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Great Plains Energy Incorporated (NYSE:GXP)

Q4 2011 Earnings Call

February 28, 2012 9:00 am ET

Executives

Kevin E. Bryant - Vice President of Investor Relations and Treasurer

Michael J. Chesser - Chairman, Chief Executive Officer, Chairman of Executive Committee, Chairman of Kansas City Power & Light, Chairman of GMO, Chief Executive Officer of GMO and Chief Executive Officer of Kansas City Power & Light

Terry Bassham - President, Chief Operating officer, Director, President of Kcp&L and Chief Operating officer of Kcp&L

James C. Shay - Chief Financial Officer and Senior Vice President of Finance & Strategic Development

Unknown Executive -

Analysts

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Paul Patterson - Glenrock Associates LLC

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Andrew Levi - Caris & Company, Inc., Research Division

Unknown Analyst

Shahriar Pourreza - Citigroup Inc, Research Division

James Bellessa - D.A. Davidson & Co., Research Division

Kamal B. Patel - Wells Fargo Securities, LLC, Research Division

Operator

Good morning. My name is Lindsey, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Fourth Quarter Year End Earnings Conference Call. [Operator Instructions] Thank you. Mr. Kevin Bryant, Vice President of Investor Relations and Treasurer, you may begin your conference.

Kevin E. Bryant

Thank you, Lindsey, and good morning. Welcome to Great Plains Energy's 2011 Fourth Quarter and Year End Earnings Conference Call. Joining me this morning to present our results are Mike Chesser, Chairman and Chief Executive Officer; Terry Bassham, President and Chief Operating Officer; and Jim Shay, Senior Vice President and Chief Financial Officer.

Before we begin, I must remind you of the inherent uncertainties in any forward-looking statements in our discussion this morning. Slide 2 and the disclosure on our SEC filings contain a list of some of the factors that could cause future results to differ materially from our expectations.

I also want to remind everyone that we issued our earnings release after the market closed yesterday. That release is available, along with today's webcast slides and supplemental financial information regarding the quarter and the full year, on the main page of our website at www.greatplainsenergy.com. We will also be issuing our 2011 10-K this week, which will be available on the main page of our website.

With that, I'll now hand the call to Mike Chesser.

Michael J. Chesser

Thanks very much, Kevin. Let me start by saying, as many of you know, last week I announced my decision to retire as Chief Executive Officer of Great Plains Energy and KCP&L. Over the last 9 years, our company has grown and evolved significantly, and I believe as we stand here today, we are positioned for significant growth.

That said, one of the most important roles of any CEO is to develop the next generation of company leadership. The selection of Terry Bassham to succeed me is a strong showing of support from our board. Their confidence, not just in Terry, but in the entire management team. I have every confidence in Terry and the team as well and look forward to continuing to work with them through this period of transition as I retain the role of Chairman of the Board.

On a personal note, it truly has been a pleasure to work with many of you. Your support has been greatly appreciated during the last 9 years as our company has evolved to the strong point where it is today.

I hope you had the opportunity to read the earnings release we issued yesterday. We announced full year earnings of $1.25 per share, which were in line with the revised guidance that we issued on our third quarter call.

At our Analyst Day presentation in August, we outlined the strategy to achieve 50 basis points of regulatory lag in 2013, and we also provided guidance that our 2012 earnings would be between $1.35 to $1.55.

Yesterday, we announced we lowered our 2012 earnings guidance to a range of $1.20 to $1.40. This was driven by near-term economic uncertainty and the impact of lower natural gas prices on our off-system sales. There had been recent developments in these areas that Jim will address in his comments as he updates you on our guidance assumptions.

Although, we're -- let me emphasize, though, that while we're reducing our 2012 guidance, we remain focused on achieving our 2013 target to reduce regulatory lag to 50 basis points. In today's presentation, we attempt to fully communicate our plans to achieve that goal.

One of our key strategies is regulatory. And as you may have seen yesterday, we filed general rate cases in our Missouri jurisdictions with a total requested increase in rates of $189 million. We understand the challenges in asking for our -- asking our customers for a rate increase, but we're asking for these increases so we can maintain a reliable electric system, make renewable energy and environmental investments needed to meet government mandates and expand energy efficiency programs. Terry will provide more details around the rate case filings in his comments.

As you can see on Slide 4, we had many accomplishments in 2011, including enhancing our renewable generation portfolio, introducing initiatives that streamline our business, rightsizing our organization and aggressively managing costs. Our many accomplishments during the year are examples of our commitment to providing award-winning, reliable service to our customers, while at the same time, improving shareholder returns.

For the past several years, we have worked to create a fair and balanced framework to partner with our customers and encourage investment in energy efficiency. In December, we became the first utility in the state of Missouri to file for a comprehensive energy efficiency program under the Missouri Energy Efficiency Investment Act or MEEIA. A benefit of energy efficiency is scalability. It can be increased or decreased depending upon energy resource needs of a utility. Our energy efficiency programs have created jobs within the local communities and have allowed us to partner with our customers to understand how we can all use energy better and smarter than we do today, and Terry will provide additional details on our MEEIA filings in his remarks.

So with that, I'd like to introduce Terry, who will provide you with an update on the many things happening on the regulatory and operations front.

Terry Bassham

Thanks, Mike, and good morning, everyone. Before I get started, let me be the first to thank Mike for his leadership during his tenure with the company. Mike's vision has been instrumental to the evolution of this company, and I'm grateful for his contributions and personal support. I look forward to continuing the legacy of strong leadership at Great Plains Energy and working closely with Mike to ensure a smooth transition.

Turning to Slide 6, I'll spend a few minutes discussing our rate case filings and update on construction at La Cygne, performance at our plants and customer consumption.

