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Public Service Enterprise’s (PEG) Ralph Izzo on Q3 2015 Results – Earnings Call Transcript

Public Service Enterprise Group Inc. (NYSE: PEG ) Q3 2015 Earnings Conference Call October 30, 2015 11:00 AM ET Executives Kathleen Lally – VP of IR Ralph Izzo – Chairman President & CEO Dan Creeg – EVP & CFO Analysts Paul Patterson – Glenrock Associates Travis Miller – Morningstar Michael Lapides – Goldman Sachs Sophie Karp – Citigroup Gregg Orrill – Barclays Capital Operator Ladies and gentlemen, thank you for standing by. My name is Kelly and I’m your event operator today. I would like to welcome everyone to today’s conference, Public Service Enterprise Group Third Quarter 2015 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, this conference is being recorded today, Friday, October 30, 2015, and will be available for telephone replay beginning at 1 PM Eastern time today until 11:30 p.m. Eastern time on November 6, 2015. It will also be available as an audio webcast on PSEG’s corporate website at www.PSEG.com. I would now like to turn the conference over to Kathleen Lally. Please go ahead. Kathleen Lally Thank you, Kelly. Good morning. Thank you all for participating in our earnings call this morning. As you are aware, we released third quarter 2015 earnings statements earlier today. As mentioned, the release and attachments are posted on our website at www.PSEG.com, under the investor section. We also posted a series of slides that detail operating results by Company for the quarter. Our 10-Q for the period ended September 30, 2015, is expected to be filed shortly. As, the earnings release and other matters that we discuss in today’s call contain forward looking statements and estimates that are subject to various risks and uncertainties and although we may elect to update those forward looking statements from time-to-time, we specifically disclaim any obligation to do so even if our estimate changes, unless of course we are required to do so. Our release also contains adjusted non-GAAP operating earnings. Please refer to today’s 8-K or other filings for a discussion of the factors that may cause results to differ from management’s projections, forecasts, and expectations, and for a reconciliation of operating earnings to GAAP results. I would now like to turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of Public Service Group, and also joining Ralph on the call today is Dan Creeg, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions and we ask that you limit yourself to one question and one follow up to give everyone an opportunity to join us on the call. Thank you. Ralph Izzo Thanks, Kathleen, and thank you everyone for joining us today. Earlier this morning we reported operating earnings for the third quarter of 2015 of $0.80 per share, that’s a 4% improvement over the $0.77 earned in 2014’s third quarter. The results for the third quarter bring PSEG’s operating earnings for the nine months ended September to $2.41 per share, which represents a 6% increase over the $2.27 per share earned during the first nine months of last year. Slides 4 and 5 contain the detail on the results for the third quarter and for the nine months. We delivered solid earnings in the third quarter and year-to-date, and we made excellent progress on our objectives for growing our business. PSE&G continues to deliver on the earnings promise of its expanded capital program and PSEG Power achieved solid operational and financial results driven by improved performance from its nuclear and combined cycle fleet. During the quarter, PSE&G recent agreement with the staff of the New Jersey Board of Public Utilities and the New Jersey Division of Rate Council that provided for PSE&G to invest $905 million over a three year period beginning next year to replace aging cast iron gas mains. Approval by the BPU later this year will allow PSE&G to continue the work begun under Energy Strong, supporting a clean, safe, and reliable gas system well into the future. This agreement follows upon BPU’s support earlier this year for a $95 million expansion of PSE&G’s investment in energy efficiency programs. PSE&G’s focus on improving the resiliency of the grid and increasing operational efficiency has translated once again into PSE&G being recognized as the most reliable utility in the Mid Atlantic region for the 14th consecutive year. PSE&G’s responsiveness was also recognized with receipt of the outstanding outage response time award for restoring customers 30% faster than any other large investor owned utility. This is by no means the end of the infrastructure and replacement needs for PSE&G and its customers. Turning to PSEG Power. It is increasing its investment in clean, efficient gas fired capacity. Power cleared a new 540 megawatt combined cycle gas plant at the Sewaren station as part of PJM’s reliability pricing model base residual auction. The new unit represents an investment of about $625 million to $675 million. The development of new capacity at Sewaren is in addition to Power’s announced plans to construct and operate a new 755-megawatt combined cycle unit at the Keys Energy Center in Maryland for between $825 million and $875 million. Both units are expected to achieve operational status in 2018. PSEG Power’s $1.5 billion investment will expand its gas-fired combined cycle capacity in its core PJM market to approximately 3,800 megawatts as Power’s overall gas-fired combined cycle capacity, which includes facilities in Bethlehem, New York grows to represent 4600 megawatts. PJM’s capacity performance initiative under RPM provided the correct incentives for investment. PSEG Power cleared approximately 8,700 megawatts at an average price of $215 per megawatt day. Auction prices reflected the increased risk of nonperformance associated with the auction’s new rules. Power adjusted its bidding strategy to reflect this new reality with an emphasis on availability and reliability under capacity performance. And we believe Power’s fleet is well positioned to perform given its dispatch flexibility, diverse fuel mix, and anticipated improvement in efficiency. The new paradigm underlying PJM’s capacity market is one sign of a more constructive regulatory environment for wholesale generating assets. The Federal Energy Regulatory Commission’s notice of proposed rule-making on energy price formation issued in September is further recognition that rule changes may be required to appropriately compensate generation for the true cost of operation. Our total planned investment program covering PSE&G and Power for the five-year period ending in 2019 has expanded by 20% since the start of the year and now totals $15.6 billion. Our investments in PSE&G are expected to improve the resilience of the grid as we replace aging equipment and meet customer needs for reliability. Our investment programs are projected to result in annual double-digit growth in PSE&G’s rate base for the coming five-year period. Our investment in PSEG Power should enhance our market position with improvements in the fleet’s efficiency and reliability. In a word, we are executing well in a dynamic market. Based on the strength of our results, we are updating our guidance for 2015’s operating earnings. We’ve narrowed our range for guidance as we’ve increased the lower end. For 2015, we are now forecasting operating earnings of $2.85 to $2.95 per share, which is different from our prior $2.80 to $2.95 per share. PSE&G has grown to represent more than half of our operating earnings as Power continues to provide strong free cash flow. We have maintained a disciplined approach to investing as our strong financial position supports growth without the need to issue equity. We intend to utilize our financial strength to meet the high standards for reliability expected by our customers and enhance the returns required by our shareholders. I’ll now turn the call over to Dan to review our operating results in greater detail. Dan Creeg Thank you, Ralph, and good morning, everybody. I’ll review our quarterly operating earnings as well as the outlook for full-year results by subsidiary company. As Ralph noted, PSEG reported operating earnings for the third quarter of 2015 of $0.80 per share versus $0.70 per share in the third quarter of last year. For the nine months ended September 30th, we reported operating earnings of $2.41 per share versus $2.27 per share last year. We provided you a waterfall chart on Slide 10 that takes you through the net changes in quarter-over-quarter operating earnings by major business and a similar chart on Slide 12 that provides you with the changes in operating