艾索倫電力 (EXC) 2015 Q2 法說會逐字稿

Good morning. Thank you for standing by. At this time I would like to welcome everyone to the Exelon Corporation Q2 2015 earnings conference call. (Operator Instructions). Thank you.

I would now like to turn today's conference over to Francis Idehen. Thank you. You may begin.

Thank you, Holly. Good morning, everyone. Thank you for joining our second-quarter 2015 earnings conference call. Leading the call today are Chris Crane, Exelon's President and Chief Executive Officer; Joe Nigro, CEO of Constellation; and Jack Thayer, Chief Financial Officer. They are joined by other members of Exelon's senior management team who will be available to answer your questions following our prepared remarks.

We issued our earnings release this morning along with the presentation, each of which can be found in the investor relations section of Exelon's website. The earnings release and other matters which we discuss during today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. Actual results could differ from our forward-looking statements based on factors and assumptions discussed in today's material, comments made during this call, and in the risk factors section of the 10-K which we filed in February as well as in the earnings release and the 10-Q which we expect to file later today.

Please refer to the 10-K, today's 8-K and 10-Q and Exelon's other filings for a discussion of factors that may cause the results to differ from management's projections, forecasts and expectations.

Today's presentation also includes references to adjusted operating earnings and other non-GAAP measures. Please refer to the information contained in the appendix of our presentation and our earnings release for a reconciliation between the non-GAAP measures to the nearest equivalent GAAP measures. We have scheduled 45 minutes for today's call.

I will now turn the call over to Chris Crane, Exelon's CEO.

Thanks, Francis, and good morning, everybody. Thanks for joining. We are pleased to report another strong quarter with our earnings coming in at $0.59 per share, surpassing our guidance of $0.45 to $0.55 per share. You will hear more from Jack in a minute on the specifics and Joe Nigro will also provide some color around the performance.

We have seen a number of positive developments that affect various businesses this quarter. The two primary catalysts for us this year are the PHI acquisition and the capacity market auctions. We received approval on the merger since our last call in Maryland in May, leaving Washington DC as our only outstanding jurisdiction to close the merger, which we expect to hear from soon. We are looking forward to a positive outcome there.

Upon closing the merger, our focus will shift to the integration of PHI Utilities into the Exelon Utilities to align our operations to better serve the PHI customers base.

Another major catalyst is the capacity performance revisions that have been made. While we continue to believe that FERC came to the right conclusion putting reliability at the center of its planning process to ensure the customers in the region are well served, we always were aware that DR and energy efficiency were in the 18, 19 auction. The most recent change that allows DR and energy efficiency to participate in the transition auctions we believe to be nonmaterial to the outcome.

We are disappointed in the delay but we think that we will be on the right track to recognize the value of our highly reliable fleet going forward.

We remain confident that the capacity construct is the best way to protect the grid as we await further clarification on the timing of these transition auctions. I think we are getting that in the last days, so by the September timeframe, we should have clarity on the value proposition along with the reliability measures being enacted.

In Illinois, the legislative session ended without a resolution on the market redesign for the low carbon portfolio standard. We were disappointed that we were not able to get this outcome before the session ended but understand that the state is focused right now on its budget priorities. The nuclear plants provide significant value to this state and its economy and it is mostly important to its consumers.

Looking ahead, we have certain regulatory and operational triggers in September that require us to make some tough choices on specific assets this fall, particularly in light of the continued pressure on the power markets. We are continuing on with our disciplined plan on evaluating the assets and their likelihood to stay within the stack and we will bring that to closure with our decision in September.

Despite these markets challenges, we continue to find ways to create value in our Constellation business which Joe is going to talk about shortly. Part of our resilience to the power market weakness is driven by our ability to capitalize on our generation to load strategy. In this quarter, we show the benefit from the lower cost to serve load and increasing our utility business has been able to reduce the overall volatility at the enterprise level and deliver growth. You can expect that to be even more true over time, not only as we shift our business mix with the acquisition of PHI, but also with our infrastructure improvement investments. We are investing $16 billion in our existing utilities over the next five years which provides respectable growth rates and roughly another $7 billion with the addition of PHI.

