美國電力 (AEP) 2013 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the American Electric Power fourth-quarter 2013 earnings conference call. For the conference all the participant lines are in a listen-only mode. There will be an opportunity for your questions; instructions will be given at that time. As a reminder, today's call is being recorded. I will now turn the conference over to Ms. Julie Sherwood, please go ahead.

Thank you, John. Good morning, everyone; welcome to the fourth-quarter 2013 earnings webcast of American Electric Power. Our earnings release, presentation slides and related financial information are available on our website, AEP.com. Today we will be making forward-looking statements during the call. There are many factors that may cause future results to differ materially from these statements. Please refer to our SEC filings for a discussion of these factors.

Joining me this morning for opening remarks are Nick Akins, our Chairman, President and Chief Executive Officer, and Brian Tierney, our Chief Financial Officer. We will take your questions following their remarks. I will now turn the call over to Nick.

Thanks, Julie. Happy New Year to everyone and thanks for joining us today. Usually the New Year comes with a sense of renewed optimism that our best days lie ahead. I can tell you here at AEP reviewing what has been accomplished during 2013, and after a more detailed review of the fundamentals during the fourth quarter, there is reason to be optimistic. The foundation has been set for continued success and perhaps finally a growing economy.

We talk a lot here about infrastructure development, including transmission, the customer experience and the employee experience, and this provides the focus for the actions we take. In that context I am very pleased to report several significant accomplishments during 2013.

Our safety performance -- for the second year in a row we accomplished zero fatalities on our entire system with one of the best safety records we have ever had. Moreover, we also had our best year from an environmental stewardship and compliance perspective. We are very proud of both these accomplishments; that in my view is a strong indicator of the health of the organization.

We completed corporate separation on time and accomplished many of our objectives including the transfer of the Ohio generation assets to APCo Kentucky and the new unregulated generation company. I want to thank all the commissions and the other stakeholders for their cooperation to get this done.

We delivered fourth-quarter 2013 GAAP earnings of $0.71 per share and operating earnings of $0.60 per share, including the year 2013 with GAAP earnings of $3.04 per share and operating earnings of $3.23 per share, solidly in the upper range of guidance.

Rate activity was positive with $340 million of secured rate changes across our state jurisdictions. I'm pleased to report from last week that PUCT did reverse the AFUDC decision that had previously gone against us and I'm very thankful they did that and indicated that we can invest in Texas in a positive fashion.

We completed two securitizations totaling $648 million in APCo in Ohio with one remaining securitization, that is regarding the Ohio fuel. We exceeded our performance improvement targets for the year and our current 2014 initiatives are continuing positively and on schedule. Our previous dividend increases announced during 2013 improved our dividend payout by 6.4% and continues our focus on maintaining the dividend commensurate with earnings.

We continue to target 60% to 70% payout dividend ratio. Our total shareholder return for the year was 14.2%, so a very good year. Our employees have quickly responded to the challenges that we faced during 2013 and came through with flying colors. Our emphasis on execution, culture and financial and strategic discipline are paying dividends, no pun intended.

As an example the Gavin plant has gone through lean activities and recognized a change in the operating practices certainly during this event we had with the polar vortex. So it is just early indication of the successes that we've had relative to the lean activities. I am pleased with the response and energy of our employees as we redefine the culture of AEP, and in fact the future of AEP. So let's talk about the future, 2014.

We are reaffirming our guidance ranges for 2014, 2015 and 2016 and the 4% to 6% growth rate. 2014 guidance is $3.20 to $3.40 per share. Our continuous improvement initiatives are progressing well with four plants done with the lean rollout, now we're focusing on Cardinal, Mitchell, Rockport and others. We continue the wires lean work in Ohio and APCo and will soon move ahead to I&M and SWEPCO.

Our management team, including myself, participated in the team rollouts and we expect IT and the Mitchell rollout coming up soon and the energy and ingenuity of our employees is just amazing in this process. The new unregulated generation function continues to work to reform its cost structure and operating parameters in the PJM market and many other activities are progressing as well.

Transmission growth continues on plan and we continue to focus on even more capital moving to transmission as we showed you earlier in the EEI presentation late last year. We are pleased with the progress being made in this segment of our business.

We have rate proceedings in Oklahoma, Ohio, Virginia, West Virginia, Kentucky during the year. We are planning for 2014 of having rate relief of $175 million in rate recovery, 82% of which is already secured. Chuck Zebula continues his work to optimize the unregulated business to ensure that it is cash positive and contributes to earnings.

Of course cold or hot weather helps, but we continue to work on PJM capacity market reforms to enable investment to occur as well as a focus on any emerging hedging possibilities and cost-related efficiencies in this business.

Just as an aside, to quickly remark on the capacity markets and recent experience with the polar vortex, it is interesting to note that while daily gas prices are in the $5 to $6 per MMBTU range, and energy prices are soaring well beyond that supported by gas price increases alone, it is clearly evident that capacity rents are being reflected in energy prices indicating a need for further reform of capacity markets.

Looking at the physical side, when 89% of our coal capacity slated for retirement in mid-2015 is called upon and running, natural gas delivery is challenged and voltage and load reductions are occurring it is another reminder that we should carefully plan to design this social safety net we call the electric grid to meet extreme requirements, not just steady-state conditions. We believe the nexus of EPA initiatives, energy market development and security threats, whether physical or cyber, is a national security issue.

All of this that we achieved in the last year certainly contributes to the customer's experience by providing electricity in a safe, reliable, economical fashion in an environmentally respectful way.

Now let's move to my equalizer chart. We -- it is on page 5 of the presentation. The overall is approximately 9.9% ROE, it's come down a little bit, but primarily reflects rate and recovery lag from rate cases and the heavy project spend in transmission. We expect this to improve.

So if you look at the chart in the APCo area, we have the Virginia bi-annual case, the West Virginia rate case, so we expect that to continue to improve. Ohio Power is coming down because of the customer switching that is occurring. Kentucky, it is in the midst of a Mitchell transition that is occurring, we expect the base rate case to move Mitchell over the base rates.