earnings by each business on a year-to-date basis. I’ll now review each Company in more detail starting with PSE&G. As shown on Slide 14, the reported operating earnings for the third quarter of $0.44 per share compared with $0.39 per share a year ago. PSE&G’s earnings in the third quarter reflect the benefit of warmer than normal weather and an increase in revenue associated with PSE&G’s expanded capital program. The improvement in revenue more than offset a moderate increase in operating expenses. Returns from PSE&G’s expanded investment in transmission added $0.03 per share to earnings in the quarter. Weather conditions, which were much warmer than normal and warmer than a year ago, provided PSE&G’s earnings $0.02, improved PSE&G’s earnings by $0.02 per share. Earnings comparisons also improved by $0.01 per share due to an increase in electric demand coupled with revenue recovery and infrastructure related investment programs. And consistent with the first half of the year, PSE&G experienced an increase in pension expense resulting in a reduction in the quarter-over-quarter earnings of $0.01 per share. Electric sales grew 7% during the third quarter as residential customers responded to temperatures which produced 38% higher temperature humidity index than levels experienced in the year-ago period and 19% higher than normal. And on a weather-normalized basis, electric sales advanced 8/10 of a percent in the quarter and 4/10 of a percent for the nine months ended September. Growth for the nine-month period is in line with our long-term expectations for weather normalized electric sales growth. As Ralph mentioned, PSE&G reached settlement in principal with the staff of the BPU and the New Jersey Division of Rate Council on the Company’s gas system modernization program, or GSMP. The settlement provides for an investment of $905 million over a three year period beginning in 2016 and under the settlement we would invest $650 million in the program at a 975 return on equity with the remaining $255 million investment recovered as part of our next base rate case. And you may recall that we agreed as part of our Energy Strong program to file a base rate case no later than November 1, 2017. PSE&G with the addition of programs of proven pending has increased its investment program for the five year period ending in 2019 to $11.8 billion, and this represents a 10% increase in PSE&G’s capital investment plans since the start of the year and should support estimated annual double digit growth in PSE&G’s rate base over this time frame. PSE&G has also filed an update of its formula rate for transmission at the Federal Energy Regulatory Commission. The update supports PSE&G’s ability to earn its authorized return on an expanded capital base and would increase transmission revenues in 2016 by $146 million. Remember, PSE&G’s investment in transmission is expected to grow to about 50% of its rate base by the end of 2019 versus approximately 40% at the end of 2014. We’ve increased our forecast of PSE&G’s operating earnings for 2015 given strong year-to-date results and are now forecasting operating earnings of $785 million to $805 million versus $760 million to $775 million previously. Now turning to Power. Power reported operating earnings for the third quarter of 2015 of $0.33 per share and adjusted EBITDA of $401 million, and that’s compared with operating earnings of $0.34 per share and adjusted EBITDA of $386 million for the third quarter of 2014. Power’s results for the quarter reflect the impact of strong hedging and increase in operation from the gas fired combined cycle fleet, and an improvement in spark spreads which offset the effect of an expected decline in capacity prices. Higher average prices on energy hedges coupled with reduction in the cost of supply more than offset the impact on earnings of lower wholesale market prices for energy, and these items combine to increase Power’s quarter-over-quarter earnings comparisons by $0.07 per share. This improvement in margin in the quarter was partially offset by an expected decline in PJM’s capacity revenues which reduce Power’s quarter-over-quarter earnings by $0.03 per share. The reduction in capacity revenues reflects the retirement of 1800 megawatts of older inefficient peaking capacity that was no longer compliant with environmental requirements. The average price received on PJM’s capacity in the third quarter was in line with the year ago levels at $186 per megawatt day. Increase in O&M expense reduced quarter-over-quarter earnings by $0.03 per share. This increase in operating expenses primarily reflects differences in timing of outages at PSEGs Power’s nuclear facilities and is not an indicator of a higher embedded level of expenses. Lastly, the absence of prior year tax benefits reduced quarter-over-quarter earnings by $0.02 per share. As Ralph mentioned, in August PJM completed the RPM capacity auction for the 2018, 2019 year. More than 98% of Power’s capacity that cleared the auction met the new capacity performance or CP standards. The price Power will receive for capacity is expected to grow to $215 per megawatt day on average for the capacity year beginning June 1, 2018, from the $168 per megawatt day for the current year. On Slide 28, we have detail on the results of the latest capacity auction, including the number of megawatts that cleared the auction as well as the average price Power expects to receive for its capacity. Power cleared a new efficient combined cycle unit at Sewaren and plans to retire a similar amount of older inefficient steam units at that site. With the results of the latest auction, Power should see growth in its capacity revenues through 2018. The generating fleet’s operational flexibility continues to be demonstrated during this period of low energy pricing. Improved performance from the nuclear fleet and increased production in the gas fired combined cycle fleet offset a decline in production at the coal fired stations. Our nuclear fleet operated at an average capacity factor of 95% for the quarter, producing 7.8 TWh of output, representing 53% of total generation. This also represents a 3% increase in output. Performance of the nuclear facilities benefited from the absence of repair work at Salem 2 in 2014 and showed improvement year-over-year in spite of an early start to the refueling outage at Peach Bottom 3. Production from the gas fired combined cycle fleet increased 7% to 5.4 TWh for the quarter, representing 36% of total generation. The fleet operated extremely well running at an average capacity factor of 73% during the quarter in response to market demand. Output also benefited from the completion of capacity enhancement work at the Linden and Bergen stations which added 94 megawatts to the two stations over the past year. Warmer than normal summer weather had a favorable impact on the dispatch of our peaking fleet as dispatch of our coal fired assets was affected by lower wholesale energy prices. Wholesale market energy prices during the quarter continue to reflect a decline in the price of gas based on an overabundance of gas supply in the region, strong production of gas from the Marcellus Basin coupled with insufficient takeaway pipeline capacity has not unexpectedly resulted in lower prices for gas. Power’s combined cycle fleet benefited from its access to low cost gas supply in the summer and enjoyed strong spark spreads as power prices held up better than the price of gas. Power fleet is expected to produce energy at the lower end of its forecasted range of output for 2015 of 55 to 57 terawatt hours, reflecting reduced expectations for output from our coal-fired stations. This was slightly less than our prior forecast and would provide a nominal increase in output year-over-year. Approximately 80% to 85% of anticipated production for the fourth quarter is hedged at an average price of $52 per megawatt hour. Moving to 2016, Power has hedged 65% to 70% of its forecasted generation of 55 to 57 terawatt hours at an average price of $51 per megawatt hour. For 2017 Power has hedged 35% to 40% of its forecasted generation of 55 to 57 terawatt hours at an average price of $49 per megawatt hour. The percent of energy hedged in ‘16 and ‘17 is consistent with but at the lower end of the range for Power’s prescribed ratable hedging policy. And the forecast for ’16 and ’17 continues to assume that 11 to 12 terawatt hours of annual output are hedged at BGS prices. Forecast range for Power’s operating earnings for 2015 has been narrowed to $620 million to $650 million from the $620 million to $680 million prior range. This forecast of operating earnings represents adjusted EBITDA