners to the merger. In a press conference, the governor said the state is taking the position of opposing the merger as proposed. Later today, the consumer advocate is expected to file his position with the Public Utilities Commission that will complete filings by all parties and we and NextEra Energy will file our rebuttal to those positions on August 31. We believe that as we and NextEra Energy, provide more information and engage in additional discussions, the commission and others will conclude that our merger will provide significant benefits for our customers and the entire state and will further underscore Hawaii’s global leadership in clean energy. The governor also stressed the importance of having a partner who shares the vision of having 100% renewables for Hawaii, a new law, which is signed on June 8. Both Hawaiian Electric and NextEra Energy each have made clear that we are fully committed to achieving Hawaii’s new goal of 100% renewable energy by 2045. NextEra Energy has made it clear that it is committed to Hawaii and will bring a combination of renewable energy expertise, strong technological and operational knowledge, financial strength and access to capital necessary to support Hawaiian Electric’s plans. For our part, we believe NextEra Energy is the right partner for Hawaiian Electric to help us accelerate the achievement of the Hawaii’s clean energy goals. Given all the attention that has been placed on our utility transaction, I would be remiss in not mentioning our other major operating company, our bank American Savings Bank. American Savings Bank has been diligently preparing for their cross conditional spin off in parallel with our utilities – Public Utilities Commission approval process. Just as we firmly believe in the positive impact our utility merger will have on Hawaii the addition of American Savings Bank to the ranks of independent publicly traded companies based here in Hawaii will also provide significant benefits for our Hawaii customers and communities as well as for our shareholders. Back on our utility merger, last week the Hawaii Public Utilities Commission issued an order establishing the remaining timeline for the review of the merger transaction. We are currently in the discovery or information request phase of the PUC process. As I mentioned earlier, our consumer advocate is expected to file his testimony later today and we and NextEra will file our reply on August 31. All parties may then ask each other any final questions with all discovery scheduled to conclude by the end of September. Thereafter, the Public Utilities Commission will host a series of public listening session throughout the Hawaiian Islands starting in September and continuing through October 2015 to provide the public the opportunity to address the commission concerning the proposed transaction. Evidentiary hearings are scheduled to begin on November 30 and continue through December 16, 2015. Following the evidentiary hearing, the parties will file closing briefs and thereafter the commission is expected to issue its decision. Turning to slide four, in addition to the Hawaii Public Utilities Commission approval, the major items remaining for the merger with NextEra Energy and the spin off for our bank to shareholders are the following conditions. The receipt of all other required regulatory approvals from among others the Federal Communications Commission, the Federal Reserve Board related to the bank spin and expiration of the Hart-Scott-Rodino Act Antitrust period, which we filed just last Friday. I would now like to highlight the status of key utility developments. On June 29, our utility submitted their final statement of position in the distributed energy resources proceeding, which included new customer options and programs to support continued growth of rooftop photovoltaic systems in Hawaii. Recommendations included nation leading technical standard for advanced inverters, which will improve the integration of high levels of rooftop PV. New options for customers including battery equipped with rooftop PV systems, a pilot time of used rate to offer customers, the opportunity to save money by shifting their energy use to different times of the day, particularly when PV panels are most productive, as well as, a new pricing structure for new rooftop PV systems that more fairly distribute costs for operating and maintaining the electric grid. Hawaiian Electric continues to lead the nation in the integration of customer cited solar with 13% of residential customers having with rooftop solar year-to-date through June 30. Our customer adoption of solar energy in Hawaii is 20 times the national average. The utility proposals would provide greater access to rooftop PV, while helping ensure the longevity of programs in a way that protects reliability, safety and fairness for all customers. Ultimately, the Public Utility Commission will determine how and when any changes impact customers. Back in October 2014, Hawaiian Electric committed to clear a backlog of about 2,800 then pending net energy metering or NEM applications of which we have only 15 remaining. Since then, more than 15,000 additional applications have been approved to install or interconnect. As of July 15, a total of approximately 70,000 rooftop solar NEM applications have been approved by Hawaiian Electric, Maui Electric and Hawaii Electric Light Company for the five islands we serve. For our main islands of Oahu, this has resulted in close to a 30% of the single-family homes on a Oahu approved for solar PV, a very high penetration rate. On July 15, Hawaiian Electric Company proposed a community solar pilot program. If the PUC approves the pilot about 50 Oahu utility customers who don’t currently have access to rooftop solar will be able to enjoy the economic benefits of rooftop PV. Lessons learned from this pilot will help with the design of expanded programs under a community-based renewable energy tariff to be filed in October. On July 31, the PUC approved four major solar energy projects on Oahu, totaling approximately 137 megawatts, in time to meet the federal 30% tax credit, currently set to expire on December 31, 2016. The PUCs approval of these projects will provide all our customers by the end of next year with the lowest price of any solar electric city on Oahu. More than 30% lower than previous solar projects. On August 5 Maui Electric filed contracts subject to the Public Utilities Commission review and approval to purchase up to 5.7 megawatts of solar power at $11.06 per kilowatt hour. More than 30% of the electricity used in Maui County currently comes from renewable sources. So these contracts will take that percentage up even higher. Moving on to the demand response docket on the next slide. On July 28, the PUC issued an order advancing our Integrated Demand Response Portfolio Plan or IDRPP, appointing a special advisor to help with further development of the plans. The commission observed that the overall strategic and conceptual direction of the IDRPP is positive and notes that there are many welcome aspects to the proposed process and methodology. In other developments on May 28, the PUC issued an order related to our utilities revised annual decoupling filings. As a result the utilities filed revised 2015 annual incremental RAM revenues of $11.1 million. The tariff rates are effective from June 8, 2015 to May 31, 2016. In addition in the Public Utilities Commission, March 31, D&O on decoupling, the PUC also indicated that the utilities may apply for recovery of revenues for major projects, including baseline project grouped together for consideration as major projects above the RAM cap. The utilities are currently reviewing different projects and maybe submitting some for approval for recovery above the RAM cap. Finally under the required schedule for decoupling, we gave notice of our intent to file the Hawaii Electric Light Company 2016 test year rate case by December 31, 2016. Normally a general rate case using a calendar 2016 test year would be filed in the second half of 2015. However in light of the pending merger application Hawaii Electric Light has requested an extension of the date by which it must file its rate case to December 30, 2016. I’ll now ask Jim to cover Hawaii’s economy and then our financial results and outlook for the economy. Jim? James Ajello Thanks, Connie. I’ll begin by briefly commenting on Hawaii’s economy. June 2015 visitor arrivals on expenditures were up 6% and 4.4%, respectively from the same month last year and still robust after many years of strong growth. Year-to-date June 2015 visitor arrivals reached 4.3 million with total spending at $7.6 billion. Tourism is on a record trajectory in 2015. Statewide unemployment edged downward to 4% in June 2015, compared to 4.4% a year ago and still significantly below the national unemployment rate of 5.2% as of June. Recent Hawaii real estate activity remained strong during July 2015 with the median sales price for single-family homes on Oahu at $710,000, up 4% from last year and up 2.3% year-to-date July. This year through July, the pace home sales on Oahu is up 4.8%. Year-to-date May 2015 construction activity was reflective of value private building permits increased 41% compared to year-to-date May 2014. This increase is reflected by the increase in new residential, commercial and industrial projects. Overall, Hawaii’s year-to-date economic performances is being sustained by continuing strong activity in the construction and tourism industry and the University of Hawaii forecasters expect state GDP to grow 3.8% this year. As shown on slide eight second quarter 2015 GAAP earnings per share were $0.33. Core earnings per share which excluded merger expenses were $0.39 compared to $0.41 in the second quarter of 2014. Consolidated core net income was $0.9 billion higher than the prior year, but EPS was $0.02 lower due to the increased number of shares settled due to equity forward agreement. On slide nine, utility earnings were $32.8 million in the second quarter of 2015 compared to $34.2 million in the second quarter 2014, the detailed variances are shown on the slide and I’ll just highlight a few. Depreciation expense was $2 million higher, due to increasing investments for the integration of energy, improved customer reliability and greater system efficiency. Operations and maintenance expense was $1 million, higher compared to the prior year, largely due to higher consulting costs for our energy transformation plans, higher transmission and distribution costs and higher benefits expense. These partially offset by lower overhaul and smart grid costs in the second quarter of 2015. At the bank, net income for the second quarter of 2015 was $12.9 million, $0.6 million lower than the linked quarter, primarily due to $1 million in higher interest income, primarily driven by higher interest earning assets and fees, related to the early payoff of commercial loans. This was offset by $1 billion higher provision for loan losses and $1 million in higher non-interest expense, primarily to higher medical expense and the timing of professional fees and a reserve for unfunded commercial commitment. Compared to the second quarter of 2014, net income at the bank was $1.3 million higher primarily due to $1 million higher net interest income, due to higher average loan balances, $2 million in higher noninterest income, primarily from higher mortgage banking and fees on deposit products, these were partially offset by $1 million and higher noninterest expense in the second quarter of 2015, due primarily to higher pension and benefit expense. As shown on slide 10, HEI’s quarter ROE for the last 12 months was 9%, ROE contributions of 7.7% from utility and 9.6% from the bank. Slide 11, shows the utilities actual ROEs for the last 12 months, and consolidated core utility ROE of 7.7%, declined from 9% in June of 2014, primarily due to higher O&M and depreciation expense, partially offset by the RAM increase. On slide 12, you could see that American continues to deliver solid profitability metrics generally in line with targets. We have maintained a competitive return on assets of 93 basis points through the first half of the year. Year-to-date annual loan growth was 1%, and currently lower than our mid-single-digit loan growth target, mainly due to