And then I&M continues to improve at 9.3%; PSO will have a rate case this year; SWEPCO has some transmission-related cost to recover and also some Dolet Hills-related generation costs in Arkansas. And then AEP Texas continues to have a significant load growth and amortization of stranded costs is included in that number as well.

And then on the Transco Holdco side it is 9.5%, but there is obviously rapid rate of investment that is occurring there and the developmental expense related to Transource and also CREZ Texas has a T cost filing that is occurring as well. So we are seeing continued improvement there and we will continue to address that.

So, as we move into 2014 we are watching clearly some very positive indicators from the fourth quarter 2013 regarding our load. If you exclude Ormat, the bankrupt aluminum manufacturer, for the first time in not just several quarters but several years, in fact back to 2007, all of our categories -- residential, commercial and industrial load -- increased in the same quarter. That is the first time that has happened in years.

We are seeing significant shale gas and other load-related activity improve, so we are optimistic based upon the quarter that this trend could continue. Brian will address this in more detail.

2014 will be a year of significant strategic importance to AEP. Our management and the Board will focus much attention on transmission growth, our regulated businesses, the utility model for the future and what that means and we will continue to review the progress in the unregulated business as well.

So since we last talked to you all at EEI late last year, we've made some significant progress in several strategic areas -- corporate separation, the transmission allocation of capital, the infrastructure investment, focus on our regulated business, defining the business case for our unregulated business, producing quality dividends and earnings for our shareholders and quality service to our customers and defining a culture for AEP for the future. In a nutshell sticking to our knitting. That of a focused regulated business. I will turn it over to Brian at this point.

Thank you, Nick, and good morning, everyone. On slide 6 you will see our comparison of 2013 results to 2012 for both the fourth quarter and the full year. In the interest of time I will focus my remarks on the full-year column and only add comments for the quarterly comparison when necessary.

Operating earnings for the fourth quarter were $296 million, or $0.60 per share, up $0.10 per share compared to the fourth quarter of 2012. These results bring the full-year earnings to $1.573 billion or $3.23 per share compared to $1.497 billion or $3.09 per share recorded in 2012, an improvement of $0.14 per share.

Stepping through the detail from top to bottom you can see that the annual comparison was adversely affected by a combination of certain Ohio transition items that were unfavorable by $0.26 per share. This effect on earnings was driven by an increase in customer switching net of the capacity deferrals, lower capacity payments from competitive retail energy suppliers and the overall --- and the reversal of 2012 prior period unfavorable provisions.

The effective income tax rate was unfavorable $0.17 per share for the year due to unfavorable year-over-year tax to book differences accounted for on a flow-through basis, as well as positive adjustments to state income tax returns that were recorded in 2012. A significant portion of this effect was recorded during the fourth quarter. Allowance for funds used during construction, or AFUDC, was off $0.10 per share for the year due primarily to the start-up of the Turk Plant in December of 2012.

O&M expense net of offsets was unfavorable $0.05 per share for the year, primarily due to increased spending for plant outages in 2013. The unfavorable variance for the quarter reflects higher storm and employee-related costs. On a total system basis, excluding earnings offsets and river operations, O&M for 2013 was $2.8 billion, which was flat to 2012. As you may recall, we expect to hold O&M at this level in 2014 as well.

Off system sales margins net of sharing for the year were down $0.05 per share. This decline was driven by lower RPM capacity revenues that hurt results by $0.03 per share and lower trading results. The annual decline in regulated retail load of $0.02 per share is driven by the lower industrial demand across much of our service territories. I will discuss the economy and our retail sales data in more detail in upcoming slides.

AEP River operations began to rebound during the fourth quarter but were still off $0.01 per share for the year. This decline in earnings reflects the lingering impact of the drought of 2012. Weather helped our annual earnings by $0.04 per share versus 2012 and was favorable $0.07 per share versus normal weather.

Favorable interest income contributed $0.07 per share for the year due primarily to the recognition of interest income from the resolution of the UK windfall tax issue earlier in 2013. Transmission Holdco continues to grow adding $0.02 per share for the quarter and $0.07 per share for the year, reflecting significant investment in this area.

Consistent with our goal to allocate available capital to transmission, earnings for this segment were $0.16 since per share, $0.02 higher than originally forecasted with guidance for 2013. Our guidance for 2014 reflects $0.29 per share of ongoing earnings from this segment.

The quarterly comparison of the parent added $0.11 per share and was due to the make whole premium for debt retired late in 2012. The annual comparison for the parent shows a benefit of $0.15 per share due to that debt retirement and the resulting lower interest expense realized through 2013.

Rate changes were favorable by $0.11 per share for the fourth quarter. This quarterly result pushes our favorable year-to-date comparison to $0.45 per share. This improvement in earnings reflects constructive regulatory outcomes in multiple jurisdictions.

Finally, other items for the annual comparison were favorable by $0.02 per share primarily driven by lower long-term interest and lower depreciation expenses.

In summary, despite considerable headwinds in Ohio we were able to deliver results near the upper end of our guidance range. The better than expected results were aided some by weather but, more importantly, we executed on our regulatory and strategic plans. In all, 2013 was a successful year for American Electric Power.

Turning to slide 7 you will see our usual detail on normalized retail load with a new feature. On the bottom half of the slide you'll see a light blue line that adjusts the gross industrial and overall normalized load trends by factoring out the impact of the Ormat load. We felt that this presentation was helpful because, although the loss of the Ormat load was significant in terms of volume, AEP did not earn significant margin on that load.

On the bottom right quadrant you can see that weather normalized total load was down 0.8% for the quarter and 1.6% for the year. excluding Ormat the quarterly number is actually positive 0.9% and was down only 0.6% for the year. For 2014 we are forecasting total normalized load to be down 1.1%, but the forecast is essentially flat when Ormat is excluded.

