Oct 30, 2013
Executives
Gale E. Klappa - Chairman, Chief Executive Officer, Chairman of Executive Committee, Chief Executive Officer of Wisconsin Electric Power Company, Chief Executive Officer of Wisconsin Gas LLC, President of Wisconsin Electric Power Company, President of Wisconsin Gas LLC, Chairman of Wisconsin Electric Power Company, Chairman of Wisconsin Gas LLC James Patrick Keyes - Chief Financial Officer and Executive Vice President Allen L.
Leverett - President, Executive Vice President of Wisconsin Electric Power Company, Chief Executive Officer of We Generation Operations and President of We Generation Operations
Analysts
Julien Dumoulin-Smith - UBS Investment Bank, Research Division Kit Konolige - BGC Partners, Inc., Research Division Brian J. Russo - Ladenburg Thalmann & Co.
Inc., Research Division Andrew Bischof - Morningstar Inc., Research Division Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division Michael J.
Lapides - Goldman Sachs Group Inc., Research Division Jonathan P. Arnold - Deutsche Bank AG, Research Division Paul Patterson - Glenrock Associates LLC
Operator
Good afternoon, ladies and gentlemen. Thank you for waiting and welcome to Wisconsin Energy's Conference Call to review 2013 third quarter results.
This conference call is being recorded for rebroadcast. [Operator Instructions] Before the conference call begins, I will read the forward-looking language.
All statements in this presentation, other than historical facts, are forward-looking statements that involve risks and uncertainties which are subject to change at any time. Such statements are based on management's expectations at the time they are made.
In addition to the assumptions and other factors referred to in connection with the statements, factors described in the company's latest Form 10-K and subsequent reports filed with the Securities and Exchange Commission could cause actual results to differ materially from those contemplated. During the discussions, referenced earnings per share will be based on diluted earnings per share unless otherwise noted.
After the presentation, the conference will be open to analysts for questions and answers. In conjunction with this call, Wisconsin Energy has posted a package of detailed financial information on its website at www.wisconsinenergy.com.
A replay of our remarks will be available approximately 2 hours after the conclusion of this call. And now, it's my pleasure to introduce Mr.
Gale Klappa, Chairman of the Board and Chief Executive Officer of Wisconsin Energy Corporation.
Gale E. Klappa
Colleen, thank you very much. Good afternoon, everyone, and thanks for joining us as we review our 2013 third quarter results.
Let me begin, as always, by introducing the members of the Wisconsin Energy management team who are with me today. We have Allen Leverett, President of Wisconsin Energy and President and CEO of We Generation; Pat Keyes, our Chief Financial Officer; Susan Martin, General Counsel; Steve Dickson, Controller and Scott Lauber, our Treasurer.
Pat, of course, will review our financial results in detail in just a moment. But as you saw from our news release this morning, we reported earnings of $0.60 a share for the third quarter of 2013.
This compares with earnings of $0.67 a share for the third quarter 2012. Our latest results reflect a return to normal summer weather compared to the record heat that we experienced last summer.
On the positive side of the ledger, our earnings were boosted by a slight uptick in net income at We Power and by our share repurchase program. For the first 3 quarters of 2013, our earnings came in at $1.88 a share, compared to $1.92 a share for the first 9 months a year ago.
You'll recall that our year-to-date results this year reflect a $0.09 a share reduction for our customer bill credits. When our new biomass plant is complete and in commercial operation, we expect to add $0.09 a share to our fourth quarter earnings.
Turning now to the economy in our region. Wisconsin's unemployment rate declined to 6.7% in August and remains well below the national average.
However, we anticipated some continued sluggishness in the regional economy when we projected our third quarter sales. And that sluggishness is truly reflected in our numbers.
Energy sales to our large commercial and industrial customers, excluding the iron ore mines in Michigan, were down by 3.5% compared to the third quarter a year ago. When you factor in normal weather, sales to our large commercial and industrial customers, again excluding the iron ore mines, were down by 2.7%.
We did see some positive signs though in September. Overall, electricity used by our large customer segment was higher than September of a year ago.
And about half of the 17 industrial sectors that we track showed some positive growth in September. Also, we're continuing to see customer growth across our system as well.
Compared to the same time last year, new electric service installations are up by 2.7% and new natural gas installations have increased by 13.5%. Now as many of you know, we are finishing up a major construction project, our biomass-fueled power plant in Rothschild, Wisconsin.
Construction is now 97% complete and we're on-schedule for commercial operation before the end of the year. Since our last call, we recorded several significant milestones at Rothschild.
We achieved first fire using natural gas on September 17. A week later, on September 24, we synchronized the steam turbine generator for the very first time.
Also, we had our first fire using biomass on October 3. And we're continuing to test and fine-tune various systems on the unit in preparation for commercial operation.
As I've noted before, the biomass plant will help us diversify our portfolio of renewable energy. The new unit will produce electricity for the grid and steam for the Domtar paper mill on the site.
And we'll be able to dispatch the unit on-demand, the benefit of simply not available with solar or wind generation. Overall, our investment of the biomass plant is expected to total about $269 million and that's excluding allowance for funds used during construction.
In September, we also started a new construction project at one of our hydroelectric plants. We've officially began the work of building a new powerhouse at our Twin Falls hydroelectric site on the border of Wisconsin and the Upper Peninsula of Michigan.
Twin Falls is 1 of 13 hydroelectric plants on our system. It was built back in 1912, and while the plant is licensed to operate until the year 2040, the existing powerhouse really needs repair.
We considered several alternatives, but the most prudent course is to build a new powerhouse and add spillway capacity to meet current federal standards. We received a Certificate of Authority for the project from the Wisconsin Commission in May.