I want to remind everybody that we can perform well even in a rising interest rate environment which is typically a headwind in our industry. This is because our EPS is positively correlated to interest rates due to both ComEd's formula rate and ROE being tied to the 30-year treasury rate as well as the discounting of our pension liability.

Overall we are positive the Company is able to provide more stable and durable earnings streams for our shareholders with our operational expertise and driving performance across the enterprise.

With that, I will turn it over to Joe who will discuss the markets followed by Jack on the financial performance.

Thank you, Chris. Good morning, everyone. The Constellation business has continued to perform well in 2015 as a result of our generation to load matching strategy. My comments today will address market events during the second quarter and what they mean for our commercial business going forward including our hedging strategy and our updated disclosures.

Starting with slide four, the spot power markets in the second quarter have been defined by mild weather, which drove the price of power considerably lower in 2014 across PJM. The impact of low spot market conditions has carried through to the forward markets with prices down approximately $0.45 per MWh in 2016 and $1.00 per MWh in 2017 at both PJM Whub and NiHUb since the end of the first quarter. The lack of liquidity in the forward markets has exacerbated the drops in power prices and heat rates with the forward markets exhibiting volatile price moves on very little trading volume for calendar 2017 and beyond, especially at NiHub.

During the quarter, our hedging activities for 2016 to 2018 were executed through our retail and wholesale load businesses rather than on the over-the-counter market. Our fundamental view of power prices has not changed, but given the drop in market prices, there is a greater gap between the market and our fundamental view due to current natural gas prices, expected retirements, new generation resources and load assumptions.

Moving to slide five, I will discuss the forward market and its impacts on our hedging profile.

During the second quarter, we maintained our behind ratable strategy and increased our cross commodity hedge position to increase exposure to power price upside. We have successfully used this behind ratable hedging strategy in the past when our view showed upside in the market. We are 4% to 5% behind ratable in 2016 and 2017 and 7% to 8% behind ratable if you remove our cross commodity hedges at NiHub.

We are confident in our ability to adjust our hedging strategies to capitalize on our fundamental view.

Turning to slide six, I will review our updated hedge disclosure and some key changes since the end of the first quarter.

In 2015, we have a net $50 million increase to total gross margin since the end of the first quarter driven primarily by strong performance and execution. We executed on $200 million of power new business and $50 million of non-power new business during the quarter. Based on 2015 performance to date and expectations for the full-year, we have increased our power new business target by $50 million.

Our generation to load strategy was successful last year during extreme polar vortex conditions and is serving us well this year under weaker load and price conditions. It is further augmented by strong performance from our portfolio optimization activities and our Integrys acquisition.

For 2016, we saw prices decrease across most regions, decreasing around $0.45 per megawatt hour in both the mid-Atlantic and the Midwest. This resulted in a decrease in our open gross margin of approximately $200 million which was offset by our hedging activities. During the quarter, we executed $100 million of power new business and $50 million of non-power new business and are raising our power new business targets by $50 million additional due to commercial opportunities for a gross margin increase of $50 million in 2016.

For 2017, prices decreased by approximately $1 per megawatt hour in both the mid-Atlantic and Midwest. This resulted in a decrease of $300 million in our open gross margin. Despite the drop in prices, our total gross margin is only down $50 million due to our hedge position and an increase in our power new business targets of $100 million because we have line of sight into additional commercial opportunities.

Since the beginning of the year prices have fallen due to mild weather, lower gas prices, lower load demand in the Midwest and a lack of liquidity in the markets. Prices have fallen more in 2017 and beyond than in 2016. Although this weakness in the spot market has impacted forward markets, we are confident in our fundamental view of the gas and power markets and are positioning our portfolio to take advantage of this.

Now I will turn it over to Jack to review the full financial information for the quarter.