Industrial load was down 3.2% for the quarter and 4.5% for the year. Excluding Ormat quarterly industrial sales were actually up 1.6% and the annual comparison was down only 1.6%. For 2014 we are forecasting gross industrial load to be down 2.2%, but positive 1.2% when adjusted for Ormat.

There were a number of new industrial expansions especially related to the oil and gas sector that we expected to come online earlier in 2013 but were delayed until the second half of the year. Looking forward to 2014 we expect an additional 270 MW of new industrial load to come online. This will help to offset the negative drag on industrial growth caused by the loss of Ormat. We will take a closer look at industrial load on the next slide.

Residential sales, shown in the upper left quadrant, were up 0.9% for the quarter which brings the annual sales flat to 2012. We continue to see modest customer growth in our Western service areas while our East customer counts are essentially flat. Average usage per customer has been impacted by home energy efficiency programs. For these reasons we are expecting normalized residential sales to be down nearly 1% in 2014.

Finally, in the upper right-hand quadrant you can see that commercial sales were essentially flat for the quarter and the year. Commercial sales saw some growth in Texas, Ohio and Oklahoma where we've seen stronger employment gains. We are forecasting commercial sales to be roughly flat in 2014.

Let me stop here and provide an update on the economy within AEP's footprint. AEP's service territory continues to experience economic growth despite the drag that the federal fiscal austerity measures placed on our economy. Most economists predicted that the third quarter would be most impacted by the sequestration and this was true for us.

For the fourth quarter GDP growth in AEP service territory was 1.3% which is an improvement over the 1.1% growth we saw in the third quarter but still below the projected fourth-quarter growth for the US of 2.3%. Fortunately employment statistics, which are a better indicator of electricity sales and GDP, were not as weak and remained steady through 2013. Job growth in AEP's Western footprint was up 1.4% and just below the US at 1.7%, while job growth in the East moderated recently to 0.8%.

With that segue let's turn to slide 8 where you will see the quarterly and annual results from our five largest industrial sectors. Our largest sector, primary metals, was down 23% for the quarter and 18% for the year. Earlier I mentioned the curtail of production of Ormat and excluding this effect the sector would have been down closer to 7% in 2013. That customer has now fully ceased operations and so we expect to see this impact through the third quarter of 2014.

Chemical manufacturing sales were up nearly 5% for the quarter bringing the annual decline to 0.3%. We saw a number of customers increase their production towards the end of 2013. As global markets for chemicals continue to recover we expect this export industry will grow.

Petroleum and coal products sales were down 2.5% for the quarter and 1.6% for the year. This was mostly due to three specific refineries that were down for routine maintenance in 2013. Excluding these three customer sales to this sector were up 2.5% for the year.

The mining sector, excluding oil and gas, was up 0.6% for the quarter but still down 1.4% for the year. This decline reflects the continued impact of low natural gas prices and weak demand from utilities and metal producers.

Paper manufacturing was up 7.5% for the quarter and 3.3% for the year driven by a major expansion in Ohio along with higher demand in our Western footprint. Although not in our top five sectors, we continue to see growth in the oil and gas extraction and pipeline transportation sectors driven by continued gains related to shale gas activity.

Slide 9 provides a picture of the financial health of the Company. Our total debt to capitalization improved in 2013 ending the year at 54.3%. We look back as far as 1999 and 2013 had the lowest percentage of debt to capitalization over that time frame.

Other important metrics, FFO interest coverage and FFO to debt continue to be solidly in the BBB and Baa2 range at 4.7 times and 18.8% respectively. We also ended the year with a strong liquidity position of $3.5 billion bolstered by our two revolving credit lines and our term loan facility.

On the bottom left-hand side of the page you will see that our qualified pension funding has increased to fully 99%, the Company has aggressively funded this plan to the benefit of our employees, retirees, shareholders and bondholders. In addition to the funding the Company has been working hard to match the duration of the assets to the liabilities and to de-risk the plan as it approaches full funding.

In addition to our pension results, our other postemployment benefit plan is now more than fully funded at 117%. This is a result of changes that we made in 2012 to our postemployment medical plans for future retirees. The financial strength depicted on this slide demonstrates the commitment that our Board and management have to growing the Company and at the same time maintaining a very strong balance sheet.

Turning to slide 10, we can review some of our assumptions and sensitivities underpinning our 2014 comments range of $3.20 per share to $3.40 per share. As you would expect, a key sensitivity is retail sales volumes which we've already discussed. Remember that we base our guidance on normal weather. While you would be right to think that load has been strong so far with the extreme January weather, please be cautioned that this is only one month in what should work out to be yet another 12-month year.

Our regulated and competitive businesses have different sensitivities to wholesale prices for power at $0.01 and $0.02 per share per dollar for the year respectively. And of course O&M expenses and taxes are also key to earnings with a 1% change in O&M having a $0.04 per share impact and a 1% change in the effective tax rate having a $0.05 per share impact on earnings. At this point in the year we do not anticipate much variability in the tax rate for 2014.

A significant driver for 2014 earnings is rate changes of $175 million. As Nick said earlier in his remark, of this amount the Company has already secured 82%. Most of the remaining amount is expected to come from wholesale FERC formula rate customers where annual rate adjustments are fairly routine.

You can see the power and natural gas prices that were used in formulating our guidance. Prices have changed since we developed this guidance last year but at just 27 days into the new year it makes a lot of sense to maintain or operating earnings guidance and to keep it steady as she goes. More than ever with some of the market challenges we face in 2015 through 2017 we will be actively managing outage schedules and expenses in response to revenue changes in order to keep inside the guidance comb you see on the left-hand side of the next page.

So turning to slide 11, I want to reiterate a point that Nick made earlier in his remarks, our 4% to 6% growth rate is predicated on continued investment in our regulated properties and by our continued focus on sustainable cost savings and O&M discipline. The green flags on the right highlight the major initiatives that are underway. Let me provide some granularity on two of the work programs in order to provide insight that this is a serious focus of management and employees as we begin 2014.