Since our last update, we received all the necessary permits including a license amendment from the Federal Energy Regulatory Commission. We expect to complete the Twin Falls project in 2016, and we're estimating that the cost will be in the range of $60 million to $65 million, again excluding allowance for funds used during construction.
You may recall that we're also planning to convert our Valley Power Plant from coal to natural gas. The Valley Plant is a cogeneration facility located along the Menomonee River near downtown Milwaukee.
Valley generates electricity for the grid, produces steam to heat more than 450 buildings in the downtown Milwaukee business center and provides voltage support for our distribution network. We filed for construction authority with the Wisconsin Commission on April 26 and a Notice of Proceeding was issued by the commission in late June.
If approved, we plan to complete the Valley conversion in late 2015 or early 2016 at an estimated cost of $65 million to $70 million, excluding allowance for funds used during construction. It's important to note that before we begin the conversion, we must also upgrade the existing natural gas pipeline that runs near the facility.
That upgrade began in March of this year at an estimated cost of approximately $26 million. Converting Valley to natural gas will reduce our operating costs and enhance the environmental performance of the units.
We expect the electric capacity of the plant to remain the same at 280 megawatts and we believe our plan will help support a vibrant downtown Milwaukee for many years to come. Switching gears now, you'll recall that in 2011, our board authorized us to repurchase up to $300 million of Wisconsin Energy common stock.
That authorization runs through the end of this year. During the third quarter, we purchased approximately 1,147,000 shares.
Since the program began, in total, we've repurchased 7,121,000 shares at a cost just under $254.8 million. That equates to an average purchase price of $35.78 a share.
Regarding our dividend policy, at our July board meeting, the board voted to accelerate to the second half of 2013 the dividend action that was planned for the first quarter of 2014. As a result, the directors declared a quarterly cash dividend of $0.3825 on the company's common stock.
This was an increase of $0.0425 a share in the quarterly dividend and it raised the annual rate from $1.36 a share to now $1.53 a share. The board also reaffirmed the dividend policy that calls for our payout ratio to rise to 65% to 70% of earnings in 2017, a level that we believe will be much more competitive with our peers across the regulated utility sector.
And now I'd like to touch on our growth plan and on the investment opportunities that we see unfolding over the next several years. You may recall that our capital budget calls for spending $3.2 billion to $3.5 billion over the 5-year period 2013 through 2017.
In this 5-year plan, we're shifting from the large high-profile projects that were part of Power the Future to many smaller scale projects designed to upgrade our aging distribution infrastructure. Over the 5-year period, we'll place a greater focus on pipes, poles, wires, transformers and substations, the building blocks of our delivery business.
We've already begun rebuilding 2,000 miles of electric distribution lines, replacing 18,500 power poles, 20,000 transformers and literally hundreds of substation components. On the natural gas distribution side of our business, we started to replace 1,250 miles of gas mains; 83,000 individual gas distribution lines; and approximately 233,000 meter sets.
The primary risks associated with these projects, developmental, legal, regulatory and construction, are naturally more manageable given the smaller scale and scope of the distribution work. But this work is no less valuable or important than the megaprojects we've completed in recent years.
Our focus on renewing the distribution networks is essential to maintaining our status as the most reliable utility in the Midwest. Turning now to Oak Creek.
We continue to make progress on our fuel flexibility initiative at the Oak Creek expansion units. As you may recall, the units initially were permitted to burn bituminous coal.
However, given the current cost differential between bituminous and Powder River Basin sub-bituminous coal, blending the 2 types of coal could save our customers between $25 million and $50 million a year depending upon the mix. After receiving environmental approvals, we began testing a blend of bituminous and Powder River Basin coal of our Oak Creek expansion units in May.
Testing has been progressing well and is expected to continue into 2015. These tests will help us identify the equipment modifications that will be needed on a permanent basis to increase the percentage of Powder River Basin coal in our fuel mix at Oak Creek.
We expect to submit an application for a Certificate of Authority to the Wisconsin Commission in late 2014 or early 2015. Of course, we will need this approval to make the necessary modifications at the plant.
It's important to note that the investments we're planning on the generation side of our business, converting Valley to natural gas, changing our fuel mix at Oak Creek, are expected to lower costs for customers. The Valley conversion is projected to save up to $20 million a year in operating costs.
And as I mentioned, our fuel flexibility efforts at Oak Creek could save customers up to $50 million a year, again, depending on the fuel mix. On the natural gas distribution side of our business point, you may recall that we filed an application with the Wisconsin Commission in March to build a natural gas lateral in West Central Wisconsin.
In August, we filed a supplement to provide additional information, primarily environmental data. The 85-mile line would run between Eau Claire County in the far western part of the state and the City of Tomah in Monroe County.
The project will address reliability concerns in Western Wisconsin and meet growing demand, driven in part by customers continuing to convert from propane to natural gas and by the growth of the sand mining industry in the region. I might add that over the past few months, 8 communities along with the proposed route have passed resolutions authorizing us to begin operating natural gas distribution systems within their borders.
If approved by the Wisconsin Commission, we expect an in-service date for the new line during the fourth quarter of 2015. The projected cost is $150 million to $170 million, excluding allowance for funds used during construction.
We're also continuing to follow another possible investment opportunity, the potential sale of the State of Wisconsin's electric and steam generating plants. On June 30, as you may recall, Governor Walker signed into law a new state budget that includes a provision expanding the State's authority to sell or lease certain state-owned properties.
This means that the administration now has the authority to sell the State's electric, steam and chilled-water production and distribution facilities. The State is moving forward, and in early October, state officials began the process of selecting an outside financial advisor.
No formal timetable has been announced but if the sale does take place, we expect that it would occur in late 2014 or early 2015. And now before wrapping things up, I have a quick update for you on American Transmission Company.
As you know, we're the second largest owner of ATC with an ownership stake of 26.2%. ATC recently published its 10-year capital investment plan for the years 2013 through 2022.
