Joe Bergstein - VP, IR Bill Spence - Chairman, President & CEO Vince Sorgi - CFO Rick Klingensmith - President, Global Business Paul Farr - President, PPL Energy Supply & PPL Generation Greg Dudkin - President, PPL Electric Utilities.
Greg Gordon - Evercore ISI Dan Eggers - Credit Suisse Anthony Crowdell - Jefferies Paul Ridzon - KeyBanc Paul Patterson - Glenrock Associates Julien Dumoulin-Smith - UBS Neel Mitra - Tudor Pickering Steven Fleishman - Wolfe Research Michael Lapides - Goldman Sachs Jonathan Arnold - Deutsche Bank.
Welcome to the PPL Corporation Third Quarter 2014 Earnings Conference Call. (Operator Instructions). I would now like to turn the conference over to Joe Bergstein, Vice President, Investor Relations. Please go ahead..
Thank you. Good morning and thank you for joining the PPL conference call on third quarter results and our general business outlook. We're providing slides of this presentation on our website at www.pplweb.com.
Any statements made in this presentation about future operating results or other future events are forward-looking statements under the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from such forward-looking statements.
A discussion of factors that could cause actual results or events to differ is contained in the appendix to this presentation and in the company's SEC filings. At this time, I would like to turn the call over to Bill Spence, PPL Chairman, President and CEO..
Thank you, Joe. Good morning, everyone. Thanks for joining us today. With me on the call this morning are Vince Sorgi, PPL's Chief Financial Officer and the Presidents of our four business segments.
Moving to slide 3, our agenda this morning starts with an overview of third quarter earnings and operational results and an update on our 2014 earnings forecast which we have raised for the third time this year. After my remarks, Vince will review our segment financials and then we will take your questions.
Looking back on our performance through the first nine months of 2014, we put an impressive year together, delivering solid results while overcoming some challenges brought on by Mother Nature and executing on a substantial strategic effort positioning the company for future success.
We continue to invest heavily in our regulated infrastructure, enhancing grid reliability for customers in each of our service territories and providing an avenue of stable returns for our investors and at supply, the team has in a great job of managing both base load and intermediate fleets which is reflected in the continuous improvement in our expected results throughout the year.
We expect to carry this momentum through the remainder of 2014, continuing our approach of excellence and execution and identifying ways to deliver value. Let's move onto third quarter results.
Turning to slide 4, today we announced reported earnings of $0.74 per share for the third quarter that is an increase from $0.62 per share in the third quarter of 2013. Adjusting for special items, our earnings from ongoing operations were $0.54 per share in the quarter, a decrease from $0.66 per share in the third quarter of last year.
Year-to-date reported earnings were $1.57 per share, compared to $1.90 per share in the first nine months of 2013. Earnings per share from ongoing operations for the first nine months of the year were $1.87, an increase from $1.85 per share in the same period a year ago.
Strong year-to-date performance in our regulated businesses, combined with continuing strong performance in our competitive energy supply business has led to exceptional results through the first nine months of the year.
Our domestic utilities improved earnings from ongoing operations by a combined $60 million year-over-year, primarily resulting from returns on additional transmission investments in Pennsylvania, power plant environmental projects in Kentucky and higher sales volumes.
The improved sales volumes were primarily driven by weather, as the mild spring and summer were more than offset by unusually cold weather in the first quarter of this year. Let's move to slide 5 for an update on our 2014 ongoing earnings forecast.
Our continuing strong results led us to announce today an increase of our ongoing earnings forecast to $2.37 to $2.47 per share. The new mid-point, $2.42 per share, is $0.12 higher than the mid-point we announced in August and almost 13% higher than the midpoint of the initial 2014 forecast which we provided in the first quarter.
On the regulated front, we see an improvement in the UK regulated segment earnings and remain on track in our domestic utilities. As you can see on this slide, our forecast increase is primarily driven by higher expected earnings from supply.
The strong 2014 performance of PPL's competitive energy supply business underscores the inherent value of this business and its ongoing potential as market fundamentals improve. These 2014 results provide additional confirmation that the spinoff of our supply segment will create significant short- and long-term value for our shareowners.
Vince will discuss the details of our updated forecast in a few minutes. Now let's turn to slide 6 for an update on our regulated operations.
Starting in the UK, we're pleased to announce that WPD earned a combined $130 million in annual bonus revenues for its premier customer service and reliability metrics for the regulatory year ending March 31, 2014. This is a $17 million increase over the previous regulatory year. We expect OpGen [ph] to confirm this amount by the end of 2014.
In Kentucky, we're announcing today our plans to file a rate case later this month. We provided a high level summary of the filing on slide 7 which I will discuss in a few moments.
On a last quarterly call, we had just announced Project Compass, a proposed 725 mile transmission line through the shale gas regions of Pennsylvania and into New York and New Jersey and Maryland.