the timing of loan closures expected in the second half of the year. We continue to expect to achieve our target of mid-single-digit loan growth for the year. In the second quarter, loan growth was driven primarily by higher commercial market and residential loans and home equity lines of credit, offset by payoffs in the commercial real estate and consumer portfolios. Year-to-date net interest margin remains in line with expectations, benefiting from interest and fees related to prepays and payoff of commercial real estate and commercial and industrial loans. Year-to-date credit cost remain low, as our solid asset quality and strong risk management, resulted in year-to-date net charge-off ratio of 8 basis points, still very attractive relative to peers. Overall, the bank continues to maintain its low risk profile, strong balance sheet and straightforward community business banking model. On slide 13, our net interest margin was 3.52% in the second quarter of 2015, consistent with the linked quarter. Our interest earning asset yield declined by 1 basis point. Our liability cost of 22 basis points remained unchanged from the linked quarter. On slide 14, we show an improving trend in year-to-date 2015 noninterest income, which was primarily driven by higher mortgage banking income, as we have made a conscious decision to sell a larger portion of our low rate mortgage loan originations, increasing fee income on deposit liabilities, due to deposit related initiatives and increasing fee income on other financial products. Credit quality continues to be strong, reflecting prudent credit risk management and the healthy local economy. Second quarter of 2015 net charge-off ratio was 11 basis points, compared to 4 basis points in the linked quarter. The increase in that charge-off ratio was due to the charge-off of two commercial loans and higher charge-offs associated with growth in the consumer portfolio. Provision for loan losses was higher than the linked quarter and prior year quarter mainly due to the downgrade of one large commercial lending relationship and higher charge-offs. The allowance for loan losses was 1.04% of outstanding loans at $46.4 million at quarter end compared to 1.03% at the end of the linked quarter and 0.99% of the prior year end. On slide 16 nonperforming assets ratio was 70 basis points, 10 basis points lower compared to the end of the first quarter and lower than the 1.05% at the end of the second quarter last year. This is consistent with our solid credit quality and effective credit management. Slide 17, illustrates Americans continue to do attractive asset and funding mix relative to our peer banks. Americans June 30, 2015 balance sheet is stacked against the last accretive billable data sets for our peers, which is as of March 15. 99% of our loan portfolio is funded with low cost core deposits versus the aggregate of our peers at 88%. Year-to-date total deposits increased $180 million or 7.8% annualized, while maintaining a very low cost of funds of 22 basis points. 18 basis points lower than the median of our peers. American remains well-capitalized at June 30, with a leverage ratio of 8.8%, tangible common equity to total assets ratio of 8.2% and total capital ratio of 13.5%. In the second quarter, American paid $7.5 million in dividends to HEI, while maintaining healthy capital levels. Now I’ll address HEIs outlook for 2015. Utilities updated three year capital expenditures consisting of both foundational and transformational investments is forecast to be $0.8 billion to $1.7 billion. Our foundational investments represent core investments needed to continue to in deliver safe, reliable and efficient service to our customers. They include projects to replace aging infrastructure, to improve reliability, making or upgrading customer connections and improving our internal structure, to be more efficient and effective. Many of our major transformational initiatives depend on external factors, which could impact our ability to execute. Our applications for approval of The Schofield Generating Station is at the PUC and we expect to file applications for battery storage, LNG and smart grid later in 2015. For 2015, we expect rate base growth to be in the range of 1.5% to 3%. On our 2014 ending rate base balance of $2.7 billion. We would note that our long-term rate-base growth forecast is subject to PUC approval of our major capital expenditures. We are reaffirming HEI’s earnings guidance of $1.64 to $1.74 per share, excluding any expenses relating to the pending merger and spin off transactions. Last quarter we guided towards the low end of the range as a result of the early equity forward settlement of 4.7 million shares in March of 2015. The March 31 PUC decision and order on the Schedule B decoupling mechanism issues. The 2015 impact of the dilution in the early equity forward settlement is approximately $0.04 a share. At utility, there is no change to the EPS guidance. Guidance range that we are guiding towards the lower end of that range to offset the impact of the PUCs May 28 decoupling order, we are carefully managing expenses and we are revising our O&M guidance to approximately, a 2% decline compared to 2014 levels, instead of prior guidance of a 2% increase. As we have mentioned in the first quarter 2015 in our earnings release, we lowered the 2015 CapEx to $250 million from $420 million. And correspondingly revised our three year forecast range of $0.8 billion to $1.7 billion. In 2015 rate-based growth is now expected to be 1.5% to 3%. At the bank, there are no changes to the EPS guidance range and key assumptions. Connie, now I will turn the call back to you. Constance Lau Thanks, Jim. In summary, our utility is leading the industry and integrating renewables and distributed generation and continues to be focused on expanding customer options and lowering customer bills. Our bank continues to be a solid performer and will continue to focus on its core banking business targeting mid-single-digit loan growth and strong credit quality. Last Friday our board maintained our quarterly dividend of $0.31 per share. The dividend yield continues to be attractive at 4% as of Friday’s market close and we have paid our dividend uninterrupted since 1901. Finally, we firmly believe that as the Hawaii Public Utilities Commission merger review process continues that we NextEra Energy have the opportunity to provide more information and engage in additional discussions with the PUC, the commission and others, should conclude that this merger can and will provide significant benefits for our customers and can help accelerate achievement of the clean energy future that we all want for Hawaii. And with that, we look forward to hearing your questions. Question-and-Answer Session Operator [Operator Instructions] Our first question comes from Paul Patterson with Glenrock Associates. Paul Patterson Aloha. Constance Lau Hi, Paul. How are you? Paul Patterson All right. How is it going? Constance Lau Good. Paul Patterson On the merger, and the governor’s comments and everything, what is the outlook for the potential for settlement versus a fully litigated case? Could you just give us a little bit of a flavor for that? Constance Lau I’m not sure I can really an answer that question Paul, because we’re still in that discovery phase and so there’s quite a bit of discussion that still needs to occur. I think as the Public Utilities Commission order that came out establishing the remainder of the process, it shows that a lot of that will occur this fall. I think as we go forward, we will probably get greater clarity in that question. Later today, CA needs to file, so we still need to see his testimony as well. Paul Patterson Sure. Okay, but I mean, so should we think, maybe after discovery processes completed that that might be a more likely time that settlement discussions could take place. Does that make sense? Constance Lau As you know settlement discussions can occur any time along the way, but certainly we would think that you we would at least want to see the initial positions of all the parties. Paul Patterson Okay. And then on the RAM order, in the PSIP. I guess, the changes that they made, my understanding was that that was pending the outcome of the PUCs review of the PSIP. I’m wondering what the schedule looks like regarding that and what we might see if you have gossip out there? Constance Lau Sure. And actually I think Alan is with us and perhaps I can turn that question over to him on the PSIPs. Alan Oshima Yeah, Paul, good morning. Paul Patterson Good morning. Alan Oshima Actually the RAM decoupling and the PSIPs, we don’t believe are connected at all. I think the PSIP will go on its separate track. It’s more of a technical discussion as to our power supply moving forward. The RAM is more financial based and operational, so I think it’s a transition year this year, it’s a first year that we’re having to comply with some of the new changes to the decoupling and we’re doing that, as we speak. Paul Patterson Okay. So I mean, my understanding that the RAM was being amended on interim basis, pending the outcome of PUCs review PSIP plans. I mean, I believe I read that in the order, I guess. I guess, so I’m wondering is is how do you think the – I mean, are you saying they’re not connected. I mean, that’s what I’m sort of a little bit confused on. James Ajello Capital expenditures are always connected and how the RAM decoupling will operate. Of course, will be somewhat affected by what PSIPs come up with. But they’re separate dockets and they’re not directly connected. Paul Patterson Okay. Just one final one here, a couple of things. You guys have pushed back the LNG stuff and oil prices are down. I’m wondering one of the reasons why you wanted to do the LNG was that you thought it would have environmental, but also substantial cost benefits for the ratepayers and that was an issue that I think the PUC was concerned about. How should we think about the pushback in the LNG importation? The lower price of oil in terms of what we’re seeing in terms of customer’s rates and stuff right now. Constance Lau So Paul, I think as with any major project and this would be quite a major project for Hawaii to be bringing another fuel source. You only have to take into account the changing conditions and as you pointed out there was a pretty significant change in some of the basic assumptions with the shift in the oil prices. So I think the way you want to look at it is that we are continuing forward, but we’ve got to make sure that bringing LNG into Hawaii still makes sense because at the end of the day, our ultimate goal is to bring it into lower cost for our customers. I think as you know, you know the commodity price with LNG is only a very small portion of the total cost to customers. A lot of it really is in building what I call the virtual pipeline across the water and it’s really the logistics that are most important in designing this project. So there’s been quite a bit of work that’s been going on in that regard in advancing the ideas on the most economical and efficient way to bring the liquefied natural gas into the state, while still assuring reliability of supply. So we are proceeding forward. I think we still believe that there is benefit for our customers, but we need to work through all of the changing analysis. I’ll ask Alan, if he’d like to add anything to that. Alan Oshima No. That’s totally correct. I mean, we’re looking at all the environmental benefits as well. I mean, it’s not a one-sided view of this, we have to look at it from all sides. Paul Patterson Sure. Any timeframe in terms of when might hear about what your revised analysis or any key date we should be thinking about? Alan Oshima Yeah, we’ll be I think making some decisions later this year and then probably moving forward. Depending on those decisions in early 2016. Paul Patterson Okay. Great. I’ll let people ask questions. Thanks a lot. Operator Our next question comes from Charles Fishman with Morningstar. Charles Fishman Thank you. If you’d give me some help here I think my notes on your status of the Public Service Commissioners might be out of date. Were all three commissioners, the current reserve appointed by the former governor? Constance Lau No, the Chair is new and was appointed by our new governor earlier this