TXNM Energy Inc (TXNM) 2016 Q3 法說會逐字稿

Good morning and welcome to the PNM Resources third-quarter conference call.

(Operator Instructions)

Please note this event is being recorded. I would now like to turn the conference over to Jimmie Blotter, Director of Investor Relations. Please go ahead.

Thank you Danielle, and thank you everyone for joining us this morning for the PNM Resources third-quarter 2016 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 Charles 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.

Thank you Jimmie. Good morning everyone, and happy three days before Halloween. Thank you all for joining us this morning to discuss the Company's third-quarter results.

We will begin on slide 4. Third-quarter earnings per diluted share were $0.68 on a GAAP basis including write-downs associated with the final rates case order at PNM. Ongoing earnings per diluted share were $0.78 for the third quarter of 2016, up slightly from $0.76 in the third quarter of 2015. We continue to affirm our 2016 consolidated, ongoing earning guidance of $1.55 to $1.65.

After 13 months, the general rate case at PNM resulted in a final order on September 28, granting a non-fuel revenue increase of $61.2 million. While the order represents an improvement over the hearing examiner's recommended decision in the case, it only represents about half of our 125 -- excuse me, $121.5 million request, and does not provide full recovery of all of the investments we have made in our system.

On September 30, we filed a notice of appeal with the New Mexico Supreme Court, and this past Wednesday we filed our statement of issues outlining how we believe the commission misapplied the law and facts with regard to our investments in Palo Verde, and the pollution control technology at the San Juan generating station. While some recovery is approved in the rate increase for the 64 megawatts of Palo Verde Unit 2 purchase capacity and the half-price extended lease payments, both the purchase and extensions were deemed imprudent in the final order.

This determination on prudence was used to disallow the fair market value price and limit recovery to no more than the estimated net book value on the 64 megawatts, to disallow the un-depreciated value of past leasehold improvements associated with the 64 megawatts, and shift the future responsibility for Palo Verde's decommissioning cost away from the customers and on to shareholders. We do not believe that these determinations are consistent with either the law or the facts.

Outside of Palo Verde, mission determined that because PNM proposed the balanced draft conversion to the New Mexico Environment Department as part of the air permitting process for San Juan, PNM was responsible for this permit condition. The commission rejected the air permit condition as a justification of the cost of the balanced draft and held that PNM was imprudent in proposing this condition. As a result, the commission disallowed the investment.

We clearly believe that this determination is also inconsistent with the law and the facts and failed to recognize properly the New Mexico Environment Department's authority over air quality compliance issues in the state. After the commission filed the case record, the New Mexico Supreme Court will set the calendar for the rest of the process. There is no required timeframe for the court to act on the appeal, although utility appeals do have priority under New Mexico law.

For purposes of writing down the value of the assets under appeal we have estimated a minimum of 15 months based on the timetable of other utility cases in the past. The timing of this schedule will not affect our plans to file our next rate case using a 2018 future test year. We will file that case in December of this year.

Return to economic development for a minute. We continue to see promising results from our state's economic development efforts. As you are aware, Facebook selected New Mexico for its data center, and the groundbreaking ceremony for their facility was held earlier this month.

While this is not a significant earnings driver for us it is a major win for New Mexico. It supports our ability to attract major companies. Since this announcement, we have seen increased interest from other companies.

The New Mexico Partnership, which is the state's official business recruiting organization, was instrumental in recruiting Facebook to New Mexico. I am honored to chair this organization and I am pleased with the group's accomplishments, but we still have a lot to do. We continue to work with various organizations to bring new businesses to the state and help existing businesses expand.

Site selectors are commenting on a noticeable improvement in the business friendliness of New Mexico. Remember, though, relocation and expansion of companies has a long sales cycle. As for existing businesses, we're seeing sector growth in the areas of education, healthcare services, and professional services.

New Mexico's nominal personal income is growing, housing prices are increasing, and home inventory is decreasing. We have all of the leading indicators for residential and commercial growth. It will take some time to see the results reflected in our sales, but we're moving in the right direction.