Thank you, Joe, and good morning, everyone. We had another strong quarter. My remarks will cover our financial results for the quarter, third quarter guidance range and our cash outlook.

Starting with our second-quarter results on slide seven, Exelon exceeded our guidance range and delivered earnings at $0.59 per share. This compares to $0.51 per share for the second quarter of 2014. Exelon's utilities delivered combined earnings of $0.25 per share and were flat to the second quarter of last year.

During the quarter, we saw favorable weather at PECO and unfavorable weather at ComEd. Cooling degree days were up nearly 37% from the prior year and 47.4% above normal in Southeastern Pennsylvania and down 34% from the prior year and 21.6% below normal in Northern Illinois.

Distribution revenues at ComEd and BGE were higher quarter over quarter. In addition, BGE had a decrease in uncollectible accounts expense compared to the second quarter of 2014.

Exelon Generation had another strong quarter delivering earnings of $0.36 per share, $0.09 higher than the same period last year. As Joe mentioned, our generation to load matching strategy continues to prove effective. We benefited from a lower cost to serve both our retail and wholesale customers and had strong performance from our portfolio management team.

In addition compared to the second quarter of 2014, we had fewer outage days at our nuclear plants, had a positive contribution from the Integrys acquisition, higher realized nuclear decommissioning trust fund gains and received additional benefits quarter over quarter from a cancellation of the DOE spent nuclear fuel fee. These positive factors were partially offset by higher tax and interest expense.

More detail on the quarter-over-quarter drivers for each operating company can be found on slides 18 and 19 in the appendix.

For the third quarter, we are providing guidance of $0.65 to $0.75 per share. Accounting for the impact of the increased share count and the debt associated with PEPCO Holdings transaction and assuming the transaction closes in the third quarter, we are narrowing our full-year guidance from $2.25 to $2.55 per share to $2.35 to $2.55 per share. Our guidance does not assume that bonus depreciation is extended.

Slide eight provides an update on our cash flow expectations for this year. We have simplified the format of our slide to provide a clearer view of our cash flow in each operating company including explicitly showing free cash flow. We project cash flow from operations of $6.6 billion. We project free cash flow of $900 million at generation in 2015. 80% of our total growth capital expenditures are being invested in our utilities over the next three years which will provide stable earnings growth.

In June we completed the debt portion of our financing for the PEPCO transaction by issuing $4.2 billion in senior notes with the majority of these proceeds being used to fund the transaction. Strong market demand allowed us to upsize the offering enabling us to pull forward some future planned corporate debt issuances. We issued across-the-tenor spectrum with an average maturity of approximately 14 years and an average weighted average coupon of 3.79%.

Earlier this month we completed the settlement of the equity forward transaction. The combination of these financings allows us to close the merger quickly upon receiving approval from the DC Public Service Commission. Our balance sheet remains strong and gives us the ability to invest and grow our business. As a reminder, the appendix includes several schedules that will help you in your modeling efforts.

Thank you. We will now open the line for questions.

(Operator Instructions). Greg Gordon, Evercore ISI.

A couple of questions. First, when you talk about commercial opportunities in the context of your comfort level raising your guidance for power new business to go, are we talking about sort of the inherent counter-cyclicality of the margins in that business in a low wholesale environment, i.e., are we moving closer off of the $2.00 floor in margins and closer to the $4.00 peak of the cycle margins that you see in that business historically? Or is it simply new customers, more volumes than you had projected in either the gas or the electric business?

Yes, Greg, in this specific instance, specifically for 2016 where we are raising our power new business to go by $50 million and 2017 by $100 million, it is not related to those load margins, it is more specifically related to some proprietary structured commercial opportunities that we have really solid line of sight into on our wholesale side of the business quite frankly.