As Mike indicated, we filed rate cases in Missouri yesterday, requesting a total annual increase of $189 million, reflecting an ROE of 10.4%. The test year in the filings was the 12 months ended September 2011, with an anticipated true-up date of August 31, 2012. New rates are anticipated to be effective in late January 2013.

The equity ratio were approximately 52.5%, does not include any new equity issuances that could potentially be used to finance wind projects, which Jim will give you an update on in his comments.

The projected combined rate base in these cases is approximately $226 million, higher than at the conclusion of the last rate cases for these jurisdictions, reflecting an increase of approximately 6%. The increase includes about $43 million for the portion of Crossroads that was disallowed at MPS in the previous rate case.

We work to keep to ask in these rate cases as reasonable as possible, so that our overall rates remain below the national average. We are also working to aggressively manage cost. For instance, with steps implemented in 2011, such as the organizational realignment and voluntary separation program, we reduced our workforce. We are maintaining flat operating budgets and creating more efficient work processes throughout the company. We are hopeful that successful outcomes in the current rate cases will enable us to avoid filing rate cases for a couple of years thereafter.

At the same time, the filing of these cases is key to our ability to reduce regulatory lag. In the KCP&L Missouri case, we requested a change in the wholesale margin cap to approximately $23 million, which is updated estimate of the 40th percentile. The current cap is about $46 million or the 40th percentile determined in the last rate case. The inability to achieve the wholesale margin targets embedded in our current KCP&L in Missouri retail rates negatively impacted our 2011 results due to coal conservation and reduced demand. As Mike mentioned, one of the primary reasons we're reducing guidance for 2012 is that we are projecting we will once again not be able to achieve the amount of wholesale margin in rates due to natural gas prices and continued soft demand.

Reducing the wholesale margin threshold to avoid this shortfall in the future is an important element of yesterday's rate filing.

In conjunction with the proposed cap to the -- change in the cap, we've asked for a sharing mechanism for sales above the 60th percentile, where the company would keep 25% and customers 75%. For sales below the 40th percentile, we're proposing that the company take 75% of the loss, and customers, 25%. Wholesale margins achieved between 40th and 60th percentiles would be returned to customers as before.

Included in the filing, a request for property tax, renewable energy standard and transmission trackers, we've also requested an interim energy charge, including the offset for wholesale margin changes utilizing the shared mechanism I just discussed.

At GMO, our rate case request includes recovery for new and enhanced energy efficiency and demand side management programs under MEEIA. As Mike mentioned, we also made our initial filing for the MEEIA rider in December. In the event commission authorizes recovery through the rider, the cost would be removed from this case.

Similar to KCP&L Missouri, we requested property tax, renewable energy standard and transmission trackers at GMO. In December, we also filed a notice of intent to Missouri to merge KCP&L and GMO. At the present time, we suspended our efforts to file a merger case, instead we requested approval in our current rate cases to combine inventory, which would create additional cost efficiencies. We will continue to evaluate a merger of KCP&L and GMO, and we'll keep you updated on the rate cases as we move forward.

In Kansas, we anticipate filing a rate case in the second quarter of 2012. Keep in mind that the statutory requirement for a commission order in rate cases in Kansas is 8 months. While the primary request in the Kansas case will be the inclusion of La Cygne environmental project, CWIP construction work in progress and rate base consistent with Kansas statutes.

Turning now to Slide 10, I'd like to provide you an update on a few regulatory developments. First in Kansas, we requested a property tax rider that was recently approved by the KCC. The rider became effective on February 1 and calls for an annually-adjusted charge to recover property tax cost above what is included in rate -- base rates. Getting this rider was one of the steps to reduce regulatory lag that we outlined in our Analyst Day presentation last August.

Regarding the MEEIA filing at GMO, the proposal calls for a recovery of program cost and incentive consisting of a portion of the shared benefits and a performance award and a recovery mechanism for lost revenues. If approved, the mechanism would be in the form of a rider. Procedural schedule has been set, and an order's expected in the matter in June 2012.

We'd also made a MEEIA filing at -- for KCP&L, but we threw the case earlier this month. With the addition of Iatan 2 and the lack of growth in our service territory, KCP&L does not need additional capacity at this time. As such, we did not want to propose the additional increase in customer rates in the short term for long-term benefits, given the current state of the economy. We remain committed, however, to energy efficiency as one of the lowest cost resources for supplying electricity.

In Missouri, KCP&L filed an accounting authority order or an AAO, requesting authority to defer, for future recovery, costs associated with coal conservation and other expenses resulting from the 2011 Missouri River flooding. While the amount requested is confidential, I can tell you that we asked for incremental nonfuel cost, losses related to increased fuel and purchased power expenses for retail load and losses related to reduced off-system sales margins impacting our ability to meet the 40th percentile, offset in base rates in our last case. If granted, the AAO would allow us to defer and amortize those incremental costs over future periods for inclusion in future cases, including the case just filed.

As a reminder, we have fuel recovery mechanisms for KCP&L in Kansas and at GMO, but not for KCP&L in Missouri. Also in Missouri, KCP&L and GMO filed an AAO requesting authority to defer the cost to comply with the solar rebate requirements to the state's renewable energy standard. We expect cost to comply will increase, and project 2012 expenditures will total $6 million. Amortization of these costs is included in the cases just filed. Requesting these AAOs are part of our continued effort to reduce regulatory lag.

Moving to Slide 11, site preparation at La Cygne is ongoing, and last month, we installed the foundation for the new chimney shell. Our plan is to complete the approximately 600-foot tall chimney shell by the 2012 third quarter and make way for heavy construction later this year. The project remains on schedule for completion during the second quarter of 2015. And upon completion, 72% of our coal fleet will have emission-reducing scrubbers installed.

