Talen Energy Corp (TLN) 2015 Q4 法說會逐字稿

Good morning and welcome to the Talen Energy fourth quarter and year-end results conference call. (Operator Instructions)

Please note this event is being recorded.

I would now like to turn the conference over to Andy Ludwig, Director of Investor Relations. Mr. Ludwig, please go ahead.

Thanks, Keith. And good morning everyone. Thank you for joining the Talen Energy conference call to discuss fourth quarter and year-end 2015 results. Today's presentation is being webcast and we are providing slides of the presentation on our website at talenenergy.com.

This presentation may contain forward-looking statements and we encourage you to review our filings with the SEC to learn more about certain risk factors that could cause actual results to differ from these forward-looking statements. This presentation also will contain reference to non-GAAP financial information that we will use to measure our business. You can find the reconciliation between the non-GAAP financial measures we use and the most directly comparable GAAP measures in the schedules to our earnings release and in the presentation that we've posted on our website. I will now turn the call over to Paul Farr, Talen Energy President and CEO.

Thanks, Andy, and good morning, everyone. Joining me on the call today with prepared remarks Jeremy McGuire, our CFO; as well as Joe Hopf, our Chief Commercial Officer. Our CNO, Tim Rausch, had some commitments up at the plant today and could not join us as we're in final preparation for the Unit 1 refueling outage that starts in a couple weeks.

We'll follow our normal format on the call today as outlined on the agenda on slide three. Before I jump into the slides though, let me make a few high level remarks on some important near-term drivers. The sector obviously continues to face challenges from low prices, low demand growth and challenges from certain market participants looking for subsidies from utility customers for their uneconomic plants. We are actively engaged on a number of fronts with respect to both the lack of economic merits of those contracts vis-a-vis consumers as well as with FERC given the preferential nature of those contracts between affiliates.

In terms of the Company response to low commodity prices, we continue to focus significantly on cost reduction, both OEM and CapEx, as well as the risk profile of our portfolio and our balance sheet. We are well underway with the Brunner Island co-fire project and are actually looking to bring Brunner Island Unit 3 capability online for that capacity as early as this August.

As I'll get to later in my remarks we're continuing to look at the merits of a comparable project at Montour. We can look at making those investments and potentially take other actions with respect to our asset mix and the balance sheet even in a capital constrained environment given the $1.2 billion in after-tax sales proceeds from announced and closed asset sales, strong free cash flow and significant improvements in our effective cash tax rate looking forward a number of years. Jeremy will discuss capital allocation including the potential for liability management in his remarks.

Let's move into the slides, as I'm certain in the Q&A session we'll dialogue more on these and other topics. 2015 was an extremely busy and successful year at Talen Energy from many perspectives. We were highly successful in M&A, cost cutting, integrating new assets, implementing new systems and generally launching the new company.

A number of our successes are outlined on page four. We completed the spin merge transaction in June, captured synergies in 2015 significantly in excess of estimates provided at the spin announcement and increased future synergy expectations; completed the 2,500 megawatt MACH Gen CCGT acquisition in early November; executed sales transactions with three different counterparties for our FERC mitigation assets at very attractive prices and completed two of these sales earlier this year

with an expectation we'll close on the sale of the PA hydro assets in late March; sold the renewables business; and surpassed the midpoints of the increased guidance targets in adjusted EBITDA and free cash flow that we provided on our Q3 call, driven by strong generation performance and the increased synergies we captured as well as cuts in CapEx.

Our nuclear and PJM gas assets had very strong performance this past year. Susquehanna delivered record output in 2015 of almost 21 million megawatt hours at a 94% capacity factor, and spark spreads remained very strong in PJM. I will address the asset performance more in a few minutes.

As outlined on the right-hand side of the slide, the strong fleet performance and our continuing focus on efficiency drove 2015 adjusted EBITDA and free cash flow performance ahead of the midpoints for these metrics that we guided to on the Q3 call. I'm extremely proud of the entire Talen Energy team for delivering this performance in a difficult commodity environment in the face of an extremely mild winter.

Turning now to 2016, on slide five, we've outlined our guidance targets for adjusted EBITDA and free cash flow at the very top of the slide. We forecast a midpoint adjusted EBITDA of $735 million and a midpoint for free cash flow of $350 million.