I will go ahead and turn the call over to Chuck to talk about the financial details of the quarter.

Thank you Pat, and good morning everyone. Beginning on slide 6 we're beginning to see slight traction in the economic developments efforts that Pat talked about. PNM's residential weather normalized load was up 0.2% for the quarter and commercial continues to show strength with an increase of 1.8%. The strength in this segment is spread across various sectors and represents small business growth in our service territory particularly the Albuquerque metro area.

This sector is responsible for the employment growth in Albuquerque which was 1.2% on a rolling 12 month average. Industrial, however, was down 12.1% compared to third quarter 2015, and down 8.9% year-to-date. This brings total weather normalized load at PNM down 0.4% compared to the third quarter of 2015, and down 0.6% year-to-date, which is in line with our guidance for the year of flat to down 2%. We continue to experience customer growth at 0.7%.

TNMP continues to perform well. The volumetric load was up 3.7% in third quarter this year compared to last year, and is up 3% on a year-to-date basis. This is at the upper end of our guidance range of 2% to 3% growth for 2016. Demand-based load also continues to show strength at 4.2% for the third quarter and 2.9% on a year-to-date basis.

We continue to see growth in TNMP service territory driven by employment growth in the diverse Houston and Dallas economies and the continued customer growth in the Permian Basin in west Texas. For example in TNMP southeastern area end user growth year-over-year has been 2.5% year-to-date, in north Texas 1.6% year-to-date, and in west Texas 1.9% year-to-date. Other areas of our service territory continue to see end user growth around 1%, which brings the total growth to 1.5% compared to the forecast of 1% growth.

Now moving to slide 9. We had ongoing earnings of $0.78 for the third quarter of 2016 compared to $0.76 in the third quarter of 2015. PNM was flat, TNMP was up $0.01, and corporate and other was also up $0.01, which represents a net interest income on the loan with Westmoreland that was entered into earlier this year.

Now turning to slide 8 to review the earnings drivers. At PNM you are aware that our rate case filing was [vote] delayed, and the final order did not include full recovery of our prudently invested capital. As a result, we have been managing our business cautiously, implementing cost-savings since June. This contributed to a $0.04 reduction in O&M costs compared to the third quarter of last year and was part of the narrowed guidance range we provided last quarter.

As expected the elimination of the Palo Verde Unit 2 leased cost represents an increase of $0.03. Although low overall it was down during the third quarter, the increase in the residential and commercial segments who pay higher prices than industrial have caused the earnings to increase by $0.02, compared to third quarter of 2015. Looking forward to Q4, I expect the load will remain in the forecasted range, likely coming in flat to down 1% for the year. Given that fourth quarter is a seasonably weaker quarter, I would not expect to see an earnings pickup for the load in the quarter.

Given the October 1 implementation of new rates under the final order of the rate case, some higher revenue was recorded in September as the new rates are applied to any September usage that was built in October under our normal billing cycles. This increase results by $0.01.

FUDC continues to be a reduction, as expected, due to our lower construction balances after last year's peak spending levels and reduced earnings by $0.04. We also had higher depreciation in property tax expense of $0.02 due to the increased plant balances.

Palo Verde Unit 3 sales were hedged for 2016 at a lower market price than 2015, which caused results to be $0.02 lower and interest expense also reduced earnings by $0.01, primarily because of the additional long-term debt that PNM entered into August of 2015. The Navopache first generation contract was $0.01 lower than Q3 of 2015.

Moving to TNMP, the increases in load that I discussed earlier added $0.01 compared to the third quarter of 2015. Rate relief from TCOS filings added another $0.01. These increases were partially offset by higher depreciation expense and property tax on increased plant investments that support this growing load.

Now moving to slide 9, I will review our capital update. Today we're providing both an update to our capital forecast into our potential earnings power slides. Overall, we have added $184 million to the forecasted spending at PNM, TNMP, and corporate. These changes at the Companies represent a net increase at PNM of $42 million, $90 million at TNMP, and $52 million at corporate.