As a reminder, current plans also include retrofits at Montrose 3 and Sibley 3, which are the other high-likelihood projects outlined in our Analyst Day presentation last August. Upon completion of these units, which is expected by approximately 2017, 85% of our coal fleet would be scrubbed. No decision has been made on our less-likely projects, but to give you a perspective, the net book value of those units is approximately $100 million.

As depicted on Slide 12, our 2011 combined equivalent availability factor or EAF was 80% compared to 83% in 2010. The primary driver of the decrease was our Wolf Creek nuclear operating unit, which was shut down during most of 2011 second quarter for an extended refueling outage.

Overall, our coal plants had an EAF of 81% in 2011, which is essentially on par with 2010. We achieved this EAF despite managing our coal fleet to mitigate the impact of the Missouri River flooding. The coal conservation efforts were completed in October. We continue to build our coal inventories and expect to be at normal levels in the second quarter of this year.

For the full year 2011, Wolf Creek had an EAF of 71% and 22% decline from 2010 due to the extended refueling outage.

On January 13, 2012, a breaker and a substation located at Wolf Creek failed. This failure was immediately followed by a loss of station power at Wolf Creek, resulting in an unscheduled shutdown of the unit. Wolf Creek is expected to resume normal operations in March 2012 following completion of repairs. The schedule assumes no discovery during the course of repairs of additional required work and that all requirements, NRC, for resumption of normal operations are satisfied. It's too early to quantify any impact, but we expect there will be additional maintenance expenses and capital expenses as a result of this unscheduled outage.

Although the additional maintenance expenses and capital expenditures as a result of the outage have not been finalized, we believe any impacts are covered in our current guidance range. Providing safe and reliable energy is our highest priority, and we take that responsibility seriously. We'll keep you updated of any further developments.

Next, turn to Slide 13. I'll close out my section with comments on our retail customer consumption. Overall, retail megawatt hour sales were down for the fourth quarter 2011 by 2.4%, compared to the same period last year. For the full year 2011, retail megawatt hour sales were down about 1.7% compared to 2010, with a little less than 1/2 of that decline attributable to weather.

Compared to normal weather, the full year revenues are favorable by approximately $49 million or about $0.12 per share. On a weather-normalized basis, sales declined 1% in 2011 compared to 2010. Our residential and industrial sectors were down 2.4% and 1.4%, while the commercial sector was slightly up, with an increase of 0.3%.

As you may recall in the third quarter, we were forecasting a full year 2011 decline and weather-normalized demand of 50 to 75 basis points, which implied modest growth in the fourth quarter compared to the actual decline of 1.2%. Based on the decline in the fourth quarter, we've reduced our gross assumption -- growth assumption for 2012, which Jim will address in his comments.

Slide 14 provides a little more of a historical look at customer sectors. As has been the case with other utilities, it's difficult for us to identify the exact drivers of change over a specific time period. Potential contributors to the low demand in our region, be customers focusing on conservation, energy efficiency and switching to natural gas heat due to low natural gas prices. Additionally, housing starts in the region remained low compared to the last 10 years, but the decline has leveled off.

On the positive side, from December 2010 to December 2011, the Kansas City area had a net gain of 2,700 jobs and the unemployment rate decreased from 8.6% to 7.3%. We continue to believe that Kansas City region is well positioned in the long term, with a diversified economy that will revolve in areas such as data center operations, other technologies and renewables. Although projecting customer [indiscernible] consumption remains challenging given the current economy, we will continue to monitor this closely for signs of developing trends.

I'll turn the call over to Jim.

James C. Shay

Thank you, Terry, and good morning, everyone. I'll begin with Slide 16, which provides current year comparisons to prior year. For the year, Great Plains Energy's consolidated earnings were $1.25 per share, compared with $1.53 in 2010. The $0.28 per share decline includes $0.22 in special factors incurred prior to the fourth quarter and includes the impacts of Missouri River flooding and extended refueling outage at Wolf Creek, severance cost associated with the organizational realignment and voluntary separation programs and costs associated with rate case outcomes. These special factors are outlined in more detail in the Appendix.

This slide shows that the impacts of weather and demand resulted in a $0.06 per share decline compared to prior year. The $0.09 per share in the column titled, Lag, includes the impacts of fuel transportation cost increases prior to the effective date of new KCP&L Missouri retail rates and higher property taxes. You'll note that 2011 has a favorable comparison to 2010 of $0.07 per share relating to prior year write-offs, associated with the Iatan 1 environmental retrofit and Iatan 2 projects.

Slide 17 provides an income statement view of our 2011 results, including $172.8 million in earnings or $1.25 per share compared to $210.1 million or $1.53 per share in 2010. The Electric Utility segment's decline in earnings to $1.44 per share from $1.72 per share in 2010 was due to the drivers I just discussed. The other category had a loss of $0.19 per share, which was unchanged from 2010.

Slide 18 provides a look at the fourth quarter 2011 results with earnings of $1.7 million or $0.01 per share compared to a loss of $5.3 million or $0.04 per share, with the increase all at the Electric Utility segment.

On Slide 19, we provide a recap of 2011 using the regulatory view we presented in our Analyst Day presentation in August. You'll recall in that presentation we communicated that the regulatory earnings potential for 2011 was $1.91, which is based on $5.6 billion in rate base with a 10% ROE and a 47.5% common equity ratio. In August, we then used a similar format to this slide and provided a walk-down to our 2011 guidance range, at that time, $1.10 to $1.25 in EPS.

Based on stronger third quarter demand and the impacts of weather, we increased our guidance to $1.22 to $1.32 in connection with our third quarter earnings release, which is shown on the slide.