I'd like to highlight that we have incorporated the very mild start to the year and the end of January forwards into this forecast. As an offset to the gross margin challenges, we've cut further into O&M spending and meaningfully into what our CapEx is for the year given what our prior estimates were.

Our tax team has also done a great job of implementing plans to maximize benefits of bonus depreciation and accelerated use of the MACH Gen tax attributes. While we executed strongly on a number of strategic initiatives in 2015, we continue to have quite a meaningful list of value drivers that we're focused on as we're now in 2016.

We've discussed many of these with you in the past, but I'd like to highlight that we're holding schedule on the Brunner Island co-fire project with an expectation that the full capability will be in place by year-end 2016 and, as I mentioned earlier, Unit 3's capability as early as August. We continue to assess the economic merits of coal firing the 1,500 megawatt Montour plant and look forward to finalizing the cost estimates and the most optimal pipeline interconnection in the near future.

And at Keystone and Conemaugh, activity is well underway with the other owners to improve the cost profile of those plants. The group is currently in the process of evaluating the movement to a four-year outage cycle comparable to the rest of our coal fleet.

Moving to the right hand portion of the slide, we're fully on track to close the sale of the hydros by the end of Q1 at a very attractive valuation. Embedded in our 2016 guidance are significant reductions in both O&M spending and CapEx as mentioned previously, and we continue to look for ways to reduce costs while keeping plant reliability levels high.

I will talk about Harquahala on the next slide but we have found ways to improve its short-term economics as we look for a more permanent path to value. On the tax front we expect to be an AMT payer for the foreseeable future given bonus depreciation, our ability to optimize the use of the tax gen attributes and the potential tax benefits associated with exiting Montana.

Let's turn to slide six now for updates on Harquahala and the potential Montour co-fire project.

As natural gas prices remain low and coal fired generation faces numerous environmental challenges, we see Harquahala being able to deliver significant value in the WECC. We continue to evaluate various alternatives with respect to the facility including PPAs or potential sales of units to third parties as a path to value creation.

We have refined the estimated economics of relocating the units and have worked with two different parties on these estimates. Hence, the range you see of $315 a kilowatt to $500 a kilowatt, the latter of which is the upper end of the range of our original estimate or the number for our original estimate.

We'll continue to simultaneously evaluate both paths to value with expected final action by the end of this year. Based on current estimates, we also see potential value in executing a coal firing project at the 1,500 megawatt Montour facility which would allow us to achieve a 9,400 heat rate on those units if fully fired on gas.

We're evaluating interconnection options for the roughly 15 mile spur with multiple midstream companies to Leidy, MARC I and Transco. Our current baseline assumption would be to have a third-party pipeline company build the pipeline spur, allowing us to preserve capital, and we're already in discussions on that front. If we ultimately do decide to proceed, construction is expected to take 18 to 24 months.

Now, let's turn to page eight for an operational review. The standout performance from Susquehanna was complemented by excellent availability from the gas fired fleet. Our Pennsylvania coal assets continue to be negatively impacted by very low gas prices especially given their location atop the Marcellus, as well as by significant transmission work that continues to the south of those units to alleviate north/south congestion into Baltimore.

As local gas basis improves and we return to more normal congestion patterns when the transmission work is completed, with an expected completion by mid-2017, we would expect our coal economics in Pennsylvania to improve, with the improvement in those economics partially offset by negative basis impacts to the Maryland assets. Furthermore, the gas co-fire project at Brunner Island will materially improve the economics of that plant should gas remain lower for longer.

Susquehanna's output of 18.5 million megawatt hours shown on this slide reflects our 90% ownership in the plant versus the almost 21 million megawatt hours that I referenced earlier which is 100% of the plant's output. I want to thank Tim and his entire team for the excellent performance this past year and for their continued focus on safety and reliability as well as cost in this difficult environment.

As shown on the upper right chart as CP comes into play beginning this year -- mid this year, we have continued our very strong track record of forced outage experience in the east at the same time as we have further trimmed costs. While our safety experience compares favorably to the utility average, we are not satisfied with the recent trend and are increasing our focus on safety to reduce our incident rate.