To your point though, I think it is important to note, we have raised our targets each $50 million each quarter for 2015 for a total of $100 million so far year to date. And a lot of that has been driven by really three things. One is the monetization of loads that we sold at higher prices last year. So we have seen increased value from that load-serving business, some of our optimization activities. And then we went in as you saw from our disclosures last quarter, we went in with a short bias with a backstop of our own generation and given the results of market prices that in 2015 to date that have performed well.

We would only look to raise those targets, the power to go targets or non-power to go targets if we have good line of sight into specific opportunities and in this case we do.

Okay, follow-up to that. If these are fairly chunky opportunities and you win them, will we get sort of a discrete disclosure or would we get -- would you just update it on a quarterly basis as per your usual moving from to go to into the headwind?

We will disclose that when the negotiations are complete.

Greg, it will be in the MD&A disclosure in our 10-Q when it occurs.

Okay. Second question, in light of economic conditions in Texas, most of your investors would probably rather see you pull the plug on this gas-fired project that you are pursuing. What gives you the confidence that the through the cycle economics of that investment are still worth going forward in this environment?

So as we said, we have got a very good deal on acquiring these assets on our brownfield site, minimal infrastructure investment. They still have a double-digit IRR with these market forwards. If you just projected we stay here for 10 years and then plug the fundamentals in after, we are still at a double-digit IRR. This is a solid investment. These are going to be dispatched first. They are the highly efficient, air cooled and at the right price.

Concise answer. Thank you. Take care.

Steve Fleishman, Wolfe Research.

Good morning. First to Jack, clarification. So in the updated 2015 guidance, are you including some amount of [POM] both the business and the financing cost? And if so, is it positive or negative within the year?

So Steve, we are including the equity and the debt associated with the PHI acquisition. So for share count purposes, that incorporates a weighted average share base of 892 million shares. It does assume the third quarter close of PHI and there is a measure of dilution this year that is related to the increased share count and the debt. And as we pursue rate cases on PHI, improve their revenues and earnings we will see the accretion that we anticipate with that transaction in future periods.

Okay, so just to clarify when you net for this short period into year-end, when you net POM revenue and the financing costs, it is actually -- your numbers would have been higher in this guidance if you hadn't included that?

Modestly, Steve. But not materially so.

But the future accretion guidance that you gave at the last quarter or recent commentary that is still good for future years?

The impact on rate cases and the deferral of those rate cases modestly impacts the accretion but we are still at the -- as we disclosed at the last quarter, we are still at the bottom end of the range in 2017 that we gave.

So it is 2018 to get to that -- more to that mid-point of the run rate that we talked about.

Right, but you clarified that I think the last call or so. (multiple speakers)

$0.15 in 2017 and you will see us head to the upper end in 2018.

Okay. Second question is just with respect to the power views, I kind of feel like the last few calls you have been able a bit more mixed on your power views, you are a lot more bullish right now at least I guess with respect to NiHub. Is that mainly just the fact that you had to pull back as of Q2 end and so you are just more bullish because the starting price is lower or are you more bullish even if prices had stayed flat?

The prices have gone lower. We are more bullish, they are non-sustainable at this level.

Steve, what I would say is our view of the absolute value of power price hasn't changed quarter over quarter. And what has changed is we saw a material drop in the back end of the power curve and I'm talking in NiHub but it is attributable to West Hub as well but our upside is really baked at NiHub where we see material upside as you move out into that 2018, 2019 timeframe. We see upside as well in that 2016, 2017 period and what has changed is the market has fallen so much quarter over quarter, our absolute view of power price hasn't changed. So that spread has gotten wider and when we look at our fundamental models at NiHub in particular, we see a lot of value that could still be derived and that is due to the changing dispatch stack and some of the other things that we have talked about previously.

Talk about the lack of liquidity.

Yes, the liquidity piece of it is a big part of it, Steve. We had approximately $0.40 a megawatt hour drop in PJM at West Hub and NiHub in calendar 2016. That is the most liquid period on the forward curve. When we pull data that we have access to and look at what is going on in the out years 2018, 2019, 2020 where we saw a material drop in prices, there is absolutely nothing trading at NiHub.