Specifically I want to point out the change in PNM's generation which includes the modification to the planned 80 megawatt peaker. The rationale for this decision is coming out of the analysis being done for the integrated resources plan, which is due by July 3, 2017.

We're still early in the process, but one of the initial elements we are analyzing is the demand forecast. While our system continues to be peakier than it has been historically, we're finding the highest points are not as high as we had been previously forecasted. As a result of this we have decided to file a motion to withdraw the CCN application for the 80 megawatts peaker later today.

We believe that it is appropriate to change our capital forecast on the 80 megawatt peaker to a 40 megawatt peaker that is operational in 2020. As a reminder, part of the BART agreement that was finalized in December of last year is that we are required to file in 2018 to determine the extent to which San Juan should continue serving PNM's retail customers after June 30, 2022.

To facilitate the 2018 filing, we plan to develop two resource portfolios in our 2017 IRP: one with San Juan continued beyond 2022, and one where it shuts down. Consequently, the IRP, which includes the public input process, will be a valuable guiding document as we look at our total generation mix in the years to come.

Also at PNM we have committed additional spending to TNMP. This additional spending enhances the transition system to serve the additional renewable projects that are expected to come online in New Mexico. The 30 megawatts of solar we built for Facebook is included in the corporate and other category. Together these changes result in rate-based compound annual growth for 2015 of 4% to 6% for PNM, and 8% to 10% for TNMP.

Now moving to slide 10. We have updated the potential earnings power slide to reflect the outcome of the PNM rate case including the reduction in PNM's retail and renewable ROE from 10% to 9.575% and the new capital forecast. Corporate and other has also been updated for the Westmoreland [loan] and initial debt.

As you can see, the result is there is potential earnings power in 2017 of $1.80 to $1.87. The rate base for 2017 has been reduced for the Palo Verde Unit 2 and balanced draft disallowances, which are being appealed to the New Mexico Supreme Court. In 2019 we have shown the full range of outcomes from the Supreme Court appeal. The resulting earnings power in 2019 is [205 to 223].

Let me point out that in 2018 we have presented the earnings power assuming that we will not realize any earnings related to the rate base items that are under appeal. We expect that those items will be ruled on sometime during 2018, and so there may be some upside depending on the timing of when the Supreme Court's decision and any resulting commission actions occur.

Now moving to slide 11. We have reflected the rate case results particularly the lower ROE in our five-year earnings growth goal that began in 2014. As you can see we expect to achieve 7% to 8% earnings growth through 2019. I also want to remind you the Board will review the dividend in December. We continue to expect above average industry dividend growth. There likely will be an increase similar to last year.

Overall, we continue to be on track with our preparations for the next rate case, which we expect to file in early December. Keep in mind that this rate case includes recovery for the shutdown of San Juan Units 2 and 3, in the addition of Palo Verde Unit 3 to rate base that was part of the BART settlement.

We will discuss the rate case as well as the 2017 guidance with you on our Analyst Day in New York City on December 14. Again, we appreciate the continued support of our Company, and with that I will turn it back over to Pat.

Thanks, Chuck. Before I conclude the call today I would like to draw your attention to the new sustainability portal that we have added to pnmresources.com. We operate PNM Resources in an ethical, open, and transparent manner and have created the sustainability portal to give our stakeholders information about these activities.

The information provided here will be updated on a regular basis and is categorized by environmental, economic, social, and governance information. I strongly encourage you to visit the site and learn about all of the great work that we do at PNM Resources to ensure that we are providing for a sustainable future.

As we wrap up the call today, we certainly continue to have a full plate of regulatory activities in New Mexico between the Supreme Court appeal, the integrated resource plan process, and our upcoming general rate case filing. It's a testament to both the ability and the dedication of our employees as we move straight into these items from a lengthy rate case proceeding, and it is also a testament to the hundreds of employees that continue to provide reliable electricity and excellent customer service to our customers in both New Mexico and Texas.

PNM set another all-time high for overall customer satisfaction in the latest JD Power residential customer satisfaction survey. It is encouraging to see that our focus in this area has not gone unnoticed by our customers.

