Jonathan Thayer – EVP and CFO
Maureen Borkowski, Chairman, President and CEO, Ameren Transmission Company of Illinois
Martin Lyons, Ameren EVP and CFO, Ameren Corp.
Steve Fleishman - Wolfe Research
Exelon Corporation (EXC) Wolfe Research Power and Gas Leaders Conference Call September 25, 2013 3:00 PM ET
Steve Fleishman - Wolfe Research
For our final panel, we'll have Exelon speak and we have Jack Thayer. Jack is CFO of Exelon.
We have forward-looking statements included in this presentation. Please review them at your leisure.
Starting on Slide 3, just a quick overview. I think many of you know Exelon. We are one of the largest competitive integrateds in United States. We operate a fleet of 35 gigawatts; 19 of that nuclear, we operate the largest nuclear fleet in the United States. Have significant gas generation, approximately 10 gigawatts and we also have a large renewable portfolio, most of it contracted. And some of you may have seen we just completed recent financing earlier this week to finance certain of those assets on a project-level basis.
The Constellation side of our business. We have the largest competitive marketing arm in the United States. We serve more than 1 million customers. We have topnotch portfolio and risk management capabilities and extensive suite of products that we sell to both wholesale as well as retail, commercial, industrial customers.
And then finally, we are the operator of three large urban utilities; ComEd in Chicago, PECO in Philadelphia and BG&E in Baltimore, more than 6.6 million customers across those three utilities. Good jurisdictions, improving jurisdictions in the case of Illinois as well as Maryland and Pennsylvania continues to be one of the top regulatory jurisdictions in the U.S. We have a significant investment program there as well and we are also investing in significant transmission infrastructure across our utilities.
In terms of our investment profile, we invest across all parts of the value chain, starting with fuels through conventional generation, renewables at the customer level on the electric and gas utility side as well as on the competitive side through retail and beyond the meter.
We have a common approach in all of these businesses. We seek operational excellence. We are a process-driven company. We are very rigorous in terms of how we approach our activities. We are opportunistic, when it comes to growth and investment, but we're disciplined as well.
And then from a regulatory standpoint, we do believe that this is one of our core competencies. It's what allowed us to close the Constellation acquisition in 11 months. And it's also what's allowed us to along with partners like Ameren, State of Illinois as well as working in Maryland improved the regulatory relationships that we have to the benefit of customers and shareholders.
No question, we're in a very tough market environment, low gas prices, low capacity prices and transitioned away from coal and towards subsidized renewable has meaningfully impacted the economics of our merchant part of our business. We've responded in part by retiring certain assets. We have sharpened our focus on operations and cost management with the Constellation merger. Our synergies from that are $550 million that we expect to achieve in 2014 during the full year.
We're investing in significant amounts in our utilities, roughly $13.5 billion over the next five years, primarily around smart grid, infrastructure hardening and reliability investment. We'll invest approximately $2 billion in the merchant part of our business just to give you some context of the relationship between those investment avenues and agendas. Clearly, we're favoring reliable visible cash flows versus some of the volatility we've seen in the merchant side. Within the merchant itself, of that $2 billion a significant component of that will be in contracted renewables.
We do believe in a fundamental power recovery. We are positioning ourselves from a hedging standpoint to take advantage of that. We hedge on a ratable basis over a three year period, but we have the ability to hedge either ahead or behind ratable, depending on the opportunities we see. We have been hedging behind ratable, because we do believe that as we get closer to the deliver year, the impact of the coal retirements we've seen and the coal retirements we expect will cause prices to go higher in the markets we serve.
We have been an advocate and continue to be a strong advocate for competitive markets. We think it's the most effective way to meet our customers' energy needs. It brings value to the communities and we're working hard to bring value to the shareholders. We are looking extensively at incremental investments. Some of you may recall, we mentioned having balance sheet capacity on our recent investor call, after resizing the dividend and we're looking to deploy that and to scale it at $1 billion to $2 billion of debt capacity and invest that in opportunities that we see.
So just in closing, in terms of who we are and what we believe our value proposition is. We believe in clean energy and competitive markets, we are leading advocates in both. And we through our management model believe we are if not the finest, one of the finest operators in nuclear assets in the world. We have leading positions in our retail and wholesale platform. And as others are moving away on the financial side from this market, we believe there is incremental opportunity there to provide risk products to our wholesale, muni and co-op customers as well as commercial industrials customers.