There have been some few sporadic trades at West Hub and you see the market set prices off of those trades and our view is through time that spread relationship between West Hub and NiHub is going to collapse because of the retirements on the Western side, the new builds on the Eastern side. And that is why we think there is material upside.

But our fundamental absolute view on power price hasn't changed, it is just the way the market reacted quarter over quarter.

Thank you very much.

Daniel Eggers, Credit Suisse.

On PEPCO, can we just talk about the process -- assuming that a DC decision comes soon, what is the process for closing from this point and what bearing does the Maryland appeal have on your ability to close right now?

We expect to -- assuming an acceptable order from the DC Commission, we expect to close promptly after that order. Our contract would indicate that that will take place within 48 hours of approval by the DC Commission. And we don't think that the Maryland motion should be any bar to us closing. We don't believe that motion has any merit whatsoever.

As you know, the alleged conflict of interest of one of the commissioners having a preliminary interviewing discussion which she stopped with a nonparty isn't the basis under Maryland law to question the independence of that decision let alone stay the proceedings. No court in Maryland and no commission in Maryland has ever suggested there is a conflict with the Commissioner of any agency having a conversation with a nonparty particularly whereas here Exelon is one of some 45 Board members, 140 members in an agency that includes public interest groups like Public Citizen, which was a party below and was the first one to raise this conflict issue. So we don't think that motion has any merit.

We filed a response yesterday with the court and we plan to go ahead and close promptly after the DC Commission issue is in order assuming that that order has acceptable conditions and we have faith that the DC Commission will do the right thing. We think we have put in a strong case with a lot of benefits for customers and protections for customers and we look forward to a prompt closing.

Okay, got it. And then I guess just on the nuclear plants in Illinois, with PJM I guess probably moving the closure date to October, that is still probably before Illinois can act legislatively. With the drop in the forward curves, is there a practical way where you can look at those plants and think that they stay economic without some sort of legislation in Illinois and does that force your hand come October?

The capacity market fixes focused on reliability will not be enough to keep all of the units economically viable. It does give us some support for the investments that we continue to make on the assets to maintain their reliability but it is not totally there. We need a market fix in Illinois to stop the noncompetitive nature of the market and short of the legislation to fix that, we will have to make decisions on retiring assets that are not economically viable.

As we talked about previously, we have requirements around notification to PJM of our intent to retire units. It is an 18-month notification. We also have commitments around when we have to notify of our availability for the 2018/2019 auction in participation on that. And very importantly, we have to order and design cores, fuel cores that take a while for us -- the 2019/2020 auction. I said 2018/2019 � 2019/2020 auction, our participation there.

And we have to order the cores and there is a long lead time there. Are we going to run for an additional year, are we going to run for a longer period of time? And that is a very expensive decision to make. So at least on the PJM, we will make the decision, the final decision if we are going to do that in the September timeframe. We have been in consultation with the Board and we will continue to consult with the Board and when management has made their decision, we will pass that to the Board for the final approval in that timeframe and continue with outreach to our stakeholders.

Chris, just given the fact that you are not going to have legislation realistically done before September and you kind of have laid out the other challenges, what would cause you to not close the plants come September based on the fact pattern you just laid out for us?

If the units clear the 2018/2019 auction, that would show that they are financially viable. That is a long shot in our opinion just because of the cost structure and how the forwards have continued to collapse at the bus at a couple of these units. We have got the transmission constraints, we have got the overproduction in importation of wind that not only drops the spot but continues to collapse the forward curve. The disconnect between NiHub and the bus at some of these units is $6-$7 and we have worked very closely with all the stakeholders involved for over a year and a half on trying to come to resolution. And it is the time that we will have to make the decision after we see what happens with the capacity auctions.

We don't take the decision lightly. We understand the effect that we have on the communities and potential effect on employees. This has been a long-term issue that we have been evaluating and trying to come to resolution and we are staying within the timeline. Actually we extended our timeline last year to give more time to come up with the proper market fixes and to be compensated adequately for operating these units versus subsidizing a low-cost market.