for the full year in the range of $1,545 billion to $1,595 billion. Now, turning to enterprise and other where we reported operating earnings of $11 million or $0.03 per share for the third quarter of 2015 versus operating earnings of $22 million or $0.04 per share in the third quarter of 2014 and the decline in operating earnings reflects the absence of prior year tax benefits at Energy Holdings partially offset by lower expenses and higher interest income at the parent. And the forecast for enterprise and other full-year earnings for 2015 remains $40 million to $50 million. And lastly relating to financing, PCG closed the quarter with $271 million of cash on its balance sheet with debt at the end of the quarter representing 41.5% of consolidated capital. PCG’s five-year capital program has increased to $15.6 billion with the announced agreements for PSE&G and Power’s plans to develop new capacity. PSE&G’s capital program represents 75% of our planned capital expenditures with Power’s capital program representing 25%. Given our strong balance sheet and expectations for Power’s free cash flow generation, we’re able to finance our capital requirements without the need to issue equity. So as mentioned, we are pleased to update our guidance for 2015’s operating earnings to $2.85 to $2.95 per share and results in this range would represent the third year of growth in operating earnings. And we’re now ready for your questions. Question-and-Answer Session Operator Ladies and gentlemen, we will now begin the question-and-answer session for members of the financial community [Operator Instructions]. Your first question will come from the line of Paul Patterson with Glenrock Associates. Paul Patterson Last quarter you were discussing potentially exploring the retail market and I was wondering if you had any update on that or any thoughts given the third quarter and what have you? Ralph Izzo Paul, it’s Ralph. We did talk about it and we still are considering different options. Again to the extent that we think about retail, it’s only in the context of the effectiveness of our hedges. This is not an offensive play. This is how do we make sure that assets that we own and operate in places like PS zone and in places like Eastern Mac and places like Bethlehem, New York, are effectively hedged when the liquid hub is at PJM west. So it’s really just about the effectiveness of hedging and how to make sure that we optimize that. So, one thing we did to make sure we hedge effectively by purchasing the Keys Energy Center. That’s not retail. That’s a way to get at managing basis differentials and effective hedges. So we are still looking at it, but nothing imminent to announce. Paul Patterson Okay. And then on the re-contracting and low cost of service — again a good quarter for that. Given where you see things heading into 2016, any thoughts about how that — how things look with respect to that? Ralph Izzo So that was definitely explicitly stated in Dan’s point of you view, right. So we don’t out guess the market. We have a very clear set of guidelines that we give our trading organization in terms of how much they can hedge in terms of max and mins, all based upon calculations of VaR and gross margin at risk, and we allow them to use their judgment in terms of how market sentiment might be affecting near term prices that may be slightly out of whack with respect to fundamentals, and we allow them to lean a little bit heavier in their hedging as they did last year which benefited us because prices did kind of come up pretty strong after last winter. And as Dan pointed out, right now we’re a little bit lighter than we would typically be hedged in 2017, but still within our normal range, not taking a strong point of view that the market has this all wrong, but you can infer from that that we think maybe there’s a little bit more bearishness in the market than is normally the case. Paul Patterson Okay. Thanks a lot. Operator Your next question will come from the line of Travis Miller with Morningstar. Travis Miller Good morning. Thank you. Ralph Izzo Hi, Travis. Travis Miller Real quick one. I want to clarify. Do you guys expect the BPU to decide on that gas replacement program later this year, is that right? Ralph Izzo We’re told it’s going to be on the November agenda. Travis Miller November agenda. Okay. Great. And then thinking more broadly here, those plants that you retired, what did you see during the summer in terms of how that capacity and ultimately energy at the peak levels was replaced? Were you guys picking up some of that? Were there other areas where you were seeing that replaced? Ralph Izzo Our Kearny peaking units did run during the summer. We did have to run our Hudson unit on gas during the summer, but Sewaren, the units that we replaced, did not run during the summer. Travis Miller Okay. So you’re picking up that mostly with your other facilities, is that? Ralph Izzo That’s right. We had some expansion in some of our combined cycle units which ran, our LM6000s ran, but the old steam units that sometimes in the past we had to turn on, we did not have to turn on this year. Dan Creeg A little bit of the peaking units were up as well. Coal units is where our volume was down. Our peakers picked up some of that volume. Travis Miller Okay. More strategically, how do you think now about enterprise and what you can do there when investments might go there, just that segment in general? Ralph Izzo Well, we see really two primary operating subsidiaries in power and in utility, Travis. The earnings that you see at enterprise really are borne out of some residual legacy leases on real estate that are very, very small and of course LIPA which is on an exactly as planned trajectory of starting out at $0.03, going to $0.08 by 2017. This year I think it’s about $0.03 or $0.04. Next year that will go up to $0.06 or $0.07 and then $0.07 or $0.08 two years after as per the contract. There are no plans to put a lot up at the parent level in terms of new businesses. Travis Miller Okay. Great. Thank you very much. Operator Your next question will come from the line of Michael Lapides with Goldman Sachs. Michael Lapides Hey, Ralph. Thank you guys for taking my question. I want to know if we should see what your investment in Power is for the next couple of years as a bit of a strategy shift or a bit of a view in the market? And the reason why I ask that is if I go back over the prior six or seven, six or eight years a lot of what you’ve done in Power is actually more of the harvest mode. Meaning, once you finish the environmental CapEx on Hudson and Mercer, a lot of what you had done at Power had either been divesting assets or realizing the significant cash flow, the free cash flow, that the remaining assets the large portfolio created. We’re now seeing a little bit of a shift and now you’re becoming much more of an investor in new assets, whether it’s building on existing sites or buying development projects. Is that a do you think the market has changed type of view or is there some other structural view that you’re trying to express in utilizing the cash flow that way versus other potential methodologies, either allocating it to the balance sheet or allocating it even more investment at E&G? Just curious. Ralph Izzo That’s a very good question, Michael. We do get that from a lot of our investors so I thank you for giving us a chance to answer it. It is definitely not a strategy shift. We believe that both businesses are quite viable, quite strong, and need to be tended to in terms of their investment and growth opportunities. I think if you look at a short enough period of time, you could create whatever strategy you want to from a short enough period of time, but if I just take you back over the last five years, PSE&G made up about 80% of the capital program versus Power being 20%, and if I look ahead five years based on what I know today, that 80/20 becomes 75/25 and it’s no more than that. So, if you think about Power the last five years, we spent $400 million operating nuclear units. We spent a couple $100 million dollars on peakers. We spent a couple $100 million dollars on advanced gas path upgrades. So, now we’re not doing that. Instead, we’re going to take an old steam unit that had 550 megawatts of capacity that there was no way it could survive in a CP future and said, okay, instead of just retiring that and leaving nothing there and losing the injection rights, let’s build a combined cycle unit because we like the way those numbers look. Instead of upgrading, instead of expanding, we’re going to build a natural gas combined cycle unit. As I mentioned before when I was