year. Charles Fishman And previous governor was Democrat as well, Connie. Wasn’t he? Constance Lau Yes, correct. Charles Fishman Okay. And then is Champley is still on and his term is up next year. Constance Lau Yes. Commissioner Champley is still on and also Commissioner Akiba. Charles Fishman Okay. Well, thanks for updating me. Just one other comment. I was at my church yesterday, an electrical engineer came up to me and said that the local utility in St. Louis had a meeting last week among electrical engineers and the integration of solar going on in Hawaii was a big topic of discussion. So you can pass on to your operation people that what they’re doing has some very far reaching input to other places. Constance Lau Thanks, Charles. As I mentioned in my comments, particularly on the use of the advanced inverters, we really are setting a tone for the nation and better use of that technology to help in the integration of rooftop PV. Charles Fishman Good luck on the merger. Constance Lau Thank you. Operator Our next question comes from Michael Weinstein with UBS. Michael Weinstein Hi, Connie, how are you doing. Constance Lau Hi, Michael, how are you? Michael Weinstein Good. My question, I don’t want to prejudice the merger outcome or anything like that. But I was just curious how separate is the spin of ASB from the merger process with NextEra? Is it possible that, for instance, and just really hypothetical of the Commissioner rejected, the merger would you still want to spin ASB in, could that still happen, given the tax implications? Constance Lau That we would go back to the analysis that we normally have had with respect to the separation of the two companies and we’d have to analyze it at that point in time. But at the moment the spin of the bank is cross conditional with the merger application, so that that would only occur if the merger goes forward. As you know a real key piece of the agreement with NextEra is that they will be paying the tax on the spin for our shareholders, so that our shareholders can receive the shares tax free, plus there is a great benefit to the bank in the step up of the tax basis. So it’s very positive transaction when it is combined with the merger with NextEra. If there is no merger, we’d have to analyze it as a standalone transaction. Michael Weinstein Got you. Okay, thank you so much. Constance Lau Sure. Operator Our next question comes from Nick Yuelys with Gabelli & Company. Nick Yuelys Congratulations on a good quarter. Constance Lau Thanks, Nick. Nick Yuelys I was just wondering following up on that last question, if all the regulatory approvals necessary for the bank spin off weren’t completed by the time the PUC approves the merger. What would happen? Constance Lau So let me just address that basic proposition because we really haven’t talked much about all the preparations going on at the bank for the spin. We are not expecting that the bank will not be prepared for a spin. As you know, we’ve got a very, very good team in at the bank. Many of whom have been with publicly traded companies previously. So we feel that there are quite well prepared to handle the bank when it spins off. And they have been having ongoing discussions with their regulators, the office of the Comptroller of the Currency and Jim Ajello has been having similar discussions with the Federal Reserve Board on behalf of the holding company. So we’re expecting that the bank will be quite well prepared for the spin. There may be some timing issues with respect to closing of quarters and years and that. But otherwise we believe the bank will be quite well prepared. Nick Yuelys Okay. Great. Then my guess is, do you need to make a filing with the FCC or how will that approval process work? Constance Lau On the FCC, the utility has some licenses with respect to communications that need to be transferred. So that one is while we mentioned that it’s one of a lot of little approvals that need to occur, but it’s not a major one at all. Nick Yuelys Okay. Great. Then my last one on the four solar project that the PUC approved at the end of July. Are those included in the CapEx numbers or are those some a little bit of upside to that? Constance Lau So those are actually by IPPs. Remember we had that so-called waiver group of projects where we went out for an RFP and so those are all by independent developers. Nick Yuelys Okay. Good, that’s all I have. Thank you very much. Operator Our next question comes from Andy Levi with Avon Capital. Andy Levi Hi, good morning. Constance Lau Hi, Andy. Andy Levi Just two quick questions, if as we look at your CapEx numbers and you included the transformational piece as well in ’16 and ’17, which CapEx in the $700 million range. What would and again, assuming standalone. What would the equity needs of the company be? Constance Lau So Andy, let me ask Jim to address that because we’ve looked at that, not with respect to the transformational capital, but the overall picture. So, Jim? James Ajello Thanks, Connie, and hi, Andy. So we haven’t yet sketched out the capital needs entirely yet. We’ll make sure that the utilities, regulatory ratio is about 58% equity, and 42%, 43% debt will be observed. I will tell you in general, I think there will be well under $200 million, but we haven’t put a fine point on that as yet. Andy Levi And that would be for both years or …? James Ajello I’m just talking about prompt year 2016. Andy Levi Okay. And then just on the RAM, could you just explain to us kind of what was changed in the order, the preliminary order relative to how the RAM worked before. Constance Lau Sure. Jim, I don’t know if, Tayne, is there, she’s probably the best to go into those details. Tayne S. Y. Sekimura I’m here. So basically the change in the RAM, what the commission did was, it focused on a target level of revenues and was based on what was included in the last rate cases and the last RAMs, and basically escalated it for inflation and that served as the cap for the RAM. And that’s a lot different from the previous RAM that was in effect, which actually went through a series of looking at, what was included in the rate case with escalated by the components of O&M, rate base and depreciation. So what commission did in the revised RAM was not make any differentiation between the RAM component, but just calculated based on a level of revenue. Constance Lau So, Andy, I don’t know, if you remember under the capital RAM they were looking at both the major projects and in the so-called baseline projects. The baseline projects went in at a historical five-year average. What they did was they just and talked about CapEx in total with as James said an inflationary adjustment similar to the inflator on the O&M side. Then said, we want to take a look at all the projects over that and review and that’s where we’re now looking at any projects that would be above that cap and reviewing whether to submit additional filings. They actually left the door open to design additional processes to process those amounts that are over the cap. Andy Levi And so with that being the case, the $11 million increase that you talk about in your handout, was that under the new method or the old method? Constance Lau That was the $11 million is under the new method. Andy Levi Okay and what was the increase the year before, I’m just curious, if you remember, I don’t if you have that number, but. So under the old method. James Ajello So, Andy, we’ll follow-up with you after the call. Andy Levi Yeah, that’s fine. And then just one last question, and I’ll let somebody else go. So under the new method, I guess, if I’m not mistaken the way you describe and having read a little bit about it, that would I guess, lead to more frequent rate filings, is that how we should view it, so you could recover your capital cost on more timely basis? Constance Lau No. Not necessarily. The RAM mechanism still provides for the triennial review, but what it may mean is that we may be processing some of the CapEx under mechanisms that are supplemental to the RAM. Andy Levi And that’s I guess, what they’re working on now? Constance Lau Correct. Andy Levi Perfect. Thank you very much. Constance Lau Yeah, that’s part of that transitional issue that Alan alluded to. Andy Levi I understand now. Thank you. Operator Our next question comes from Sachin Shah with Albert Fried. Sachin Shah Hi, good morning. Thanks for taking call. Just to understand the governor’s recommendation. From past precedence, is there any past precedence of the governor making such a recommendation and the PUC going along with the governor or going against the governor? I know that you’re going to make a compelling case, the companies are going to make compelling case against that recommendation and other opposition. But just trying to understand you know how much influence does the governor’s recommendation subjectively have on the PUC? Constance Lau Yeah, so this is a very new process within our Commission because while there has been some utility mergers throughout Hawaii’s history. They really have been much smaller than this proposed transaction. And particularly for this governor, this governor just came in this year, so everybody is really looking very carefully, but I’d say with new eyes at this particular transaction because they really haven’t been a lot of other transactions that one can point to. Sachin Shah Okay. So this is just new process, new ground for everybody and so the contentions as that we may be seeing are opposition comes along with the territory of this new process I guess. Constance Lau Yes, yeah. It’s part of the process and as the governor also said, it’s early in the process and he’s sure that there will be lots more discussion and that we haven’t heard the last on it yet. Sachin Shah Okay. Fair enough. Thank you. Alan Oshima Hi, Connie, this is Alan, it’s not a new process per sequential, it’s a process in this case, but there are regulatory frameworks for this from past transactions, that I think the electrical regulatory process will continue as they have described that in the filings. Constance Lau Yeah, thanks Alan. Operator And this is company operator; I’m actually showing no further questions at this time. Clifford Chen Thank you, Kevin. If there are no further questions, I would like to thank everyone for their participation today and have a good week. Bye-bye. Operator Well, ladies and gentlemen, this does conclude today’s presentation. You may now disconnect and have a wonderful day.

National Fuel Gas’ (NFG) CEO Ron Tanski on Q3 2015 Results – Earnings Call Transcript