I don't mean to beat this to death and I will stop after this, but would closing a quad or a Clinton show up noticeably as accretive to you guys on 2017 numbers?

We have not looked at that and don't look at it. We analyze the plants as a standalone in their own economics so it is about a plant losing money. We have not evaluated -- others have and others have talked about the impact to consumers on those units closing, the state itself did that assessment. And there is some material impact on the consumer but we have not evaluated anything specific to Exelon.

Okay, very good. Thank you.

Jonathan Arnold, Deutsche Bank.

Good morning, guys. Just given your comments about liquidity in the forward curve, is it fair to assume that you have probably not done much in the way of 2018 hedging yet because ordinarily you would have been a couple of quarters into it. Just curious if you can give us any insight?

Yes, Jonathan, we are behind our ratable sales plan in 2018. As you know, we have a very big load serving book of business so we have captured opportunities both in our retail and wholesale load serving businesses to the extent possible in 2018. And in addition at times as we have spoken about in other years, we use the gas market as well. But to sell straight OTC power in 2018, we have not done much if any of that at all.

And then just to revisit the commercial opportunities comment, can you give us any insight as to what kind of opportunities you are talking about and are they the result of others pulling back from the market or just successful discussions with potential clients I guess?

It is early on that one, Jonathan. We will do the full disclosure when we complete the negotiations.

Sorry to re-ask that. Chris, at the outset you made the comment that you saw the inclusion of DR in the transition auctions as being I think you said nonmaterial to the outcome. Could you share a bit more of your logic and thought process behind that statement?

Yes. Joe?

Jonathan, it is Joe. First of all, we lost over $1 billion in market cap post the announcement of that, of the inclusion of DR in 2016, 2017 and 2017, 2018 and we really thought it was a little bit of an overreaction. As Chris mentioned, we are disappointed in the delay but we don't believe there is going to be a material impact to either of those transition auctions.

As you are aware, DR was already included in 2018, 2019 and beyond. The reason we don't think it is a material impact in the transition auctions is really related to how the auctions themselves cleared on the base residual and the separation in price in 2016/2017 on one side and then the amount of DR that cleared in 2017/2018 auction. And when we put that all into our models, it is very similar to what we read quite frankly from a lot of what has been written by the equity community that it is going to be a limited impact.

Okay, thank you for that.

Julien Smith, UBS.

Good morning. So first quick question and it does kind rehash a little bit here but on the fundamental upside you are talking about, just to be clear, what does that assume in terms of retirements just to be clear, your own retirements particularly as you are thinking about the life of your portfolio here in the back half of the year?

We have not evaluated the potential retirement of any of our assets on market forward prices. And so this is just based off of fundamentals of what has been announced and what we see for retirements, what we see for the economic viability of the existing fleet and what they would have to clear to stay viable going forward.

So it is not a sustainable market forward with the asset mix that it is currently in, it has nothing to do with any forward decision we would make.

Right, so just to be clear, nuclear retirements would be incremental to your fundamental upside?

We have not analyzed it and I wouldn't want to project one way or the other. They are two different things. The nuclear asset retirement is based off of the economic viability of the asset on a standalone. And we have had losses in free cash flow losses in the trailing five years of some significance and we project going forward with these market forwards them to be even worse than they were a year ago which is driving us to make that decision. It is not based off of any potential impact on the market forwards or the rest of the fleet's viability.

Got it. And then two subsequent questions here. First, in terms of the FCF losses, what would you estimate those as being both for the Eastern portfolio and for the ComEd portfolio as it stands today?

Secondly, tied into that as you evaluate the remaining life of some of these assets, would you imagine layering one announcement after another so I suppose specifically there is a timing issue related to ordering new cores. I imagine certain units have to get those orders in before others. Could we see one nuclear retirement and then subsequently depending on what happens in the legislative arena, etc., see further announcements later this year and try to reconcile the bigger issues around FCF deficit?