answering Paul’s question, there’s some changes going on in basis. We want to know how can we manage that better. We saw a great opportunity handling that in the key investment. At the same time we announced $1 billion in new utility investments between gas system maintenance modernization and energy efficiency, and as we pointed out that program at $300 million a year run rate has 30 years to go. We only got three years of approval. So what we have is do very strong businesses, both worthy of investment, both which we look at where we can maximize the benefit for our customers and achieve the return expectations of our shareholders. So really nothing has changed; absolutely understandable why people would ask the question. If you just looked at a three-month window, all the sudden you see, wow, Power’s investing $1.6 billion and utility’s investing $1 billion. but I don’t think you should look at narrow short windows like that. Michael Lapides One other question, you talk about rate-based growth at the utilities, meaning double-digit rate base growth. Do you expect earnings growth to match rate base growth over time? Ralph Izzo So it will be close but it can’t match it. So the reason for that is quite simple. I am so proud of our utility folks for controlling costs, but even in the best of years you have labor escalation in our union contracts that are like 2.5%. You just look at management wage growth of 2.5%, 3% and then you look at load growth on a weather-normalized basis of 0.4% on the electric side and I think it’s 0.8% on the gas side. So you just do the arithmetic and the O&M expense outstrips the growth in load. So that bit of a drag peels away at some of the contemporaneous returns that you go get from the rate-based growth. That’s why these things don’t match perfectly. Operator [Operator Instructions] You have a question from the line of Sophie Karp with Citigroup. Sophie Karp Thank you for taking my question. I wanted to ask you about the nuclear economics as we continue to see very low gas environment obviously in the — if this prevails do you see any meaningful change in the nuclear economics for your assets and does that change your view of their long-term strategy with respect to those assets? Ralph Izzo Sophie, it’s an excellent question. Each of our units is over 1,000 megawatts. I think if you look at both fixed and variable O&M, I don’t know if we’ve published the operating cost of them, but it is $37 a megawatt hour, both fixed and variable. If you look at nuclear fuel costs it’s far, far, far less than that. So given our capacity prices, given our variable O&M costs, our units are absolutely fine. They’d be a lot finer if gas was at $8 and $10 an MMBtu. But as you well know, some of the challenges other units have had is, number one, their size in terms of their ability to spread their fixed cost and, number two, some of the distortions that are created by the production tax credit in particular from wind farms. That’s not to minimize the competitive pressures associated with natural gas, but what we’re seeing is margin compression and we’re nowhere near a point operating at anything but positive margins for those units. I think there will be a period, I don’t know how long that will be, of competitive pressure on them, but eventually there’s going to be a price on carbon. I don’t know if that’s going to be under CPP or some other paradigm, and these units will be able to ride through these a little bit more difficult times without any problem and then really benefit from that carbon regimen in the future. Sophie Karp My other question was about transmission investments. Are you looking into any incremental transmission investment opportunities right now maybe through FERC order 1000 or any other transmission investments that are not currently in your plan or have not been contemplated previously? Dan Creeg So I mean the FERC 1000 process has been around for a while and I guess I would say has been gaining traction for a while. We’ve been through the most recent and first opportunity here within PJM and with Artificial Island. So, yes, we are definitely involved in them. I think a lot of the areas in the country are still formulating the best way to move into this new regimen, so I would say that the prognosis for large investments in the very near term in that regard are probably less, but I think over time it is still an area where we think we have the skills and expertise that we can bring to it and we think we can be very successful in that arena. Ralph Izzo And Sophie, it’s important to realize that the $12 billion in the utilities prospective five-year capital program of which I think 60% or 70% is transmission. None of that is subject to FERC order 1000 competition. It’s all stuff that doesn’t meet the criteria for FERC 1000. The exception as Dan just implied is the $120 million of Artificial Island project that we won that’s included in that number. Operator Your next question will come from the line of Gregg Orrill with Barclays. Gregg Orrill Ralph, you’ve talked about having an excess balance sheet capacity of $2 billion to $3 billion against your FFO to debt targets. Ralph Izzo Right. Gregg Orrill And where does stock buyback stand in the way you’re thinking of using that money? Has anything changed about your thinking? Ralph Izzo Sure, thanks, Gregg, for the question. So nothing has changed really. We have this sort of three tiered prioritization on how to use the balance sheet. Number one is reinvesting in the business and we’ve been public about the fact that we will bid Bridgeport Harbor combined cycle unit in the upcoming forward capacity market in New England in February. I just mentioned a minute ago that the gas system needs $300 million per year and we have a three year program. If you subtract three from five that means there’s two years that are unfunded in the plan right now. You may recall, Gregg, that we when we originally filed for Energy Strong goodness gracious two and half years ago we asked for $3.6 million as the first part of a five year program and we got $1.2 million approved and it was only put into a three year program, so that’s halfway done already. And if you take 1.5 from 5, that means three and a half years of the five year program is unfunded, so there’s $1 billion plus in investment opportunity there. So just looking at those three, Bridgeport Harbor, gas, and Energy Strong, you’re looking at anywhere from $2.5 billion to $3 billion of investment opportunity that we’ve publicly discussed. Second thing is, look, let’s face it, we know the utility’s a steady grower but we know Power’s in a commodity cyclical business and we know how important dividends are to our investors and we’ve been promising consistent growth in our dividend, so we’d like to make sure that balance sheet has a little bit of an ability to absorb some of the ebbs and flows of the commodity markets, so that’s a second priority for us. And then, third but not one that we would never do but something that we talk about all the time, if our cost of capital is a little out of whack because the balance sheet is a little too robust and the investment opportunities are kind of far off, then let’s think about share repurchase as a way to get that cost of capital back in line. So that really hasn’t changed at all in terms of the three tier prioritization but perhaps a little more color on the details. Operator Mr. Izzo, Mr. Creeg, there are no further questions at this time. Please continue with your presentation or closing remarks. Ralph Izzo Thank you very much. So, look, I hope your take away is the same as the message we were trying to deliver which is the Company is in great shape. Our fleet of plants, our nuclear units, our combined cycle units are running well. The utility is hitting all of its growth targets as it executes its capital program and the balance sheet remains very healthy. So, we hope that you all come out to meet Dan if you haven’t met him just yet. He stepped right in and fabulous job for us, and we’ll see you in Florida in two weeks. Thanks, everyone. Have a good day. Operator Ladies and gentlemen, that does conclude your conference call for today. You may now disconnect and thank you for participating. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. 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Mean-Variance-Optimization Applied To Portfolios Using QQQ During Bear Markets