And we have proven track record of operational excellence. We are a proven investor. Certain of our recent investments like the Boston Gen Acquisition, like Wolf Hollow in ERCOT, like the Navasota acquisition and John Deere Renewables have clearly delivered value for shareholders even against a challenging merchant environment.
And we are focused on value return to our shareholders through a sustainable dividend. By 2016 and 2017, utility will support the entirety of our dividend. We are looking at opportunities to continue to grow and redeploy capital and no mistaking with the significant generation position we have more than 200 terawatt hours of annual generation. We are certainly well-positioned to the extent that the power recovery that's embedded in our thesis does occur to benefit meaningfully to the upside.
Steve Fleishman - Wolfe Research
Just maybe then kick us off on the questions. Marty, maybe you could first talk about the transition out of the generation business into a pure utility. Where do you see as some of the [current] [ph] benefits for the company from that in terms of difference in how it's been run or financed going forward. And then Jack, I guess on the same side just kind of do you feel like the model both together make sense for you guys for the long-term. And how much have you looked that whether it makes sense or more of a pure-play model, Marty first?
Sure, Steve. First of all in terms of the merchant divestitures I mentioned in the prepared remarks, we expect that transaction will close later this year in the fourth quarter. Right now, we're seeking regulatory approval of both FERC and for the transfer of an Air Variance at the Pollution Control Board in Illinois. Again, expect to be in a position to close that transaction later this year and then transition to be in a fully rate-regulated operation.
For us, I think as I stated in the call, the prepared remarks, to transition away from the merchant operations for us, it has been a smaller part of our business. And in terms of earnings contributions, as power prices decline, became a smaller, smaller contributor. We believe that through the divestiture of that business it will greatly improve the predictability of our earnings and cash flows going forward.
As I hope you saw in the slide deck, I think we have an ambitious rate based growth plan ahead of us. And with it hope to produce predictable growth in both earnings and cash flows. And put ourselves in a business position to be able to increase the dividend prospectively, as that rate base and growth does turn into earnings growth.
I think the divestiture of the merchant business provides investors greater visibility, predictability in terms of those earnings and cash flows and in greater certainty in terms of the outcome of that rate base for a strategy. Certainly for us, the announced divestiture and the move towards closing, I think has allowed investors to refocus on not only the rate base growth plans we have but some of the improvement that has occurred in our regulatory jurisdictions, and I think folks are finding that to be attractive.
So as Marty mentioned, clearly we're the product of the assets that we own. In Ameren's case, the merchant was a smaller part of their business, with respect to Exelon and the large nuclear fleet as well as the ownership for the Constellation business that has, is and has been a meaningful part of the story at Exelon.
And from a scale perspective I think it would make it challenging to pivot to a purely regulated model. That said, we do see real value in this integrated model. We think it creates roughly $2.5 billion of value in part because embedding our constellation business as part of an integrated utility, affords us balance sheet and investment grade rating that would be challenging to procure on a purely merchant standalone basis.
You marry that up with the importance of investment grade rating, when you're operating the largest nuclear fleet, and we think that that collectively is a strong argument for the structure certainly that we have, but we appreciate why others within different circumstances may perceive a purely merchant or a purely regulated model.
I would say that there is a measure of countercyclicality to each of these businesses. And most importantly the opportunities to redeploy free cash flow from either business, where we see incremental opportunities. So as I mentioned in my prepared remarks, we will be taking $13.5 billion of free cash flow and investments proceeds from our merchant business and redeploying that into the regulated side of our business, meaningfully rebalancing the earnings and contribution that we see.
With that said, to the extent that after this investment phase as the utility is generating significant cash flow, there may be the opportunity to redeploy that into growth at the merchant. And in effect, we just go balance our investment where we see the best and highest return. And that's been a very good model for us to spike the economic headwinds that have come with the shale gas revolution.
Steve Fleishman - Wolfe Research
A question for Maureen, maybe you could give us a little bit of sense, first on the Illinois Rivers project and maybe all of your projects, multi-value, I assume that means reliability, maybe renewables, power market, benefits`. Just maybe give a little flavor of what the lines will do to the region? And then also a little bit on resolving the missing pieces on Illinois Rivers, is it a risk that we get stuck with missing pieces and that issue can be resolved?