You can see on the slide that our actual results are in line with the revised guidance range. The fourth quarter includes the impacts of weather and demand previously discussed, along with reduced wholesale margins due in part to lower natural gas prices. I will discuss the impacts of natural gas prices later in this presentation

On a normalized basis for 2011, we achieved a 9.4% ROE, representing 60 basis points of regulatory lag off of our authorized ROE of 10%. As you can see by the maturity schedule at the bottom of Slide 20, we have a sizable amount of debt maturing in 2012 and 2013. Our near-term fixed income plans include the remarketing of the debt component of our $287.5 million in equity units. Proceeds from the settlement of the equity units will be used to replace a portion of GMO's $500 million, 11.875% senior notes that mature in July 2012. Given our 2012 and 2013 maturity schedule, we continue to evaluate a number of refinancing alternatives, but expect to refinance the remaining portion of this GMO maturity with an issuance of new long-term debt by early 2013. The conversion of the equity units in June of this year will increase common stock outstanding by 17.1 million shares.

In the fourth quarter of 2011, we did announce the signing of two 100-megawatt wind PPAs, with attractive pricing. And we're considering converting one of the agreements to ownership. At that time, we discussed the possibility of issuing equity to finance a portion of the project if we expected it to be accretive within 12 to 24 months. Although ownership remains an option, we did not include it in yesterday's rate case filing, as we haven't been able to structure a transaction that would both provide a lower cost to customers and be accretive to shareholders. Any conversion from PPA to ownership would require the right commercial terms and have a construction schedule that would allow for the inclusion of any assets in rate base and the corresponding equity issued in the capital structure in the current rate cases. Given these constraints, as time goes by, conversion of the PPA to ownership becomes less likely.

Lastly, we continue to maintain a strong liquidity position with approximately $915 million of available capacity on our credit lines. In the fourth quarter 2011, we also took advantage of attractive market conditions to refinance and extend the term of our $1.25 billion revolving credit facilities to December 2016.

Slide 21 contains a historical perspective of 3 key [indiscernible] credit ratios, including the full year 2011. Our FFO to debt ended the year at 12.4%. Lower credit metrics in 2011 were, in part, driven by the previously discussed special factors. We expect that our 2012 year-over-year credit metrics will improve compared to 2011 due to the elimination of these factors, along with the 2012 benefit of a full year of retail rates in Missouri.

On Slide 22, we provide a walk of our 2011 EPS of $1.25 to our 2012 updated guidance range of $1.20 to $1.40. Our updated guidance range is $0.15 per share below our previous guidance range of $1.35 to $1.55, primarily due to the following 2 factors: first, in providing our initial guidance, we were forecasting 1% weather-normalized demand growth. Based on the decline we saw in the fourth quarter on our updated view, we are now forecasting 0.5% weather-normalized demand growth for 2012.

Second, a significant decline in natural gas prices has impacted the off-system sales market and our ability to achieve the prescribed level of wholesale margins embedded in our current KCP&L Missouri retail rates. I will discuss the impact of wholesale margins on our updated forecast in more detail on the following slide.

The other elements of the walk are fairly straightforward and include the reductions for the 2000 -- the impacts of 2011 weather compared to normal, 2011 carrying costs for Iatan under construction accounting prior to new rates in Missouri and higher outstanding shares in 2012 associated with the equity converts. These declines were offset by increased 2012 earnings relating to the benefit of a full year of new retail rates in Missouri, combined with the elimination of the previously discussed special factors.

We have a guidance variability range of $0.20 per share to cover changes in demand, impacts of weather any regulatory outcomes, fleet performance, unanticipated costs and other factors.

Turning to Slide 23, in providing our initial $1.35 to $1.55 guidance for 2012, we assumed that we would be able to achieve the $46 million of wholesale margin included in our KCP&L Missouri rates. The above chart shows the significant decline in natural gas prices since last summer. Although we were seeing pressure on natural gas prices in the fourth quarter, it was difficult to assess the impact on wholesale margins on our forecast as there are other factors to consider, including weather and demand. One additional factor complicating the analysis was the timing of the impact of the Cross-State Air Pollution Control Rule, or CSAPR, which was stayed on December 31 by the D.C. Circuit Court. Had CSAPR gone into effect January 1, we believe it would have had some impact on the wholesale market. The actual impact, had that occurred, is unclear as it is unknown what coal units in the region would have been forced to curtail generation. Under that scenario, Iatan and other company generations that met the compliance requirements may have positioned us well for the wholesale markets.

On Slide 24, we are presenting our 2012 guidance in a format using the regulatory view we presented on Slide 19. The 2011 actual information is presented for comparative purposes. And you'll recall that on a normalized basis, we achieved a 9.4% ROE with 60 points of lag. We also include our previous guidance of $1.35 to $1.55, and you can see that the corresponding regulatory lag was targeted at 70 to 180 basis points. Our current guidance targets regulatory lag at 160 to 270 basis points. Our 90 basis points increase in projected regulatory lag includes 60 basis points relating to wholesale margins and 30 basis points tied to other effects, primarily including lower demand.

Before I turn to 2013 projected drivers, I would like to point out that we have included our 2012 to 2014 capital expenditure plan and a 2011 to 2012 net free cash flow schedule in the Appendix.

On Slide 25, I'd like to wrap up my section with a few comments about progress we've made since our Analyst Day presentation towards achieving our 2013 goal of 50 basis points of regulatory lag. This slide provides an overview of our operational and regulatory strategies. From an operational standpoint, we remain focused on improving plant performance and maintaining system reliability. At the same time, we are controlling costs tightly during this period of continued slower -- low growth.

On the regulatory front, we filed cases in Missouri and are executing on the rider and tracker strategies we discussed last summer.