The plan calls for a $3 billion to $3.6 billion of capital spending to bolster reliability and reduce congestion in the region. Now the previous 10-year plan have called for a higher level of investment in the range of $3.9 billion to $4.8 billion.
However, we do not expect the new plan to have a major impact on our near-term earnings forecast because similar to the prior plan, much of the investment is back-end loaded. I should also point out that the new 10-year plan from ATC only covers projects inside the franchise footprint in Wisconsin in the Upper Peninsula of Michigan.
ATC is also pursuing investments outside this footprint through a joint venture with the Duke Energy. The joint venture has proposed approximately $4 billion of new transmission in the broader Midwest and in the western part of the country.
Any of these projects, if approved, would provide additional investment upside through ATC's 50% share on the joint venture. Turning to Wisconsin rate matters, at the end of July, we filed our 2014 fuel case.
We're asking the Wisconsin Commission for approval to reduce our fuel recovery rate next year by approximately $30 million. The primary driver of the savings is a reduction in the delivered cost of coal.
And finally, before closing my remarks, I'd like to update you on our Michigan operations. As you recall, under Michigan law, retail customers may choose an alternative supplier to provide power supply service.
The law limits customer choice to 10% of Michigan's retail sales, but the law excludes from this cap the iron ore mines in Michigan's Upper Peninsula. Of course, we continue to provide distribution and customer service functions regardless of the power supplier.
As we reported to you on our last call, the 2 iron ore mines we were serving on an interruptible tariff switched to an alternative supplier on September 1. Several smaller retail customers have switched as well.
We do not expect the loss of the mines or the smaller customers to have a material impact on our consolidated financial projections for 2013. We have taken and will continue to take multiple steps to mitigate the losses for 2014 and beyond.
For example, we filed a requested with MISO, of the Mid-continent Independent System Operator, to suspend operations of all 5 of our generating units at our Presque Isle Power Plant. In October, MISO informed us that all the units are necessary to maintain reliability in Northern Michigan.
As a result, we are eligible for systems support resource payments from MISO to recover our costs for operating the units. We currently are working with MISO to determine the exact amounts of these payments and we expect to become eligible to receive the payments beginning in February of 2014.
Although the long-term impact of the Michigan choice law is still uncertain, we expect the successful mitigation efforts and a reasonable regulatory response should make our net financial exposure immaterial. That said, given the loss of load in Michigan's Upper Peninsula, we need to reevaluate our supply portfolio.
Before the departure of the mines, we had a long-term need for at least a portion of the Presque Isle Power Plant. At this point, we do not have that need.
As a result, we're working with Wolverine Power Cooperative to modify the joint venture structure that we developed last year so that it works for both Wolverine and our customers over the long term. And now, with more details on our third quarter and our outlook for the remainder of 2013, here's Pat.
James Patrick Keyes
Thank you, Gale. As Gale mentioned, our 2013 third quarter earnings were $0.60 a share, compared to $0.67 a share for the same quarter in 2013.
As expected, the results were slightly lower than last year because of a return to normal summer weather and customer bill credits related to our new biomass plant. Our consolidated operating income for the third quarter was $258 million as compared to $280.6 million in 2012, and that's a decrease of $22.6 million.
Starting with the utility energy segment. You'll see that operating income in the third quarter of 2013 totaled $166.6 million, a decrease of $24.4 million from the third quarter of 2012.
The primary driver was the milder weather, which we estimate reduced our electric margins by $22.9 million. In addition, depreciation expense increased by $5.2 million, primarily because of the major environmental project that went into service last year.
As I've mentioned in previous earnings calls, we expect to receive a federal treasury grant related to our new biomass facility, which is scheduled to go into service by the end of the year. Our customers currently benefit from this grant through bill credits.
However, accounting rules do not allow us to recognize the grant income until the plant is placed in service. We estimate that our third quarter earnings would have been $0.03 a share higher and our earnings for the first 9 months would have been $0.09 a share higher have we recorded the grant income to match the bill credits.
Therefore, we expect to see a $0.09 pick up in the fourth quarter when we recognize the grant income after the biomass plant is placed into service. Now turning to our nonutility segment.
Operating income was up $1.7 million this quarter because of the final approval of our Power the Future plan cost in the last Wisconsin rate case. We expect this increase to continue in the fourth quarter.
Taking the changes for these 2 segments together and a slight improvement at corporate and other, you arrive at the $22.6 million decrease in operating income. Earnings from our investment in the American Transmission Company totaled $17.1 million in the third quarter and that's level with the same period in 2012.
Our other income, net, declined by $3.9 million, primarily because of lower AFUDC. AFUDC decreased because we completed the final stages of the air quality control system for the older Oak Creek units last year.
In addition, our net interest expense increased by $1.1 million, primarily because of lower capitalized interest. When compared to the third quarter 2012, our tax expense is down because of lower pretax income.
We expect our effective tax rate for 2013 will be between 36% and 37%. Combining all of these items brings you to $137.5 million of net income for the third quarter 2013 or earnings of $0.60 per share.
During the first 9 months of 2013, our adjusted operating cash flows totaled $1,053,000,000, which is a $25 million increase from the same period in 2012. The increase largely came from cash received this year through customer rates for recovery of regulatory assets.
In addition, during the first 9 months of 2013, we made no contributions to our benefits plan compared to $100 million contribution made in the same timeframe in 2012. This increase was partially offset by a $33 million decrease in restricted cash related to a customer refund in 2012 of a settlement with the Department of Energy.
Our total capital expenditures increased by $20 million in the first 9 months of 2013 compared to 2012, primarily because of investments in our distribution infrastructure. We paid $242.3 million in common dividends in the first 9 months of 2013, an increase of $34.9 million or almost 17% over the first 9 months of 2012.