With regards to the multi-value project, I mean that's actually a term that's defined by the Midwest ISO in their tariff. And it does involve meeting the renewable portfolio standards across the MISO footprint as well as addressing reliability needs and congestion relief. It increases import capabilities. There's a whole host of benefits that these multi-value projects offer.
Specific to Illinois Rivers, we definitely will see local benefits as well as the regional benefits on which these projects were approved. The benefit to the State of Illinois include, helping them meet their renewable portfolio standards, supporting some of the renewable developments, that's already going on in Illinois. But there are also significant reliability benefits to these projects. In parts, that's why we have so many substations associated with the Illinois Rivers project, its 400 miles line and 10 substations. And that really is what allows you to get those local reliability benefits.
With regard to the ICC [Illinois Commerce Commission] order and our request for rehearing, first and foremost, the ICC approved the need for the project. They completely understand that the only way you're going to get the benefit from that project is to have a continuous path across the State of Illinois of 345,000 volt line and to have those substations in place, because it's the substations that connect to the existing system that allow you to get the local benefits.
So really the issues are more about routing and location, specifically with regard to the two line segments that were not approved. There was some back and forth in the case about, whether the line should be routed through the substation that we proposed or if it might be better to route the line through a different substation because it appeared that that might result in fewer miles of line in total, marginally fewer, but the objective of the Commission is to approve the most cost effective solution that gets you the benefits you want.
So as a part of the rehearing process and we do expect that the ICC will grant our rehearing request. We'll put additional evidence on the record stating why we believe that the solution we proposed is technically the best solution to get the benefits for the customers.
The issue with regard to the substations was really about whether or not Ameren Transmission Company of Illinois was making adequate use of the existing footprint of the existing Ameren Illinois Company substation. The new 345 kV substations will connect to the existing substations that Ameren Illinois Company already owns, and the commission I think was hoping that we were being conservative in making the best use of the real estate that Ameren Illinois Company already owned.
And again, what we plan to do is to put additional evidence on the record demonstrating the actual layout of facilities with regard to both Ameren Illinois Company existing subs and the additional adjoining properties that we intend to purchase, so that really is what the issue is. It's all about location and routing and real estate, so we expect those issues to be resolved, and the commission will rule on the rehearing request in March of next year.
Steve Fleishman - Wolfe Research
Just one clarification on the -- you mentioned reliability in the RPS, but on the congestion benefit, Dynegy for example talks about difficulty getting power to any hubs from Southern Illinois. Is there something that will meaningfully change that or that doesn't really do much there?
The Illinois Rivers project will definitely help with some congestion issues. There are additional projects that Ameren has proposed to the Midwest ISO that are specifically targeted at reducing congestion in Southern Illinois. Those projects are still working their way through the Midwest ISO transmission expansion plan, but certainly that would provide additional opportunity for investment over and above the investment that we've already identified.
Steve Fleishman - Wolfe Research
Jack and maybe Marty as well, one thing I know, you talked a little bit about some pressure on nuclear economics, at least like the smaller single-unit type plants, we have Vermont Yankee shutdown got announced, I think probably since we last talked. What's your sense on the ability for these single-units plants to make it nuclear as a whole? I assume the big plants are going to still be very economic, but latest thoughts there?
I'd say it’s very [asset to market] (ph). So Steve, as you mentioned on the asset side, aging, smaller, single-site nukes are coming under significant cost pressures depending on the market that they are in. So, of these within our fleet, we have a pre-existing agreement in New Jersey to shut down Oyster Creek in 2019.
Others that are single-site and small are plants like our [indiscernible] asset that has a PPA that concludes in the middle of 2014. And New York, particularly upstate New York in the absence of a meaningful capacity market and with a low power price regime makes the viability of that asset something we have to explore.
Depending on the market, you can have some unexpected challenged assets as well. If you look at our -- well on the topic of Southern Illinois, if you look at our Clinton asset, which is very large, one of our most modern nuclear reactors, one of our best operating in fact, last time it ran breaker to breaker. It's about 1,100 megawatts, it's in Southern Illinois. It's in the MISO market without a meaningful capacity market, and it's competing against wind overnights, which is printing negative prices for healthy parts of the year such that we are effectively paying to run at certain times of the day.