We continue to target 50 basis points of lag for 2013. The outcome of our 2012 rate cases and the timing of the effective rates -- effective dates of those rates will be key drivers of our success in meeting this goal. As we described in August, low growth in the overall economy will also be key factors.

That includes my comments. Thanks for your participation today. And I will now turn it back over to Mike.

Michael J. Chesser

Thanks, Jim. So to wrap up, we're focused on executing the strategy of reducing regulatory lag in 2013 and improving total shareholder returns that we shared with you last August. We've taking steps to rightsize and streamline our business model. We've built a strong asset platform, and we have some attractive opportunities to expand it further over the next few years. And I think it's important to note that our experienced and dedicated management team has been and continues to be committed to delivering safe and reliable low-cost electricity to our customers, providing a strong foundation for our company going forward.

Thank you very much for your attention this morning. Terry, Jim and I would be happy to take any questions you might have at this time.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Paul Ridzon with KeyBanc.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Congratulations, Mike, on seeing the company to the CEP. That was a big undertaking.

Michael J. Chesser

Thanks a lot Paul. It was an interesting time.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Just -- I have a few questions. One is, what have you baked into the new guidance as far as 1Q weather to date? Secondly, what circumstances may have changed that you think you have a better chance of getting Crossroads in rates this time around? And then just the interaction of fuel recovery if there is a GMO, KCP&L merger?

Michael J. Chesser

I'll let Terry comment.

Terry Bassham

Yes, writing all 3 of them down real quick. In terms of weather, I mean, obviously what we've seen so far this year fits into what we've given in terms of guidance. But in general, we're early in the year. And that's part of the reason the guidance range is as wide as it is. Changes in Crossroads asked, I mean basically, we have appealed that issue and also believe that there were some inaccuracies in their look at the transmission and other issues to value that asset and get it back to customers. And so we've got several arguments you'll see there that we believe are clarified somewhat and are supportive of our appeal from that perspective. And then finally, in terms of fuel recovery, I don't think that the merger would have affected our ability necessarily to get a fuel factor at KCP&L. I think we're likely looking at the termination, if you will, of the final piece of that agreement, which means we won't likely be able to ask for that until 2015.

Operator

Your next question comes from the line of Paul Patterson, Glenrock Associates.

Paul Patterson - Glenrock Associates LLC

I wanted to focus on the load growth a little bit here. It seems to have been lower quite a bit for some time now than what you guys have projected. And I'm sort of just trying to wonder here what -- I know that there's some of the components that on Slide 14, you give us -- just was wondering like what the exposure is sort of is here in terms of switching to natural gas and the conversion to keep pumps and what have you? How we should think about that going forward and why you see that changing or how you see that changing going into 2012?

Michael J. Chesser

Sure. Well, it has been difficult for utilities across the country these days to figure out why load hasn't grown more than it has. Obviously, housing starts are down. So that's a big contributor. But there's also the latent impact of energy efficiency, and we're just all trying to figure it out with that means for load going forward. In terms of our system, the one thing that we have been expecting is that some of the pickup in additional jobs and some of the -- that we talked about, some of the additional commercial growth, would have led to higher residential consumption. But there's still a lot of foreclosures out there. There's still a lot of mortgages underwater, and it looks like the impact of that is having -- is lasting longer than normal. In fact, I was just reading an article yesterday that for Warren Buffett, he had predicted that by the end of 2012, the housing market would be back. And he confessed that he was 100% wrong on that factor. So when exactly we're going to see that turnaround, we're not sure. And how much load growth will occur with that turnaround given the energy efficiency impacts, we're not sure. But in terms of the fundamentals of our economy, in Kansas City, they look to us to be as strong as any of the companies we compare ourselves with in the Midwest.

Paul Patterson - Glenrock Associates LLC

Right. So that's why I want to sort of focus here a little bit on some of these elements here, the switching to natural gas, the conversion to more efficient heat pumps. Leaving the housing market and everything to the side, what kind of exposure do you have there in terms of competition from natural gas and this energy efficiency stuff? I mean, how should we think about that?

Michael J. Chesser

Let me make a comment, then I want Jim to add to this as well. Natural gas impact -- or the natural gas prices could impact our heat pump sales during the wintertime where the margin is really not that great. The big impact for us in terms of growth is in the summer and the air conditioning load. So that -- and natural gas might hit us on the margin, but it would not be significant for the total earnings for the year. But Jim, you might want to add to that?

James C. Shay

Yes, one comment I'd make is you recall through 6 months, we had negative load growth of 2%. In our Analyst Day guidance, we had projected flat for the second half of the year, which would have put us at minus 1% for the year, which is what we actually achieved. And then we had an early placeholder projected load growth of 1% for next year. But as you'll recall in the third quarter, we had some pretty good growth. We had 0.9% and had forecasted modest growth for the fourth quarter and with the actual decline for the fourth quarter, although we maintained flat for the second half or achieved our minus 1% forecast, we just felt that was appropriate based on the fourth quarter trend to put more caution into next year's load growth forecast, protect the integrity and methodology around the guidance and reduce the guidance for that $0.05 related to load growth. So, we just -- we're not as encouraged as we thought we would be by fourth quarter growth, which is the reason for the adjusted guidance.

Paul Patterson - Glenrock Associates LLC

Just finally, decoupling, have you guys -- what are your thoughts about that? And also, just long term load growth, I mean, do you guys have a projection on that or in terms of usage, what have you, leaving again, things like the economy rebounding, kind of activity outside of it? Sort of just customer usage, do you guys have any expectation for that?

Michael J. Chesser

Well, again, that's the $64,000 question for utilities of these days. We do -- our IRP, we plan on some level of growth. What is it, 1% or so?