I fully expect that with this focus from the operations teams, we'll improve upon our performance in this area as we move into 2016 and beyond.

Moving to slide nine, between the east and west, we have a tale of two tapes here in terms of forward pricing: continued spark spread expansion at PJM for 2016 and 2017 given lower regional gas prices; and spark spreads declines in Texas given poor weather, lower Henry hub gas pricing, lesser liquidity and the impact of wind on the system. We are now over four years removed from the last meaningful summer weather that we have had in Texas.

In terms of market outlook, we haven't seen anything surprising out of PJM sensitivity data, and demand growth remain muted. The movement to 100% CP in the 2020/2021 capacity auction should cause prices to clear higher than we experienced last year and likely where prices will clear this May for the 2019/2020 performance year.

While we were clearly disappointed with the Supreme Court's decision on DR and continue to believe at that DR is in fact a retail product, the ruling itself will have limited impact on the one remaining CP auction that is 80% CP and 20% base. Further, given the latitude the Supreme Court provided to FERC, we think that bodes well for the outcomes of the court's review of the Maryland and New Jersey litigation which was argued yesterday in front of the court.

On the ERCOT front, I think the update is relatively straightforward. We're not sure how the solid fuel plants in this market can continue to deal with low and declining gas prices as well as enhanced environmental regulations and make the math work to remain open. We can't make the math work on new build in this renewable intensive market that has no capacity revenue support, and the assets that have relatively attractive heat rates have sold for a fraction of replacement value.

The extension of the renewable tax credits also doesn't help the supply dynamic. But as the more challenged units make the hard decision to close and we return to a more normal weather pattern, we expect improved economics from our Texas units.

Turning to the northeast markets on slide 10, New York spark spreads are flat to up for 2016 and 2017. Closure of challenged solid fuel plants should continue to bolster the energy and capacity prices as we move through time.

In New England, spreads for 2016 and 2017 are down 10% or more year-on-year driven by gas prices remaining higher at Algonquin and recent sparks delivering a little lower than historical levels which is driving down the outer year curves. We would expect the outer year sparks to expand due to additional Algonquin pipeline capacity forecasted to be in service by November 2016.

The relatively strong capacity prices have attracted 900 megawatts of net new supply over the prior auction, driven by the still relatively strong capacity pricing in combination with potential near-term impacts of bonus depreciation.

On slide 11, we provide our hedge levels and pricing along with sensitivities to heat rates, power prices and gas prices. Given the very temperate fall and winter weather, the market never experienced the normal seasonal rally that we traditionally hedge into for the prompt year. That said, we're comfortable with our hedge levels for 2016 within the context of our guidance especially given that our eastern solid fuel plants are hedged at almost 75%.

Looking at our portfolio's average hedged prices, you will notice a few changes from our last update. Average 2016 hedged sparks reflect a decline in the east, however, that's not from declining prices. It's a result of hedging some of our higher heat rate plants in the off-peak which have seen relatively high spark spreads in the last quarter versus historic levels.

Similarly, in ERCOT, we have layered some off-peak hedges which lowered the average price. Historically, we have been focused on hedging on-peak hours. I will now turn the call over to Jeremy for a more in-depth review of the financial highlights before moving into Q&A. Jeremy?

Thanks, Paul. On slide 13, we show how fourth quarter results compared to the same quarter in 2014. Margins were higher driven mostly by the addition of RJS, higher PJM capacity prices and improved spark spreads. O&M was a bit higher due principally to the addition of RJS with a partial offset from synergies and lower outage costs.

The next slide shows the same comparison of 2014 and 2015 adjusted EBITDA on a full year basis. Similar to the quarter-over-quarter comparison on the prior page, the biggest driver was the addition of RJS. 2015 also experienced higher realized energy prices, increased spark spreads and improved nuclear availability as compared to 2014. So negative drivers were lower overall capacity revenues and lower volumes on full requirements sales contracts.

In 2014, we also experienced the effects of the polar vortex and realized gains on certain commodity positions, both representing margins not repeated in 2015. The increased O&M from RJS was generally offset by synergy attainment and lower outage expenses.