We have discussed fairly openly the units, the effective units. PJM's rules require us an earlier notification than MISO's rules. And so we would be moving forward if we have to on PJM units before MISO units. We don't projects a MISO decision until beginning of next year looking at the opportunities we have with that unit even through legislation or other mechanisms to secure the required revenues that we need there.

We have talked about New York units where we are still working with our partners and our stakeholders in New York to look at is there a viable way beyond reliability must run situation to maintain economic viability there? And the final asset that has been in discussion is Oyster Creek which we have already have an agreed-upon early retirement date at the end of 2019. So short of some type of failure that was a costly failure on the unit, we would run into that period to allow adequate transition, utilization of the fuel and adequate transition of our employee base to other facilities.

Got it, but just to be clear about the MISO unit there, depending on the success this year in the legislative arena, would that drive that decision?

It would heavily weight our decision.

Great. Thank you.

Chris Turnure, JPMorgan.

Good morning, guys. I wanted to get a little bit more color on the PEPCO approval process here and the core challenge than what you've already talked about. Do you have any sense of the precedent or a precedent for actually staying a commission order? Obviously you disagree with the merit of this case but do you have any precedent there and what would be the path forward if it was not stayed and you got the decision out of the stay?

Thanks. It is Darryl again. The precedent at a stay is very clear in Maryland. It is an extraordinary remedy, it is rarely granted. You have to show a likelihood of success on the merits and the motion does not on the merits of the underlying merger raise any issues whatsoever. The only issue it raises is this [thesis] reported conflict claim which we think is very, very weak. So we don't think they attempted to meet that. They would also have to show irreparable harm which they spend a paragraph trying to satisfy that. It is really not very persuasive in our view.

They would have to show that a stay is in the public interest and of course not only has the Maryland Commission but the New Jersey Commission, the FERC, the Delaware Commission have all found that this merger is in the public interest and they would also have to show that the hardships favor them. And in our pleading, we lay out why disrupting a $7 billion merger outweighs any hardships that would occur from the grant of the stay.

So we think it is an extraordinary remedy, we don't think that they have come close to meeting those standards in any respect and the law is also very clear that in Maryland it is not a balancing. It has to satisfy each and every one of those elements and in this case in our view, they hadn't satisfied any of them.

So that leaves us in a position where upon DC approval and assuming that the court agrees with the pleading we filed yesterday and doesn't grant a stay, that promptly upon the DC Commission joining the other commissions and finding that this is in the public interest and assuming that any conditions it imposes are not unduly burdensome, that we would close promptly.

Okay, great. That is very helpful and then my understanding is that DC has to rule by the end of August. Is there any flexibility around that timing, can they extend that again?

There is no clock in DC so they are not under any time constraint. Generally the DC Commission has ruled within 90 days of something being fully briefed and submitted to them. This was fully briefed at the end of May so that 90 days would end at the end of August. I think that is where that date comes from. Obviously we are hopeful that sooner is better than later but that will be up to the DC Commission and they will rule when they have finished their work. They are I think acutely aware that a lot of people are looking for a decision from them and they understand that but they will take the time that they deem necessary in order to do their job right.

Okay. And then if I could real quick, Joe I just want to follow-up. You mentioned lack of liquidity in the forward markets a couple of times on the call here. Is this a lack of liquidity that exceeds the general nature of these markets and what have you seen historically, has it increased? And if that is the case, do you have an opinion as to why there might be so few trades going on out there?

I think it is probably worse than it has been historically. And I think some of it is there is just no natural buyers that far out on the forward curve as I said, come back into the forward curve, we dropped much more than 2016 where there were more natural buyers when we talk about retail or speculators or other participants. So I think with some of the folks that used to participate in the markets not doing that, some on the banking side and others, I think it has had a material impact.

Great, thanks a lot.

Thank you. That will conclude today's conference call. We appreciate your participation. You may now disconnect.