National Fuel Gas Company (NYSE: NFG ) Q3 2015 Earnings Conference Call August 07, 2015 11:00 AM ET Executives Brian Welsch – IR Ron Tanski – CEO Dave Bauer – Treasurer and Principal Financial Officer Matt Cabell – President of Seneca Resources Corporation Analysts Becca Followill – U.S. Capital Advisors Holly Stewart – Howard Weil Chris Tillett – Jefferies Operator Good day, ladies and gentlemen, and welcome to the Q3 2015 National Fuel Gas Company Earnings Conference call. My name is Halley, and I am your operator for today. At this time, all participants are in listen-only mode. We will conduct a question-and-answer session towards the end of this conference. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I’d now like to turn the call over to Mr. Brian Welsch, Director of Investor Relations. Please proceed, sir. Brian Welsch Thank you, Halley, 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 Matt Cabell, President of Seneca Resources Corporation. At the end of the prepared remarks, we will open up the discussion to questions. The third quarter earnings release and August inventor 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’ll turn it over to Ron Tanski. Ron Tanski Thanks Brian and good morning everyone. Operating earnings are $0.55 per share for the third quarter or $0.18 per share lower than the last year’s third quarter. If you look at the drivers of that decrease that we breakout on page 11 of the earnings release it’s easy to see that three items in our exploration and production segment explain most all of the year-to-year decrease. Those items were lower commodity prices, decreased production and offsetting the first two items the reduction in our DD&A rate. The decrease in production is largely a result of our shutting in wells in Appalachian when the spot prices are too low. We continue to look for opportunities to sale our spot production at acceptable prices but there is simply too much gas and not enough pipeline infrastructures to move those supplies to attractive price points. As we pointed out in the release we curtailed approximately 12.5 Bcf of production during the quarter. Lower commodity prices have obviously been the story for most energy companies this earning season and we’ve seen some firms make major reductions in their capital expenditure budgets. We’re watching our spending too, but I’ll remind everyone that our CapEx plans have always been relatively conservative. Our current rig scheduling and drilling programs are designed to bring on enough production to fill the pipelines that we’re building to move their production to better pricing points. We continue to move forward with our plans to build the pipelines to help move production out of the basin both for owned Seneca Resources and for third party producers. Construction is underway on three of our interstate pipeline projects. Our West Side expansion project along our line and corridor, our Tuscarora Lateral project in the more central portion of our system and our Northern Access 2015 project, all of these projects are moving along on schedule and we expect that they will all be in service in the last quarter — calendar quarter of this year. The Northern Access 2015 project will allow Seneca to move140,000 dekatherms per day of gas to Canada at the Niagara interaction with TransCanada and the West Side expansion will allow Seneca to flow an additional 30,000 dekatherms per day, a portion moving to Canada and the remainder to Texas Eastern. We have shown Seneca’s transportation capacity graphically on Page 24 of our Investor Relations slide deck on our website. When combining this 170,000 dekatherms of near term capacity with the 490,000 dekatherms per day of capacity, that Seneca has in our Northern Access 2016 project you can see that we’ve got a substantial growth trajectory moving forward from our current productive capacity of 150,000 dekatherms per day in our western development area. Both Matt and Dave will give some more color on our marketing activities and hedging positions. But I am pleased to say there ongoing approach of regularly layering in hedges has put us in good shape with respect to revenue certainty for a good portion of our firms sales for the rest of this year and next fiscal year. Lower commodity prices have obviously cut into our earnings but our diversified model continues to produce healthy cash flow. Our balance sheet is in good shape but I don’t see any need to alter our strategy to build more pipelines and drilled the wells necessary to fill those pipelines. These investments help us accomplished two goals they generate significant cash flows for at least the next 15 years and they provide Seneca’s with the ability to move gas to our market with significantly better pricing. This integrated approach to developing our assets combined with the flexibility offered by our fee mineral acreage position is allowing us to deal with the current pricing challenges and puts us in a great position for continued growth. Our financing requirements for 2015 and 2016 are meaningful but our outspend is driven almost entirely by our investments and our long term midstream infrastructure. Dave will talk about the debt financing we completed in June to cover our 2015 capital program. And looking ahead in next fiscal year as we’ve said in the past the MLP structure is an option that we’re evaluating for our midstream business and given the right market condition we think it’s a very good option. The MLP market and frankly the entire energy space is under pressure right now but markets go up and down and just because there is a dislocation today doesn’t mean it will continue forever. And MLP is not only option, there are number of ways to finance our business. We’re certainly aware of our capital needs in fiscal 2016 and we’ll pick the financing option that we think is best for our shareholders. One thing is clear, there is lot of capital looking to be put to work in the midstream space. We have a great set of assets a great management team and a great plan to grow the business. In the end those are key to attracting the best sources of capital. Now I’ll turn the call over to Matt Cabell to give Seneca update. Matt Cabell Thanks Ron and good morning everyone. For the fiscal third quarter Seneca produced 36.2 Bcfe which is 11% or 4 Bcfe less than last year’s third quarter. However during this year’s third quarter we sold only our firm volumes in the Marcellus and curtailed 12.5 Bcf or approximately 140 million cubic feet per day of potential spot sales due to low prices. Absent those curtailments production would have been up 20%. In California our 2015 drilling programs have had good results and provide attractive returns even at today’s low prices. At $50 oil we earn returns of 30% to 40% on wells we drilled in the North Midway, South Midway and East Coalinga areas which represents the majority of our current and fiscal 2016 capital budget. We are also feeling good about our opportunities to grow California production over the next several years due to opportunities we see at East Coalinga and add two additional farm-in deals that are near in completion. I hope to have these two deals inked by the next call and we’ll provide some details then. Moving on to the Marcellus development in the Clermont Rich Valley areas is going well with 52 Clermont area wells drilled in the first nine months of fiscal ’15 and 24 completed. Our most recent completion in the North half of our E9E pad came on at rates ranging from 8.5 million to 10 million cubic feet per day. IP rates and EURs have been remarkably consistent in the CRB area. We also continue to drive down drilling and completion cost. Our average fiscal 2015 development well cost was $5.8 million for a 36 stages well with 7,000 foot lateral length. On the marketing front we continue to take a portfolio approach to our marketing arrangements. Optimizing the value of our firm transportation while minimizing risks through a series of firm’s sales. For example this November the Northern access 2015 project will go into service we have 140,000 dekatherms of firm transport capacity locked up under firm sales contracts with Dawn Index pricing. Dawn continues to trade a premium, so we were able to convert a portion of the Dawn sales contracts to NYMEX plus $0.35 per MMBtu for November 1 through March 31. In addition, we recently requested proposals to purchase a portion of the gas we will transport in the Northern Access 2016 project. We were pleased with the diversity and number of parties that participated and are currently negotiating a mix of Dawn Indexed and fixed price deals tied to a portion of our capacity on the project. Our active marketing and hedging program has gone long way to insulate Seneca from low natural gas prices. For the third quarter our average after hedging sales price was $3.32 per Mcf, which is over a $1 higher than the pre-hedged price. Looking forward to fiscal 2016 we now have a 114 Bcf of our gas production locked in both physically and financially at an average price of $3.50 per Mcf so we are well positioned should low prices persist in to next year. Moving now to the Utica, I am sure that many of you saw the high rate test that we announced by our peers in Westmoreland and Green Counties. We have two Utica test planned that should connect the trend between these recent wells and Tioga County where our recent Utica well tested 22.7 million cubic feet per day. As I mentioned on our last call the planned wells will be drilled in conjunction with our ongoing Marcellus development in the Clermont area. The rig is just moved to the E9-M pad where we plan to drill 10 Marcellus wells and one Utica. This will be a 5,500 foot lateral with an expected total cost of about $12 million. We expect to frac this pad in the third quarter of fiscal ‘16 and should have a test rate shortly thereafter. Given our larger contiguous fee acreage position a successful Clermont area Utica test could have a major impact on Seneca’s overall resource potential. In summary, our development program continues to show consistent predictable results. We are driving down costs and locking in margins through firm sales and hedging, although we’re dropping a rig early in ‘16 and reducing our capital spending from 2015 to 2016. We are on track to fully utilize the 700,000 dekatherms of firm transportation that we’ll have in 2017 and in addition to thousands of de-risked Marcellus well locations. We are optimistic about the potential for Utica development across a broad swap of our acreage. With that I’ll turn it over to Dave. Dave Bauer Thank you, Matt. Good morning everyone. Ron hit on the major drivers for the quarter’s earnings and other than the impairment charge there really wasn’t anything unusual on the quarter. Last night release explains the major variances in earnings, so I won’t repeat them again here. Instead I will focus on our expectations for the remainder of the fiscal year and our initial guidance for next year. With respect to 2015 our updated earnings guidance is $2.90 to $3 per share excluding ceiling test impairments. That’s up from our previous range of $2.75 to $2.90 mostly due to lower expected DD&A expense. As a result of the third quarter ceiling test charge we expect Seneca’s per unit DD&A rate for the fourth quarter will be in the $1.35 per Mcfe area. That will lower the full year DD&A rate to about $1.55 per Mcfe at the low end of our previous guidance of $1.55 to $1.65. Production for the year is now expected to be 155 to 160 Bcfe. The midpoint is the level should achieve assuming we don’t sale any spot volumes in August and September. We haven’t produced above our level of firms sales commitments for the better part of the calendar year and based on the prices we’ve seen thus far we don’t think it’s likely we’ll have meaningful spot sales in the remainder of the fourth quarter. However should prices improved, we have the ability to produce about 4 Bcf per month into the spot markets. In terms of pricing we’re assuming Henry Hub price for natural gas of $2.75 per Mcf. However because all of the 2 Bcf of our firm sales for the quarter are hedged changes in natural gas price saw minimal impact on our earnings. For crude oil we’re assuming WTI price of $50 a barrel. That’s little higher than the current IMX [ph] prices, we are better than 60% hedge for the fourth quarter. Looking to next year our preliminary earnings guidance for fiscal ‘16 is a range of $3 to $3.30 per share excluding any ceiling test impairment charges. In terms of pricing we’re assuming a Henry Hub gas price of $3.25 per Mcf and a WTI crude oil price of $55 a barrel. In addition we’re assuming we’ll receive $1.75 per Mcf for Marcellus spot buy-ins. There has been considerable volatility in commodity prices particularly with respect to crude oil and we expect to refine our pricing assumptions as we move into the fiscal year. Seneca’s production forecast of 158 to 232 Bcfe has a wider than normal range which reflects the uncertainty around Appalachian gas pricing and our ability to sell spot volumes at an acceptable price. We’re optimistic that Seneca will have spot sales, but want to manage expectations given our recent experience. Therefore, we’re presenting a full range of potential outcomes. If we saw a 100% of our expected spot volumes will be at the high end of the range, if we don’t sale any spot volumes will be at the low end. From an expense standpoint the ranges you see on page 25 of last night’s release are all based on the 195 Bcfe mid-point of our production forecast. The improvements in per unit LOE, G&A and production tax expenses compared to our third quarter rates are attributable to the expected increase in Seneca’s production volumes. As you’d expect our DD&A rate will decrease sharply as a result of the ceiling test impairments. So we excluded our future ceiling test charges themselves from our earnings guidance. We have tried to estimate with the DD&A rate will look post impairments. However given number of variable that go into that calculation it’s possible the range will