Our 2013 dividend includes 2 increases: The first in March, and then again in September. Our current quarterly dividend rate is $0.3825 per share.
Our adjusted debt-to-capital ratio was 52% at the end of September. Our calculation creates half of our hybrid security as common equity, which is consistent with past presentations.
The projected year-end debt-to-total capital is expected to be relatively flat with 2012 year end. We are using cash to satisfy any shares required for our 401(k) plan, options and other programs.
So going forward, we do not expect to issue any additional shares. As shown in the earnings package on our website, retail sales of electricity, excluding the mines, decreased by 2.9% in the first 9 months of 2013 as compared to the first 9 months of 2012.
Our normalized sales were down by 0.8%. All normalized sales are adjusted for the effects of leap year and weather.
Looking at the individual customer segments, actual residential sales for the first 9 months of the year we're down 3.9% because of a return to normal summer weather. On a normalized basis, sales we're down 0.2%.
Across our small commercial and industrial group, sales for the first 9 months were down 1.1%. On a normalized basis, sales to small commercial and industrial customers were down 0.6%.
And on a normalized basis, sales for the first 9 months of 2013 in the large commercial industrial segment, again excluding the iron ore mines, were down 1.8%. On the natural gas distribution side of the business, total volumes during the first 9 months of the year, excluding the volumes used in power generation, increased by 20.9%, primarily due to colder winter weather.
On a normalized basis, gas volumes for the first 9 months of the year rose 2% as compared to 2012. This growth is the result of an increase in customers, fuel switching to natural gas and the positive impact of additional gas used in the sand mining industry.
Overall, these gas volumes we're better than our projections. Finally, as we look ahead to the fourth quarter, we are tightening our annual earnings guidance.
Our prior guidance was $2.41 to $2.48 a share. Our new guidance is $2.43 to $2.48 a share.
Again, our new guidance for 2013 is $2.43 to $2.48 a share. This reflects our strong performance through the first 9 months of the year, assumes normal weather, takes into consideration the effects of the Michigan choice law and recognizes the grant income associated with the biomass plant.
And with that, I will turn things back to Gale.
Gale E. Klappa
Pat, thank you very much. Overall, we're on track and focused on delivering value for our customers and our stockholders.
Operator
[Operator Instructions] Julien Dumoulin-Smith with UBS.
Julien Dumoulin-Smith - UBS Investment Bank, Research Division
So first question here, just with regards to the Wolverine and Presque Isle and all that, what are you guys trying to get out there? I mean, is this ultimately shut down or is this a sale or something in between?
Gale E. Klappa
Well, we'll ask Allen to give you some detail, but let me just kind of frame this for you again, because you're asking an important question. A year ago, we truly believed, looking at our demand projections and looking at the demand in the Upper Peninsula, that we had a need for a portion, at least the portion of the Presque Isle 5 unit facility.
However, that plant is going to need environmental upgrades. And Allen and his folks worked very hard with Wolverine Power Cooperative to put together, what I thought was a very elegant solution, which was Wolverine would fund completely the cost of the environmental upgrades in return for a pro rata ownership of the plant, roughly 1/3.
That really, we thought, fit both Wolverine's need and our need going forward. But now with the loss of the mines, we simply don't have retail customers to support basically our continued cost of the plant.
So we're looking at each one of the paths. We obviously, in the interim, are being told we have to run the plant and now we're eligible for the system support resource payments from MISO.
But in the longer-term, really, we're looking at all the alternatives and Allen can give you some detail.
Allen L. Leverett
Yes, and I would say probably long term, Julien, I think from a practical standpoint, there are probably only 2 likely paths. One path is I'll call it some renegotiated version of the joint venture agreement.
So perhaps instead of having 5 units at the plant, maybe only have 3 units. So perhaps you downsize it, perhaps Wolverine maybe and some other entity own those -- the smaller plant.
So, I mean that's one potential path. I would say the other potential path is, there's just the dissolution basically of the joint venture agreement we have now.
We run the unit. As Gale mentioned, we run the units as long as they are required by MISO, and MISO is making those SSR payments and then, once the units are no longer needed, well, they'd be retired.
So I think from a practical standpoint, that those are really the only 2 paths. It's hard for me to imagine a path where the joint venture agreement, as currently structured, that we can continue with that, because as Gale mentioned, we've had such a change in our demand as a company.
So hopefully that helps some.
Julien Dumoulin-Smith - UBS Investment Bank, Research Division
Absolutely. And just curious, if you don't mind following up on, what does this mean for customers rates, just at the end of the day in the UP?
Gale E. Klappa
Well, we can both take a shot at that. In terms of the customer rates and the UP, I mean backing up, if the plant is going to continue to operate for the longer term, someone has to cover the cost of the operation.
And our view would be that I mean customer rates in the UP probably would continue to go up some because either way, our customers in Michigan would have to support -- if the plant were to run for the long term, customer rates would have to support the environmental upgrades and the ongoing production costs and fixed production costs of the plant. I think everyone is aware of that.
There's a lot of discussion going on. Clear, the governor's office would very much like, in Michigan, the plant to stay open.
They really believe there is future economic growth there and particularly in terms of the mining industry. So lots of discussions going on right now, and I would guess that the picture would become much clearer certainly over the course of the next few months.
Julien Dumoulin-Smith - UBS Investment Bank, Research Division
Got you. And then maybe following up on some comments from some of your peers today.
Just trying to get a sense, longer-term, how do you see your earnings growth rate trending here? I mean just given the sort of availability of investment opportunities, I'm curious as you balance ATC and others, are we seeing a consistent trend here or is there some slowing in their future, just to throw it out there.
Gale E. Klappa
Well, we're in the process now, Julien, of completing our next rolling 5-year capital spending plan. But from everything I'm seeing, I mean we have said, as you know, that our medium-term growth looks like 4% to 6% off our 2011 base.