We’ve been meeting with officials at the state PUCs and governor's offices in the states where customers will benefit, Pennsylvania, New Jersey, New York and Maryland. Those meetings have gone well overall and we plan to have continuing dialogues on the project benefits.
We're also meeting with other key agencies and other transmission operators in the region. We will continue to update you as we reach project milestones.
Turning to the Kentucky filing on slide 7, our requests are for increases in annual basis electric rates of $30 million and $150 million at LG&E and KU, respectively and an increase in annual base gas rates of $14 million at LG&E.
The increases are principally driven by investments in generation supply and other infrastructure investments needed to maintain and enhance the safe reliable delivery of electricity and natural gas to our customers and to meet federal environmental regulations.
The single biggest investment driving the requested increase is the company's new, natural gas combined cycle plants Cane Run 7 which is scheduled to go into service in May of 2015. The filing will be based upon a forward test year and in June 30, 2016 assuming an ROE of 10.5% with new rates effective July of 2015.
Moving to slide 8, let's take a brief look at sales volumes in our domestic utility operations. In Kentucky for the quarter and trailing 12 months, strong industrial load growth has more than offset the weakness experienced in residential and commercial sales, leading to overall weather normalized sales growth of about 0.1% and 0.5%, respectively.
The industrial growth has been driven by expansions and increased production at some of our larger customer's facilities. Mild weather in Q3 of this year negatively impacted actual sales volumes relative to last year.
In Pennsylvania, we experienced a modest decline in weather normalized sales quarter-over-quarter, primarily driven by lower residential sales.
On an actual basis, cooling degree days were down by roughly 14% which drove weak demand from residential customers, weather normalized commercial sales were up over 1% which helped offset some of the residential weaknesses, while industrial sales were relatively flat for the quarter.
PA weather normalized sales continue to trend in positive territory at about 0.5% for the trailing 12 months. Moving to slide 9, let's talk first about the progress related to the spinoff of our competitive generation business which will be combined with Riverstone's competitive generation business to form Talen Energy.
Discussions with regulatory agencies are proceeding as expected and there have been no surprises in the process. We still anticipate closing in either the first or second quarter of 2015.
The Talen Energy transition team headed by Paul Farr, President of PPL Energy Supply is on track to achieve at least $155 million in annual run rate synergies for Talen which was a target we had established.
Separately at PPL, we have identified a targeted annual support cost savings to eliminate at least $75 million of disynergies created by the spin, most of which will be achieved in 2015. These cost savings are also consistent with the targeted reductions discussed when we announced the spinoff transaction in June.
Moving on to the pending sale of the Montana Hydro facilities to Northwestern Energy, I'm pleased to report that the Montana Public Service Commission has approved the transaction. FERC approved Northwestern Energy's financing plans for the transaction last week clearing the way for an expected closing by year end.
Just a brief update on the Susquehanna plant, as you know, we installed redesigned shortened last stage blades on one of the Unit 1 low-pressure turbine this past spring. Our continuous monitoring of turbine performance shows that the new, shorter blades have significantly reduced blade tip vibration.
We're finalizing plans to install these shorter blades on the remaining low-pressure turbines over the next couple of refueling outages, starting with multiple turbines on Unit 2 during the refueling outage next spring. We don't expect to need special turbine maintenance outages after these modifications are completed.
Turning to a summary of plant performance for the quarter, you will notice from our updated hedge disclosures in the appendix that our 2014 expected base load output declined by about 3 gigawatt hours since our last update.
The primary driver of this decrease was due to lower than planned output from our Eastern coal facilities during the quarter as depressed load and prices from mild summer weather led to a 30% average capacity factor for the period.
While actual coal generation was down given these lower prices, our hedging program proved beneficial, as we captured value for the portfolio through the financial settlement of the higher priced forward sales contracts.
Excellent plan performance from our natural gas units which ran at a 98% capacity factor also added value as spark spreads improved in the third quarter driven by very low spot natural gas pricing.
Before we move onto Vince's comments, I would like take this opportunity to say that PPL employees have done an excellent job in designing and implementing a transition process that will allow Talen Energy to operate safely and efficiently on day one and will result in a more streamlined corporate structure for the remaining businesses of PPL Corporation.
And we're doing the significant transition work while maintaining our focus on business results, reliability, safety. 2014 has obviously been an eventful year for PPL, one in which we're blazing new paths and growing value for shareowners, even while we continue to provide the highest quality service to our customers.
Our high level of performance during this challenging year further strengthens my confidence that both PPL and Talen Energy will be very successful companies for years to come. I look forward to your questions after we hear some additional earnings details from Vince Sorgi.
Vince?.
Thanks, Bill and good morning everyone. Let's move to slide 10, PPL's third quarter earnings from ongoing operations decreased from last year driven primarily by lower earnings at our competitive supply segment, the Kentucky regulated segment and the UK regulated segment.