change meaningfully in the coming quarters. As you can see from pages 56 to 57 of our new IR deck we’re well hedged for fiscal ’16 and as Matt said earlier, we’ve locked in 114 Bcf of natural gas production at a price of about $3.50 per Mcf. And that equates to about 80% of our firm sales volumes and at the midpoint of our production forecast about 65% of our expected natural gas production. On the oil side we have about 1.3 million barrels hedged at $93 barrel which represents about 45% of our expected oil production. Together the excitement earnings and cash flow should track the increase in Seneca’s volumes. For fiscal ’16 assuming the midpoint of Seneca’s production forecast we expect the gathering excitements revenues will be about $95 million up from the 75 million to 80 million we forecast for fiscal ’15. As we add compression to Clermont system operating and depreciation expenses will increase meaningfully relative to their current levels. But a large portion of the revenue increase should fall to the bottom line. Turning to the regulated businesses fiscal ’16 should be a good year for the pipeline and storage segment. This fall the Northern Access 15, West Side expansion and Tuscarora Lateral projects go into service adding $27 million of incremental revenues in 2016. However that increase will be likely offset in part by a variety of smaller items including some typical re-contract again both pipeline system and a decrease in short term transportation revenue is somewhat weather related and recall the last winter was significantly colder than normal. Our forecast for 2016 assumes normal weather. Considering those items we expect pipeline and storage revenue for fiscal ’16 will be in the range of $300 million to $310 million. We expect ONM expense in this segment will increase to about $85 million to $90 million part of that increase relates to higher operating cost associated with our recent expansion projects and part relates to an expected $4 million increase in the retirement benefit cost which is driven by some anticipated changes in our plans actuarial assumptions. Lastly with respect to the utility, we’re expecting a decline in that segment earnings in fiscal ’16 for two reasons. First as I just mentioned our forecast assumes normal weather. In fiscal ’15 colder than normal weather contributed about $0.05 per share at earnings. Additionally, as you recall in the second quarter of fiscal ’15 an audit in the New York division of the utility resulted in an adjustment to benefited earnings by about $0.04 of share. And we don’t expect that adjustment will recur in 2016. Turning to capital spending page 7 of our new IR deck contains our updated capital spending estimates for fiscal ’15. We narrowed our consolidated guidance to a range of 990 million to 1.045 billion at the midpoint of $55 million decrease from our previous guidance. About half of the decrease is related to the timing and spending between fiscal years in the E&P gathering and pipeline segments. The other half relates to the utility Dunkirk project at the timing of which is become less clear. The owner of the power plant that would be served by the project is facing some legal and regulatory challenges with respect to its repurchasing of the plant. We stand ready to build the project once those challenges are resolved but given the uncertainty we are removing the project form our capital budget. For fiscal ’16 our consolidated range is now 1.1 billion to 1.3 billion, up modestly from our previous guidance. There aren’t any major changes in our spending plans the variation are mostly attributable to timing. Given the changes in our earnings and capital spending guidance we now expect and outspend in fiscal ’15 that’s just under $400 million. In June we issued $450 million of long term debt to fund that outspend. Looking to next year we expect our capital expenditures and dividend, we’ll exceed cash from operations in the range of 500 million to 600 million. We have short term credit facilities to initially finance that outspend if it’s necessary and as you know we’re evaluating longer term financing alternatives. As a place older our earnings guidance for fiscal ’16 assume we use terms we used short term debt and we’ll obviously updates that guidance we refine our ultimate financing finance. With that, I’ll close and ask the operator to open the line for questions. Question-and-Answer Session Operator [Operator Instruction] Our first question comes from Becca Followill, U.S. Capital Advisors. Please go ahead. You are now live in the call. Becca Followill Couple of questions for you, one I know that you sounded you’ve taken off some of the list in the short term in the Dawn hedges in favor of a higher NYMEX price. What we’re seeing so far is what we have tried to estimate with the DD&A rate will look post impairments. However given number of variable that go into that calculation it’s possible the range will change meaningfully in the coming quarters. As you can see from pages 56 to 57 of our new IR deck we’re well hedged for fiscal ’16 and as Matt said earlier, we’ve locked in 114 Bcf of natural gas production at a price of about $3.50 per Mcf. And that equates to about 80% of our firm sales volumes and at the midpoint of our production forecast about 65% of our expected natural gas production. On the oil side we have about 1.3 million barrels hedged at $93 barrel which represents about 45% of our expected oil production. Together the excitement earnings and cash flow should track the increase in Seneca’s volumes. For fiscal ’16 assuming the midpoint of Seneca’s production forecast we expect the gathering excitements revenues will be about $95 million up from the 75 million to 80 million we forecast for fiscal ’15. As we add compression to Clermont system operating and depreciation expenses will increase meaningfully relative to their current levels. But a large portion of the revenue increase should fall to the bottom line. Turning to the regulated businesses fiscal ’16 should be a good year for the pipeline and storage segment. This fall the Northern Access 15, West Side expansion and Tuscarora Lateral projects go into service adding $27 million of incremental revenues in 2016. However that increase will be likely offset in part by a variety of smaller items including some typical re-contract again both pipeline system and a decrease in short term transportation revenue is somewhat weather related and recall the last winter was significantly colder than normal. Our forecast for 2016 assumes normal weather. Considering those items we expect pipeline and storage revenue for fiscal ’16 will be in the range of $300 million to $310 million. We expect ONM expense in this segment will increase to about $85 million to $90 million part of that increase relates to higher operating cost associated with our recent expansion projects and part relates to an expected $4 million increase in the retirement benefit cost which is driven by some anticipated changes in our plans actuarial assumptions. Lastly with respect to the utility, we’re expecting a decline in that segment earnings in fiscal ’16 for two reasons. First as I just mentioned our forecast assumes normal weather. In fiscal ’15 colder than normal weather contributed about $0.05 per share at earnings. Additionally, as you recall in the second quarter of fiscal ’15 an audit in the New York division of the utility resulted in an adjustment to benefited earnings by about $0.04 of share. And we don’t expect that adjustment will recur in 2016. Turning to capital spending page 7 of our new IR deck contains our updated capital spending estimates for fiscal ’15. We narrowed our consolidated guidance to a range of 990 million to 1.045 billion at the midpoint of $55 million decrease from our previous guidance. About half of the decrease is related to the timing and spending between fiscal years in the E&P gathering and pipeline segments. The other half relates to the utility Dunkirk project at the timing of which is become less clear. The owner of the power plant that would be served by the project is facing some legal and regulatory challenges with respect to its repurchasing of the plant. We stand ready to build the project once those challenges are resolved but given the uncertainty we are removing the project form our capital budget. For fiscal ’16 our consolidated range is now 1.1 billion to 1.3 billion, up modestly from our previous guidance. There aren’t any major changes in our spending plans the variation are mostly attributable to timing. Given the changes in our earnings and capital spending guidance we now expect and outspend in fiscal ’15 that’s just under $400 million. In June we issued $450 million of long term debt to fund that outspend. Looking to next year we expect our capital expenditures and dividend, we’ll exceed cash from operations in the range of 500 million to 600 million. We have short term credit facilities to initially finance that outspend if it’s necessary and as you know we’re evaluating longer term financing alternatives. As a place older our earnings guidance for fiscal ’16 assume we use terms we used short term debt and we’ll obviously updates that guidance we refine our ultimate financing finance. With that, I’ll close and ask the operator to open the line for questions. Question-and-Answer Session Operator [Operator Instruction] Our first question comes from Becca Followill, U.S. Capital Advisors. Please go ahead. You are now live in the call. Becca Followill Couple of questions for you, one I know that you sounded you’ve taken off some of the list in the short term in the Dawn hedges in favor of a higher NYMEX price. What we’re seeing so far is what direct reversal completion that just trying to get basis for in Chicago, can you talk little bit about your capacity going to Dawn on and how much you have hedged. In the out years thoughts which is short debt maybe 17, 18, 19? Ron Tanski You have referenced from the slide deck. Back on page 27 is our IR deck is our hedge positions going out. We don’t have a larger amount of longer term hedges in place for 2016 we have 19 Bcf at Dawn, 2017, 22 Bcf and a more modest amount financially hedged that fit on. Becca Followill Is there enough liquidity to hedge out some of this in future years? Dave Bauer We are looking at that and we haven’t looked much beyond 2018 but we haven’t had really any difficulty executing trades in the closer years. Becca Followill And what did some other spreads look like relative to historical, are they already reflecting some pressure on that basis? Dave Bauer Well, the trade that we’ve done have generally than it a premium to NYMEX, obviously you go further out the liquidity discount gets to be a bit greater so for example in the near years we may be doing at a full year NYMEX plus 10 to 20 or so but then as you’ve move towards the 18 time period that roads to more NYMEX flat type level. And as you move beyond that, we do get indicative levels but the liquidity premium tends to increase quite a bit. Becca Followill Thank you. That’s helpful. On the well cost for Utica the 12 million that you’ve talked about the new well that you’re going to drill, what’s the depth on that in some of the early wells that we’ve seen, I know you’ve drilled a couple already but some of the early ones that we’ve seen from ECTE and coming in much, much higher than that? Ron Tanski Yes, depth for our Clermont Utica well is on the order of 10,500 feet true vertical depth. So it’s a little shallower. But I would say the bigger factor is that we’re drilling this on an existing Clermont Marcellus pad. So the infrastructures there its sharing pad cost with 10 other wells. Our water handling is all in place you don’t have to truck water from the long distance. So there is a big, big benefit to developing something like this as part of an existing development rather than one-off well that’s far from everything else. Becca Followill Got you. Thank you. And then will that 12 million include some of the normal science cost that happen with early wells to drive that up a little but higher? Ron Tanski Yes, there isn’t a whole lot of additional science in this particular well and I would also say that well cost estimate is probably on the conservative side. I hope we can do cheaper than that. Becca Followill Right, thank