Let's turn to slide 15. Here we provide some additional detail on the 2016 guidance introduced by Paul. The top chart shows how our 2016 adjusted EBITDA range compares to our 2015 performance. After removing the 2015 contribution from assets sold or under agreement to be sold as part of our FERC required market mitigation, the biggest change is based on an expectation that overall margins will be lower in 2016.

I would also point out that our 2016 adjusted EBITDA and adjusted free cash flow guidance ranges excludes contributions from mitigation assets sold or currently under agreement to be sold. Of course, those assets will have an impact on our 2016 results. As we progress through the year and provide quarterly performance updates, we will show the adjustments for those assets, so you will be able to tie actual performance to guidance.

On this page, we have also provided additional detail to bridge from the adjusted EBITDA range to the adjusted free cash flow range. One item worth spending a little time on is the positive contribution from cash taxes. There are a couple of items in play.

First, overall we are expecting to pay cash taxes in 2016 because of the taxable gains on the asset sales. You will recall that we announced gross proceeds of $1.5 billion and net after-tax proceeds of $1.2 billion. The taxes payable on the asset sales are essentially charged against gross proceeds and are therefore not part of adjusted free cash flow. The extension of bonus depreciation and an ability to use acquired NOLs has allowed us to offset a significant portion of the taxable income created by the asset sales.

Putting aside the taxable income created by the asset sales, we would otherwise have been an AMT payer with de minimis cash taxes in 2016. As Paul mentioned earlier, with bonus depreciation and our tax attributes, this is a position we expect to be in for the foreseeable future.

Slide 16 brings bridges our formal 2016 guidance ranges initiated today from the point estimates we provided last June. Consistent with Paul's prior discussion of our key markets, margins are down. We have responded to continued declines in margins and expected margins with plans to reduce O&M by $70 million and CapEx by $45 million in 2016. As I discussed on the prior page, bonus depreciation and our tax attributes have allowed us to offset a significant amount of taxable income from the asset sales.

One other item I would point out on this page is the negative $15 million thin red bar on the adjusted free cash flow graph labeled change in presentation basis. When we discussed adjusted free cash flow with you previously, we carved out all growth capital. As a matter of accounting convention, we allocate a portion of our corporate interest costs to major capital projects which means it is capitalized and not deducted as interest expense.

On an adjusted free cash flow basis, you get to the same spot as capitalized interest comes out through CapEx except when it comes to growth capital that is carved out. Going forward, we will only carve out growth capital that is represented by actual amounts expended on a project and not the capitalized interest. The associated capitalized interest will remain as CapEx; it's just not carved out. We think this is a better presentation of adjusted free cash flow.

Moving to slide 17, we have provided an update on our planned capital sources and uses. We currently anticipate being in a very strong cash position at the end of 2016 and expect to keep well within our leverage lane on a net debt basis notwithstanding the pressure on margins. The capital priorities remain generally the same as we have consistently articulated. However, our expected cash position is a bit unique. We continue to consider various alternatives to drive value by deploying this cash.

The secondary trading performance of certain of our debt issues has us looking harder at liability management strategies. I will touch on that more on the next page.

I would just say that we are in a temporary holding pattern on final capital allocation decisions for 2016 until, one, we close the sale of East hydro and get the cash; and, two, the Montour gas co-fire project evaluation is complete.

Okay. Let's move to my last page before I turn it back over to Paul. On slide 18, we have included a table with recent quotes on our unsecured debt tranches. Most of them are quoted at significant discounts to par. It is certainly not lost on us that the rout in the energy sector has not only affected stock prices but credit spreads as well. And much like our stock performance, we think the decline in our bond prices is overdone.

As I said, we have not made any final decisions on capital allocation, but the dislocation in our bonds definitely has our attention. With that, I'll turn it back to Paul for some closing remarks.

Thanks, Jeremy. On slide 19, we summarize some of the highlights that what we view as the strengths of the Company. I'm not going to go through this line by line, but let me say that clearly, nothing has changed from our perspective on strategy from when we began this journey. Our assets and the risk profile that come from those assets need to be completely aligned with our balance sheet and we think we have accomplished that objective.

Our assets are in fundamentally strong markets, many of which are or almost all of which are supported by -- except in the Texas instance and Montana -- capacity constructs that have improved over time. The MACH Gen acquisition and the gas co-firing capability being implemented at Brunner will greatly reduce the coal fired economic and environmental exposures thus reducing risk to our portfolio.