Let's move to the detailed segment review starting with the UK results on slide 11. Our UK regulated segment earned $0.28 per share in the third quarter, a $0.03 decrease from last year. This decrease was due to higher income taxes from a UK tax benefit recorded in the third quarter of 2013 and higher U.S.
taxes in the 2014 related to cash repatriation. We had higher financing costs from higher debt balances to fund our CapEx and higher depreciation from assets placed in service.
These negative earnings drivers were partially offset by higher utility revenues due to the net result of higher prices and lower volumes primarily driven by weather and lower O&M driven by lower pension expense. Moving to slide 12, Kentucky earned $0.12 per share in the third quarter, a $0.02 decrease compared to a year ago.
This decrease was primarily driven by higher O&M and higher financing costs from higher debt balances to fund the CapEx. In addition, higher margins from environmental capital investments were offset by lower sales volume due to mild weather.
Turning to slide 13, our Pennsylvania regulated segment earned $0.08 per share in the quarter, flat compared to last year with higher returns on additional transmission capital investments of about $0.01, being offset by multiple minor earnings drivers.
Moving to slide 14, our competitive generation segment earned $0.07 per share in the third quarter, a decrease of $0.07 compared to last year.
This decrease was primarily the result of lower Eastern Energy margins driven by lower hedged base load energy prices and lower capacity prices partially offset by favorable asset performance at our base load units.
Lower margins were partially offset by lower O&M at our fossil facilities, lower financing costs and lower income taxes resulting from a negative adjustment to deferred tax assets recorded in 2013. Let's move to slide 15 and review in more detail our updated earnings forecast.
As Bill noted, we're raising and tightening our 2014 earnings guidance this morning. Of the $0.12 increase to the mid-point, we added $0.07 at supply primarily drive by higher projected margins, the lower depreciation, the lower financing costs and lower income taxes.
We also increased the UK regulated segment mid-point by $0.03 driven by higher revenues, lower O&M from lower network maintenance expenses and lower financing costs. These are all consistent with what we have been experiencing through the first nine months of the year. These positive drivers were partially offset by higher U.S.
income taxes related to a legal entity restructuring we completed at the end of October. You may have read about that reorganization, as both S&P and Moody's issued and reaffirmed our credit ratings on Friday for the applicable WPD entities that have third-party debt outstanding.
The restructuring brings ownership of all four distribution network operators under a single UK holding company, better positioning our UK operations for further debt issuances. From a cash repatriation perspective, we will incur some additional U.S. tax in 2014, as certain of the steps within the restructuring were taxable transactions.
However, the new structure also provides future flexibility for how we source our cash repatriation from the UK. In addition to increasing supply in the UK, our expectations for corporate and other also improved by $0.02 primarily from lower expected O&M as we're not filling open positions as we work through the various transition efforts.
That completes the more detail financial overview. And I'll now turn the call back over to Bill for the Q&A.
Bill?.
Okay. Thank you, Vince. And operator we're ready for questions..
(Operator Instructions). Our first question comes from Greg Gordon at Evercore ISI..
A couple of questions, first, on the UK, this is like for the fourth or fifth time you've raised guidance for 2014 which is great momentum.
Looking at $1.38 when I think about that your 2015 midpoint for the 2015 guidance you’ve given for PPL post the spin, you got a $1.36 embedded in there at the to 2015 midpoint which will be $0.02 below your guidance for '14 now.
Is there any reason to believe that there is some significant potential downside in earnings off the $1.38 this year? Is there something happening on the revenue line or expense line with currency that we need to think about as we think about where you'd be inside that guidance range?.
Sure. Well you'll recall that next year for at least a portion of the year beginning April 1, we start the new Reo, revenue reset. So there's a step down in revenue on the top line that we'll experience next year.
Somewhat offset by higher than expected or -- and then initially communicated bonus revenues that we've recently been awarded in the last cycle. I'll ask Rick Klingensmith, President of our Global Business to comment on any other drivers or factors including currency.
Rick?.
As bill mentioned, Greg, the major affect for us next year is the revenue change that comes as a result of the REO ED-1 implementation on April 1. So that's what's really driving the earnings downward as compared to this year's $1.38, offsetting that we'll see some lower U.S. and UK income taxes.
As Vince had mentioned about some of the cash repatriations and the restructuring that we just went through we'll see a benefit within our earnings next year for that.
With the hedging that we did on the currency side, we're seeing some benefits as well when next year's earnings to help offset and mitigate the revenue decline as a result of the REO ED-1. And so the $1.36 that we’re forecasting for next year incorporates the decline as well as some of the upsides that we're seeing from tax and currency as well..
And the regulated segment bonus revenues that you talked about on slide 6, $130 million, $17 million increase, when do those actually start to flow through and what was your expectation that you baked into the midpoint of your guidance?.
Sure. The expectation was exactly that because when we provided that guidance earlier this year we had completed our year and which is the end of March and so we knew what the results were, we just had to go through an audit process to be able to confirm and ensure that the results were accurate.