you. And then on the financing for 2016 the short fall of $500 million to $600 million, I know maybe you said you’re going to — right now in the plan it’s short term debt, at what point or what’s the timeframe if you’re looking to make a decision on whether or not you’ll financial it differently? Ron Tanski Well, as Ron said we’ve been evaluating NPL and other structures and as we move through the year and start to spend dollars on Northern Access, we’ll be announcing our definitive financing plans. Becca Followill The changes in what happened with NLPs lately and then downturn cause you in that anyway? Ron Tanski Well, not really Becca, we had just given the previous schedule we’ve talked about with respect to receiving the first certificate and when construction activity actually begin hasn’t changed. So we’ve got some time, obviously the market is going to do something, what it’s going to do we’re not sure, but we think no one is going to try to call a bottom here anytime soon but we may have already passed that, but that’s far enough out, that to talk about it in any kind of detail, would just to be able to bit premature. Becca Followill Understand. Thank you, guys. Operator We have no further questions. [Operator Instructions] We have another question and it comes from the line of Holly Stewart of Howard Weil Please go ahead. Holly Stewart Matt, maybe just one or two for you, several of your peers I guess have been talking about deferring completions as they’re heading into 2016 just to have that baseline of production growth and you’ve got quite a bit of volume curtail. But curious how you’re thinking about different completion as you kind of exit the year into ’16. Matt Cabell Yes so as I mentioned in my prepared comments at Clermont we drilled 52 wells, only completed 24. We expect to end the year — to end ’16 was about 50 wells that are drilled, but not completed. Although I think that number may include a handful that are completed and just not online at that time. Holly Stewart Is that in ’15 or in ’16 sorry? Matt Cabell The end of fiscal ’15. At the end of fiscal ’16 or best guess is about 65 wells that are drilled but not completed. Recognizing that with Northern Access 16 coming on at the end of the year we’ll probably have a fairly big slug of completion in that time frame just right after the end of fiscal ’16. Holly Stewart Okay so that kind of what bridge is that gap if you look at slide 18, I think it where it says the firm sales to future SE capacity and going from the 220 to 660. So that’s really what’s helping get you up to that rate as you enter into fiscal ’17? I’m assuming. Matt Cabell I’m finding the reference on the slide — you mean the gap between fiscal ’16 and fiscal ’17. Yes there is a big slug of completions for us. And the other thing that happens is we go from an assumption of some curtailments of spot volumes to not really having to curtail any more spot because we’ve got the firm transportation in fiscal ’17. Holly Stewart And maybe just kind of along the same lines, just kind of curious as your macro view. You’ve obviously got a lot shut in, but you also have from a spot fill standpoint, there’s the potential to shutdown lot more in 2016. So is there anything that you’re seeing out there as you look into your crystal ball and just ended 2016 from a Northeast PA standpoint, that there could be some pricing or release? Ron Tanski As we look at the projects coming on there is two projects that come on kind of late this year. Sort of the beginning of the winter that should de-bottle neck Northeast Pennsylvania to some degree. And our view is that winter spot pricing given normal weather and it may at least be acceptable such that we’ll be selling some spot this winter. It’s difficult to predict that Holly but there is our best guess. I would expect that that would be a winter phenomenon though, not necessarily for the full year. Operator Our next question comes from the line of Chris Sighinolfi from Jefferies. Please go ahead. Chris Tillett This is Chris Tillett on for Chris Sighinolfi how are you? Just a follow up on Becca’s question obviously the MLP has been on the lot of investors mind recently and given the kind of the turn-in in outlook in the market. I’d just be curious to hear your thoughts on some of the alternatives you’re considering and how you think about approaching this process in a non-MLP world. Matt Cabell I think if you obviously it’s a rather recent phenomena with respect to the MLP market. But I was thinking and really hasn’t changed all that much. And as I said it really would be premature to be talking about us pulling the trigger on any particular type of financing. Since we’ve given our schedule and given our timing we’ve have plenty of time to see how the market sort this self out. I guess that’s about all I’m prepare to say at this point. Operator We have no further questions. I would now like to turn the call over to Mr. Brian Welsch for closing remarks. Thank you. Brian Welsch Thank you, Halley. 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 pm Eastern Time on both our website and by telephone and will run through the close of business on Friday, August 15, 2015. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com. And to access by telephone, call 1-888-286-8010, and enter passcode 97670814. This concludes our conference call for today. Thank you and goodbye. Operator Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Have a great day. 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Chesapeake Utilities’ (CPK) CEO Mike McMasters Discusses Q2 2015 Results – Earnings Call Transcript

Chesapeake Utilities Corp. (NYSE: CPK ) Q2 2015 Earnings Conference Call August 7, 2015 10:30 ET Executives Mike McMasters – President and Chief Executive Officer Beth Cooper – Senior Vice President and Chief Financial Officer Analysts Michael Gaugler – Janney Montgomery Roger Liddell – Clear Harbor Asset Management John Hanson – Praesidis Operator Good morning. My name is Mariana and I will be your conference operator today. At this time, I would like to welcome everyone to the Chesapeake Utilities Second Quarter Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. Senior Vice President and Chief Financial Officer, Beth Cooper, you may begin your conference. Beth Cooper Thank you and good morning, everyone. We appreciate you joining us this morning to review our second quarter and year-to-date 2015 results. Joining me on the call today with prepared remarks is Mike McMasters, President and CEO. We also have several additional members of our management team here with us today to answer questions following prepared remarks. The presentation to accompany our discussion today can be accessed on our website at www.chpk.com under the Investor section and Events and Webcast subsection or via our IR app. Moving to Slide 2, before we begin, let me remind you that matters discussed in this conference call may include forward-looking statements that involve risks and uncertainties. Forward-looking statements and projections could differ materially from our actual results. The Safe Harbor for forward-looking statements section of the company’s 2014 Annual Report on Form 10-K, provides further information on the factors that could cause such statements to differ from our actual results. Finally, please note that earnings per share data, is shown on a fully diluted basis and reflects the company’s 3-for-2 stock split effective September 8, 2014. While second quarter results are typically lower due to the seasonality of our regulated and unregulated energy business segments, we are pleased to report quarter-over-quarter increases in net income and earnings per share driven by continued strong growth in our regulated energy distribution and natural gas transmission businesses. We also continue to execute on our strategic growth plans. On April 1, we closed on the acquisition of Gatherco. During the quarter, we made significant progress in our integration of Gatherco, which we have re-branded as Aspire Energy of Ohio. We are also continuing to develop and cultivate profitable growth opportunities in our natural gas and propane businesses across Delmarva and in Florida. Our Florida Gas Reliability Infrastructure Program, or GRIP, as we commonly refer to it, is generating increased earnings as we make natural gas infrastructure investments to further enhance the safety and reliability for our systems. Finally, the outcome of the Florida electric base rate case supplemented our earnings for the quarter. As shown on Slide 3, on Thursday, we announced second quarter 2015 net income of $6.3 million, or $0.41 per share, an increase of $1.2 million, or $0.06 per share compared to the same quarter in 2014. Second quarter 2015 results reflect the continued successful execution of our strategy to generate profitable growth from service expansions, acquisitions, major projects, continued investment in the GRIP program and the electric rate case in Florida. The growth in our Regulated Energy segment generated increased operating income that offset the weather-sensitive unregulated energy businesses. The second quarter’s results also included $900,000 after-tax gain or $0.06 per share from a settlement with a vendor related to a customer billing system implementation. As we look out over the rest of the year, we believe we are well-positioned to build on our successful track record given the Gatherco acquisition, several major projects currently in progress, and other key strategic actions we are undertaking. Mike will elaborate on these later in the call. I will now highlight the accomplishments and results for the two business segments during the second quarter. Detailed discussions of the changes in gross margin and other operating expenses by business segment for the quarter and six months ended June 30, 2015 are provided in our press release and quarterly report on Form 10-Q, both of which were filed on Thursday. Turning to Slide 4, Chesapeake’s Regulated Energy businesses, which include our natural gas transmission and distribution and electric distribution operations generated operating income of $13.6 million in the second quarter of 2015 compared to $10.7 million for the same quarter in 2014. The increase in Regulated Energy operating income reflected $4 million in additional gross margin from customer growth, the GRIP service expansions and the electric rate case. Other operating expenses increased by $1.1 million, which included a $1.5 million credit offset to expenses associated with the settlement for billing system implementation, which was mentioned earlier. Absent the offset, other operating expenses increased by $2.6 million. The increase in other operating expenses reflected higher payroll costs to support growth and as a result of increased quarterly results, other transaction cost, costs associated with system integrity and facility improvements as well as depreciation and other related costs because of increased investments. As shown on Slide 5, the Unregulated Energy segment reported a second quarter 2015 operating loss of $540,000 compared to an operating loss of $43,000 for the same period in 2014. A $2.1 million increase in gross margin for this segment was offset by a $2.6 million increase in other operating expenses. The Unregulated Energy segment has typically reported an operating loss or very modest earnings during the second quarter due to the seasonal nature of the propane distribution operations. Slide 6 highlights the key variances between second quarter net income and earnings per share results for 2015 and 2014. As mentioned earlier, earnings per share was $0.41, an increase of $0.06, or 17% quarter-over-quarter. First, there were several unusual items that in total resulted in a $0.05 increase in 2015 second quarter earnings per share. As previously mentioned, a settlement with a vendor on the implementation of a customer billing system contributed $0.06 per share. Also of a non-recurring nature, the sale of our Florida fuel line maintenance contracts to third-party during the second quarter of 2014 offset by the absence of BravePoint, which was sold in 2014 resulted in $0.01 lower earnings per share in the second quarter of 2015. In our Regulated Energy segment, increased gross margin of $0.17 per share was generated from the key growth