Terry Bassham

Yes, I think what you would expect from us in the future once we see, if you will, a return to normalcy, is maybe rather to 2% to 3%, more like a 1% to 2% growth over time.

Michael J. Chesser

If that turns out to not be the case, and utilities, including us, will be looking at other regulatory models, other forms of dealing with a flat growth environment. And one of the things we would look at would be decoupling along with other options.

Operator

Your next question comes from the line of Michael Lapides with Goldman Sachs.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Mike, congrats on your announcement. And Terry, kudos on the opportunity. I want to -- Jim, if you can bridge me a little bit. In the rate case filing, you talk about a 52.5% equity layer. If I look at your GAAP financials, and obviously, they'll differ, I can only get there if I exclude all of the notes, all of the commercial paper and even all of the current maturities of long-term debt. Can you just bridge me -- I mean obviously some of those current maturities are going to convert into long-term debt. Can you bridge me how you get to what it implied? I mean, total equity layer, if I included all the short-term and current maturities, would be like low 40s. Can you just kind of bridge me how you get to 52.5%?

James C. Shay

The prior filing had 47.5%. And so if we just factor in the impacts of the equity unit converts without an additional long-term debt issuance this year, which would be our current thinking. You can see in the Appendix, we show that we carry -- we would plan to carry higher short-term balances in kind of the $0.5 billion range through the year. But that's about a 4%, a 4.3% impact as you bridge from 47.5% to 52.5%.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it. And so when do you -- I guess, do you view yourselves for multiple years carrying that kind of short-term debt balance? Or do you see yourself trying to take that out in '13?

James C. Shay

Well, in '13, we would combine it with another refinancing. We have in '13, $150 million maturing in 2013. So we would just combine that -- we would probably do all that long-term financing at the same time in early 2013.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it. And Terry, how are you thinking about -- I mean, I know you just filed, so it's kind of early to think about it already. But what's the long run rate case strategy and timeline looks like? I mean, you've been in rate case filings pretty much every 12 to 15 months for the last 5 or 6 years. What happens after this case?

Terry Bassham

Well, the plan would be to work through this case, get a fair outcome and not have to be back in until La Cygne was completed. We talked to investors and customers and regulators about kind of a mid-to-higher single-digit increase expected and then the off-system sales market has really bit us there. But still, the focus is on 2013, having an outcome, which provides us with ability to operate our business within our rate structure, and work through the next couple of years on La Cygne and not have another case until we have a large asset addition from that perspective.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

And wouldn't La Cygne though create a decent bit of lag during the construction process or do we just think it's just kind of adds to AFUDC in Missouri and you get some recovery in Kansas?

Terry Bassham

Yes, we're going to get -- we should get it equipped in Kansas and there'll be a lag in cash, but we should have AFUDC on earnings, but we have no lag on earnings during that period. And we've worked through the cash piece of it, and we're comfortable with managing that.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it. And last item, now that your shares are kind of trading, if I strip out the goodwill, kind of right at book value or adjusted book value, how much does that impact your decision-making regarding whether to do the wind project in rate base versus outside?

Terry Bassham

Well, obviously it does. I mean obviously, we want to be very cautious about issuing equity that's not accretive to shareholders. It's affecting our wind decisions, it's affecting a lot of things where we're managing our business and our capital spend, whether it be strategic or everyday to ensure that we don't get in a position where that's required. And in part, because of that very thing.

Operator

Your next question comes from the line of Andrew Levi with Caris.

Andrew Levi - Caris & Company, Inc., Research Division

Just a couple of questions. And maybe I missed this one, but what are you assuming as far as retail load growth or retail sales growth for 2012?

Terry Bassham

0.5%.

Andrew Levi - Caris & Company, Inc., Research Division

And just back, maybe I didn't hear it correctly. I was kind of looking at a couple of things, but, so you're saying to get the 52.5% equity ratio based on your rate filing, there's no need to issue any equity beyond the converts?

James C. Shay

That's correct.

Andrew Levi - Caris & Company, Inc., Research Division

Okay, got that. And then for 2013, and obviously at the Analyst Meeting, you didn't give specific guidance, but you kind of walked us through a scenario that could get to a certain earnings level. I just want to make sure, I mean, I see what you have in your slides, but you kind of just touched on it, that your assumptions for 2013 with the exception of a lower base of sales is basically unchanged?

Terry Bassham

Yes, I would say that our sales -- obviously, will continue -- we'll have to watch that, see where it goes. And our focus remains on a regulatory outcome that would get us the 50 basis points of lag. That's the way we expect to operate our business. The rate case we filed yesterday is a larger ask than we anticipated for that very reason. We need additional dollars because of this off-system sales credit to achieve the same results, which again is a focus on this elimination of regulatory lag.

Andrew Levi - Caris & Company, Inc., Research Division

And this 15% rate increase that you're asking for -- or 10% to 15%, I should say. How much of it is from the wholesale sales part?

Terry Bassham

A little over 1/3 of it is related solely to the effects of the off-system sales margins in KCP&L. The 10% is in MP&S, which has a fuel factor. And the 14.7% ask in light and power has a fuel factor as well. And that increased -- increase -- in the increased ask is related to additional infrastructure to improve reliability up at St. Joe. So you can see that the real change at KCP&L is related primarily to the off-system sales impacts.

Andrew Levi - Caris & Company, Inc., Research Division

On off-system sales. How does -- how do the regulators kind of view that in Missouri? I mean is that something that's going to be hotly debated or is it kind of more of a formulaic type of approach? Do you understand what I'm saying? Not a straight passthrough obviously, but...