And so what we have in our midpoint for next year was exactly that 130 million as we move forward..
Okay.
Switching to PPL supply, am I right in looking at the slides and comparing them to the last disclosure that expected generation in 2015 from your intermediate and peeking fleet is about up about 3 kWh? What's caused you to -- if that’s in fact accurate -- what's caused you to recalibrate that expectation?.
Sure. That's correct and the increase is really driven by the low gas prices in the summer producing that 98% capacity factor on our natural gas plants that I commented earlier on the intermediate unit.
Paul, do you want to add any more color to that?.
In '15, Greg, the built just went through '14 and '15 it's really all looking at the improved spark spread that we’re seeing in the market. So we've seen as you can look at the market pricing that we gave you in Q2 versus Q3, natural gas prices are off but spark spread grew pretty dramatically.
So that level of output will basically put us on par to achieve something pretty comparable to the gas performance in calendar 2014..
Final question, in Kentucky, have you actually filed the case and if not when do you plan on formally filing and when we will get a final decision?.
We have given them notice and we’re about to put the publication into the press. We won't file a case until the very end of November. It generally takes about seven months in a case like this so we would expect new rates to go in July 1, 2015 [ph]..
The next question comes from Dan Eggers with Credit Suisse..
Can you talk a little more about where you're finding your bolt-on energies on Talen and avoiding the dissynergies at the residual PPO, kind of as you've gotten into it where those bucketing dollars have come from and where you think you’re on the continuum of doing better or worse from those numbers?.
Sure. Maybe I'll ask Vince to comment on the PPL Corp side and then Paul can comment on the Talen Energy side. Go ahead, Vince..
Sure. So first of all I will say that we're well within the target of the $75 million that we’re going after at Corp. I would say we are right around that plus or minus a couple million dollars. So I would say we’re pretty much honing in right on that, on that $75 million, Dan.
And it's really coming from restructuring the corporate support services organizations, I call it condense and consolidate. So we're reducing layers of management and condensing more functions under fewer Presidents and higher level organizations. So there's a pretty significant reorganization going on.
We've also looked at noncritical third-party services and other things like that. So it's really just taken a deep dive into the corporate center..
On the Talen Energy side, we really split that. If you think back to the June 10th presentation, $85 million in headquarters and services costs, $60 million in operations think about as a plan for $10 million for margin in the HQ and services.
So even though we haven't been able to work extremely closely with the Riverstone folks because of anti-trust reasons as we go through the approval processes that are well underway.
From the diligence that we did, the yearly dialogue that we did, we have a very good idea in terms of the plans where we can get the 60 that will well underway into achieving -- the headquarters and services it's really just looking at setting up from a bottoms up perspective.
The HQ for Talen Energy relative to the level of costs that PPL charges the supply business today, again, I feel really good about the capability to achieve that $85 million and another $10 million in marketing with the way that Riverstone hedges their plans versus the more dynamic way that we manage our portfolio, we feel good about that as well.
I would hope there would be additional opportunities as we're able to get into supply chain, IT, some other activities when we're able to be more involved with that fleet. But today we're doing it based upon the best information that we've got, but we do feel good about where we're..
Okay. And I guess, Paul, just on the Susquehanna blade issues.
How the long do you think it's going to take to get the shorter blades put in all the turbines and then what is the maintenance profile over the next year or two, how long it takes to get that done as far as the frequency of extended or more frequent outages?.
As Bill indicated in the prepared remarks, upto three low pressure turbines that are on each of the units. In the unit one outage this past spring we replaced one of the three that would be the one that had the most issues since we've been discovering the issue that we've got with the blades.
On unit two, we replaced that one as well as another so we'll replace two of the three LP turbine with the lower blades next spring on unit two. The third turbine on each of the units, we haven't seen any major issues with. So in our business plan for next year we have got the plant refueling outage and blade modification outage for unit two.
We do not have an incremental outage factored in for unit one because we think based upon the data we're seeing on those turbines, that we will be able to make it through two, the refueling outage in spring of 2016 where we'd replace the other two turbines with a lower blades and that will pretty much take care.
We have one unit left in spring of '17 but we don't think we are going to need to have interim outages on the units following the spring -- for spring refill next year..
And they can be accomplished -- those retrofits if you will within our normal refueling outage timeframe. So it's not going to increase the outage, the normal outage scheduled. We can fit it with insight that window..
Okay.
And Bill, guess one another question, with the drop in gas prices and prospectively higher capacity prices, can you talk about what interests you might be seeing on generators looking for interconnection to the system for new builds capacity and how you queue that in in more timely fashion and the Compass Project which is pretty long dated?.
That’s really run through the PJM planning process and obviously PPL on our transmission side we’re part of that process, but I think there is ongoing interest in building new natural gas plants, but I wouldn't say that current capacity potential upside or lower gas prices are driving it much more significant than we had saw in the past.