And right now, I would say that, that stands in terms of as good a projection as we can divine by looking into the future. And remember, we have, as I mentioned in the prepared remarks, we have a significant amount of investment that needs to be made in our delivery networks, in upgrading our aging infrastructure.
So about 2/3 of the capital spending that we've identified for 2013 through 2017, is really being devoted to upgrading the reliability of our distribution networks and that is work that needs to continue. So I would say, the best range can give you at the moment is 4% to 6% EPS growth.
Operator
Kit Konolige with BGC Financial please state your question.
Kit Konolige - BGC Partners, Inc., Research Division
Let me, Gale, just follow up on your discussion just now regarding earnings growth. So in order to get earnings growth with -- well, let me ask this.
What kind of sales growth do you see feeding into that earnings growth over the next whatever it is, 3 to 5 years?
Gale E. Klappa
Well, Kit, as you know, we've been, I think, appropriately conservative in our sales growth projections. I believe, when we are all together last year at the EEI Conference in November, I think we were the only major company projecting literally no growth in kilowatt hour sales for 2013.
I mean, as it's turning out, that projection was pretty much on target.
Kit Konolige - BGC Partners, Inc., Research Division
You were the only ones right.
Gale E. Klappa
Yes. Sometimes we get lucky.
But long story short, as we're putting our rolling 5-year plan together and updating it, I think you're going to see sales growth projections on the electric side in the 0.3% to 0.5% growth range. That's currently what we're focusing on and we're now completing, as we do every year, interviews with our 120 largest industrial customers to get their input on the demand that they see over the next year.
So we'll refine all of that, but I think right now, you can expect in our new 5-year plan, to see about 0.3% to 0.5% annual weather normal increase in electric sales.
Kit Konolige - BGC Partners, Inc., Research Division
So that relatively low level of load growth would suggest that you'll need some -- and relatively high level of capital spending would imply that you'd need some significant rate relief over that period.
Gale E. Klappa
Well, certainly some rate release, but I think more in the lines of historic inflation over time and let me explain why. Yes, the sales growth projections are moderate to low.
I think appropriate but moderate to low. But we're also making significant amount of investments on the capital you referred to, that will help us take out operation and maintenance costs.
And we mentioned a couple of them in the prepared remarks. For example, our proposal to convert our Valley Power Plant from coal to natural gas, we expect that will take out roughly $20 million a year in operating costs.
The concept of fuel flexibility that we're testing out at our new Oak Creek units, that $25 million to $50 million of fuel cost savings. Pat, our IT group also reports up through Pat and we have a whole list of very significant IT capital projects designed to take out operation and maintenance costs and make our processes more efficient.
So we think we can modify and reduce what otherwise would be a larger rate increase request simply by wisely spending capital that makes us more efficient and takes out O&M. And I think that would be another lever that you will see us employ over the course of the next 5 to 7 years.
Kit Konolige - BGC Partners, Inc., Research Division
All right. Great.
And then a separate area on the ATC and the Duke joint ventures. Is the Duke JV in particular, what do you realistically see as the likelihood of some of those $4 billion in proposed projects coming to fruition?
Gale E. Klappa
Let me say first, I'm going to ask Allen because he sits on the board of ATC, to give you a specific answer. But to frame that answer for you, Kit, we have always been, as you know, reasonably conservative in terms of what we put into our financial model.
We're not going overpromise and underdeliver. And so we've been quite conservative in terms of taking the ATC plan and shaping it to what we think is a conservative estimate of what may happen.
And many of those projects as you know, just because of the nature of large transmission projects, are back-end loaded in the financial model. Allen?
Allen L. Leverett
Yes, and Kit, I mean, maybe just picking up on that. Gale, certainly in the script, addressed the first 5 years.
What I mean by that is the impact of the revised ATC outlook on the first 5 years of our financial projections, and as he said, really no impact on that first 5 years. So let me maybe address kind of the period beyond the first 5 years.
When we develop longer-term projections and we look at the outlook from ATC for inside the footprint, we really use, what I would, call a midrange case. I mean, we don't take the most conservative nor do we take the highest case.
We sort of take kind of a midrange case for inside the footprint. However, outside the footprint, we use a low-range case meaning a much more conservative outlook on what ATC might be able to invest.
So as we look at, if ATC can do better than that low-range case outside the footprint, it's already, reasonably speaking, a low bar, we'd be optimistic that on a net basis, we could be right back to kind of the 10-year outlook that they had before and possibly even have a little upside above that. And certainly, with the outlook, it would still be supportive of the 4% to 6% EPS growth target that Gale mentioned earlier to Julien's question.
So hopefully that helps a little bit, Kit.
Operator
Brian Russo with Ladenburg Thalmann.
Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division
Just curious, do you have a depreciated book value for the Presque Isle Plant?
Gale E. Klappa
Yes. Right at about $219 million.
Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division
Okay. And what were the primary drivers of the lower, revised CapEx at ATC?
What was driving that?
Gale E. Klappa
Allen?
Allen L. Leverett
Yes. And then, I would sort of put it in 2 or possibly 3 categories.
Far and away, the biggest driver, ATC had put forward a plan for addressing transmission issues in the Upper Peninsula of Michigan. And in the new plan, the size of those investments is less than in the old plan.
So that's kind of the first area, if you will, that was causing a difference. The second thing that was causing a difference, as I'm sure you're aware, the Kewaunee Nuclear Plant here in Wisconsin is now shut down.
So it's shut down. They were going to be some transmission improvements that would've been required if it had continued to operate.
Those are no longer going to be required or at least the level that are going to be required are now much less because of the Kewaunee Plant is not going to operate over the long-term. And then finally, there were 2 345 kV projects.