Terry Bassham

No, well, there's no debate in the sense that the plan is to return all margins to customers. So a part of our pitch is because we're returning all margins to customers, we should have a reasonable mechanism, which doesn't really provide a lot of risk to the company. Again, we're going to provide those back. So our position is that the 40th percentile, number one, has to be adjusted, the market has changed. Therefore, the number associated with that number goes down pretty dramatically again from almost $50 million to around $23 million. In addition to that, what we've proposed is a sharing mechanism that gives us some protection on the downside and gives us some opportunity on the upside, again because ultimately, we're providing these margins back to customers. The risk to the company should be neutral. So that's -- I don't think there will be an argument at all about the fact that we're giving them all back. The question will be on the mechanism itself and the balance between customers and the company.

Andrew Levi - Caris & Company, Inc., Research Division

Okay. And was 2012 wholesale sales, I mean, or at least, the way that you're looking at -- or maybe just the first quarter, I should really say. Was there any effect from the Wolf Creek outage on wholesale sales?

Terry Bassham

No. Given the current market, Wolf Creek being down will certainly impact us a little bit in the sense that it's our cheapest incremental power. But given the first of the year, the timing of the year and the current market, it wouldn't be a major impact on an annual basis.

Andrew Levi - Caris & Company, Inc., Research Division

And I assume there weren't -- because of kind of the weather and all that, there weren't major replacement power costs relating to Wolf Creek?

Terry Bassham

No, absolutely. Absolutely not, yes.

Operator

Your next question comes from the line of John Ally [ph] with JJ Capital.

Unknown Analyst

I apologize I joined a little bit late. So I'm sorry if you went over this already. The rate base in the filed rate case, how much higher is that than last time?

Terry Bassham

About $226 million additional over and above the last rate case, rate base.

Unknown Analyst

And that's mostly Iatan?

Terry Bassham

No, it's a combination of Iatan, ongoing capital spent on both KCP&L with all 3 companies ongoing T&D systems, and there's some Wolf Creek in there as well as we expect to continue to spend some dollars at Wolf Creek on capital upgrades and some capital from Wolf Creek from the last outage.

Unknown Analyst

Great. And what is the, I guess, the O&M impact from Wolf Creek for 2012? The Wolf Creek current outage?

Terry Bassham

It's -- we don't have a final number yet, but it's not -- it's already included in the guidance range. So it's not material outside that guidance range.

Unknown Analyst

I'm just trying to figure out for next year using that because it's a historic test year.

Terry Bassham

Yes, the outage is not over yet, so we'll update you as the outage gets complete.

Operator

Your next question comes from the line of Shahriar Pourreza with Citigroup.

Shahriar Pourreza - Citigroup Inc, Research Division

Question on La Cygne. Any chance of filling an abbreviated rate case similar to what your counterpart did in Kansas rather than filing a general rate case?

Terry Bassham

Yes, well, so let me back up. Yes, after this rate case. We have a need to file this rate case for other reasons. But as they did, we will follow Westar's lead in this case and talk about the ability, maybe to file an abbreviated case in between. But this case, we've got other issues as well, which we'll need to file a full case just as they did here this first go-around.

Shahriar Pourreza - Citigroup Inc, Research Division

Assuming that you get an abbreviated rate case for La Cygne, when do you foresee filing for another rate case following this one?

Terry Bassham

In Kansas, if we file effect, so -- effectively rates again in January of 2013, you could accumulate another annual number of dollars in 2013. So you might consider filing something in '14. I think '13, '14, we'll just see how that works for the abbreviated case. Again, let me stress. Our plan will still be to operate our business within those rates other than that.

Shahriar Pourreza - Citigroup Inc, Research Division

Okay, right. And just one last question. Can you just remind me what KCP&L Kansas' rate base is right now, approximately?

James C. Shay

I believe it's $1.8 billion. Let me double check that number.

Terry Bassham

Yes, that about right?

James C. Shay

Yes, $1.8 billion.

Shahriar Pourreza - Citigroup Inc, Research Division

And this is as of when?

James C. Shay

The previous filing of...

Terry Bassham

September, this case, it would be the prior case?

James C. Shay

Yes, prior case.

Operator

The next question comes from the line of James Bellessa of D.A. Davidson.

James Bellessa - D.A. Davidson & Co., Research Division

I'm looking at the generation fleet availability slide or table in your press release, and you had a slide also that was related. And at the same time, I understand that the Wolf Creek plant was in a forced outage status in the fourth quarter, at least, a portion of it. But the slide in the table says that the availability of nuclear was 100% in the fourth quarter, how is that?

Terry Bassham

The outage started on January 13. So Wolf Creek was operating at 100% in the fourth quarter.

James Bellessa - D.A. Davidson & Co., Research Division

I see. But it says the forced outage at Wolf Creek had an impact -- adverse impact on the fourth quarter, oh fourth quarter 2010 results. That's my error...

Terry Bassham

Yes.

Operator

[Operator Instructions] Your next question comes from the line Kamal Patel with Wells Fargo.

Kamal B. Patel - Wells Fargo Securities, LLC, Research Division

I had a quick follow-up questions on your debt financing plans. You mentioned the GMO maturity. That will be addressed through the convert or the equity units -- equity offering?

James C. Shay

That's correct.

Kamal B. Patel - Wells Fargo Securities, LLC, Research Division

What about the remainder, because that's roughly $300 million? That leaves some remaining, from what I remember?

James C. Shay

Yes, we would carry that on a short term, we have ample capacity and we would combine that with refinancing in 2013. Another maturity.

Kamal B. Patel - Wells Fargo Securities, LLC, Research Division

And at KCP&L, that would be probably be the same intent, is push it into 2013 or...?

James C. Shay

That's correct.

Kamal B. Patel - Wells Fargo Securities, LLC, Research Division

Okay. And the maturities at the holding company that you have the equity in it, note would be reoffered?