I think a number of the developers that started these projects anticipated improving fundamentals and we’re already preparing for a lot of this not necessarily the PJM capacity price construct change, but time I guess will tell through the PJM process as to how much incremental interest we see..
Yes, I would say, Dan, that a lot of those projects that are being built are not projects that would qualify for the CP product, so we typically stick with single few, no storage capability, no gas transmission, so there will be a limited impact in terms of the CP outcome. .
The next question comes from Anthony Crowdell with Jefferies..
I just wanted to jump on Dan's question I guess for a clarification with the capacity performance product. I mean your I guess non-solid fuel plants, you know oil and gas that are in supply.
I mean do you think they can achieve the -- if they have dual fuel switching capability, could they achieve that forced outage rate that PJM is looking for?.
I think you might have asked two questions there. So on our dual fuel oil and gas unit, any of your units can (indiscernible) it would qualify.
For example, our Martins Creek facility would qualify where Ironwood and Lower Mount Bethel would not except for the extent that we can locate storage and get firm gas transition if we can for either all or partial of those facilities those may qualify.
But we do expect there's going to be limited capability in the market to be able to deliver much product along those lines.
When we think about the level of CapEx spend that we've driven out of the coal plants, there may be some modest increments to deal with the penalty exposure depending upon how that gets quantified but I wouldn't look from the PPL plan perspective at Montour (indiscernible) but those will be material cost increases..
The next question comes from Paul Ridzon at KeyBanc..
Sorry if I missed it, but with the shorter turbines at the Susquehanna, is there a D Rate [ph] associated with that?.
There would be a very limited D Rate only during certain periods of the year so not really material in the long run. So, yes there would be a small D Rate with the shorter blades..
That would be summer I assume?.
Yes in the summer..
If we replace two of the three were actually flat. If you replace one and there's actually a minor uplift because we get more output in the summer, we're generator [ph] limited in the winter.
Replacing the second one puts us back to flat and then the third one would be it's less than 10 MW per unit that would be impacted if all three are ultimately changed out..
When you announced Talen you kind of gave a forward-looking EBITDA of 627.
Where does that given the uplift you see?.
When you think about the numbers that we have provided on the supply side for PPL, I think you can get a reasonable calculation of the uplift. We have not been getting details up pace in terms of hedging, modeling parameters from the Riverstone folks.
Again we’re competitive with them until we get through the anti-trust regulatory approval process with DOJ so we can to certain regulations but we’re not prepared to provide an update to EBITDA today..
Can you give an update on the PPL side? Perhaps on Riverstone?.
Yes until we provide our earnings update at the end of the year in January, I'll refrain from that. We’re still going through our normal business planning process and looking at O&M and CapEx and fuel and the hedges. We're as prices have improved here recently including very recently with the uplifts in '15, we've and even '16 we've been hedging more.
So I would be giving you information that would be outside of the 930 numbers that are in the market prices and hegding data that we provided in the deck, So I think we will refrain today..
The next question comes from Paul Patterson at Glenrock Associates..
Just the following on the situation with the merger and what have you.
The independent market monitor as you know has been filing recommendations, I know they are just recommendations but it's hard for me to quantify what the impact of sort of cost that are -- mitigation might mean for some of the proposals he has with respect to getting restraints or divesture limitations.
I was wondering do you guys have any sense or any quantification if in fact any of those were adopted what the impact could be?.
We don't have any quantification of that. And as you kind of mentioned, it is really hard to calculate something like that given the complex nature of his comments and the way some of those kind of work when you say together, but some work in one direction and some go the other way. So it's kind of hard to assess that type of thought process they are.
So we have not quantified it, what it might mean..
I don't think it changes our view of (indiscernible) assessment of market power and how they're going to test us in any meaningful way. So we feel as comfortable as we did before he has made comments similar to this, the outer units, some of them are a bit more mitigated in nature.
But these same assets tend to have approved for their transaction processes. So we’re -- again nothing surprising by way of what he said for the analysis behind it, it's hard to perfectly predict that we very currently think that we fully meet FERCs requirement with either of the two packages that we proposed..
And in terms of the process, it looks like we’re kind of finished with the process, at least in terms of the back-and-forth between you guys and the IMM.
When do we expect could you give me -- went do you FERC will act on this?.
I think FERC should act by year end, hopefully by mid-December type timeframe, as are just reading the tea leaves now and then the DOJ would be sometime in mid-January to mid-February given the process..
And then on Act 128 Phase III, how do you guys see that -- I know they are beginning the process and what have you, but do you think that might impact the sales growth maybe -- do you think maybe the growing fruit [ph] with such efficiency and stuff has sort of gone away perhaps and perhaps we might see better sales growth given what's happened with Act I29 or just any flavor you can give us in terms of what you see might be happening there?.