One, that's sort of a -- more of an east-west line that went from Wisconsin over to Minnesota; another line, more north-south, that went from Wisconsin down into Iowa. In the previous outlook, ATC had projected that they would be able to invest the capital for the entire length of both of those lines.
And as it turned out, they're only able to invest roughly half of the investment required in each of the lines. So Xcel will get half of that east-west line that I mentioned, and ITC will get half of that north-south line that I mentioned.
But at a high level, those are the 3 major drivers, if you will, of the change in their outlook.
Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division
Okay. My last question, I'm just curious, you reported $0.60 and that was above the quarterly guidance of $0.52 to $0.56 you conveyed in August.
So I was just curious what enabled you to beat your budget.
Gale E. Klappa
What allowed us to beat the budget?
Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division
Yes.
Gale E. Klappa
Well, I think a couple of things. First of all, really good solid operation and maintenance cost control from our folks.
And then on weather normal basis, we were projecting weather normal but we did a little bit better, I believe, particularly in September on energy sales than we had projected.
Operator
Andy Bischof with Morningstar, please state your question.
Andrew Bischof - Morningstar Inc., Research Division
Really quick question for you guys this afternoon. In Michigan, you mentioned you'd be eligible for systems support payments in February.
When would you expect to know the details of that support?
Gale E. Klappa
Well, I would hope we'll know the details of that support by the end of the year, certainly by early January because the process that MISO goes through -- and first of all, now that they've determined that we are eligible for the payments, the next step is we and they sit down with a detailed analysis of the operating costs, of the potential capital costs over the course of the next few years, and then we and they agree on a level of payment. That whole agreement, then, is subject to approval by the Federal Energy Regulatory Commission.
And once submitted, Allen, I believe the FERC has 60 days to respond.
Allen L. Leverett
That's right.
Gale E. Klappa
So we would hope to have all those discussions wrapped up with MISO by the end of the year, and a filing to FERC very early in the new year.
Operator
Paul Ridzon with KeyBanc Capital Markets, please state your question.
Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division
Your former coworkers went into extra innings so I missed if you gave them the potential capital opportunities at Oak Valley and Valley -- Oak Creek and Valley.
Gale E. Klappa
We talked about fuel flexibility at Oak Creek. At Valley, we did talk about the potential capital opportunity, $65 million to $70 million.
We're in the approval process right now with the Wisconsin Commission. That process is moving along as expected.
And then in addition, if you remember, we said to convert Valley from coal to natural gas, $65 million to $70 million capital investment. But in addition to that, we need to complete an upgrade of the natural gas pipeline that runs near the facility.
That work has been approved and is actually underway, began in March and our expected total cost of that would be about $26 million, in addition to the $65 million to $70 million related to the Valley conversion.
Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division
So Oak Creek is really just material handling, not so much capital?
Allen L. Leverett
Well, it could be capital, Paul. And we really need to get through the testing phase with the burning the blends of sub-bituminous and bituminous coal.
And depending on the results of that, you could get, reasonably speaking, a wide range of potential capital investment opportunities. I mean, if you had to do -- if you're able to do what the engineers call in-furnace blending, that might be something on the order of $20 million to $25 million of capital.
If you're not able to do that reliably, you might have to do -- you might have to actually have a blending facility and that could be upwards of $100 million. But we're just not really going to know where we are on that continuum of solutions until we finished the testing.
Gale E. Klappa
And we did say that we would -- assuming the testing continues to give us positive results, that we would file a -- for construction authority with the Wisconsin Commission late '14 or early '15.
Allen L. Leverett
Correct.
Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division
And then how would SSR payments compare to the return you're currently earning? Or not earning?
Gale E. Klappa
That's a good question. Well, we really need to work through all of this with MISO, but let me just kind of break this into a couple of categories for you.
If you think about the cost we incurred to operate the plant, well, there are fuel costs. Well, those fuel costs are, by and large, recovered through the hourly energy market.
So the fuel cost we should be getting full recovery for. There's what we call variable O&M, the additional costs reproducing the incremental kilowatt hour.
The variable O&M also should be recovered through the hourly energy market. Then we have fixed production costs.
So the fixed cost of operating the facility, the staffing, the normal O&M, the maintenance, et cetera, et cetera, and our guesstimate there is, not only guesstimate but that's part of what SSR payments are supposed to cover. So to put it all into perspective, if nothing -- if we did nothing, the margin hit pretax would be, Allen, $50 million to $54 million?
Allen L. Leverett
Right.
Gale E. Klappa
However, in our discussions with MISO, we're in the range now of $35 million to $82 million, depending upon how much of the capital that we might spend over the next several years to keep the unit reliable, how much of that capital MISO is willing to cover. But I think by definition, the MISO SSR payments are designed to, at a minimum, compensate you for the fixed production costs.
Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division
Does -- did Michigan energy legislation contemplate what would happen if [indiscernible] stranded asset?
Gale E. Klappa
Well, I think originally it did. However, if you recall the 2008 amendment to the Michigan choice law, many believe that stranded costs were not recoverable after the amendment to that law.
And I believe that basically, the law said that anyone who is getting -- any utility getting stranded costs that the commission had to make sure those stranded costs were recovered and completely recovered through billing by October of this year. Right?
The position of the Michigan commission is that under that law, future stranded costs are not recoverable.
Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division
And then just lastly, any forward look on the impact of discount rates on your pension?
Gale E. Klappa
Well, I'll ask Pat to give you a more specific answer, but right now, I mean, going into this year and through where we stand today, we are virtually fully funded on our pension plan. We have not made any cash contribution to the pension plan this year, simply hasn't been needed.
I think we're, I think, one of the few companies in our industry that is in really very good shape related to pension funding and funding up our obligations under the plan. Pat?