Our crews in Texas went back east in October, traveling to aid in hurricane Matthew restoration efforts. I'd like to thank them for doing such great work with no injuries. This type of work is a true reflection of our Company and our industry's values. Thank you again for joining us today. Operator, let's now open it up for questions.

(Operator Instructions)

Insoo Kim, RBC Capital Markets.

Regarding the plan to withdraw the 80 megawatt peaker TNMP proposal, have -- in your analysis, has the future potential buildout of renewables and the potential need for backup generation also been accounted for in this decision?

Insoo, the decision is really primarily driven at this point with the demand forecast being slightly under what we projected. And the other factors that go into this is cost and the actual reliability of this system which is important when you are beginning to add renewables in the system of making sure that we can maintain that reliability with more renewables to the system.

So in our analysis that are preliminary at this point we felt it was prudent to recognize that the demand forecast is falling slightly off what we had originally projected. It basically just means the peaking is continuing to grow but not at the pace that we anticipated, so we need about 20 megawatts in those years that we thought we would need to add the additional peaking capacity, and we can do that from just purchases in the market and then we see the growth in that peaking going into 2019 and 2020.

And of course if there is additional data centers or other components that could be considered at some point in time, that could certainly accelerate that. But at this point we think it is better to be conservative relative to where we are today, what we see in the forecast, and the fact that we think we can solve less than 40 megawatts of peaking capacity through purchases in the market, so we just pushed that capital into 2019 and 2020 at a 40 megawatt peaker.

Remember, Insoo, the next jump in the renewable portfolio standard comes in 2020 when we go up to a 20% by 2020 so that is when we have that need. And as Chuck said if we get some more data centers we can obviously accelerate that peaker.

Understood. And I do not know if I missed this earlier but what are some of the items that went into the additional CapEx at the T&D at PNM as well as TNMP?

There's a number. At TNMP certainly we continue to invest in a transmission component of the business, but also we're seeing growth in the distribution side. So we're just seeing opportunities given the growth that we can continue to invest more to allocate capital to meet that continued above average growth. In New Mexico we continue to see some opportunities really on the transmission side as we begin to see more renewables being built in our service territory around in the territory in New Mexico, and also in the distribution side and mainly in substations and reliability aspects of our system.

We have had pipeline projects in anticipation of what would be an update when the time came to reallocate the capital to both businesses, and we have just completed that analysis. And as a result of that we're reflecting that as a new capital plan to be more current on what we see in the next several years through 2019 and 2020.

Just lastly, turning to the earnings power slide. So given the implementation of the future test year, I know part of that was applied in the recent rate case and the full future test year that's going to be implemented in the up coming rate case. How much do think that will help in reducing regulatory lag in New Mexico and allow you to earn close to that 9.575 % [that is allowed] level?

For 2017, obviously we did not get the four test year. This rate increase went in October 1, so you'll start to see some regulatory lag in 2017 just by additional capital investment and depreciation that gets cleared with projects that clear in 2017. But you are probably still in that 30 basis points range within the 9.575% return. So it's still an attractive earnings expectation.

But you cannot get to the allowed return, and given the fact that you will have some additional capital and depreciation that will be picked up in 2017. And then in 2018 would be a full four test year. We need to look into 2018 to begin to earn our allowed return based on that being a true four test year.

Ali Agha, SunTrust.

First question, Pat or Chuck, given the experience you have going through this current rate case and the kind of pushback on issues that you would have assumed were pretty settled, how does that influence your thinking as you file the next one in December? Does that change much in terms of how you're thinking about that having gone through this one?

Ali, if you look at the last case in this upcoming case they are really different animals. The pushback in this current case was really around what value and was it prudent to buy Palo Verde, and then the balanced draft. This next case what is going in is the what's agreed-upon in the BART settlement is the majority of the case. Obviously there's some catch-up T&D.

But in those items we're already agreed on, the values have been set for those, and we had everybody with a signatory to the case other than one party. So you've got an agreed-upon value for all of those, and so the only discussion around those really should be around what's the ROE. Obviously no commission can bind a future commission, but again, since everybody signed onto it all of the interveners will have to support that.