Yes, we're just starting to work on taking a look at Phase III, you raised a good question about what the future opportunities are and from Phase II, we're still seeing some economically justified opportunities for savings for energy efficiency. And I think from a long-term perspective, we are basically looking at flat sales growth.
Our five-year look is about a 0.5%. So that's basically what we're looking at. So we’re not looking at significant increases in our load that’s basically flat..
And then Reggie, there's some obviously due to the elections today but if the democrat were to win and (indiscernible) has the polls, it seems to sort of for joining Reggie.
Do you see that potentially impacting you guys at all?.
Well I guess it remains to be seen, but we haven't gotten the full details from the prospective Governor on his energy plan totally. I think there has been some comments made about taxes on shale gas, but as it relates to Reggie, kind of remains to be seen.
I think the other question is whether it would require legislation to make it happen or not and if so and that might be a tough thing to gets..
Okay.
And then just finally on the currency hedge position, could you give a refresher on how much you've hedged? And at what price for the (indiscernible)?.
Sure, Paul, for 2015, we're at 98% hedged at a 163 rate and so that was included in our guidance for 2015 and then for 2016 which we've given you guidance on as well, we're 55% hedged at a $1.64 per pound rates..
Your next question comes from Julien Dumoulin-Smith from UBS..
So kind of a higher level question here to start off, I'm curious, can you clarify or at least give us a little bit of a timeline in thinking about getting better than a 4% EPS growth rate, perhaps some comments previously around 4 to 6.
How do you think about getting there? Where do you see yourself today particularly in the context of better synergy realization?.
Sure. We’re in the midst of our financial planning process right now and we're going to be looking to optimize the current plant that we’ve by year-end and so far we don't see anything at the moment that would suggest we can't grow earnings by at least the 4% annually that we've communicated previously.
Of course we hope to improve upon that and we will be providing an update on earnings growth projections on the year-end earnings call. So, expect on the next call that we will give you some additional flavor on that..
And then little bit of a detail over on the supply side. Montana, you have a single asset left really.
What's the thought process there as you look towards realizing this Talen deal?.
The thought process there is one for hydro the next few weeks we move forward to the North Western [ph]. We will be optimizing our cost to cost structure to deal with the smaller asset mix. We would plan on continuing to run the four units at that Colstrip. We had previously communicated the plant to shut down come spring which is still the plan.
So we will continue to run the assets there, the positive cash flow units to the extent that another party has a view to create a capability for us to exit at the value that represents our fundamental reevaluations, that’s something that we can entertain not unlike that we did with hydros..
And then perhaps this is going a bridge too far, but what do you think in terms of CP in PJM in terms of aggregate revenue upside or impact to the market ultimately for your portfolio given your comments and responses to prior questions?.
You started off right in terms of your bridge too far.
I will be down there today with one of the coalitions in front of the Board making our very strong points that when you look at the fact that roughly more than half of the coal-fired generation in PJM earns no economic return and it's flat to negative cash flow that they completely unsustainable situation.
If we just look at what at our units (indiscernible) while they are positive cash flow, from the '09 - '10 period we went from just under $200 a megawatt a day to a little under a $120 a megawatt a day in the 17-18 [ph] auction.
We've gone from 80% plus capacity factors over that time frame to less than 50 and the amount that we're earning for every megawatt hour that we produce is getting closer to being the variable cost of production. So it's a very challenging situation for the coal plant.
On the Talen side, we're not going to live with scenarios where any one of the plant subsidizes other facilities. And I think other companies are resolutely in the same spot.
So we find as a system to provide the right levels of revenue to ensure that these assets remained in the marketplace and are reliable or we’re going to see an accelerated -- even for units that are in place, significant legacy investments and complying with care and with max [ph].
You’re going to see more of those facilities shut down and have the system become more volatile. So because only when more gas is going to get built, as Bill indicated in earlier remarks and Vince did, in Q3 we had less than 30% capacity factors on our coal units.
It worked out fine because we can buy product back from the market and satisfy hedges at net prices losing money at peak but gaining in off-peak less than we can produce it for but over the long term that’s unsustainable and our gas plants are running at base loads.
So that's why obviously you're seeing D Rate [ph] expansion that you're seeing in '15, in '16 it's starting with less liquidity there, but some of the market value the units. And if the answer is yes then we need a durable, sustainable revenue stream to these plants because this is new capital going in.
This isn't O&M that they are asking for in terms of reliability and people have been really cutting back capital in the facilities and it's very difficult to actually today to predict reliability.
So that risk reward as well on the penalty side has to be balanced as several companies are going to need to play some relatively material investments in the plan to get them to the level that avoids penalty structures..
I would just add that as proposed, the capacity construct would be a net positive a significant positive to the overall Talen Energy fleets given a significant levels of base load that we have with firm fuel. So it obviously includes nuclear and the coal assets as well as any dual fuel.
So given the characteristics of our portfolio, this would be a significant potential upside to the Talen Energy fleet..