Summary Portfolios using QQQ and bond mutual funds achieved high returns with low risk from 1999 to 2015. The parameters of the mean-variance optimization (MVO) algorithm can be easily adapted to the risk tolerance of the investors. MVO strategy is very robust, and it may continue to perform well in the future. The idea of writing this article came from a comment by Varan, a frequent contributor on Seeking Alpha. Varan suggested that I investigate the performance of a portfolio using the PowerShares QQQ Trust ETF (NASDAQ: QQQ ) during the 2000 to 2003 period. Since two funds in the portfolio, the iShares 1-3 Year Treasury Bond ETF (NYSEARCA: SHY ) and the iShares 20+ Year Treasury Bond ETF (NYSEARCA: TLT ), were created in July 2002, Varan suggested that I use two mutual funds with similar holdings, the Vanguard Long Term Treasury Fund (MUTF: VUSTX ) and the Fidelity Limited Term Government Fund (MUTF: FFXSX ). In the articles on the simple ETF portfolio the simulations did not cover the 2000-03 bear market when QQQ had a maximum drawdown of -82.96%. We frequently hear investors saying that tactical asset allocation using bond funds will not work anymore because everybody expects a secular bond bear market. So, it is relevant to ask how tactical asset allocation worked using an asset that suffered a severe bear market. In that respect, QQQ is a prime example, having suffered such deep and prolonged losses during the 2000-03 bear market. It has taken twelve years for QQQ to recover and reach the level it had at its top in March 2000. The new portfolio is made up of the following four assets: SPDR S&P MidCap 400 ETF (NYSEARCA: MDY ) PowerShares QQQ Trust ETF Vanguard Long Term Treasury Fund Fidelity Limited Term Government Fund Basic information about the funds was extracted from Yahoo Finance and marketwatch.com and it is shown in table 1. Table 1. Symbol Inception Date Net Assets Yield% Category MDY 5/04/1995 14.23B 1.41% Mid-Cap Blend QQQ 3/03/1999 36.93B 0.96% Large Growth VUSTX 5/19/1986 3.27B 2.75% Long Term Treasury Bond FFXSX 11/10/1986 385M 0.68% Short Term Treasury Bond The data for the study were downloaded from Yahoo Finance on the Historical Prices menu for MDY, QQQ, VUSTX, and FFXSX. We use the daily price data adjusted for dividend payments. For the adaptive allocation strategy, the portfolio is managed as dictated by the Mean-Variance Optimization (MVO) algorithm developed on the Modern Portfolio Theory (Markowitz). The allocation is rebalanced monthly at market closing of the first trading day of the month. The optimization algorithm seeks to maximize the return under a constraint on the portfolio risk determined as the standard deviation of daily returns. The portfolios are optimized for three levels of risk: LOW, MID and HIGH. The corresponding annual volatility targets are 5%, 10% and 15% respectively. In Table 2 we show the performance of the strategy applied monthly from June 1999 to September 2015. Table 2. Performance of MVO algorithm applied monthly versus 100% in QQQ. TotRet% CAGR% VOL% maxDD% Sharpe Sortino 2015 return LOW risk 268.91 8.32 5.51 -5.51 1.51 2.19 3.60% MID risk 553.49 12.18 10.3 -10.55 1.18 1.68 3.10% HIGH risk 824.31 14.59 15.11 -16.12 0.97 1.36 -0.24% QQQ 124.69 5.08 29.43 -82.96 0.17 0.23 -1.22% In table 2 we see that all MVO portfolios had stellar performance over the 16 years of this study, even though QQQ had a very rocky ride. Also, notice that the realized volatilities of the MVO strategies are well correlated with the maximum drawdown and the realized annual returns. The 2015 returns column reports the results during 2015 to the end of September. It shows that all MVO strategies performed better than QQQ. The LOW and MID risk portfolios achieved a positive return of over 3% while QQQ lost 1.33%. The HIGH risk portfolio lost a minute 0.24%. The equity curves for all portfolios are shown in Figure 1. (click to enlarge) Figure 1. Equity curves of the portfolios with MVO monthly optimization versus QQQ over the whole time interval from June 1999 to September 2015. Source: All charts in this article are based on calculations using the adjusted daily closing share prices of securities. In figure 2 we show the equity curves during a shorter period that includes the 2000-03 bear market, specifically, we show the June 1999 to December 2003 interval. During the first nine months there was a steep increase in QQQ price followed by a three year bear market. We also included a nine month period of recovery. (click to enlarge) Figure 2. Equity curves of the portfolios with MVO monthly optimization versus QQQ over the time interval from June 1999 to December 2003. We see that all MVO portfolios increased at a slow pace during the bear market. The HIGH risk portfolio was basically flat from March 2000 to March 2003, while the LOW and MID risk portfolios achieved small but steady gains. The details of their performance are given in table 3. Table 3. Returns of QQQ and MVO portfolios during the 2000-03 bear market. Time Interval QQQ LOW_Risk MID_Risk HIGH_Risk 6/10/1999-3/28/2000 123.95% 13.32% 23.93% 53.15% 3/29/2000-3/11/2003 -79.79% 26.21% 22.72% 6.65% 3/12/2003-12/31/2003 53.25% 10.59% 17.86% 34.09% In figure 3 we show the equity curves of the MVO portfolio during the 2008-09 bear market. We included nine months of recovery from April to December 2009. (click to enlarge) Figure 3. Equity curves of the portfolios with MVO monthly optimization versus QQQ over the time interval from October 2007 to December 2009. In figure 3 we see that QQQ suffered a large loss from October 2007 to March 2009. During the same interval, the HIGH risk portfolio lost 8.40%, the MID portfolio was flat, and the LOW risk portfolio gained 7.29%. The exact numbers are given in table 4. Table 4. Returns of QQQ and MVO portfolios during the 2008-09 bear market. Time Interval QQQ LOW_Risk MID_Risk HIGH_Risk 10/1/2007-3/09/2009 -50.27 7.29 0.37 -8.40 3/10/2009-12/31/2009 78.72 8.71 19.35 42.54 Finally, in figure 4 we show the equity curves from September 2014 to September 2015. (click to enlarge) Figure 4. Equity curves of the portfolios with MVO monthly optimization versus QQQ over the time interval from September 2014 to September 2015. In figure 4 we see that QQQ as well as all the MVO portfolios were very volatile, but their equity was bound in a narrow range. Still, the LOW and MID risk portfolios outperformed by realizing modest gains. The exact gains and losses are given in table 5. Table 5. Returns of QQQ and MVO portfolios during the latest one year and the first nine months of 2015. Time Interval QQQ LOW_Risk MID_Risk HIGH_Risk 9/30/2014-9/30/2015 3.63 8.18 9.17 3.58 12/31/2014-9/30/2015 -1.22 3.60 3.10 -0.24 To give the reader more insight into how the MVO strategy succeeds in making gains even when an asset of the portfolio suffers extremely large losses, we present in the following three figures the monthly allocations during the period from June 1999 to December 2003. We decided to display the allocations over a short time interval in order to get graphs that are easy to read. (click to enlarge) Figure 5. Monthly allocations of the portfolios LOW risk strategy over the 2000-03 bear market. In figure 5 we see that the LOW risk strategy allocated, on average, over 60% of the money to the short term bond fund. QQQ was not allocated any funds between March 2000 and November 2002. The long term bond fund was allocated substantial funds during the bear market. (click to enlarge) Figure 6. Monthly allocations of the portfolios MID risk strategy over the 2000-03 bear market. The MID risk strategy allocated more funds to the long term bond fund than to the short term during the bear market. Again, QQQ was allocated the smallest amount of funds during the bear market. (click to enlarge) Figure 7. Monthly allocations of the portfolios HIGH risk strategy over the 2000-03 bear market. The HIGH risk portfolio allocated very little money to the short term bonds. During the bear market most money went alternately to the long term bonds and the mid cap MDY. QQQ was still not allocated any significant funds from April 2000 to November 2002. In table 6 we show the October 2015 allocations for all the strategies. Table 6. Current allocations for October 2015. MDY QQQ FFXSX VUSTX LOW risk 0% 0% 70% 30% MID risk 0% 0% 31% 69% HIGH risk 0% 0% 0% 100% Conclusion The Mean-Variance Optimization strategy applied to a well-constructed portfolio of stocks and bonds performs quite satisfactorily during deep bear markets. It also offers a very simple mechanism of adaptation to the risk tolerance of the investors by trading off risk and returns. The illustrations of this article give us confidence that MVO strategy is very robust, and it may continue to perform well in the future. Additional disclosure: The article was written for educational purposes and should not be considered as specific investment advice.