Management is providing our employees with the tools and processes to advance continuous improvement and our employees are providing the ingenuity and the know-how to get the job done. On the generation side, four of our larger generating plants have engaged in employee led sustainable improvement programs beginning in 2013.

These plants have already experienced expense savings through more efficient work practices, heat rate improvements and better utilization of the contractor workforce. Similar programs have started at additional plants already in 2014 with five more to go during the year. In 2015 four additional plants will be engaged.

Our generating plants are leading the rest of the Company in continuous improvement initiatives, demonstrating the gains that can be realized through these efforts. Similar programs have been launched by our distribution employees. Two districts began initiatives in 2013 with 16 scheduled for 2014, nine in 2015 and two in 2016. These districts are using employee led idea generation, benchmarking and white boarding to streamline their processes, better engage our workforce and to focus on customer service and savings.

Our transmission, supply-chain, procurement and corporate center organizations are engaged in similar programs, demonstrating that continuous improvement in employee engagement are part of our culture. Our employees are well aware of the opportunities and challenges presented by our changing business environment. They also have the passion and drive to make the most of the opportunities to meet the challenges and to serve our customers as they expect to be served.

On Wednesday of this week Nick will lead another employee meeting on these subjects as a way of ensuring that all 18,500 employees are informed, motivated and engaged as we move forward. With that I will turn the call over to the operator for your questions.

(Operator Instructions). Greg Gordon, ISI Group.

Congratulations on a good year. A couple questions. First, can you repeat what you said about your --- what was the buildup for your assumptions on residential sales? And then can you extrapolate on what that means sort of going forward over the next several years of your forecast?

Yes, we are anticipating residential sales to be down almost a percentage point in 2014 and we think it is largely being impacted by a lot of the energy efficiency programs that we have across our service territory with Ohio, Indiana and some other states having some pretty aggressive programs. So it is impacting load, also customer counts are an impact as well.

We are seeing positive customer count growth in the Western part of our service territory and pretty stagnant customer growth in the eastern part of our service territory. So when you put those effects together is definitely a drag. We will see how things work out as we go through the year and we will obviously be updating you quarter by quarter. But we are anticipating some load decline and the residential sector in 2014.

So, Greg, the last quarter of the year indicated some positive strength to that but I think we're going to have to sort of see that play out before we make any changes.

I guess what I'm asking you is as we think about the guidance ranges for 2015 and 2016, not asking you to give specific drivers across all the factors in the business, but would it be fair to say you are assuming continued reductions in residential demand through time due to federal and state energy efficiency standards? Or do you think that your base case for economic growth beats into that and you could get back to positive net residential growth?

Our load growth assumptions through 2016 are very, very conservative. So I mean we are not forecasting to hit our numbers -- the classic 1% to 2% load growth that we had seen earlier in the century. We are anticipating that negative 0.5% to positive 0.5% load across the timeframe.

So it is relatively flat, it is less than 0.5%.

Great, thanks. Second question is on what you are seeing -- I know you have a de minimis footprint relative to a lot of the other companies when it comes to competitive generation in retail, but it is still significant for you. Have you seen behavior change on the part of retail consumers and wholesale buyers in the last several weeks with regard to what they are willing to pay for longer-term power contracts?

Wholesale prices are up quite a bit in 2014, last three weeks, not as much out the curve. But are you starting to see some depth and breadth to the market come back as volatility comes back or not?

Yes, Greg, we really haven't seen much of that yet. Obviously there's going to have to be a little history that plays out here with the weather. But also it is pretty clear that capacity rents are included in energy prices. So with the market reforms that are occurring plus the experiences people are having relative to this extreme weather, there may be opportunities for additional hedging to occur and also for customers to finally see that we need to sort of lock things up for the long term. So it may be helpful, but at this point it is too early to tell.

Okay, thank you, guys.

Dan Eggers, Credit Suisse.

Just kind of now that the transition for the competitor generation of Ohio is kind of on its way, can you just share your updated thoughts on the future of competitive generation in the AEP business mix? And maybe what Greg was asking, are you starting to see or are you able to engage in conversations about some long-term supply agreements to help put some more visibility in that business?

Yes, Dan, I think we stand by originally what we said relative to this business, that it will hinge upon our ability to see this additional hedging occur, that we can firm up the supply and make it look quasi regulated. At this point, because capacity markets have been depressed, and recent experience aside, it is difficult to tell how successful we will be in our ability to hedge that up.

But we are not standing on our laurels with that. We are aggressively looking at the cost structure of the business. We are also reforming the way we operate at our plants because they know full well their survival is at risk there. And so, we are going to do everything we can do to position this fleet to where it is positive and also address the market reforms that are occurring at FERC now.

And then hopefully with the events that have transpired recently with the weather it could help us in terms of -- get additional hedges in place. But that business, our retail operation together now with that generation fleet, there are some opportunities there. So we are working on all fronts to ensure that we are able to position this business as best we can. And at the end of the day it needs to look quasi regulated to us.

I guess, Nick, from a market reform perspective, given the time horizon even to the next RPM results actually affecting your earnings contribution, are there changes that can happen in a reasonable time period that would give you guys comfort to wait it out? Or are you going to need a customer to come in and buy in rather than having policy reforms do it?

That remains to be seen. We have -- I think there are two or three of the changes, market changes that PJM has filed at FERC, we expect another to get filed with this triennial review of the curve itself, there are some opportunities there if it is done in a positive fashion. But we are going to have to see the results actually of what FERC approves.

And it is important for us to see that FERC understands the issues that are in play here and that they obviously make wise decisions on what that market reform should be. And certainly this first round of the two or three filings that have been made by PJM will be instructive in terms of what FERC's mood is relative to market reform.

I think just one last question, Nick, just on -- Greg asked about residential load, but commercial also looking pretty flat for 2014 versus 2013 with sustained GDP growth and that sort of thing. Is there potential that that number will start to spruce up or are you just not seeing kind of the growth in construction and commercial space to give you confidence that it's coming back?