drivers previously highlighted. In the Unregulated Energy segment, margins generated by Aspire Energy of Ohio, as well as higher retail propane margins accounted for an increase of $0.10 per share. The expenses associated with operating Aspire Energy of Ohio as well as higher operating expenses largely driven by our continued growth, increased transaction cost as well as cost associated with system integrity and facility improvements offset this additional gross margin by $0.19 per share. Finally, interest and other net changes reduced quarter-over-quarter earnings per share by $0.06, including a $0.02 per share impact of dilution from the issuance of shares for Gatherco. Slide 7 highlights the financial results for the first six months of 2015 and 2014. We are pleased to report that the first six months have been very strong. The company reported diluted earnings per share of $1.83 for the first six months of 2015, up $0.26 or 17% over the same period in 2014. Increased operating income from the Regulated and Unregulated Energy segments contributed almost equally to the higher earnings for the first six months, which was supplemented by the absence of an operating loss in 2015 from BravePoint. Slide 8 highlights the key variances in terms of net income and earnings per share contribution between the results for the first six months of 2015 and 2014. Unusual items resulted in an $0.08 increase in earnings per share for the first six months of 2015. In our Regulated Energy segment increased gross margin of $0.34 per share was generated from natural gas customer growth, service expansions in the natural gas transmission businesses, the GRIP program in Florida and the electric rate case. In the Unregulated Energy segment, margins generated by Aspire Energy of Ohio, higher retail propane margins, and increased customer consumption which were partially offset by lower wholesale propane volatility opportunities for Xeron accounted for an increase of $0.28 per share. Higher operating expenses associated with the addition of Aspire Energy of Ohio, the cost of serving growth and expansions as well as increased results year-to-date, other transaction costs and system reliability and facility improvement costs partially offset this additional gross margin by $0.34 per share. Interest charges and other changes reduced year-to-date earnings per share by $0.10, including a $0.04 per share impact of dilution from the issuance of shares for Gatherco. Slide 9 highlights the company’s commitment to maintaining a strong balance sheet, which should facilitate access to competitively priced capital to fund our growth initiatives. Our equity to permanent capitalization was 69.2% and equity to total capitalization was 57.5% at the end of June 2015. We target to maintain a ratio of equity to total capitalization of 50% to 60% and will access longer term capital as necessary to meet our financing needs. Our financial success has been a result of our ability to identify significant opportunities to invest in growth, while maintaining our disciplined capital allocation process. We set targets for new investments and pursue profitable growth opportunities that meet our investment objectives, while achieving target returns. The level and impact of the capital investments we have made has continued to fall through the earnings and dividend growth and ultimately the shareholder return that have consistently set us apart over the last eight years. The current forecast for 2015 capital expenditures is $160 million to $190 million as shown on Slide 10. This does not include the $52.5 million acquisition of Gatherco, net of the cash acquired in the transaction. The current forecast is less than our original budget of $223 million. The change in our forecast represents a shift in the timing of the spending on some items from 2015 to 2016 and does not reflect a reduction in our planned investments for future growth. Of the forecasted expenditures for 2015, $115 million to $145 million are expected to be invested in our regulated energy operations. In terms of the large projects, we have previously disclosed the associated 2015 capital expenditures include $27.7 million for the Eight Flags combined heat and power plant and related facilities; $12.7 million for the Calpine mainline expansion; and our projected spend of approximately $29 million for GRIP. Our team works closely with our customers to develop and deliver customized solutions that fulfill their energy needs and also achieve the financial objectives of both parties. The projects we are undertaking today are much more diverse and larger in terms of their magnitude. In addition, it is important to note that there is a lag between the finalization of a budget estimate for a project and inclusion in our capital budget when we are positioned to announce the project and then ultimately when it is placed into service. The permitting and regulatory processes have become much longer and have expanded the overall timeline of the projects. As we have mentioned previously, we have historically spent 82% to 88% of the original capital budget that we announced at the beginning of the respective years. We are committed to making future investments in our businesses in a disciplined manner that represents valued, customized energy solutions for our customers at attractive returns for our shareholders. Now, I will turn the call over to Mike. Mike McMasters Thank you, Beth. Good morning, everyone. As we have previously discussed, we update our strategic plan every year. We ask our business unit leaders to engage our employees to figure out ways to go at rates faster than they could if they simply continued to do what they are doing today. As reflected on Slide 11, we are continuing to the implementation of our aggressive growth strategy. This slide summarizes the largest projects and acquisitions that are contributing to our growth in 2015. The recent Gatherco acquisition, now Aspire Energy, contributed approximately $1.6 million in margin during the second quarter, as expected to contribute approximately $8.8 million in 2015. The expansions to provide new services to transmission customers in New Castle and Kent Counties, Delaware and Polk County, Florida added $919,000 in gross margin during the second quarter of 2015 and $2.4 million of gross margin during the first six months of 2015. For the full year of 2015, these expansions are expected to generate gross margin of $5.3 million, an excess of the margins that they generated last year. We expect to spend about $29 million on the GRIP safety program during 2015. The increase in margin contribution from the GRIP program for the second quarter and first six months of 2015 were $1.1 million and $1.8 million, respectively. Turning to Slide 12, on April 1, 2015 we completed the acquisition of Gatherco and merged the company into our newly formed subsidiary, Aspire Energy of Ohio, LLC. The enterprise value net of cash acquired was $52.8 million. Aspire operates 16 gathering systems and over 2,400 miles of pipeline in the areas in and around the Utica Shale in Eastern and Central Ohio. The company serves more than 300 producers with gathering and liquids processing services and also delivers natural gas to two local distribution companies that serve approximately 30,000 customers. We believe that there are significant growth opportunities period to add both production and distribution customers to the system. Aspire also owns variable rights of way that could present additional opportunities for growth as shale development continues in Ohio. We are making good progress in the integration of Gatherco into the Chesapeake family. As we indicated, we announced the transaction we have rebranded Gatherco as Aspire Energy. We recently announced that Doug Ward joined our team as Business Unit Leader and Vice President of Aspire Energy. Doug has 25 years of leadership experience in the natural gas industry. We have moved some administrative functions to Chesapeake’s headquarters and have began the implementation of our safety, environmental compliance and other programs. We have completed the management transition and have been successful in our employee and customer retention efforts and are in the process of filling the positions to support our growth plans for this business. We believe that Aspire Energy of Ohio will be accretive to earnings in its first full year of operations. Approximately 92% of the margins from natural gas services to producers and deliveries to the commercial and residential markets, which are tracking as expected. As anticipated, the current reduction in natural gas versus natural gas liquids spread has reduced margins for processing. Approximately 8% of the margin is from two processing facilities on the system. As a part of Chesapeake, Aspire Energy now has the resources to accelerate their growth in accordance with our strategic plan. We expect growth to come from additional sales to local distribution companies that we serve and additional gathering systems – gathering services to producers. Turning to Slide 13, in November of last year, we implemented a $3.8 million rate increase in our Florida electric distribution system. This increase generated $731,000 and $1.5 million in additional margin during the second quarter and first six months of 2015, respectively. We are also in the process of preparing a rate case for our Sandpiper Energy operation in Maryland. This filing is required to support the original rates that the Maryland PSC approved and we filed for approval of the acquisition and our original tariff. Finally, as a part of a settlement in Eastern Shore Natural Gas Company’s most recent rate increase, we are required to file a rate case with the FERC that will establish new rates effective February 1, 2017. Slide 14 summarizes two large projects that are currently under construction that are expected to be completed and contribute to earnings in 2016 and Eastern Shore’s system reliability project proposal filed with the FERC this year. In total, the two projects under development are expected to produce approximately $13.1 million in gross margin annually. In addition, at these projects we are continuing to work with our customers to develop projects and services that are responsive to their needs that are also expected to generate growth. Slide 15 describes in further detail the pipeline expansion to serve Calpine Energy Services’ Garrison Energy Center power plan. The project currently under construction will generate significant additional margins beginning in 2016. Eastern Shore Natural Gas will invest approximately $30 million to build facilities to serve Calpine Energy’s Garrison Energy Center in Kent County. Eastern Shore provided Calpine with firm service during the non-heating months from May to October and provided interruptible service from November to April. This project is expected to go into service during the first half of 2016 and should provide an additional $5.8 million of annual margins. Turning to Slide 16, as a part of our ongoing efforts to maintain the quality of our service to our customers, we continuously monitor our systems to ensure that they are operating as designed or expected. During the polar vortex, in the first quarter of 2014 we experience sort of challenges. Accordingly, we reevaluated or system and concluded that we should invest in more facilities to maintain the reliability of our system and provide more operating flexibility to address future unforeseen circumstances. The project is estimated to cost $32.1 million and involves the installation of one compressor and 10.1 miles of 16-inch pipeline. The Federal Energy Regulatory Commission or FERC has accepted and publicly noticed Eastern Shore application. Eastern Shore has requested FERC issue an order granting the certificate for the project by December 2015. The targeted in-service date for this project is the third quarter of 2016. Slide 17 describes in further detail the second major project under construction, Eight Flags Energy. Eight Flags Energy is constructing a combined heat and power plant that will be located on Amelia Island, Florida at the Rayonier Advanced Materials paper mill. The plant will have 19 megawatts – 20 megawatts of generation capacity and all electricity generated will be sold to our electric