Roughly -- I know the filing comes in December, but just to give us some perspective, what kind of a rough rate increase would be embedded in this next filing?

December, December -- when the rate case comes out we will go over that with you.

Okay. And then I know -- I believe a couple of seats are up for election in November. What is your read on what comes out of that and does that in any way in your mind change the tone of the composition of the commission?

The two seats are already decided as both candidates are running unopposed. Commissioner Espinoza up in Santa Fe ran unopposed, and so she will be the Commissioner. Cynthia Hall here in Bernalillo County beat Karen Montoya in her primary. She's running unopposed so she will also be the Commissioner. Hard to tell where they are going to be.

I think we're going to continue to have discussions, and the main questions are going to be what does the future of our generation portfolio look like. And as Chuck mentioned, we're doing the integrated resource plan with the two separate scenarios, and I that think that will help sort of set the tone for the commission discussion more than anything else.

Okay. But you will think Commissioner Hall -- future Commissioner Hall wouldn't be much of a change from what we have been seeing so far?

Hard to tell. They are very careful when they campaign not to say anything because of the fact that it can get them taken off the of cases so it will be hard to tell.

Again, I think a lot of what's going to set the tone is what the generation portfolio is going to be because if you look at with the discussion is at the commission it is all around coal and nuclear. It is not around T&D.

Last question, looking at the overall load picture in New Mexico, are you getting any signs to suggest that we may be close to a bottom? We've been still seeing this negative year-over-year comparisons. I guess industrial was the big driver this quarter, but any sign that you can point to that tells you that we may have bottomed out here?

Ali, as Pat pointed out there's a lot of economic development activity that is occurring and certainly some successes that we are seeing. But still takes time for that to be reflected and incorporated into a more solid trend in our load growth.

And we still see a decline on the industrial side, but since the customer growth, although it being slightly above average with energy efficiency and renewables, would still kind of offset any kind benefit we'd get from customer growth. So if you net all of that against the slight declining on the industrial side probably still feel like there is a slight trend downward. Maybe not as aggressive as much as 2% as we have seen in last year and this year's guidance, but certainly a slight negative into 2017 just to be reflective of what we see today.

Just to clarify Chuck, I think I heard you right, but did you say that given the past year's issues you think about a 30 basis point lag is probably what will happen in 2017?

I think that is a reasonable expectation. You're going to see some lag off of the 9.575%, so I think reasonably considering we haven't provided guidance in 2017, but I think that is probably fair just as a perspective of how we see some regulatory lag going into 2017 around 30 basis points, probably an area to think about.

Anthony Crowdell, Jefferies.

First question I have is on slide 9 depreciation. Any chance you can break that out for us [per sub] or help us to separate this for PSNM and TNMP?

Anthony, I think it would be better just to call Jimmie, or I will have Jimmie call you and she will work that through with you.

Also, when I look in 2017 and 2018 at PSNM, the -- how much revenue each year do you get from either riders or FERC spending? There should be some rate increase in there that are not related to NMPRC rate increases. What is a reasonable estimate to assume you get each year?

Actually if you look at slide 10 you can see the renewable rider and you can see FERC.

Right, but there is some lag -- you mentioned there is some lag there. So have you provided any guidance on what type of revenue you get each year?

You can calculate this but on the FERC side we talk about 7% to 9%, roughly 8% is probably a reasonable assumption given the fact you are filing on a historical basis. And then just obviously you get a decline in the rate base for the renewables for the depreciation of the assets that we have. We can break it down for you if that would help you, but Jimmie can do that for you and give you some feedback.

Lastly, I just want to make sure I am understanding all the peaker math. And when I look at -- first, I think when you guys were on the road in October or maybe September you had mentioned the key elements of the next filing involved 80 megawatt gas peaker. That's lowered to 40 megawatts, but is that 40 megawatts going to be next rate filing?

Actually that'll pick up in 2020 if we file rate case because if we started spending that in 2019 and finish and clear that peaker in 2020. So if we file for 2020 rate case that is when it would be picked up.