PNM Resources’ (PNM) CEO Patricia Collawn on Q3 2015 Results – Earnings Call Transcript

PNM Resources, Inc. (NYSE: PNM ) Q3 2015 Earnings Conference Call October 30, 2015 11:00 AM ET Executives Jimmie Blotter – Director of Investor Relations Patricia Collawn – Chairman, President, Chief Executive Officer Charles Eldred – Chief Financial Officer, Executive Vice President Analysts Anthony Crowdell – Jefferies & Company Brian Russo – Ladenburg Thalmann Paul Ridzon – KeyBanc Capital Markets Operator Good morning and welcome to the PNM Resources Third Quarter 2015 Conference Call. All participants will be in listen-only mode. [Operator Instructions]. After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Jimmie Blotter. Please go ahead. Jimmie Blotter Thank you, [Annie] and thank you everyone for joining us this morning for the PNM Resources third quarter 2015 earnings conference call. Please note that the presentation for this conference call and other supporting documents are available on our website at pnmresources.com. Joining me today are PNM Resources Chairman, President and CEO, Pat Vincent-Collawn and Chuck Eldred, our Executive Vice President and Chief Financial Officer. As well as several other members of our Executive Management team. Before I turn the call over to Pat, I need to remind you that some of the information provided this morning should be considered forward looking statements pursuant to the Private Securities Litigation Reform Act of 1995. We caution you that all of the forward looking statements are based upon current expectations and estimates and that PNM Resources assumes no obligation to update this information. For a detailed discussion of factors affecting PNM Resources’ results. Please refer to our current and future Annual reports on Form 10-K, Quarterly Reports on Form 10-Q, as well as reports on Form 8-K filed with the SEC. And with that, I will turn the call over to Pat. Patricia Collawn Thank you, Jimmie and good morning, everyone. Thank you for joining us on this beautiful New Mexico morning. I’m sorry you aren’t here in person to enjoy the weather and to see our wonderful Halloween costumes. I am pleased to report that PNM Resources delivered a solid performance in the third quarter continuing to build on the momentum that we have established. Start with Slide 4. Our GAAP earnings per share for the third quarter of 2015 were $0.76 compared to $0.69 in the third quarter of last year. Year-to-date in 2015 our GAAP earnings are a $1.34 compared to a $1.21 in 2014. Ongoing earnings were $0.76 compared to $0.68 from the third quarter last year. Year-to-date ongoing earnings in 2015 are a $1.41, up $0.16 from this time last year. We are also narrowing our guidance range for the year to a $1.56 to $1.61. Chuck will provide more detailed look into the numbers in a few moments. Before we do that, I will provide updates regarding our BART plan and other regulator proceedings and review the timeline for PNM’s general rate case filing. But first I would like to take a momentum to share something of which we are very proud. PNM was recently honored with the 2015 reliability one award recognizing the company as one of the very best midsized investor of utilities in the nation. As Jeff Lewis ReliabilityOne program Director stated in the new release about the award, reliability is ultimately one of the most tangible means to customer engagement any added. PNM has demonstrated that is understand the essence of customer engagement and is consistently providing superior service. This achievement is the result of tireless efforts and dedication of our employees who focus each and everyday on serving our customers and our communities. I would like to thank them for their hard work. Moving onto Slide 5, will discuss the latest development regarding San Juan generating station and the BART process. The new hearing on the case began as schedule on October 13 and concluded on October 20. The purposes of the hearing was to consider the new stipulated settlement agreement that the company reached with the majority of parties in the case. The hearing also covered the filing of signed ownership restructuring and coal supply agreements the lack of which was the primarily reason for the hearing examiners recommendation in April. In addition to commission staff and the Attorney General, signatory to the agreement include two environmental groups Western Resource Advocates and the New Mexico Coalition for Clean Affordable Energy. The New Mexico Industrial Energy Consumers, New Mexico Independent Power Producers and the renewable energy advocacy groups, Interwest Energy Alliance, also joins the agreement. This is the list that shows strong and diverse support for what we’re confident is a good settlement. Santa Fe and Bernalillo Counties and Albuquerque Bernalillo County Water Utility Authority are not joining the settlement, but they no longer oppose the deal. While the City of Santa Fe oppose the original agreement, the city has not taken a position on the new settlement. The highlights of the agreement are the CCN for the additional 132 megawatts in San Juan Unit 4. A CCN for bringing a 134 megawatts of Palo Verde 3 into rate base. Retirement of San Juan Units 2 and 3 and the recovery of half of the remaining un-depreciated investments and the instillation of SNCR Technology on San Juan Units 1 and 4 with accelerated cost recovery. One Environmental Group, the New Energy Economy continues to approach any agreement on San Juan. As filed a motion with Commission asking that four to five commissioners recuse themselves from the case. The group alleges the commissioners have improper ex BART case communications about the cash with PNM, claims that the commissioners are biased and then they have also prejudged the case. The commissioners denied the New Energy Economy’s claims and rejected the call for their recusal. And then they filed the petition with the New Mexico Supreme Court asking the justices to force the recusal of the commissioners and requesting a stay of the case until the petition is acted on. They also asked that PNM’s application of the Commission be dismissed. The court ultimately permitted the hearing to proceed as scheduled but state the commissioners from taking any action on the matter until the court makes a decision. As we clearly demonstrated in previous filings at the Commission, we believe any easy position is baseless. Oral arguments will be held on November 9, and we believe the court will act quickly on this matter. Let’s now go to Slide 6, and take a look at other regulatory matters. The Commission’s hearing examiner recommended approval of PNM’s 2016 renewable energy plan. The company continues to meet the renewable portfolio standard and our plan continues the rate rider for recovery of the associated costs. We expect the Commission to issue a final order in late November. Regarding, PNMs appeal of the New Mexico Commission’s definition of the future test year. The Commission held workshops to attempt to reach agreement among interested parties on the definition. Agreement was reached on a definition that would allow a future test year to begin 13 months from the date of a rate case application. On this basis PNM and the PRC filed a joint motion to remand the final order of the Commission in for 30 days stay of the appeal to allow reconsideration by the Commission. This will also gives the Commission and opportunity to docket a new rule making to incorporate the agreed-upon definition into the future test role. The Supreme Court has not yet acted on this motion. Meanwhile PNMs rate case filing is moving forward. The procedural schedule calls for staff and intervener’s to file testimony by January 29 and the hearing is scheduled to begin March 14. At FERC regarding our transmission formula rate case, we are still waiting on the FERC to act on the settlement we filed in March. We filed a settlement on the Navopache contract with FERC yesterday. I will give some high level comments on this and then Chuck will walk you through the detail in his section. Navopache made filing at FERC earlier this year requesting the authority to source their power from other suppliers based on a particular clause in the contract. Although we do not agree with their interpretation, we saw as an opportunity to return this portion of our assets to serve our retail costumers. With increased environmental regulations like the Clean Power Plan we believe that there will be continued reduction of base load generation assets in the future especially coal, as well as the introduction of more intermittent renewable resources. As this happens the stability of the grid will be diminished and one of the best way to protect our retail customers is to have generation resources that we own and are dedicated to serving these customers. Serving our customers with reliable and cost effective power is a core element of our business strategy. We felt it was in the best interest of our New Mexico customers to exit the contract with Navopache knows and brining those resources back to the retail jurisdiction. Over in Texas, TNMPs July 17 key cost filings requesting an increase of $1.4 million was approved and went into effect September 10. This reflects a $7 million increase in transmission rate base over our last filings. Now, I’ll turn things over to Chuck for in-depth look of the numbers. Charles Eldred Thank you, Pat and good morning, everyone. Beginning with Slide 8, load at PNM continues to be in line with our guidance of flat to down 3%. We saw continued strength in customer growth at PNM increasing to 0.8% for the quarter and holding to 0.7% year-to-date. Those are above our 2015 forecast at 0.5%. Residential was flat year-to-date and total load is down 1.4%. Economic growth in New Mexico continues to be slow. Looking at employment growth for Albuquerque, which is a major portion of PNM service territory. You can see that we are up from where we were a year ago and then it has trended around 1.5% through this year. This supports what we have been experiencing that the economy has not yet seen any significant upticks, but it’s holding fairly steady. You can