distribution system in Florida. Steam from the plant will be sold to Rayonier Advanced Materials and a contract for these sales has been executed. The combined heat and power plant and the related facilities will cost approximately $40 million to construct. Site construction has started on July 13, 2015. In addition to generating approximately $7.3 million in incremental annual gross margin, the electric output from the plant is expected to reduce our purchased electric costs thus saving our electric customers approximately $3 million to $4 million annually. The project is expected to be online in the third quarter of 2016. Turning to Slide 18, the environmental and economic advantages of natural gas continued to provide opportunities for the expansion of its use in our service territory and across the United States. Natural gas is an abundant, clean and affordable fuel and the significant reserves that we have here in the United States continued to provide security of supply and price. This is reflected in the comparison of energy prices on the Slide 18. As indicated, even with the falling price of oil last year, natural gas still enjoys a price advantage compared to oil and is expected to maintain this advantage for the foreseeable future. This natural gas price advantage coupled with our other competitive advantages creates the opportunities for continued growth. Turning to Slide 19, we see attractive opportunities for growth across our energy businesses. As in the past, we will continue to look for profitable opportunities in natural gas distribution and transmission businesses. As a result of past expansions, we continued to be positioned to provide service to many new customers where service was not previously available. To maximize this opportunity, we have implemented conversion programs to make it easy for these customers to convert to natural gas. As evidenced by the development of our Eight Flags’ CHP plant, we are also looking to provide new services to our existing customers. Finally, we expect to generate additional margins for initiatives such as the GRIP program, providing natural gas service to power generators and other applications for natural gas. In the unregulated business we will continue to pursue profitable opportunities both inside and outside of our current footprint. Increased housing activity will generate growth in our community gas system and startups initiatives. In the vehicular fuel market, we currently operate five public and six private propane fueling stations. We are currently negotiating with a number of companies and organizations to provide this service and expand our market in Florida, Maryland, Pennsylvania and Delaware. While this initiative is relatively small today, it is an example of a strategy that could supplement our growth down the road. Additionally, combined heat and power projects, compressed natural gas and midstream opportunities all represent potential avenues to supplement growth in this segment. Turning to Slide 20, we believe that the key to our success has been and will continue to be our ability to identify and develop opportunities to invest significant amounts of capital at returns to justify investment. As the chart on Slide 20 shows Chesapeake ranks near the top of 43 gas distribution, electric and combination companies in terms of capital invested and return on capital over the past 3 years. Our ability to achieve higher than industry average returns while investing higher than industry average levels of capital relative to our size is the cornerstone of our strong financial results. Slide 21 shows our continuous dividend growth. On May 6, 2015, the Board of Directors increased the company’s annualized dividend by $0.07 or 6.5%. Compound annual growth in the dividend over the past 5 years has been 5.5% and has been supported by earnings growth, as evidenced by an average payout ratio of 46% over the 5 years ended 2014. We understand how important dividends are to investors, particularly given the expectations for broad total market returns. We also believe that superior earnings and dividend growth will enhance shareholder value going forward. We are committed to dividend growth supported by earnings growth and believe that with the growth potential in and outside our service territories and our low payout, we are well-positioned to provide superior dividend growth in the future. As the shareholder return chart on Slide 22 shows, Chesapeake has produced top quartile total return to shareholders for the FERC 1, 3, 5, 10 and 20 years ended June 30, 2015. For each of the five periods shown said, Chesapeake shareholders have earned more than 14% returns on a compound annual basis. Slide 23 shows our financial performance over the past 1, 3 and 5 years. I am proud to say that our employees have delivered top quartile performance in 18 out of 20 categories. Further, our 10 year and 20 year compound annual total shareholder returns are 14% and 14.4% respectively, ranked the first amongst our peers. We will work hard to sustain our performance and track record going forward. Turning to slide 24, as we have said before our success starts with engaged, dedicated and capable employees that construct and operate safe, reliable energy delivery systems whether they are pipelines, wires or trucks. Our employees take care of our customers and the communities we serve. They also do a remarkable job of identifying, developing and transforming growth opportunities in a disciplined manner. We manage regulation to produce the free returns to shareholders. Our employees drive for growth, their determination and consistent performance enables us to deliver clean, reliable, low cost energy solutions to our customers, generate returns on capital that are above peer group medians and as a result access the capital necessary to sustain our growth. We will now be happy to take questions. Thank you. Question-and-Answer Session Operator [Operator Instructions] Your first question comes from the line of Michael Gaugler from Janney Montgomery. Your line is open. Michael Gaugler Good morning everyone. Mike McMasters Good morning Mike, how are you doing? Beth Cooper Good morning. Michael Gaugler Just one question Mike, on the White Oak mainline expansion project, the 7 miles or so, 16-inch pipe that’s going to loop in Chester County, does that actually in Chester County open up any other opportunities for further service expansions in the region perhaps maybe a little more in Pennsylvania versus Delaware or both? Mike McMasters Well, I guess every time – generically, I guess, Mike, every time we extend a pipeline facility somewhere there are some opportunities that get opened up. We haven’t identified as we speak here today any opportunities along that section of pipe. Michael Gaugler Okay. Just notice where that’s probably going to cross and figure there might be something else behind it in terms of expansions? Mike McMasters Yes. We do look for those, Mike, so… Michael Gaugler Okay, thanks. Operator Your next question comes from the line of Roger Liddell from Clear Harbor Asset Management. Your line is open. Roger Liddell Thank you and good morning. Mike McMasters Good morning, Roger. Roger Liddell I wanted to follow-up with a question on combined heat and power opportunities in Florida. And of course, Eight Flags looks to be a superb example of those opportunities. And I wanted to put it in the context of there is some nuclear construction underway in South Carolina and Georgia. And my recollection is that Turkey Point is still assumed to be built in Southern Florida. The most recent publicity I have seen on Georgia Power’s Plant Vogtle 3 and 4 is that the dates and budgets are almost unknowable. And assuming the last published figures on budget and on completion dates holds, which I think is highly unlikely. The present value of continuing the construction and benefit over the lifetime of Plant Vogtle versus just stopping now and going gas that benefit of continuing nuclear eroded at almost 40% in the last year. So, here it is close to Florida, what could be a startling example of the questions, the issues of pursuing nuclear, which takes us to Turkey Point and it maybe that those plants wind up being canceled out of common sense and prudence. So, I should think the opportunities in Florida for meaningful rollout of additional combined heat and power could be an even more attractive opportunity. Could you respond to that? Mike McMasters I would say, Roger, we agree with that. The opportunity on Amelia Island was one. There is multiple opportunities that we see in the southeastern part of the country and we are looking at those – and they are, as you know, very complex, at least from our perspective, they are complex to develop and to some degree, you have to be careful with what’s the economic situation given the replacement power cost, but we are optimistic about that and are looking at opportunities for combined heat and power more than one. So, this project actually has opened up, has caught some people’s attention. I think we are cautiously optimistic that we will be able to get something develop. It will take some time. I suspect this project in particular that we are doing took several years to come to a contractual agreement and then obviously some permitting etcetera and then finally construction. So, there will be a long lead time on these projects. Roger Liddell Well, fair enough. But if you think they are complex, how would you like to be building nuclear? Mike McMasters That would be, I would agree, multiple increased complexity. Roger Liddell Yes. Well, I understand your point of the lead times and the caution that you have demonstrated before you go after these opportunities. I appreciate that. I guess you are not in a position to throw goals or aspirations out there perhaps in the future call you would be able to do so but I remain optimistic on the opportunity for the company? Mike McMasters Yes. If we – as we move down this road, if there comes a point where we may, we have multiple opportunities that were close to and maybe able to put some sort of expectation out there. But right now, it’s we are talking about multiple opportunities, but we are not at a place where we are getting to a point where it’s even 50% probable, I would say. Roger Liddell Fair enough. Thank you. Mike McMasters You are welcome. Operator [Operator Instructions] Your next question comes from the line of John Hanson from Praesidis. Your line is open. John Hanson Good morning. Mike McMasters Good morning, John. Beth Cooper Good morning. John Hanson Just a quick question, you mentioned the CapEx was going to slide from ‘15 to ‘16, what kind of projects are we sliding? Beth Cooper In particular, John, some of those projects that we talked about, for example, the Eight Flags project in total, that’s a project. The capital cost is about $40 million. We expect to incur about $28 million of that this year, but there will be a chunk that moves into next year. And in our original capital budget, more of that was actually falling into the current year. Similarly, some of the other larger projects that we are looking at that necessarily, they haven’t been finalized. The timeline on some of those have also slipped. So, from our standpoint, its expansion projects that we are trying to look at, those that are both announced as well as those that are in the pipeline as well as – there maybe a few dollars as it relates to the Calpine project, those types of things that may move from year-to-year. Mike McMasters And some of that, John, is driven by permitting and regulatory timelines, expanding here more recently. John Hanson On the Eight Flags project, it is still targeting that in service July next year? Beth Cooper Yes. John Hanson Okay. Alright, thanks. Mike McMasters Yes. Operator There are no further questions at this time. I would like to turn the call back over to President and CEO, Mike McMasters. Mike McMasters Thank you everyone for joining us on our call today and for your interest in Chesapeake Utilities. We are proud of what our team has accomplished for shareholders in the past and we are committed to working hard to deliver superior shareholder results in the future. Thank you. Beth Cooper Thank you. Operator This concludes today’s conference call. You may now disconnect.