No, I think there's a chance it will. We just Dash I think one quarter a trend doesn't make. So we have got to look at the numbers for this quarter that is occurring now and we will continue to adjust accordingly. And not just only adjust our forecast accordingly but adjust our cost structure accordingly as well and our employees are well tuned into that process at this point. So this is very much about an optimization business now.

Great, thank you.

Paul Ridzon, KeyBanc.

Congratulations on a solid quarter and year.

Thank you.

A couple of questions. At EEI you kind of indicated that your forecast didn't have any projects in the transmission side that weren't pretty ironclad. What kind of upside is there from here from what you have done since then?

Yes, so, as you recall during EEI, we had the presentation of the real projects that are in the plan right now and then we had this incremental bandwidth above that graph that showed the incremental real projects that are also in hand that we're finding capital for. As you recall, for 2013 I think we moved $120 million of capital over to transmission as a part of our regular ongoing process primarily from generation. And that has been positive for us.

We will continue to do that to achieve the capital associated with those particular projects, that is still well in hand, moving forward very well. And in fact now we are in the process of defining a ridge even above that. But that is going to be -- that is going to have to play itself out in terms of our ability to come up with real projects.

We also -- we aren't standing aside on the sidelines with Transource and other activities. We continue to pursue projects outside of our footprint as evidenced by the -- I know you probably saw that we were one of five bidders for a Canadian project done at McMurray, 500 kV project. So all that is going on on all cylinders. And we're very happy with the progress there and we will continue to identify those real projects that can be done.

Great, thank you. And then just -- you indicated you are not changing your forecast for gas or power pricing, but I assume it is safe to think that so far in the year it has been a nice tailwind. In other words, you are not having to go by power in the east side markets to fulfill some obligations?

Yes, that is -- Brian?

Yes, so, most of what we have for off-system sales, particularly for the generation resources side of the business, is hedged with its contract to Ohio for the year. So although our units are performing well, demand is strong, I wouldn't want to get -- have irrational exuberance over the fact that it has been cold and prices have been high at this point.

But you are net long so you are participating?

Well, AGR is and we are participating, but some of our operating companies are having to buy to meet their needs. And we have offered opacity to some of those companies to help fill that need and some have taken it and some haven't. And we are hoping to get positive resolution to that. But not all of our operating companies are long through this event, but AGR is.

Then lastly, just what's your early read on what is going to happen in the next capacity auction? Is it just too many things still up in the air here to predict that?

Well, I think if the market reforms that FERC has in front of it now are approved, that could be helpful. Whether it is enough remains to be seen. And that is something I think that all the generators are looking at in terms of how much surety we are going to get around the continued investment in generation for the long-term within PJM. But that remains to be seen. I think some have said a slight uptick, some have said more than that. But it remains to be seen.

Thank you very much.

Kit Konolige, BGC.

A good number of my questions have been answered already. I was just wondering if you could give us a little more color on, Nick, your equalizer slide, as you always call it, and just go through again which is improving and which is deteriorating. And also, could you provide a little detail on the transmission spend and why there is a lag there and can that be caught up. Or is that just going to -- the lag going to stabilize and we will start to see earnings grow with investment?

Yes, sure. So I will go through it. In terms of the Ohio Power, the 11.3%, that will probably continue to come down slightly because customer switching continues as part of the Ohio situation. APCo should improve; there is West Virginia base case that needs to be filed during the year. And then there's also the Virginia bi-annual case.

As far as Kentucky Power is concerned, that is in sort of the middle of a settlement that occurred relative to the Mitchell transfer. Right now there is sort of a rider in place. But later in the year a base rate case will be filed that includes Mitchell being moved over. And then also as part of that settlement all system sales revenues come back to the Company 100%. So that is helpful during the interim process. So we expect that to come up.

I&M continues to improve when you get the full value of the rate -- all the rate activity that they have been involved with -- I think the last report had 9.1% or something like that, it is up to 9.3%, which is positive and they will continue to improve. That is where we have the legislation for the nuclear lifecycle management projects, the environmental projects, so we have a really, really good recovery mechanism there.

And then PSO is in the midst of a rate case. They just filed it I think a week ago -- a little over a week ago, $45 million rate case asking for a 10.5% ROE, had some smart grid activity involved with that, so we expect a positive result there. And then as far as sweat coat is concerned, the only lagging part of SWEPCO we have is the portion of Turk that wasn't included in Arkansas retail rates. And that is being sold on the wholesale market.

But there are some increases there related to transmission related costs, filings that need to be made in the jurisdictions. And then there is some Dolet Hills expense that needs to be filed in Arkansas. So they are working on that as well so we expect that to improve. And it has moved -- originally I think it was at 7%, it is up to 7.4%. So it is on its way back up.

And then AEP Texas, it stands pretty good in terms of load growth is really helping out there. And that number also includes the amortization of the stranded cost. So it looks high, but it includes that.

And then as far as the Transco, ETT is an area where a T cost filing has been made and it still lags, and it will lag until the T cost filing is made, which that is a pretty standard filing that we have -- actually, we have already made that. But it is a pretty standard filing, works much like a fuel cost recovery mechanism. But we expect that to continue to improve.

And then we have, obviously, as we address moving capital over to transmission, remember the capital is moving to transmission and we are spending at a pretty accelerated rate there. So the project spend is getting out a little bit ahead of the recovery mechanisms, even though the recovery mechanisms are good. So it is a good place to be as long as we are meeting our earnings objectives and are able to move our capital around, that is a good place to be.

And then we have some -- a little bit of developmental expense there related to Transource that still needs to be reflected through with the construction going on within Transource. So we expect that to continue to improve as well. So really probably the only one that could move down is Ohio Power because of everything associated with the transition to Ohio. But the other jurisdictions are on their way up and doing well.

And just one other, to be clear, how much -- is essentially all of the transmission spend adjudicated by FERC and then passed through the operating companies, or is there state-level transmission rate case activity?