The asset sale proceeds, liquidity and strategic execution capability give us great opportunity to further drive value for share owners and we're going to remain disciplined in our deployment of capital including looking at opportunities on the debt side of the balance sheet as Jeremy just mentioned. And while we focus on strategy, we're obviously going to continue to look for ways to continue to drive costs out and keep reliability up. And I think we've created a very strong track record of doing just that in our relatively short period of time being a public company.

Operator, with that by way of prepared remarks, we're now ready to take questions.

(Operator Instructions) And the first question comes from Ali Ahga with SunTrust.

Thank you. Good morning.

Good morning, Ali.

Morning. Paul or Jeremy, as you look at the 2016 guidance today and, you know, it's a pretty wide range out there, but if you look at where the forward curves out, I mean, directionally can you give us a sense of where they're putting you? Is it at the lower half or the upper half of that range?

I think I'm pretty certain, Ali, that I mentioned that we used the very end of January forwards; so I would say we're right at the midpoint as we sit today, that we're very comfortable. We embedded actually January actuals where we think we're going to come out in February, the end of January curves; and as Jeremy indicated that doesn't include any contribution from the mitigated assets, the two that have already been sold or hydro that will occur end of March. So that's -- I'll call it run-rate based on the portfolio post mitigation. So we're very comfortable with the midpoint as we sit today.

Okay. And then on your cash sources and uses slide, I think it demonstrates about $611 million of cash that's not been allocated between sources and uses. In the ideal scenario, how much cash do you believe should be sitting on the balance sheet by the end of the year? How much of that gets deployed at the end of the day?

We generally think of a $200 million layer of cash is what we like to have in the accounts.

Okay.

And this would, Ali, this would have us basically paying the revolver down to zero and not implementing any term loan debt or any other things we could look at doing incrementally as well. So we're light in that respect given the legacy debt structure that we have got. Those are other things that we could look at doing over time as well.

Okay. And last question. And Paul, you really put this well. There's clearly been a huge dislocation in the public markets both equity and debt as far as merchant power securities are concerned. How do you see this public market valuing your portfolio?

And when you look at the experience you have had on private market transactions, you know, strategically, is that leading you to some options or conclusions that you may not have thought about, you know, back in June at the time of the spin-off?

I guess nothing -- as I kind of said on that, maybe a capstone on that last slide from my perspective -- or our perspective, I should say -- nothing has really changed. The deal announced this morning is not the last deal that will ever get done in the merchant space. There's plenty of other generation assets that are out there.

I think the dislocation in looking at the debt side of the equation and the equity side of the equation as it relates to prioritizing or looking at capital deployments creates opportunities as it relates to shareowner value that didn't exist a year ago, even though we weren't public a year ago, and we're clearly taking a look at those.

But as we think about how we would, you know, how we measure value on assets that could be added, how we look -- think about liability management, how we align the risk profile of our assets with the risk profile of the other side of the balance sheet, none of that's really changed.

So I think in the short-term, it creates opportunities that weren't there. But we'll look at those in the same way that we look at, you know, we're -- we have always said we're not here to grow for growth's sake. If there's assets that are available at attractive prices, of a size that we can digest, and that we don't take undue risk in either the asset or liability side, we'll take a look at those; and we do, all of them. So -- but I don't think anything has changed from the rational way that we think about capital deployment.

I guess what I was getting at was do you believe the public equity markets are the right forum for merchant IPPs?

Well, we are where we are unless or until that may change. So I, you know, there's a lot of discussion about private equity looking at public market valuations relative to asset valuations and the significant -- you know, you got these larger companies with all the synergy capability, all the capability to extract full commercial value from the assets, versus assets that are purchased and then contracted out, dispatched, contracted out running the facilities. And yes, it's not logical to me that the public companies trade at the values that they do relative to single assets.

But, you know, I think we'll all, as the public companies, be open and have to do the right thing from a shareowner value perspective and no one is precluding anything. It's just, you know, but I don't disagree with your thesis.

Thank you.

Sure.

Thank you. And the next question comes from Abe Azar with Deutsche Bank.