Unknown Executive

Yes. We would remarket the equity unit sub note, which was about $290 million. And the equity proceeds are about the same amount that we'd use to offset the GMO $500 million maturity.

Operator

Your next question comes from the line of John Ally [ph] with JJ Capital.

Unknown Analyst

Just a quick follow-up. The $200 million more of rate base, that includes a bonus appreciation in 2011, right?

James C. Shay

Yes.

Michael J. Chesser

Yes.

Unknown Analyst

Okay, great. And what do you expect to take in '12?

James C. Shay

$200 million.

Unknown Analyst

In addition to $200 million in '11 and then $200 million in '12?

James C. Shay

$200 million is the '12 number.

Unknown Analyst

Okay, so it doesn't -- how much did you take in '11?

James C. Shay

The 2011 number, I believe that number was $300 million. But I'd -- I'll have to reconfirm that.

Unknown Analyst

Okay. But the rate base that you guys filed is net of both of those numbers so....

James C. Shay

And we would -- those are net of -- our rate base is net of the deferred taxes as you'll recall.

Operator

Your next question comes from the line of Andrew Levi with Caris.

Andrew Levi - Caris & Company, Inc., Research Division

Just one follow-up. On the rate case, what are your thoughts on, politically, on asking for such a large rate increase?

Terry Bassham

Well, obviously, we have expressed our concern about having to raise rates at a time when the economy's tough. But we've talked about the fact that -- and tried to put it in the context of our reduced cost. And the fact that really what's driving this increase is -- are factors beyond our control. Things that have happened in the marketplace. And it's a tough message sometimes to explain that the main driver for our increase is a reduced credit that comes from these off-system sales. But I believe the regulators will understand that and see that it's a flow-through function. And if we had a fuel factor, it would be separate, like the other cases. So certainly, we're being, and are, very sympathetic and concerned about the effect it has on our customers. But we continue to talk about our high reliability, about our rates still remaining below national averages and our ability long term to provide assets which will support economic growth in our communities, which is important to all of us.

Michael J. Chesser

This is Mike. Let me just add that throughout this whole comprehensive energy plan, we have benefited from, what I would call, the high brand equity that we have in the community. You've heard me talk in the past about this whole community political regulatory process. We not only provide that same service and reliability, but we also are seen as highly credible players in the community. We are well regarded and have good relationships with legislators and governors. And I think overall just have a high degree of credibility. I think people believe that we wouldn't be asking for something that we didn't need to maintain financially viable. That's been our benefit throughout the comprehensive energy plan, and I think that should serve us well here as well.

Andrew Levi - Caris & Company, Inc., Research Division

And 2013 guidance, as far as regulatory lag in achieving a certain -- what was it, 50 basis points below. How much rate relief do you need to kind of achieve that?

Terry Bassham

Well, I mean I think it's reflected in our case. I mean, ultimately, we will be responsive to our case, and we'll manage our business again in the context of our rate structure. But our ask reflects our needs.

Operator

The next question comes from the line of Michael Lapides with Goldman Sachs.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Follow-up. Looking at Slide 34, the CapEx slide. Just curious, why -- and it's not huge numbers. It's a decent number in 2013. Why such an uptick in CapEx given -- even though you're environmental has actually come in -- come down a little bit, and I commend you for that because you have big environmental projects underway right now. But why bring up CapEx if load growth is anemic, if you don't have other major projects that are underway right now? And especially if this is your last rate case in Missouri for a while, any spending you do in '12 or '13, you will have cash lag, I would think, if anything, you would be trying to keep CapEx as limited as possible except on the environmental side and maybe transmission.

Terry Bassham

You're correct. From a strategy perspective. I think we've tried to describe here. And you're talking in particular, in '13, '14?

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Yes. We -- I mean, I'm really -- you don't show '14 on this slide. I'm really thinking '13 but even '12, right? Because you're up in both and its historical test year, so the higher CapEx in '12, you'll have cash lag on and you'll have it in '13 as well except on the environmental side in Kansas.

Terry Bassham

Well, we've got a couple of things that can't be adjusted for the economy. One of them is Wolf Creek. We've got some continued spend on Wolf Creek related to essential service, water and other things that are a function of our safe operation of that plant, and we got the start of our T&D projects, that are already committed there. So we're certainly watching those. We are scrutinizing every one of those budget dollars looking for opportunities. And then on the operational side, you're right, to the extent that we don't have growth, we're managing our additional CapEx there, right around depreciation on a day-to-day operation basis for that very reason. But there are some things that are not driven by the economy and you can't necessarily put off to maintain operation. So there are a couple of things there that make tick up a little, may look a little unusual.

James C. Shay

And Michael, as we think about it, we think about our 50 basis points of lag target, we think about it in terms of costs of service, but also a fairly rigorous approach to understanding how much capital lag we can have. And we'll take a look at the depreciation outcomes from the upcoming rate cases. And as Terry indicated, really manage that base CapEx in line to the best we can with depreciation rates. So we've got our eye clearly on that ball.

Michael J. Chesser

We do have some capital projects at Wolf Creek, Michael. If you take those out and you take the transmission, 2 transmissions spends out. I think that would look more like what you would expect to see.

Operator

And there are no questions at this time.

Michael J. Chesser

Okay. Let me just wrap up and say that go back to the August Day -- August Analyst Day presentation that we made. And there, we laid out [Audio Gap] look at our business, what the drivers are for 2012 and 2013. That's something we plan to consistently follow and consistently update you on as assumptions change, such as happened here with the lower natural gas prices and lower demand. So hopefully, as we go forward, you'll be able to continue to refer back to that same framework and follow our progress with full transparency. So again, thank you very much for your attention today, and we look forward to talking to you as the year goes on.

Operator

This concludes today's conference call. You may now disconnect.

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