James Patrick Keyes
Yes, Gale. I'm not sure I have too much more to add to that.
We're certainly running the miles with our actuaries and we are, as Gale mentioned, about 100% funded now. Given where we are in returns, where we anticipate the discount rate will end up, we're going to end up about 100% funded by the end of the year is our -- more or less without having any material contribution.
Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division
So you could be at a position to have pension earnings next year?
Gale E. Klappa
I don't think we're really projecting any pension earnings next year.
Operator
Michael Lapides with Goldman Sachs, please state your question.
Michael J. Lapides - Goldman Sachs Group Inc., Research Division
Easy question for you. Next year is a rate case year?
Gale E. Klappa
Yes.
Michael J. Lapides - Goldman Sachs Group Inc., Research Division
How are you thinking about relative to maybe some of you priority rate cases? How material this one is for Wisconsin Energy?
How much material this one is for your ratepayers? What are going to be some of the more important issues that, when you file this in the spring, investors should monitor?
Gale E. Klappa
Well, very good question, Michael. Let me talk with you about kind of maybe 3 elements.
I mean, first of all, where I believe, and if our projections continue to hold, I think we'll have some good news on fuel. So we should be able to, I mean, as I mentioned in our script, this would not be for 2015 but for 2014, we filed for approval to reduce our fuel recovery rate by $30 million.
And if fuel prices stay low, we should get -- we should be neutral to maybe positive, I hope, in terms of fuel cost recoveries. So that should be helpful on the rate case front for 2015 and beyond.
The second piece clearly will be, we need to recover projects, capital projects that have basically already been approved. Remember, we talked about the capital investments we're making in deliver the future.
The basic upgrades that we're making to our distribution networks, that capital that we spent, with blessing from the commission in the prior rate case, will need to be recovered in rates starting in 2015. So that will be one of the big drivers.
So I think fuel will be a help. One of the big drivers will be -- will clearly be the deliver the future capital.
And then there'd be a couple of other factors that will swing one way or another but we're hoping that this will be a moderate rate case and we don't see any sticker shock coming down the road here.
Michael J. Lapides - Goldman Sachs Group Inc., Research Division
Meaning you see something that's in the low- to mid-single-digit-increase level and not a dramatically bigger number than that?
Gale E. Klappa
That is certainly our goal and that's what we believe we will be filing for, yes.
Michael J. Lapides - Goldman Sachs Group Inc., Research Division
Got it. Last item, Presque Isle, I want to make sure I follow this correctly.
If it's $219 million in book and if it were still included in rate base kind of -- I'm going to do back-of-the-envelope math, 50/50 GAAP structure, 10% ROE, you're talking $10 million to $15 million, $10 million to $12 million of authorized net income in book. Is there any scenario where the MISO payments actually give you a greater bottom line contribution than what you would get under just traditional rate, regulatory rate making?
Gale E. Klappa
Michael, they're not -- the MISO payments are not designed to give you any kind of a greater return. I would point out that I think it's just important keep in the back of your mind, the book value of the Presque Isle Plant is still included in rate base.
Michael J. Lapides - Goldman Sachs Group Inc., Research Division
Got it. So in other words, any rate, any SSR from the MISO is basically serving as a substitute for what regulated rates otherwise would've already included had you not made the decision -- had your retirement decision kind of -- had you retired the unit?
Gale E. Klappa
Well, not exactly but I would look at it this way. Instead of the mines, the SSR payments from MISO, in essence, instead of the mines being a customer, MISO is being a customer but MISO is not necessarily going to pay you the return.
MISO will keep you whole on the operating cost and, perhaps, some capital.
Operator
Jon Arnold with Deutsche Bank, please state your question.
Jonathan P. Arnold - Deutsche Bank AG, Research Division
So quickly on the buyback. Did I hear you right that you've done $255-odd million?
Gale E. Klappa
Yes. $254.8 million, to put a fine point on it.
Jonathan P. Arnold - Deutsche Bank AG, Research Division
Okay. So if you do more or less the same in the fourth quarter that you did in the third, you will basically consume the $300 million through the end of 2013.
What's the time frame for potentially re-upping that?
Gale E. Klappa
Well, we have our normal meeting with our Board of Directors in December where we go through our 5-year plan, our 5-year capital spending plan, our 5-year projections on kilowatt hour sales growth, our 5-year projections on our capital structure. And it will be at that time, as we walk them through and get approval for our 5-year plan, it will be at that time when we will ask them for any changes, if any are warranted, in the share buyback authorization.
Jonathan P. Arnold - Deutsche Bank AG, Research Division
Okay, so if you were to tell, that would be a sort of fourth quarter earnings timing if there was a change?
Gale E. Klappa
That is correct.
Operator
Paul Patterson with Glenrock Associates, please state your question.
Paul Patterson - Glenrock Associates LLC
Just wanted to touch base on a few quick things. One was, Kit was asking about sales growth and I think you guys mentioned that you guys saw 2013 as being flat.
And to date, it's been about negative 0.8% or close to negative 1%. What...
Gale E. Klappa
Yes, negative 0.8%.
Paul Patterson - Glenrock Associates LLC
0.8%. Do you guys see a big increase this -- is there some timing issue?
What's going to end up going to happen in the fourth quarter to bring it up? Or could you just elaborate a little bit on that?
Gale E. Klappa
No. We're actually running a little bit lower than our projections on the electric sales side of the business.
Now I will say last fourth quarter, meaning the fourth quarter of 2012, the weather was mild. So on a weather-normal basis, you might see some bit of a small bit of an uptick on the electric side.
On the other side of the ledger though, we are seeing a little stronger natural gas sales, and I mentioned this in the prepared remarks, than we had anticipated. If you just look at actuals, we're up almost 20% in terms of natural gas deliveries over the first 9 months of the year ago, but we had a cold winter in the first quarter, kind of going on into April and May.