Morning. Two topics. Can you provide an update on Colstrip given the various legislation that might affect the plant?

Okay. So I think that the legislation that you're referring to is -- well, it may be Oregon as well, but definitely Washington state where Puget proposed legislation to be able to procure our interest in Unit 3 in exchange for certain capabilities that they need for asset retirement obligation recovery and other things in the state and to get around the issue of not allowing Washington utilities to take incremental exposure in coal assets. The last bit as I look at the legislation did not get -- did not get in there.

That's not -- one, I would say that would not be our only path to a final outcome as it relates to our ownership in Montana. And we will do what's necessary to try to improve the economics of, you know, those coal assets in that market. So I can't really comment on specifics on what we might do, but that's not the only path to a final solution with respect to our ownership there.

Great. And when you think about your deeply discounted debt, what are some of the options for taking that out? Is it open market purchases or do you have to do it through a public tender? And would you only rely on the cash from asset sales and free cash flow or might it make sense to draw down the revolvers to buy back some of that -- those bonds?

So I think with the quantum of cash that we have even before we, you know, consider other sources of cash to fund the liability management program, I think we're talking a scale that would in my mind most logically be played out in a public scenario, a public tender scenario. It's hard to get at major debt reductions open market. You have to cool off and obey the tender rules.

So, again, we haven't made any final decisions, but we do see this as a unique opportunity. You know, unlike any other asset, when you buy back your debt, you know with 100% certain what your return is. And at these return levels, it definitely has our attention.

So, you know, as I like to say, it's in the lab and we're working on it. We're not really ready to talk further because there are some other potential calls on our cash that would represent, you know, progress in executing the strategy of the Company. But at these discount, it's, you know, some of this is a two-for-one sale.

Right. Thank you.

Sure, thank you.

Thank you. And the next question comes from Julian Dumoulin-Smith with UBS.

Hi, good morning.

Morning, Julian.

So let's kick off the conversation first. In terms of timing of using capital on the balance sheet, I just want to be very clear here. Obviously, if you don't find some other use of it, debt reduction is a palatable way to go. At what point in time, does that happen in your mind? Do you need to wait a year to see what's going on out there? Obviously you talk about private equity et cetera. Or is there an indefinite time period in your mind?

No, I don't think it's indefinite. I think as Jeremy indicated in his -- in the prepared remarks that we're going to wait until the cash, you know, shows up. We believe the end of March on the hydro sale. I indicated that we're working our way through the cost and gas basis side of the equation for Montour.

If we -- if we come out with something, I think as Jeremy said it would likely be a bit more tender oriented. We just want to -- we want to vet through the rest of the capital priorities or the capital opportunities and the cash isn't here. So we'll get through another quarter or so and then be in a better position to provide specifics.

Great. And then further elaboration here on the capital structure, can you discuss change of control provisions in the debt by tranche here? Which ones have it? Which ones don't? And thoughts around that?

The only one that has it is the one that was issued this past May. Everything else is investment-grade covenant that came with PPL Energy Supply, including the Riverstone that migrated to the covenants of Energy Supply when we did the merger -- or excuse me, the acquisition of the Riverstone assets.

Now, we -- as I intimated we could also, as it relates to thinking about the total quantum available not just the $600 million, but we are -- other than MACH Gen -- very light or don't have term B in the structure and could look to implement the term B and use those proceeds to also come at the existing debt.

I would just append to that comment, our PEDFA municipal bonds have double trigger, so it would be change in control and a down grade.

Right.

So you can have a change in control with no down grade and they stay in place.

Got it. Okay. And then just lastly, guidance real quickly here, cash tax rate going forward, is there kind of a good run-rate number?

And then secondly on Harquahala, is there any specifically that you're waiting for? You kind of say end of year. I mean what could transpire in your mind, just to be clear?

Let me take that one. I'll let Jeremy take the tax one. We are already in discussions with various parties that are load serving entities in the market there. So those have been under way.

We completed with Siemens and another party -- those were the -- I referenced two parties one of which has actually moved CCGT, so I think we have a very good bead on the costs and we're looking at sites primarily in the east to relocate one or more of the units to the extent that we're not successful with a counter-party up there.