Our asset runs 95% of the time. It's being displaced by assets that run at most 30% to 40% of the time. And so, our hope is that as we discuss the economics and viability of these assets, the important role that they play in the ISOs in which they participate start to be both recognized as well as compensated, but in the absence of that we're getting to the point where we're having to make some hard choices.
Clinton, we've gone to annual refueling. It's a more efficient way to burn the plant, but it means it’s running less frequently. We are taking other actions, but coal has felt the brunt of subsidized generation and shale gas, nuclear is next. I think nuclear [apart] (ph) for some select instances will continue to play an important role, but it likely requires us to rethink how we're being compensated for the reliability we provide.
Steve Fleishman - Wolfe Research
Any thoughts, Callaway is obviously is regulated, but is it -- any of those issues have implications for Callaway?
So I think, you are absolutely right, Steve, we have one nuclear plant, frankly an excellent operator. Now, we are currently are a bit over its life, but it's been a very well run single-unit plant, and so we certainly have that going for us, and as you mentioned it’s rate regulated. So, we're -- certainly having been in the merchant business, we are very confident of the factors that Jack just spoke to around the challenging economics on a plant by plant basis composed by both energy and capacity market conditions, while our Callaway plant is rate regulated as we look around, it certainly keeps us laser focused on cost control at that unit and making sure we do everything that we can to continue to operate in an excellent fashion and to make sure we do so in an efficient way.
Steve Fleishman - Wolfe Research
We'll open to questions from the audience. Micahel?
Two related questions for Ameren, the Illinois Rivers project, is it possible to break that up into smaller parts if you do not get full rights of way for the whole project? And secondly, if the FERC returned discussion that we have in New England, I’ve seen in California, goes to your territories and there is a [risk] (ph) to 12%, would you have flexibility to roll back on some of your transmission investments, and has there been some discussions in Illinois about maybe 12% is too high, et cetera?
With regard to the first question about Illinois Rivers, we are actually moving out currently building the segments that have already been approved. While the first phase of that is acquiring the right of way to do that, which is we're in the progress of doing and we expect a full range of construction activities in 2014.
In the event, first of all, I think it's highly unlikely that we won't have a contiguous 345,000 path across the state of Illinois, because the commission in their discussion that immediately preceded their vote on the August 20 order made it very clear that they understand that the only way to receive the full benefits from the project is to complete the project.
So, I think there is a clear understanding of that. But in any event, we certainly are able to put segments of the project in service without having the entire thing in service. Our plan is actually to stage the in-service dates of the line segments and the substations, so that some will be put in service in 2016, some in 2017, and so on.
With regard to the question about the ROE, we are certainly following the case at FERC about the Northeast closely. There has not, at this point in time, been any moment, and it wouldn't just be the state of Illinois, it would really be within the Midwest ISO, because the 12.38% return on equity that we earned on our transmission project is the umbrella rate that's granted under the Midwest ISO tariff.
So, in all likelihood, there would have to be a movement of someone to complain that that rate was too high, which would trigger a regulatory proceeding. The regulatory proceeding in the Northeast has gone on for some time, and they are not really expecting a final ruling until next year. I actually saw some encouraging news in the administrative law judge's proposed order at FERC. I think the message that he was sending to the commissioners was I am held hostage by President. As an administrative law judge, I can't deviate from Commission President.
But he saw some merit to the arguments that experts in that case had made that maybe the artificial depression at interest rate isn't really working under this DCS analysis, and you may want to consider other options, at least that's what I read into it. That being said, in the event that there was some successful challenge to MISOs 12.38% return on equity, we did not -- when we went forward with seeking rate incentives from FERC for the Illinois Rivers project and our other projects, Mark Twain and Spoon River, we didn't request any kickers to the return on equity. We were satisfied with the 12.38% to the extent that base rate was lowered, we would be eligible to go back and seek additional incentives on the ROE at FERC.
Given the recent difficulty that Ron Binz had before the Congressional Committee of his appointment to head FERC, I wonder if any of the issues raised by the people who opposed him affect the transmission rulings that you all and the rest of the industry seem to be building a case for in terms of all presentations to investors about how wonderful it is to put FERC regulated things ahead of state regulated.