So on a weather-normal basis, we're up about 2% and we had not projected that kind of growth on the natural gas side. So there have been some compensating offsets here.
Paul Patterson - Glenrock Associates LLC
Okay. But on the electric side, it might be a little bit down, I guess, for 2013 versus last year?
Gale E. Klappa
On a weather-normal basis, I would expect a little bit down now for the calendar year. You are correct.
Paul Patterson - Glenrock Associates LLC
And then for the 3% to 5% that you mentioned, that was for several years out, is that correct?
Gale E. Klappa
0.3% to 0.5%.
Paul Patterson - Glenrock Associates LLC
That's what I meant. Sorry.
Boy, that would be a big difference, wouldn't it? What's the period of time we're talking about over -- sorry, if I missed.
What's that over that -- how many years is that over?
Gale E. Klappa
That would a rolling 5 years, so '14 to '18.
Paul Patterson - Glenrock Associates LLC
Okay, and then in terms of the rate case year and the impact on customers, you mentioned that there was a fuel decrease. And is that what was -- is that fuel decrease factored into what you expect to be that sort of mid-single digit that, I think, you guys were discussing?
Gale E. Klappa
No, and I apologized if I confused someone. The fuel decrease, the $30 million fuel decrease, we have just filed for that and would expect the commission to approve a fuel decrease in 2014.
And what I was really saying is that if fuel prices stay low and delivered cost of coal stays low and goes down a hair, we might get some help for that -- we might get some help from that in our in our filing for 2015 rates.
Paul Patterson - Glenrock Associates LLC
Okay. And then just back to electric sales growth and what you're seeing there.
What kind of GDP forecast are you guys looking at for those 5 years when you're coming up with that sort of 0.3% to 0.5%?
Gale E. Klappa
I'm looking at Scott Lauber, our Treasurer, here. But the way we -- what we do in essence, we kind of back in to a GDP.
We really do this bottoms up. We really look at customer segment by customer segment.
We look at the growth in that segment or lack thereof. So we don't start with an overarching GDP forecast.
But if I had to guess, seeing what we've seen so far, we're kind honing in on a 0.3% to 0.5% annual kilowatt hour sales growth. If I had to guess, that would be, and I'm guessing, about 1.5%, 2% GDP growth.
Paul Patterson - Glenrock Associates LLC
Okay. And then just finally, given the power price, the wholesale power price situation in MISO and given the transmission projects that we've seen being discussed and potentially may come about with respect to cross-border PJM versus MISO, congestion relief, the Seams issue, if you follow me?
Gale E. Klappa
Yes.
Paul Patterson - Glenrock Associates LLC
Do you guys see more opportunities to sell into higher-priced markets given sort of the dynamics that you guys have there? I mean, I know it doesn't make a big bottom-line impact to you guys but I do know that you're also sort of looking to provide relief to try to help out customers as much as possible in terms of off-systems sales.
Just wondering any thoughts sort of directionally about that or...
Gale E. Klappa
Well, I will be happy to give you my thought. Allen, who is very familiar with these issues as well, I'd be happy to have Allen pitching his thoughts.
I don't think near-term, certainly in the next 12 months, I wouldn't see any kind of major swing or major impact. However, if you look -- having said that, and again, I should remind everyone, energy sales for our -- sales into the MISO market over and above what our customers need, the revenue above cost from those sales go back to, as you pointed out, go back to reduced fuel costs for our customers.
So that margin, the difference between our revenue that we would get in the hourly energy market and our cost to producing that, that goes back to help customers. Now if you look at one of our line items on our statements, you'll see a big increase so far in the first 9 months of this year in our off-system sales.
That's because, already, we're seeing our Oak Creek units, our brand-new Oak Creek units, dispatched more often by MISO because of their fundamental efficiency. And we've had great availability at our Oak Creek units, our new Oak Creek units this year.
So even without any change in the Seams Agreements, even without any additional congestion relief between MISO and PJM, we're starting to see the benefits for our customers of the higher off-systems sales into the MISO market point given the fundamental efficiency of those Oak Creek units. Allen?
Allen L. Leverett
Yes. I guess, the only thing I would add, and maybe just picking on the fundamental efficiency point that Gale was making.
I mean, when you look at the collection of units that we have from a thermal-efficiency standpoint, in the case of the new Oak Creek units, one of the most efficient units in the country, the last data set I saw, Paul, it was in the top 10 for steam units in the United States. And if you certainly look within MISO at our other units and how competitive those are, we believe those are, if not in the top decile, in the next to the top decile in terms of efficiency.
So I would say, particularly if you got a higher-natural-gas-price environment, we would be very well positioned to bring some margin back for our customers, not for the owners, but certainly for our customers and that will be a wonderful thing.
Gale E. Klappa
So Paul, maybe we can get 5% energy sales growth after all.
Paul Patterson - Glenrock Associates LLC
Well, I mean, I just was wondering do you see any congestion relief between MISO and PJM? Or is that just something that's too far into the future for you guys at all.
I mean, it's like you said, it isn't a bottom line impact. I was just wondering since you guys are significant in the market, and we're also talking about wind increasing in MISO as well, just sort of...
Gale E. Klappa
Yes.
Allen L. Leverett
Right. Well, at this point, I don't see a lot of congestion relief between the 2 ISOs, between PJM and MISO.
But what we are seeing some diminution in the congestion sort of going south through our system, which I guess, ultimately, you don't have to go too far south to get to PJM. So hopefully, we'll will see some.
Gale E. Klappa
Well, ladies and gentlemen, that concludes our conference call for today. Thank you, again, for participating.
If you have any other questions, the famous Colleen Henderson will be available in our Investor Relations Office and her direct line is (414) 221-2592. Thank you very much, everybody.