Okay, so it's not going to be part of the filing in December and that is also the difference between the previous CapEx slide of PNM generation in 2018 of [168 now to 112], that is the loss of the peaker.

For the most part it's the loss of the peaker. Then we reallocated some capital both amongst the businesses and there's a net increase in PNM, but is a slight amount but it still covers the fact that we have moved that capital to 2019 and 2020, and we picked up a little bit for PNM in 2017 and the slight decrease in 2018 and a more significant pickup in infrastructure investment and the peaker that we will start building in 2019.

Again, it nets out to be overall a slight increase, and overall capital including PNM, but a shifting of that capital to be more on the backend instead of the front end that we had originally projected.

And we've been spending a lot of capital and generation, and so the transmission and distribution folks have a lot of projects that they would like to do here in New Mexico and in Texas, as we said, it continues to grow so there is opportunities for capital over there.

If I think of it, just last question, if I think about the bumps that have gone on in the regulatory process for some time and also now with low growth looks like it's pretty anemic; it seems like getting generation built or generation in rates in New Mexico has clearly been the biggest challenge -- or maybe it is just fossil and nuclear generation rates. But also just not even looking at that and with the peaker going PPA and just looking to maybe type of utility scale solar or something else to meet the needs?

That's one of the -- when we look at the integrated resource plan will be able to look at what new sources make sense, and is it utility scale solar. And actually in the San Juan replacement case when you just let the models run on their own they did pick 40 megawatts of utility scale solar, so we will continue to look at that.

We will look at PPAs where they make sense, but one of the things we found is that we tend to operate our plants better, and we know how the maintenance is done and the permitting is done, so if there is gas plants we tend to like to own them, and the same with peakers. We will look at them.

But I think Anthony it's mostly about coal and nuclear. And if you think about, and step back from New Mexico that is where the national discussion, and quite frankly, the international discussion in certain countries is on is coal and nuclear. And I think what you see here is just a reflection of that broader conversation about what kind of generation this country should have.

To add to that, Anthony, when you get to that 40 megawatt peaker you really need the technology for quick start and you cannot really resolve that through PPA. So what we're indicating that we can use the PPAs when we are under 40 megawatts and balance the system, but when it really comes to certainty of that peak hitting that 40 megawatt requirement, we need to have the quick start capability to build a reliability in the system.

Is it linear -- previously I think the 80 megawatt peaker was roughly $80 million. Is it $40 million for this peaker?

Roughly, that's about right.

Lasan Johong, Auvila Research Consulting.

I wanted to follow up on these excellent questions. Here's the thing, I understand 2018, it's mostly the [Bard] agreement coming into play, so there's not a lot of maneuvering room or changes but how do you -- given the final decision on the commission does that kind of shake your confidence about spending money going forward without gaining prior approval?

Not really because I think if you look at what the commission did not like it was Palo Verde, and it was balanced draft. And if you look at this next case as we mentioned, all but one party signed on to this agreement.

But beyond this 2018 rate case. I'm some talking about longer term for 2019, 2020 and beyond. Does that kind of give you pause?

If you look at generation we always get a CCN before we would spend money on a power plant and we will continue with that, or we get it approved through a renewable rider. And so we will continue on with that.

And the T&D spending is not where there has been much pushback on. So A, the generation spending goes down; and C, if you're going to build a -- or B, if you're going to build a peaker, for example, gas peaker we would have to get a CCN beforehand so that gives you that assurance. Obviously what was different in this case that we are taking to the Supreme Court is that we had CCNs and that was challenged.

Going back to the peaker situation, do things change somewhat differently if you have San Juan coming back after June of 2022, or not coming back after June of 2022? Or are you going to just kind of wait until you have more certainty on that before you make any decisions on additional generation?

That is the great part about this integrated resource plan process that we're going through. It's a public, participatory process, and as Chuck mentioned, we will run the two scenarios: one with San Juan and one without San Juan. So that will give us clarity on under either scenario what our generation needs and mix look like going forward. So you won't see us proposing a lot of new generation until we have that planned, then, because obviously our needs would be very different if the commission decides that we should shut down San Juan, for example.