When I think of the amount of coal fired generation that exists in the southwest, significantly including Arizona, with environmental, with low gas, to me it would be a shame to not be able to find a way to transact with a party out there to have these very low heat rate, very low run-time units. That would be the most ideal I'd say because that creates immediate value where we would be in a probably a total of a three-year process of permitting and relocation to be able to get those located to -- you know, Athens has room for another unit; there's other sites in New Jersey and PA and Mass that we are looking at to be able to relocate to as well.

But I think that we're very much on track from a timing perspective with understanding the cost and permitting dynamics on relocation as well as what the appetite is either through a sale or a PPA or both of those, because these are three independent trains that could be transacted independently or moved independently. So I think Julian we're right on track with where we thought we would be at this point in time.

Jeremy, do you want to comment on the tax?

Yes. I think, you know, it -- I think we'll be paying some de minimis taxes as an AMT payer. I think, you know, that the rate is probably not that far from zero on a cash effective basis. You won't be that wrong if you use that number.

Okay. Wonderful.

Thanks, Julian.

Thank you. And the next question comes from Greg Gordon with Evercore ISI.

Hey, guys. Good morning.

Hey Greg.

So Julian just got my answer on the tax rate. Can you give me a sense of, given your current tax planning expectations, how long you think you're practically zero? How many years?

I think our comments -- we said for the foreseeable future which is an intentionally vague comment, but it's multi-year.

At least I would go at least five years out, Greg.

Okay. That's helpful. Thanks. And when you gave us your leverage lane -- your current leverage lane, was that on the face value of the debt? Or what would it look like if we adjusted for the current trading value of the debt?

That's just based at, I'll call it, par.

At par. Right, so you could clearly potentially significantly improve that metric if you were able to through your liability management program actually get some of that debt at the prices where it's currently trading?

Correct.

Okay. Most of my other questions were asked so I will get off. Thank you.

Okay. Thanks.

Thank you. And the next question comes from Steve Fleishman with Wolfe Research.

Yes. Hi. Good morning. Just a couple follow-ups. First on Harquahala, can you give us -- is basically the target audience for load-serving entities basically any -- can those plants serve any utility in Arizona? Is it beyond just Arizona?

Any utility, muni, co-op, ag, correct. New Mexico, yes, yes.

And you've got good transmission access to get to any of them?

It's -- we have a direct -- our own direct transmission line to Palo.

Okay. And then just in terms of the cash that -- so $611 million, that's your cash expectation for -- is that like a year-end 2016?

Yes, yes.

Okay. And just when we think about how you would like to kind of run the Company from how much cash on hand going forward, what's kind of you think the right amount of kind of just having kind of cash around level so to speak?

$200 million is what we announced when we did the spin; and with buying MACH Gen, FERC mitigation assets going out it's still right around $200 million.

Okay.

But, again, as you would look at that, that's completely undrawn. I mean that's well in excess of $3 billion of liquidity, undrawn facilities. That would be with nothing. That's just --

We have no cash draws against our credit facility.

Right.

Currently.

Yes, okay. And just could you just reclarify what you said about your PJM capacity auction views?

Primarily that by DR being deemed to be within FERC's jurisdictional purview and PJM to be a wholesale product that I thought it would have a continuing impact on the 2019/2020 auction primarily on the base side of the equation. But the roughly 3,000 that cleared through, we don't see that growing significantly for the 2020/2021, which is all CP. So it will have an influence on one more auction and then not really -- nothing beyond what we have already seen by way of impact.

Okay. And then it looked like as of year-end after the lock-up expired Riverstone, you know, kept their position as is. Have they given any indication further kind of where their head is at?

No. I think, you know, I defer, you know, ultimately the Riverstone, but I'd go back to comments that they did make or had us make on their behalf at the spin is they saw significant value at the values that we saw at the spin. So I'd find it very unlikely that, you know, at this point in time at that these prices, even with where we have seen commodity decks go, that they would find it attractive to liquidate. It's just things haven't moved that much.

Great. Thank you.

You're welcome. Operator?

Yes, and as there are no more questions at the present time I would like to turn the call back over to management for any closing comments.

Okay. Thanks all for joining us on the call today. We look forward to seeing you over the next several weeks and months as we get into the conference circuit again; and have a good day. Thank you.

Thank you. The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.