see also that the U.S. average is a bit higher than Albuquerque at 2%. The economy in Texas continues to perform well. We do however see some softening of employment growth in recent periods particularly in the Houston area. As you can see on the chart there continues to be employment growth in both the Houston and Dallas, but Dallas is continuing with stronger performance. Load at TNMP is up 2.7% year-to-date which is in the guidance range to 2% to 3%. TNMP did have strong customer growth again coming in at 1.5% year-to-date which is higher than the forecasted 1%. Now turning to Slide 9 for the Q3 financial results. Ongoing earnings were $0.76 compared to $0.68 last year. Looking at the segments, each came in higher than last year, PNM up $0.05 and TNMP up $0.02, corporate and other up $0.01 because of the payoff of the 9.25% in May of this year. Now for more detail on PNM and TNMP drivers on Slide 10. Starting with PNM, AFUDC was up $0.04 this quarter. This is due to increased capital spending from the La Luz Gas Peaker in the 40 megawatt of solar that comes online this year in the San Juan, SNCR equipment. The half price renewal of Palo Verde Unit 1 leases caused a year-over-year improvement of $0.03. Weather was up $0.03. Cooling degree days this year were 6% higher than normal and 14% higher than Q3 2014. The refined coal process at San Juan which began last year in mid-November also improved earnings by $0.01 and the nuclear decommissioning trust had gains that were $0.01 higher than third quarter of last year. Renewable rate releases $0.01 improvement in Q3 of this year versus last year. As expected load cost earnings to lower by $0.03. Outage costs were $0.02 higher in Q3 of this year driven primarily by unplanned outages at four corners in San Juan. Other O&M expenses were $0.02 higher primarily caused the increases in employee medical cost. Depreciation and property tax expenses were higher by $0.01 because of the higher capital spending. Interest expense was also over $0.01 primarily due to the August issuance of $215 million of long-term debt and 3.85%. Now moving to TNMP. We saw an improvement for rate relief from the semiannual TCOS filings of $0.02. Combined load and weather were by $0.01, cooling degree days were 4% higher than normal and 8% higher than Q3 of 2014. Depreciation and property tax expenses were higher because of more capital additions. This caused results to be $0.01 lower. Now, turning to Slide 11. Today, we are narrowing our guidance range. We expect 2015 to be $1.56 to $1.61 and our previously issued guidance range was $1.50 to $1.62. This moves the end point of guidance to $1.58. We have also adjusted our segment enhancement for the remainder of the year which are on the slide. PNM will come down slightly this caused by the delay an implementation of rate case to third quarter 2016. This reduces revenue that was originally expect in December 2015 which has a [recent earnings back] for the year. Another factor that year-to-date whether is lower than normal. The remainder of the year-over-year drivers that were given but we issued 2015 guidance remain intact. TNMP is performing better than expected so guidance on that segment has been raised to account for the increases in load and weather. Finally, I would like to address the Navopache settlement. Pat is already walk you though the strategic rationale for our exist from this contract. As far as the detail to the settlement we will be able to manage the exist process from the contract and have time this considering the need for additional generation the results from the two unit shutdown at San Juan that will be including the 2018 rate case. The settlement that will have no earnings back in 2015. In 2016, the contract price will be lower but the full load will continue to serve for the entire year. In 2017 we will serve 10 megawatts around the clock which is about 23% of the current energy. Beginning in 2018 we will no longer serve this load and will plan to reallocate the rate based in the Mexico retail jurisdiction. This would allow us to reduce the cost to customers by lowering our investment in new generation capital. Since this was an agreed upon settlement with Navopache we have been able to develop plans to offset the financial impact both in 2016 and 2017. These plans include selling power in a market that would otherwise been allocated to them. Reductions in fuel and transmission expenses and other cost control measures. As a result we do not expect to have any significant earning gaps which is similar to how the expiration of Gallup contract was handled. Furthermore we will be able to execute the strategy the Pat described dedicating our jurisdictional generation resources to serving retail customers. Outside of Navopache, there are two remaining per coal sale generation contracts that we serve, which combined only represent nine megawatts. One of these contracts will terminate mid-2016 representing six megawatts this contract termination has already been reflected in our 2016 rate case filing. The final contract is three megawatts of load with the contract termination in 2019. Moving to Slide 12. We are making the number of capital adjustments to account for the changes in our resource requirement forecast. I will start by review in the generation capital. The changes that we are making the account for both Navopache in the lower load projection filed in our 2016 rate case. The $133 million investment and $187 megawatt gas peaker they have been planned to build has been reduced about $100 million which represents approximately 100 megawatts of peaking capacity. In addition the 20 megawatt of 2019 solar for $43 million has been eliminated since we do not anticipated that will need this additional capacity. The reduction in generation capital allows us to reprioritize or TNMP capital. We are able to now found about 16 million of additional projects that will continue to support the reliability for our service territory. We also made the decision to invest 50 million more into TNMP through 2019. To support their continued above the average growth. The investments are for transmission infrastructure in North Texas and in distribution systems in South Texas because the customer growth there. In summary, this makes our capital spending total $2.3 billion, up slightly from our previous forecast at $2.2 billion. We continue to expect the five-year rate base growth of PNM to be 5% to 7% and TNMP rate base growth has increased to 75% over the period. On a regulatory front is important to note that we have now made a decision regarding the CCN proceeding for the 187 megawatt gas speaker with the Commission. Additional time is needed to further evaluate other alternatives. However we are certain that we will need additional gas peaking capacity to drive the flexible reserves that are required to meet NERC operating criteria. We are therefore evaluating the 187 megawatt peaker versus smaller units to come up with the solution the best balances costs with net rate system support. We expect to make a final decision by early 2016. Now let’s take a look at what this does to the earnings power of the business on Slide 13. To begin with we have updated the 2015 guidance midpoint for the narrowed earnings range. This bring us starting point of earnings power to $1.58 for the year. For 2016, you will notice the majority that rose are consistent with our prior presentation of this slide. PNM FERC now represents only transmission, this is consistent with our long-term strategic plans that we have been discussing. As you can see the rate base number is down slightly and this is because we’re showing the FERC generation contracts and items not in rates for 2016 and 2017. But you’ll also note there is an increase in EPS because the transmission business has a higher return. The ROE assumed for the transmission business is 79%, which accounts for the lag that inherent in the formula rate methodology. Let’s move to items note in rates were Navopache is now included. In 2016 we’ll serve the entire load but at a reduced price result in a $0.03 reduction in earnings potential. We’ve also refined some of the other estimate such as our gas pension expenses. As you are aware in 2009 we exited the gas business as part of that sale. We retained the obligation for the pension of those employees. When we filed for the rate case in August we notified the Commission that we were considering annuitizing the gas portion of the pension obligation. With these plans beginning in 2016, we have removed the impact of the gas portion of the pension, which is $0.02 to $0.03 improvement to ongoing earnings. You will recognize that the bottom line for 2016 earnings potential is unchanged at $1.50 to $1.73. Now turning to Slide 14. Looking at 2017 you will notice that total PNM has shifted slightly. Again FERC now only represents transmission rate base. 2017 Navopache is included in items not in rates as a $0.06 incremental decrease compared to 2016. We have updated the other items like the gas pension assumptions. So that in total it comes to a penny to a $0.04 earnings contribution in 2017. I mentioned earlier that we have allocated additional capital to TNMP and therefore rate base is up causing earnings to increase by a penny. Overall, this brings the earning potential in 2017 slightly down to a $1.94 to $2.01 which is a $0.03 reduction to our prior presentation. Moving to 2019, what you see here is that the effects of the Navopache are no longer included in the items not in rates. The former Navopache rate base moves to PNM retail beginning in 2018 that along with our current capital forecast brings the 2019 retail rate base up to $2.5 billion. You will also notice that FERC shows a considerable increase in rate base, we expect to add additional FERC transmission customers. For example we have signed transmission service agreements for delivery of more than 400 megawatts of wind power from Eastern New Mexico that will be sold to utilities in California beginning in 2017. The bottom line for 2019 is now $2.25 to $2.36, this is a $0.06 increase over the previous low end of the range, which was $2.19. Wrapping