If you shut down San Juan could the 40 megawatt peaker turn into an 80 megawatt CCGT?

It's a very different scenario.

Look at it this way -- if you shut down San Juan you'd be shutting down 500 megawatts of power. And so 500 megawatts is going to be a combination of baseload, peak and capacity, renewables, whatever that combination replacement power would be it's going to be a different set of capital investments toward the generation over the next 20 years that would accommodate the fact that you are shutting that 500 megawatts down.

The peaker is really more reflective of how the demand forecast on the system occurs over the next few years and the potential addition of renewables in the system, i.e. more data centers if that were to come about in order to balance the system in a cost effective way. Shutting down San Juan is a much different set of circumstances to determine the replacement power of the 500 megawatts, which would, again, would be a combination of a lot of different resources to meet that requirement.

Chuck, I understand that, but my point is given that you already have a plan in place for a 40 megawatt, could that be upsized to accommodate part of the baseload equation that you were just talking about? And then you do something else with the peaker renewables.

You could have a larger gas unit, but again, the difference in how the system needs to balance itself, the peaking capacity being more for a requirement quick start as opposed to larger intermediate gas type plant. So it's a combination of both and that is what the integration resources plan is intended to do is to take all the variables in consideration, lay out the next resource requirements over 20 years, make any necessary adjustments into how we look at that load requirement in the future with different generation mixes.

The 40 megawatt peaker right now would be more isolated in our view towards what the peak demand forecast would be in the system. Not so much of the replacement of San Juan.

Any preference which way you want to go, shutting down San Juan or not shutting down San Juan?

We will let the numbers speak.

Good question. You make me want to do my Trump impersonation, but I won't do that.

No.

I'm getting close. Okay. I'm being held back.

Paul Patterson, Glenrock Associates.

I actually would like to hear the Trump impersonation, if it is okay.

You know, Paul, the problem is if he does that I've got a big can of hairspray here and I will aim it at him.

But Paul, I've got a sign that here says such a nasty woman.

Okay. A lot of my questions have been answered, but just quickly (multiple speakers) the smart [meter] thing, I know it's been suspended I think, but what is the outlook for that? I do not think it is in your plan, but is that just off the table for now or how should we think about that?

We are still looking at that and talking with folks that are part of the case. We would obviously still like to do that. It is a little tough sell right now given the economy in New Mexico because obviously one of the things that AMI does is over time it will eliminate meter reading jobs, but we're still working on that one.

The sales forecast for the next three years -- I apologize, what is it that you guys are projecting weather adjusted?

We did not show a forecast over the next year, we just said that year over year we continue to see a slight decline driven more from the industrial side. Some benefit on the commercial and residential side, but again, even though we have a slight improvement in customer growth it is not enough to offset the impact of energy efficiency and some accommodation of growth in the solar, residential solar. So that would pretty much put it on a flat year-over-year basis and then slight decline because of the industrial load.

Maybe not as much as we had this year in the guidance which was 0% to negative 2%, but maybe along the lines of a 1% reduction year over year. So again, slight decline. It's going to take a while for some of the benefits of the economic development activity that Pat alluded to in her earlier comments. We're making progress, things are beginning to show some slight improvement in tracking to that expectation, but jut too early to pick that up into the forecast and know exactly when that will transform into some real benefit there.

How should we think about next year, though, or the year after that? Was leap year in this number, by the way?

Pardon me, what did you say? I'm sorry.

Leap year, was that in this 0.6 decrease you have here, or just exclude that as well?

It is adjusted for leap year. Again, I would say to be reasonable based right now probably a negative 1% in the area of that range year over year.

Chris Ellinghaus, Williams Capital.

Can you just clarify -- I was not sure on the load growth expectation in the earnings power. Does that slight decline cover all three years?

The earnings power slide is just rate based math so it is just taking the rate base and the ROE, so there's really no load upside or downside built into that.

So does not consider load at all?