Our next question comes from Neel Mitra at Tudor Pickering..
I had a question on domestic utilities and the 4% growth rate going forward.
What are you potentially looking at in Pennsylvania and Kentucky after the ECR spending and what are some of the rate growth based projects that maybe aren't in the plan right now that you are contemplating?.
Well we provided CapEx plans for five years so I think you can -- and rate based growth. So I think at least that far out you can see pretty clearly where that growth is going to come from. The transmission and distribution systems are aging.
We're replacing a lot of that aging equipment with newer technology, so I think much of that is going to continue on even beyond the five-year program and plan. And we're going to be providing 2019 numbers on the yearend earnings call. So you get at least another additional year at that point.
I'll ask Rick and Greg to comment for both Kentucky and Pennsylvania to maybe supplement anything there..
We're in the process of putting together our plans for the next couple of years and I would expect that will continue to feel the environmental pressures particularly in the landfill slide so I would anticipate to the additional expenditures on the environmental side.
And in addition, while we did postpone the Green River facility from 2018, we probably will have to bring that back in some time 2021. So we would look at additional expense in the latter part of the period as well. And frankly just given the state of play, I'm confident the environmental requirements are going to go up..
As far as Pennsylvania, again we're in the middle of a planning process and just as Bill said, we'd see continued needs of both on the distribution and transmission but expect additional expenditures in both places..
And I think our largest growth opportunity in Pennsylvania is the Compass Program, that 725 mile transmission lines so to the extent that is ultimately approved, that would be I think a very large and meaningful project for Pennsylvania and for Greg's business..
And Paul, you kind of mentioned that your combined cycle plants are running really low while be base load plants are disadvantaged with dark spreads.
Are there any Brownfield opportunities given the fact that you're right on top of the Marcellus with a lot of your base load and intermediate plants to expand capacity there? Or would it run into some market monitor issues?.
No, there wouldn't -- to the extent we decides to build something while we’ve to go through our normal triennial process to ensure we don't have market power for that purpose from a market monitor perspective if we build, that's different than buying which creates kind of an immediate tests.
So we will be okay on the build side, I believe in this area. We have an existing site at Martin's Creek, that's buildable and dual fuel. We're still looking at very seriously the ability to gasify Brunner Island to the extent that we did that beside that pipe could also handle CCBT [ph] at that site, we’re very close by.
So we've got a couple of sites ready to go in PJM as well as two of the three sites in Texas are expandable as well if we see the right price signals and the right fundamental there..
Our next question comes from Steven Fleishman at Wolfe Research..
Just on the updated guidance for '14 and locations for '15.
So any of the -- you mentioned the UK incentive revenues and the structural change were already in the guidance when given when the Talen deal was announced? Is that correct?.
That's correct, Steve..
Okay, but is there any other benefit of the '14 improvement that would flow through to '15?.
Not really, Steve, most of the benefits of 2014 are coming from the supply segment as we talked about a little bit improvement on the WPD side in the UK. But the bulk of the outperformance in 2014 has been on the competitive gen side..
Okay and then you're expecting improvement in Kentucky in '15 and anticipated this rate filing?.
Yes. That's correct..
Okay.
And then maybe could you give us a little more sense on the new structure for the UK businesses and the ability to how flexible are you to take basically cash out every year?.
As Vince mentioned in his remarks, we've done a restructuring reorganization of our -- primarily our UK holding company organization. And as you know, we operate the WPD business as one business all for distribution network, operating companies.
But in the past, we have had two legal entity structures; the legacy, the Southwest and the South Wales business came up through one legal entity structure and the new Midlands businesses came up through a parallel but a separate legal entity structure.
And so what we've been able to accomplish here at the end of October is to bring that within a single UK holding company structure. And so that actually provides for a financially stronger holding company that should be better positioned for future debt issuances and re-financings that we now need to do out of the holding company.
It also sort of simplifies the group structure for other third parties, the credit rating agencies, the banks and other entities as well.
We do see some benefits internally, it helps us with cash management, regulatory reporting and some administrative elements and so we’re quite pleased with the reorganization that we just accomplished for this stage.
As we look to future cash repatriation, there was a side benefit in that we did within the planning of this combination, significant looks at and reviews of our cash repatriation needs for the future and how we can bring them back in a tax efficient manner. And not have higher incremental U.S.
taxes under the new structure and we were successful in being able to lower our effective tax rates out into the future as compared to this year and even the average that we have had for the last few years.
So we were not only from a business standpoint improving the structure, but we were also able to bring back the levels of cash that we've forecasted in the past and that we have commented on and provided you the numbers in the past. We'll be able to do that more tax efficiently than we had expected as well..
Our next question comes from Michael Lapides at Goldman Sachs..
Just a couple of easy questions here, first of all, in the UK can you just quantify for us what the revenue roll off in 2015 is related to implementation of REO in the spring and if I heard correctly the step up and bonus revenue is just 17 million, but I didn't hear the first piece about the roll off..