Yes, there is some transmission in the operating companies, but by and large most of it is Transco related, it is FERC regulated. And then, of course, Texas is PUCT regulated. So it is pretty straightforward. I mean we have got the projects, we know what the projects are. They are real projects and they are just plowing through the process with some favorable recovery mechanisms. So we're particularly happy with where the transmission business is going.

And final question, do you have any kind of middle term three-year view on the transmission earnings contribution and what that is going to mean for where you are in that cone of earnings guidance out for three years?

Yes. So the Ohio case by 2015 is $0.39 a share, which was I guess the original modeling we had, had it at $0.36 a share, so additional $0.03 a share. And then by 2016 we are looking at $0.43 a share and it could be upwards to $0.51 a share. So that is -- and that is based upon those real projects, as I said before.

Now if we have incremental projects above that, then there could be additional opportunities there, particularly if some of these projects that we have in PJM that have been proposed or the Canadian projects or anything else; that will also contribute beyond what we show and what we did show in the graph back at EEI.

But that EEI graph is pretty solid. As a matter of fact, it is solid. I shouldn't say it is pretty solid; it is solid. The issue for us is making sure we replow the capital back in to get that topside of transmission, and then also identify anything beyond that.

So just to be clear, if you were to hit the top side of transmission say in 2015, the $0.39, would that mean you would come in at the top side of that consolidated EPS range?

We continue to hold on to our 4% to 6% based upon that original guidance in 2013 we gave that had a [315] midpoint. It is a broad bandwidth and certainly there is a lot of things that could happen, and ins and outs in the process. So it is sort of difficult to tell at this point. But we will certainly let you know as it gets closer.

Sounds good, thank you.

Stephen Byrd, Morgan Stanley.

I wanted to talk a little bit more about transmission. Nick, you had laid out on one of the earlier slides about a 9.5% Transco earned ROE for the year, but there were a number of sort of near-term impacts to that. I wonder if you could just flesh that out a little bit more and then talk about going forward. And then I will shift to a bigger picture question.

So as far as the transmission is concerned, the T cost filing is already made. So I think they have -- six months is it -- to come up with a solution there, I think. And it is sort of -- actually, we have been very successful with our T cost filing. So I wouldn't suspect we would have any issues there. And then really the return -- the ROE of 9.5% doesn't reflect the authorized return at all. We are just getting out ahead and we are intentionally getting out ahead to make sure that we plow as much capital as we can into transmission.

And, Stephen, you also remember that our authorized ROE in PJM is 11.49% and in SPP it is 11.2%. And with the formula rates that we have for those trancos, they get updated on an annual basis. So the longest lag we have is 365 days and the average is 180. But we are plowing so much money into that business right now that there is some lag and that is being reflected in the 9.5% combined ROE.

Right, that is helpful.

So again when you look at it, we are not too concerned about the numbers -- I mean actually we're not very concerned at all at this point of 9.5% because the authorized is there, the recovery mechanism is there, the real projects are there, so we just keep plowing away. And I think we are benefiting from the years that we started this transmission business and we are reaching the critical mass in our own type of investments.

And we feel very good about what we are spending, how we are spending it and certainly the recovery mechanisms that are in place. So you will see --- I mean, I guess since last year we have been saying we are going to plow as much capital as we can into transmission and when you get out ahead of the recovery mechanisms in transmission you are doing a lot. But we are happy with the progress.

Well, Nick, your last comment goes to my broader sort of question when I think about execution risk for transmission. At EEI you laid out the categories of projects and many of those look honestly to me as relatively low-risk projects. But at a high level can you talk about execution risk to get to that higher case? What are the key things on your mind when you think about that?

I think there is minimal execution risk. These are actual projects that are on the same vein. We are not gold plating anything, we are focused on refurbishing the grid and enhancing the grid to respond to retirements --- generation retirements, RTO related projects. All those kinds of things are in that plan and there is minimal execution risk.

As long as we perform well, stay on budget, stay with the projects that we have got and ensure that we have got the right message in terms of optimization and the activities we do in transmission are needed. And that is something we -- what you're seeing in that list is really needed projects for reliability, not economic projects. Those are additive if they ever occur.

So --- and the other positive benefit is that once again the diversity of all of our states is a positive because we are investing not only in our states but the adjacent states and we have added Kansas and Missouri through Transource, so we have some distinct opportunities in all those jurisdictions and the adjacent areas to really have some tremendous benefits here. And really ultimately tremendous benefits for our customers and as well the optimization of the grid itself.

That is great, thank you very much.

Paul Patterson, Glenrock Associates.

Just wanted to first touch base on this capacity market rent that you are seeing in the energy market. Could you elaborate a little bit on that? I mean what do you see going forward with respect to this? And I know it is cold out there and what have you, but it would sort of unusually high prices it seemed in some jurisdictions, some zones and what have you. And I was just wondering if you could just elaborate a little bit more as to what you think is actually going on there and the long-term outlook?

Yes, I think you are right, I think we are seeing higher energy prices earlier than what we thought. We really thought that it would really take off when the units that we were running would retire. I mean we are retiring 7,150 MW of coal-fired generation and 89% of that is running now. And if you start to see, which we are seeing, an economy start to improve and on the heels you are trying to retire that generation, you --- I mean certainly we expected energy prices to continue to improve.

But this shows -- to me it shows where the real world and the play world collides. And it reflects through in the energy prices. And if a capacity market is not well thought out in terms of enabling investors to invest and advance relative to construction and everything else associated with the grid itself, then you wind up having this kind of thing happen.

Hey, Paul, we have been paying in our market area for gas in the PJM part of our footprint around $6 an MMBtu for gas. You are seeing PJM prices that are $1,000 a megawatt hour during emergencies going up to $1,800 a megawatt hour. Do you think the people being paid those prices are being paid for energy? They are not. PJM is basically paying people for the value of their capacity to keep the lights on.

It is not energy that they are being paid for, it is capacity. We need to start getting some of those capacity rents back in the capacity auction because PJM is showing the real value of having that capacity when they are willing to pay someone $1,800 when the price of gas is $6 an MMBtu.