No. We tried to do that when we did the guidance, but the earnings potential shows you what the potential earnings obviously of the business is from a rate base perspective. There's a few baskets of cost in there that we provide to you that are a lot of moving variables that we try to give you some perspective on that, and then once we tighten up guidance and we take everything else into consideration, ONM, cost controls, load, etc.

Can you give us a little color on the industrial weakness, where it's coming from and why you think that might continue?

We don't have a strong industrial base as it is. We are around 12%, far under most utilities. So there is a larger customer here in New Mexico in the Albuquerque area that tends to be slowing down the operations mainly because of some of the obsolescence of their technology. They've asked that we not provide that publicly, but it wouldn't take too much to figure out who is in Albuquerque to understand who that customer might be, and they are globally and nationally recognized.

I think we all know who that is.

I am just being very careful, although I could do my Trump impersonation right now. I won't do it. That is really what is driving it. There's a little bit of other variables on some co-generation and dealing with New Mexico, University of New Mexico, things like that, but again, it is really driven by that customer.

It's really that one singular entity?

That is the driver. In all honesty, that is the driver.

Pat, in light of the rate case and certainly the continuing long duration of rate cases, have you got any thought about a legislative effort to maybe try to get some relief on that?

You can only ask for so much at a legislator, and the fact that we now have a fully forecasted test year. We got that and we're going to stick with that. We are filing 13 months ahead of the time we need rates so the commission can have the entire time that they are allowed if they choose to do that.

The last rate case was obviously a bit of an anomaly because of the fact that they said our filing was not complete and that we had used the wrong test year. And two things have changed since then. One is that we have a ruling from the commission that the test year that we believe -- we at [FPF] believed was appropriate is appropriate, and then secondly we have worked out all of the filing requirements with the staff. So I think that our legislative agenda on that probably would not look to shorten that timeframe.

One last question. About the San Juan process in determining what happens in 2022, can you go through how that determination is going to be made and what sort of lead time you are going to get to make decisions in terms of replacement?

If you look at the process, the integrated resource plan process, it started this year. It's a year-long process, so it goes into the middle of next year, and then we will present an integrated resource plan to the commission.

In New Mexico, IRPs are not formally approved by the commission. They are accepted and consistency with that integrated resource plan if you put generation in constitutes prima facie evidence of that type of resource, but you still would get a CCN.

But we also agreed as part of the BART settlement that we would present a plan to the commission, one with San Juan and one without San Juan. And all of the signatories to the (inaudible) said that they would support having a decision, and the commission will make a decision on that in six months. That will be in 2018. So there is a lot of lead time there. That's 2018 and right now San Juan coal contract goes all the way to 2022. Lots of lead time is long answer to that question, but --.

John Barta, KeyBanc.

Sorry if I missed this, but on the peaker are you completely withdrawing that or just revising it to the 40 on the CCN?

We're withdrawing the peaker completely, and then as I mentioned we're looking at an updated forecast on the demand side that is included in this IRP process that Pat has alluded to. But currently our preliminary analysis which showed that, that 80 megawatt peaker would adjust itself to about a 40 megawatt requirement that would begin to build out in 2019 and 2020.

On the IRP you said 2017. Do you have any timing first or back half of the year?

It is July of 2017 it will be done.

I guess lastly, are you aware that the commission is taking on any initiative or if they're looking at any potential workshops on better understanding some of the current rate design issues that are out there?

They are not. They are looking at some workshops possibly on that metering, but nothing on the rest of rate design. We tend to handle that here in New Mexico through our rate cases.

So for example in the last case we bumped our fixed charge up a little bit and we were able to eliminate some of the residential subsidies and keep the large commercial and industrial customers much more harmless than before. We deal with them individually through our rate cases here in New Mexico.

This concludes our question and answer session. I would now like to turn the call back over to CEO Pat Vincent-Collawn for closing remarks.

Again, thank you all for joining us on this beautiful morning. I hope you all have a safe and happy Halloween and you get all the kind of candy that you want, and we look forward to seeing many of you at EEI in a couple weeks. Have a great weekend.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.