As we look to fiscal year 2015, the revenues will be changing on April 1 of that year. So it's not a full year effect. But we're seeing about a $150 million in a revenue reduction, that’s a $0.15 as our reduction for fiscal year '15.
I'm sorry, Michael, the second part of the question again?.
And so just partially offsetting that is the bonus revs, the bonus revenues are only up about -- is that $17 million or is it more than that?.
Well is 17 million higher on a regulatory year basis and again that will start on April 1st as well, so that $130 million will be coming in and starting within that period of time.
The fiscal year on fiscal year difference between 2014 and 2015 is not as great, but it absolutely helps mitigate the revenue short fall or the revenue decline that we’re seeing in 2015. What's also helping is I had mentioned earlier is that we're seeing lower taxes -- tax expense, so that’s helpful.
We’re seeing a benefit from the currency hedging that we had put into place where we're 98% hedged at a $1.63 per pound rate, so that’s how to mitigate the decline in revenue for next year..
And on PPL supply when I look at the 2016 data that's in the hedging supply, two things.
One, putting noticeable drop-offs in the volumes expected from the Eastern base load facility when you look at '15 versus '16, what's driving that?.
In '15 versus '16 we've got reversion and spark spreads, we've got only a very small portion of the year that we've got the correct facility available.
So it's market drivers and not having correct available and the mix and any further step [ph] all the way from '14 to '15 to '16 you’ve got the 3 million -- 3.5 million megawatt hours of hydro also disappearing through that time period as well..
Yes, I'm just thinking more on the PJM fleet.
The 43.1 down to 40.8 is that all spark spread driven or is it planned outage related as well?.
That's all base load, so you'll see what's happening in the spark spread, at the bottom, the dark spread at the top..
And then the last thing on coal for the Montana fleet, the 2016 data assumes a reasonable uptick in the coal pricing. Just curious for the driver of that given how weak PRB prices have been recently..
Yes so being eliminated from there is coal from the correct facility. So it's Colstrip only and it's looking at the cost plus contract at the mine relative to the volumes and spreading those overheads and so that's -- it's again it's a decently sized range given that in '16 it's all coal stratified.
But that mine outside -- that mine production I think you’ve to look at it a little differently that broad based PRB.
Not putting on the same economics as procuring from the market because we’re sole sourced from one provider from conveyor belt removal [ph]?.
And can you remind why the removal of Corette?.
Yes so Corette won't be able to meet and MATS [ph] come spring at last year on any type of economic basis that we see today. So, we just simply can't meet the SO2, mercury requirements for that facility in an economic fashion, so it's going to be shut..
So it leads to lower O&M at supply a little bit in '16 over '15 as you’ve fewer megawatts but also obviously the loss margin..
That’s correct..
We have Jonathan Arnold from Deutsche Bank..
I would just like to follow-up on the question on the UK reorganization and in terms of the making an impact on a going forward tax burden that you referenced. Can you maybe quantify that and then explain to what extent and how it flows through into the earnings reported in the U.S.
just to help us think that through? And I want to confirm it feels like that something you didn't include in your guidance whereas some of the other elements were in the guidance. So I want to make sure I'm right about that..
With regards to some of the specifics around the tax efficiency that we're seeing, I'll give you some numbers and we think about in an effective tax rate areas. In the past couple of years, 2013 our effective tax rate was about 20%.
This year as Vince had mentioned we’re seeing some higher tax on our cash repatriation and this restructuring, we’re going to be slightly over 23% this year on the effective tax rate As we go out into future, we're going to see an effective tax rate that averages slightly less than 18%.
So we're seeing some benefits out into the future, those benefits were included in the '15 and '16 guidance because we had already had plans in place for how to mitigate the REO and the revenue changes that were coming along and this will help us is further out past that period of time when we can average a lower effective tax rate than what we were expecting out in that period..
So is 19% a good number to use right through the 7-year review?.
Probably not through the entire 7-year view review, but at least through the next five years, 8-year review, I should say. But at least through the next five years that we've gone out in our calculations and our plans..
So the 18% is the right number, but it was already in the guidance --.
For 2015 and 2016, that is correct.
And the second part of your question deal with how does it flow-through earnings from a UK regulated segment, we not only report the earnings that we translate and received from WPD from the UK, but then we also incorporated and include the domestic effects which include some overhead costs here at PPL, but also include the U.S.
tax expense on class repatriation. And so the UK regulated segment just in its normal reporting process will incorporate whatever costs there are or whatever benefits there are within our earnings..
And are those numbers that you just gave the 20%, 23% and 18%, they include both of those tax items, is that correct?.
They include both the UK and the U.S. tax effects that is correct. That’s a combined effective tax rate..
Thank you Jonathan and thanks to everyone for joining the call and look forward to your questions and comments on our year-end call. Thank you..
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