I think if -- I remember back in 1984 I was in system operations and the same thing happened where you had a very cold winter, taps get frozen, instrumentation gets frozen, natural gas isn't available and it winds up being -- and energy prices go out the roof and then every one of your coal units and every other resource that you have is brought on to run.

And you also have with cold weather obviously coal piles can get frozen. But we haven't run into too much of that; we have been successful in getting through this process.

But I think it shows the value of a balanced portfolio. And when that portfolio is no longer balanced you are going to have additional risks that are placed upon the grid that we really do need to think about. And you brought up a great question that I guess we can talk about all day, but it is clearly a message that I think everyone needs to really focus on the future of the grid and what it actually means to service our customers.

Okay, I don't want to take up all day on it because I think you are right, we probably could.

Yes.

It's an interesting topic. Just back on transmission for a second, I mean you mentioned that none of this stuff is economic. Should we expect really no impact on rerating of the lines, any improvement on the actual transmission lines in terms of deliverability across regions or [LBAs] as a result of (multiple speakers)?

Oh, no, no, we are improving the deliverability, we are expanding the ratings of lines, we are putting in additional transformers, we're putting in additional substations. And a substation -- I mean we are building a substation that costs $250 million.

So these aren't small investments that are being made, but they are investments to reinforce and increase the capabilities of the grid itself. And then as well with the generation retirements, there's a lot of planning around additional transmission resources to support those retirements as well.

Right. But I mean should we think of perhaps there being an improvement in terms of transmission between LBAs at all or I mean in terms of the actual change of -- I guess the ability of power to go places where -- more power to go into certain areas that need it?

Yes, you will see it from a reliability perspective. From an economic perspective it just takes longer to do because I mean if you cross multi states then you get involved with cost allocation and the issues between RTOs and that could be sort of a limiting factor until all this gets fully rationalized.

But ultimately with the retirements, with the changes in the way the system is being used, it is clear that transmission investment will be a continued positive at least through the next decade.

Okay. And just finally on the right of first refusal and Order 1000, is there any risk that third parties might compete for this transmission CapEx (technical difficulty)?

Yes, but a lot of the transmission that we are doing is our transmission projects. So when you get into the competitive projects, that is where Order 1000 comes into play and we think we're well-positioned to compete in that environment because we have been doing it for a while. And so, not only do we have our own projects that are providing the pipeline for that critical mass, but we also have those other projects that we are competitively bidding that we're seeing success in.

Hey, Paul, what you see in our forecast for transmission spend and earnings is not subject to ROFR. Those are projects that we control that we have the ability to invest in and that are not going to be taken from us by someone else competing for them.

And that includes those incremental projects that we showed on top as well.

Okay. Thanks a lot guys, I really appreciate it.

Steven Fleishman, Wolfe Research.

I think Brian mentioned the --- in his remarks that prices are a lot higher near-term than was in your plan, but that you will be kind of over this multi-year period, actively managing outages and expenses to kind of stay within the range roughly. Could you just maybe elaborate? I read that as kind of if you are having a really good period you will use that to invest more to benefit kind of the future periods, is that ---?

Yes, you are right.

Yes, Steve, so obviously as we are working our way into 2015, 2016, 2017 and you and others have identified some of the shortfall that we have associated with the transition in Ohio and then the RPM pricing that we are facing. We are going to be doing things like moving outages around during that time period, maybe pulling some forward if we find ourselves a bit hot on earnings in an earlier period maybe pushing them out into the 2017-2018 timeframe.

And we are really going to be managing our way through this to a very high degree as we work our way through to make sure we stay in that cone that we have identified. So, if we come in --- if we see things particularly hot, whether it is weather or pricing, in 2014 we might pull some outages or expenses out of 2015-2016 into 2014 to help us manage our way through that process. So I think your description of it makes me think that you understand very well what we are doing.

And that is a process that we put in place here that I think is working just extremely well. It not only gets capital to transmission, but it also enables us to move projects from one year to another into the year and that is really a positive process for us that we have put in place.

It is worked very well; we continue to look at it. We look at numbers on a pretty regular basis to ensure that we are managing the year in the proper fashion. We will continue to do that because, as you all have pointed out, this 2014, 2015, 2016 years are critical for us, particularly 2016 because of the capacity markets. But we are managing to it and so far we are doing very well.

Okay. And just in 2014 what is your specific savings in pension and OPEBs? I know that is within your O&M budget, but just that specific line, what are the savings versus 2013?

Let me give you some detail on that. 2013 -- and you talk about two different things, Steve. We will talk about the pension cost and then the pension expense, okay.

So the cost for 2013 was $114 million and the expense ended up coming in being about $64 million, okay, the O&M expense. And then we are forecasting for 2014 the cost to be about $84 million and we are anticipating that the expense will be about $52 million. So the difference year on year, the $64 million to the $31 million is about $33 million.

Okay. Thank you very much.

Brian Chin, Bank of America.

Just given the recent weather and a little bit of how the current situation is unfolding, can you give us some color on coal days of inventory on hand? And does this prompt you to think that there might be some changes to how you head into the contracting season for coal later this year?

Typically we pull down inventories during the winter months and we have been on the order of 30 to 35 days on average for just about the whole year. I think it was -- at the top it was around 40 days and it is down to 30, 35 days and we are fine with that. And we will be very sensitive about how much additional coal procurement we do as a result.

We have a pretty flexible system and some --- a lot of are contracts are pretty flexible. So we feel pretty good about where we are at now. We don't have any changing conditions or requirements that we are placing on our coal buying efforts because of the weather. We are just performing as we thought we would.

We have got more coal than the country has cold right now. We are good to go.

Got you. Thank you very much.

Anthony Crowdell, Jeffries.

I have a question on Nick's favorite slide, the equalizer slide. just two part, where do you think the ROEs could go or what do you think is a normalized level of ROE? And what type of sensitivity could you give us say for every 50 basis point change in this regulated operations ROE we could see a $0.10 improvement in earnings or something?