I don't know that I can speak to exactly what the objections were, but I do believe that both among the existing FERC commissioners and among Congress, they all understand that transmission is absolutely essential to having a cohesive energy policy in the United States.
And that in fact with everything that's going in the natural gas markets and with environmental restrictions that more transmission just gives you more resilience and more opportunity to have vibrant competitive electric markets.
So, my sense is that no matter who ultimately ends up being the next FERC Commissioner and/or Chairman, that inherent policy I really do believe, is a a belief that they all share, that they need to establish policies that promote continued transmission investment.
Incentive of ROEs are among those policies?
Yes. That's one of the options that's still out there and available.
This question is for Marty. Regarding the triple processes for the Dynegy transaction, has there been any issues raised by MISO or other interveners or at FERC around market-powered issues at all so far? I know that's an ongoing process, but have you seen anything or anyone sort of raised any flags or anything you have seen regarding that?
No. I haven't seen anything recent on market power. You may recall that back in July, FERC did request that we provide some supplemental analysis around our market power study, which we provided within a week, and really did not change the overall conclusions of the market power analysis that was originally supplied. Since that time, we've heard no real noise around that subject.
Also on MISO, I guess, we've had a couple of panels talk about how tight the generation situation could be getting in MISO in a couple of years. And I am just sort of wondering, I guess, Exelon obviously has got sort of your own little island in the middle of MISO that could be impacted indirectly. And then, Ameren here selling assets when people are saying in a couple of years it's going to be really tight, just sort of any reactions to that upcoming situation?
From our point of view, I think if you go back over time and you look at some of the investor presentations we've made, we don't disagree that over time, we expect the market to tighten in, but for us the timing and the amount of that tightening and importantly the impact on energy capacity prices is somewhat uncertain. As I said earlier, well, that's expected, we expect that to occur, I think like many in the merchant generation space. For us strategically, we believe it's time to move on, and to be honest with you, it would be a smaller part of business as I mentioned before, and I think a distraction from our regulated investment in growth story, and for us strategically it was certainly time to move on.
I guess from our perspective, clearly we're in, we believe in capacity markets. One of the elements that's adding to the central reserve margin issue within MISO is that certain of its assets are bidding into PJM auctions and earning economic rents that they can't otherwise earn in MISO. So, I think there is probably from a -- to my earlier comments about our Clinton asset as well as others in there and then the behavior of certain participants in MISO, in their participation in the PJM auction process, there is probably an opportunity to improve the compensation for that capacity that keeps those megawatts where they reside and keeps those assets online.
Just a question for Ameren, the transmission project that you have after Illinois Rivers, are those Ameren's for sure or are those susceptible to Order 1,000 process?
The Spoon River and Mark Twain projects, which are Ameren Transmission Company of Illinois as well as I think we have in the past listed five different reliability projects in Illinois that are Ameren Illinois Company projects, those are all grandfathered in under Order 1,000.
Just a question for Jack, there is something I want to clarify if I understood you correctly, you said that under the integrated model, you see $2.5 billion revenue, could you explain that?
So, your question is around the importance of the regulated part of our business in sustaining our investment grade. As you think about, to the extent that we did not have that meaningful component of our business that was regulated, we will be held to higher FFO-to-debt standards and I say that as a proxy for our CF-to-debt and others that are used at other agencies. And to the extent that we had -- and you may recall, we have roughly $6 billion worth of credit lines where we’d try and go secure that in the market, where we’d try to use an asset-backed financial structure to support the liquidity required by both our constellation business but also our nuclear assets.
We think the price of all those -- the value [disruption] (ph) equates to $2.5 billion positive that we see from this integrated model, and hence our strong belief in the mutually reinforcing nature of the two parts of our business given their collective scale of both, not only would it be unhealthy for us to try and separate them, but economically it wouldn't be advantageous.
Jack, just on PJM, the speaker yesterday mentioned some of the things that PJM is reviewing on fixing the auction for next year. Things like MOPR changes, imports, (inaudible) and things like that, what percent from the likelihood that these will get done and implemented for the auction of next year?
So, I would liken our experience with the capacity market, and PJM is a bit akin to the game of whack-a-mole at Dave & Buster’s. Of the moles that we've had to whack back in their holes, first was demand response. We've worked to refine the definition around what qualified as well as the quantity such that it is being paid for the service that it's providing.