on Slide 15, as you can see with the potential earnings power of the business, we anticipate delivering 79% earnings growth by 2019. We also expect to provide strong dividend growth over this timeframe as well. The next review of our dividend will be done by the Board in early December. With that, I will turn it back over to Pat. Patricia Collawn Thank you, Chuck. As you can see we continue to move forward constructively. The company is on track financially and we are working through our key regulatory filings. We continue to focus on the core elements of our strategy, which is centered on serving our customers. And I’m very pleased to say that in the latest JD Power customer satisfaction scores PNM showed significant increases on all areas and that’s especially significance given our high-profile of regulatory filings. I am proud of what we have accomplished and I am especially proud of the excellent work of our dedicated employees. They truly drive the success of PNM Resources and they do it by putting our customers first every day. Operator, let’s open up the call for questions. Question-and-Answer Session Operator Thank you. [Operator Instructions]. Our first question is from Anthony Crowdell at Jefferies. Anthony Crowdell Hey, good morning. I know there was a lot of moving pieces about the Navopache stuff. But I guess if I look on Slide 13, on the Palo Verde free line, now for 16 years showing a loss of $0.12 there was before you were showing just a loss of $0.05? Patricia Collawn Good morning, Anthony. I’m going to turn that one over to Chuck. Charles Eldred Yes, Anthony, as you all know given where power prices are in the market, we’ve shown in the footnote the projections that Palo Verde 3 are down about $29 a megawatt hour, it takes about $43 a megawatt hour to breakeven. So we’ve reflected in our numbers for 2016 the fact that we have prices at a lower level. We continue to manage that, but focus here is to eventually get this into rate base and we’ll have to deal with the volatility of the market until such time occurs. Anthony Crowdell Over to Navopache the generation I guess that you were serving that contract, now you are going to use that generation to serve I guess retail customers and I’m assuming that’s in a lower margin and what the contract was for? Charles Eldred Yes, if you kind of understand that what we are talking about is whether prices in the market and as low as they are really was not beneficial for us to continue to work with Navopache on wholesale contract that begin to move that generation. That was previously allocated from the retail rate base back into rates so we can serve our customers. And coincide that, we negotiated to coincide this with the 2018 plan, two unit shutdown and Palo Verde coming in and also plans for the gas peaker. So really does balance out nicely for our overall plans and work towards getting out of the wholesale market and allowing these resources to be dedicated to our customers in serving reliable and power further going forward. Anthony Crowdell I guess, when we think about 2018, you filed a rate case I heard for the August and September, and you filed the rate case maybe get a decision sometime in October. You are going to have to file the second rate case since I guess the future test your decision came during this year was not favorable. Do you file again right after the decision comes out? I’m assuming to get rates in for early 2018, you need to file rather quickly once you get that decision out? Charles Eldred Yes, we would be looking at file in December 2016 in order to work towards an effective rate case of January 2018, so it will be coming very quickly after we settled this current rate case. Patricia Collawn And remember Anthony that our future test year cases still on appeal and we hope to get that back and then we’ll have an idea of which definition of the future test year there is so we are still waiting on that decision also. Anthony Crowdell But you cannot change the current filing now regardless of what have to the future test year, is that correct? Charles Eldred That’s correct. Patricia Collawn That’s correct. Anthony Crowdell Okay. And just lastly, my question was related to – if I go to Slide 5, you list in terms of the settlement you’ve already spend some of the money or maybe a lot of the money on the SNCR for Units 2 and 3. What would be the total – if BART is not going to approve, what is the strength, what is the total amount of stranded cost. You have a 128 here for Unit 2 and 3, but that’s only half of the investment. So that you are looking at a total somewhere like 258 then what’s also the scrubber cost that you’ve put SNCR cost for 258. Charles Eldred Yes. And Anthony, Jimmie can give you more details, but the bottom line, the SNCR capital cost for PNM are about $26 million, so 150% and also the megawatts that we intend to spend for our involvement in Unit 4. Anthony Crowdell Any other capital that you’ve spent in the plan that’s involving [indiscernible] other than SNCRs? Charles Eldred There is some balance draft capital, but we also have in the current case. Anthony Crowdell And the total of that? Charles Eldred Total of that is about $52 million so brings it up to about $78 million when you add those together. Anthony Crowdell Great, thanks for taking my questions. Patricia Collawn Thank you. Charles Eldred Thank you, Anthony. Operator The next question is from Brian Russo of Ladenburg Thalmann. Brian Russo Hi good morning. Patricia Collawn Good morning, Brian. Charles Eldred Hi, Brian. Brian Russo Just when we look at Slide 14 and the 2017 earnings potential, obviously making assumption of a 10% ROE which I guess would be subject to change, but it seems like while you get a full year of new rates in the pending rate case you are going to file another case for the 2018 future test year. Is there any reason for us to believe that your experience regulatory lag in 2017 or contingent on what the lower ROE is, are there any like major net plant expenses that hit the income statement in 2017 that to create lag? Charles Eldred There could be a slight lag on the ROE, but for the most part given what we assume the 10% continuing to make that assumption going forward. Each year there is a slight lag in returns relative to additional investment in capital and clearings that occurred at depreciation and just normal O&M cost et cetera. So just the – within the 100 basis points, we’d probably again a rule of thumb is that regulatory lag works towards the actual filing and effective rate case for 2018 to get us caught back up. Patricia Collawn But nothing major Brian, there is no expenses there. Brian Russo Okay, got it, okay. And then I think in Texas the staff recently filed a memo noting that TNMP was over earning in 2014 but recommended no action. I was just curious you know what drove the over earning in 2014 was it load, weather? Charles Eldred Yes, I would say it’s mostly load and weather and what they saw when we sat down and have discussions with them is that we continue to invest a significant amount of capital both in transition and distribution. And when you think about the clearing of the capital and the added depreciation it really gives the earnings back in line to what is allowed. So they were very open and supportive and understanding what our business model looks like in Texas and the fact that because of that growth, we’re not holding back, we’re actually investing more as I pointed out in this presentation to continue to improve the growth in the investment and transmission in TNMP. Patricia Collawn Yes, Brian we pointed out the PNM on a reliability work but TNMP’s reliability is also very good and customer complaints almost nothing in Texas. So I think the fact that we keep investing and taking care of our – they understand we are committed to the business and that’s very helpful. Brian Russo Got it. And just could you talk about the voting parameters or requirements by the New Mexico Commission meaning do you need a majority of the five’s, you need three votes in favor or against BART on order for to get approval or not. Do you understand what I am saying meaning if one commissioner [indiscernible] that you down to four, you still need three of those four to vote one sided? Patricia Collawn That is correct. You got it Brian. Brian Russo Okay, great. Thank you. Patricia Collawn Thank you. Operator [Operator Instructions] Our next question is from Paul Ridzon KeyBanc. Paul Ridzon I think you said but I may have missed it. What is the weather year-to-date versus 14 in normal? Patricia Collawn You mean in terms of the cents? Paul Ridzon Yes. Patricia Collawn Cents on earnings per share. Paul Ridzon Correct. Patricia Collawn Hang on let me go back to that page. Okay, weather was $0.043 in PNM and load and weather combined in TNMP were $0.01. Paul Ridzon This is year-to-date? Patricia Collawn Quarter. Paul Ridzon Do you have year-to-date numbers? Charles Eldred Not in front of me right now and why don’t you just call Jimmie shall give to you. Paul Ridzon I can dig a more. And then there is no procedural schedule per se at the Supreme Court, but you are expecting an expeditions review. Patricia Collawn That is correct, there is no procedural schedule, but we clearly understand the time sensitive nature of it and the benefits of getting the same of restructuring the coal contract and so we would expect them to roll quickly. Paul Ridzon Next end of November, is that fair? Patricia Collawn By the end of November we would hope sooner, but by the end of November I think that’s fair gas. Paul Ridzon Got it. Okay, thank you very much. Patricia Collawn Thanks, Paul. End of Q&A Operator There are no further questions and this concludes our question-and-answer session. I would like to turn the conference back over to Pat Vincent-Collawn for any closing remarks. Patricia Collawn Thank you, and again thank you all for joining us today. We are looking forward to seeing many of you in 10 days at EDI and will have any relevant updates there. And I hope you all have a very safe and happy Halloween. Thank you. Operator The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.