Yes, so I think when you look at the equalizer chart, I like for it to be with a [10] handle on it. And certainly we have said long-term and we are looking at around [10.2], [10.3], in that range. And you are seeing sort of a quarterly perturbation of a lot of activity that is coming into play here. So as long as it stays in that range we are in good shape. And I don't know, Brian, if you have anything you want to add?

I don't. Anthony, we could get you some type of sensitivity for across the system what a 50 basis point change in overall ROE would be, we can get that for you.

Great, thank you.

Jonathan Arnold, Deutsche Bank.

Quickly on rate for 2014, you had at EEI sort of $1.97 penciled in, now it is $1.75, is that change in things that came in lower or lower assumption on the things you haven't yet got?

2013 came in a little bit higher. So the difference is a little bit lower.

So it is basically the 2013 starting point?

Yes,

Yes.

Okay, great. And then secondly, just coming back to this demand question and in the context of some of your comments about sort of managing within the cone. I mean you did take down the residential forecast for this year by I think 80 basis points and commercial by 90 in what is less than three months. Are you genuinely seeing that much more concern versus what you were seeing in November or is this a little kind of conservatism to offset other stuff?

Yes, so you asked us two different questions with the same answer. The answer for your prior question is the same as this one, 2013 came in a little bit higher.

Okay. All right, thanks, Brian.

Michael Lapides, Goldman Sachs.

Yes, two questions unrelated. First, on the transmission side, we have seen in the MISO and in New England dockets where interveners are seeking lower transmission base ROEs. If the same thing happens in whether it is the Southwest power pool, whether it is in PJM, what do you think the tipping point is where it would change your -- I don't know, your incentive or your desire to be a sizable investor in transmission in the US?

Well, I think as long as transmission is at a premium or equal to the state rates we are in good shape. And I think clearly there is an incentive being placed on building transmission, we are happy with that. And really, once again, the FERC needs to send some messages here that from a policy perspective that we want to continue building transmission in this country. And as long as that premium is at or above the state rates then we are in good shape.

FERC was clearly, Michael, looking to attract capital into this space and what they have done with their ROEs has done exactly what FERC wanted to happen. So as long as they --- as Nick was saying, as long as they continue to send the signal that they want increased investment in this area we will respond to that signal.

I think it continues to be part and parcel to the overall grid expansion that is going on and the resilience of the grid and there is going to continue to be spend regardless. The question is, do you really want to satisfy that precursor of transmission being built out to respond to the generation retirement and so forth to optimize the grid so that you can do that as a prerequisite and then focus on the rest of the underlying system, that is what is key.

I think you have got to get through this transitional process we are at in this industry. So transmission needs to be incentivized in that regard because that will provide the greatest benefit in terms of resiliency of the grid but also in terms of the optimization of the resources that are attached to the grid.

Got it. And just looking at your non-transmission investment, so the jurisdictions where you have distribution and/or generation rate base. Where do you see the greatest year-over-year changes in capital spending, where do you see kind of a slowing of capital spending?

Incrementally more, Michael, in the APCo T investments across our system is where we are seeing significantly more investment. We're also seeing increased investment in our Cook Nuclear Power Plant and associated with some of the environmental investments that we are having to make to be responsive to MATS by 2015. So those are the general areas where we are seeing incremental investment.

Yes, I think we are at $3.5 billion to $4 billion on the environmental spend now over the period. And then when you look at the other capital that we are spending, it is block and tackle spending that typically is recovered from a regulated standpoint.

So we are sort of in a position where we are not having to build a large central station generation, but we are able to focus on transmission and distribution investments that are clearly beneficial to customers and customers actually see and that is a positive.

Got it, guys. Thank you, much appreciated.

Hugh Wynne, Sanford Bernstein.

My question is on page 11. It appears there that probably half or more of your expected pre-tax earnings improvement by 2016 will be driven by generation and perhaps a quarter or less by distribution. When I think of the generation segment that is obviously one that is transitioning to competition in an environment of $60 per megawatt day capacity prices.

Distribution, on the other hand, is probably I would imagine half of your rate base, half of your O&M, a lot of that at utilities that are under earning. I wonder if you can give me some color on the skew of these earnings improvements towards generation and the relatively small contribution from distribution.

Well, I think it is just a matter that --- generation typically has the big-ticket items that can be adjusted. And when you look at consumables for a scrubber, the way all the parasitic load operates within the plant, certainly the way that you contract for the activities associated with it particularly in terms of use of contractors versus use of employees -- all those types of things are substantial within the generation framework.

And there again generation sort of functions -- each plant functions as its own profit center. And so, doing that it can focus more readily on the benefits associated with optimization of how they operate. And from a distribution standpoint it really is a matter of outage scheduling, management with the customers, the processes that are in place that goes back through the organization.

So it is probably -- at least in our view -- when you preach from the customer side of things you want the distribution side to be very robust in terms of the way it operates to provide the customer experience that we are asking for. From a generation side, that is all done sort of as a back office function and it contributes heavily to the benefits from an OEM perspective but also from a capital perspective. And that is our expectation as we get through this.

Nuclear, part of that process hasn't been through the lean activities, they started the lean activities. Obviously we are very careful because nuclear is different. But is a heavy capital and OEM spend and there are opportunities for optimization there as well. So I think we have got the right balance when you look at generation and then when you look at transmission and distribution together you are on par.

Great, thank you very much.

And to the presenters, we have no further questions in queue.

Well, thank you all very much.

Yes. Thank you for joining us on today's call. As always, the IR team will be available to answer any additional questions you may have. John, can you please give the replay information?

Certainly. And, ladies and gentlemen, this conference is available for replay it starts today at 11 AM Eastern, will last until February 3 at midnight. You may access the replay at any time by dialing 800-475-6701 or 320-365-3844 and the access code is 313839. That does conclude your conference for today. Thank you for your participation. And you may now disconnect.