Subsequent to that, on the MOPR and subsidized generation that has been a big issue, we had a large stakeholder process last year to refine that and that was done within a 12-month timeframe, and mitigated some of the subsidized jobs related contracting behavior of certain of the states or at least made it a factor on how the auction cleared.
I think as you mentioned imports have been, roughly 8,000 megawatts of imports cleared in this recent auction. Imports has been a huge issue as well as in effect that the free optionality of newbuilds bidding in and then having the ability to acquire in subsequent auctions, the capacity they’ve been in and even in fact profit from that.
So, in this stakeholder process, we are working to both define what's actually -- what is PJM actually capable of importing, how do we take the profit and send it out of bidding behavior, and how do we weave in performance elements whether it's transmission construction to support imports or newbuild construction as well as certain credit requirements to improve delivery of in effect what exactly is RPM designed to do.
It's designed to promote reliability, and we've have seen with meaningful coal retirements and expected coal retirements as well as we've seen replacement of base-load iron in the ground with the contractual right to turn someone off for the prospect of newbuild generation that may or may not be there, and we will see the impact of this on the back of 2015 with retirements, and I think PJM and stakeholders appreciate the importance reliability is to this equation, and so my sense is that there is a fairly good chance that the stakeholder process works it's way through in time for next auction.
Steve Fleishman - Wolfe Research
Are there questions from the audience. One last question.
This is for Jack. So Jack when you look at -- you said you want to invest as much money in your utilities as possible. I imagine if there is a certain limit to that that you could just do, but you have free cash flow, you guys have been been paying down debt and stuff that's been freed up from other auctions, what’s kind of the next step on that and when do you sort of look to give a plan?
So, let me address, clearly we're very mindful. I liked Marty’s slide of showing where Ameren's rates are relative to others, and clearly we're mindful of where our rates are relative to others. I think in part that's what is driving the significant investment in ComEd. We have very advantaged customer rates there. There is an important place increasingly so because of cell phones and the role they play in our lives.
On reliability, there is opportunity around smart grid to improve the operations of the utility as well as reduced costs. And so, you see us spending meaningful dollars at ComEd. You see us at BGE spending meaningful dollars in part because of the age of those assets. We had depreciated those assets that was in the form of rates. So if you compare our PECO rates to other ComEd or to BGE, even post all of the spend that's going into both, they will still be lower than PECOs rates.
But some of it in an absolute basis, it's the absolute increase that people are focused on. You have to blend it in over time, and most importantly people focus on the total bill, and power prices have come down meaningfully, which we believe married up with the importance of reliability that our customers are expressing to their various stakeholders that represent them, presents a real opportunity for us to meaningfully invest. And as we get through this five-year period, will there be subsequent significant investment on that scale, unclear, but we feel good about that.
I think one more question, but on retail, you guys talked about competition has increased dramatically, and I think you often say that we need a hurricane to come in and kind of get rid of it?
Let the record state, I never advocate a hurricane coming anyway.
I think it would be interesting if it came in Illinois?
That would be a Six Sigma event truly.
But just we have recently seen like PJM have these sort of spiky load days, you saw demand and response kick in and what not, has that done anything to sort of takeaway or hurt any of those (inaudible) retailers?
I would say two things, there are two meaningful elements that are challenging that retail business. Number one is from a -- well, at its core, the absence of volatility. The volatility that you highlighted with the $1,000 print in PJM during the summer, we just haven't seen a lot of that.
So that's inducing our customers. This is really an insurance product against energy volatility. We have learned that when their bills come due, there is a better price and they get to save money on the next one, and then that now happened for say the last three to five years. Well, we're at the bottom or at least I hope we're at the bottom, so they're waiting for a lower price that's not going to come, but there is not that volatility that's inducing them to see the value of locking in a fixed price for an extended period of time.
The flip side of that is the market participants have been able in this low volatility environment to not fully cost the risk they are ensuring. I believe and it's our fundamental view that with the retirement of the coal assets that you're going to see, volatility has to go up. You're going to see more of those high price days. You're going to be calling demand response more frequently so that it's not a free option, and we think all of that will be good for retail margins returning back to say that $2 to $4 megawatt hour, which would be an improvement from where we are today.
Steve Fleishman - Wolfe Research
Good. Well, [congratulate] (ph) our panel. Thank you very much.
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