Ladies and gentlemen, thank you for standing by, welcome to the 2018 Q1 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during that time, simply press star then the number 1 on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you, Mr. Daniel Eggers, Senior Vice President of Investor Relations. You may begin your call.
Thank you, Geneva. Good morning, everyone. Thank you for joining our first quarter 2018 earnings conference call. Leading the call today are Chris Crane, Exelon's President and Chief Executive Officer, and Jack Thayer, Exelon's Chief Financial Officer. They're 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, both of which can be found in the investor relations section on Exelon's website. The earnings release and other matters which we discussed 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 and comments made during this call.
Please refer to today's 8-K and Exelon's other SEC filings for discussions of risk factors and factors that may cause 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 reconciliations between the non-GAAP measures and the nearest equivalent GAAP measures. We scheduled 45 minutes for today's call. I'll now turn the call over to Chris Crane, Exelon's CEO.
Thanks, Dan. Good morning, everyone. Thank you for joining us today. We have had a productive few months since our last earnings call, making important steps in reinforcing our value proposition. At our PHI utilities, we reached settlement in both Pepco Maryland and Pepco D.C. rate cases. With these settlements, we have now reached constructive settlement in all PHI jurisdictions since the close of the merger and accomplished that legacy PHI has not achieved in many years. This reflects a positive evolution of our engagement in these states. Our employees' hard work to improve system reliability and performance have led to rising consumer satisfaction. The progress we have made is reflected in our constructive partnership with our regulators. There's always more work to do, particularly on our earned ROEs, but we are encouraged by these developments.
In New Jersey, state legislators passed three important energy policy laws with strong majorities on April 12th. Most impactful to Exelon was the New Jersey ZEC Program, similar to that in New York and Illinois. That will be more fairly compensating our nuclear generating assets in New Jersey for clean energy attributes of these plants. In March, our East Coast utilities were battered by three northeasters that resulted in about $200 million of spending between capital and operating expenses. Thanks to the tireless efforts of our employees and contractors, we were able to restore power to the affected customers safely and quickly. These storms were challenging, and the benefits of our scale were on display in March. We were able to return customers to service days faster than we would have as a standalone utility. Finally, we had a strong quarter financially.
On a GAAP basis, we earned $0.60 per share versus $1.06 last year. On a non-GAAP basis, operating basis, we earned $0.96 per share versus $0.64 last year, just above the midpoint of our $0.90-$1.00 guidance range, while overcoming a $0.06 storm cost through March. Turning to slide six. At the utilities, we continue to execute at top quartile levels across key customer satisfaction and operating metrics. The investments we are making are paying off in improved reliability, which is strengthening our relationship we have with our customers and regulators. These numbers follow the standard industry practice of excluding major storms, although the benefits of our scale helped on recovery efforts, which I'll discuss on the next slide. I would note that Pepco D.C. has achieved a record reliability in the past two years since joining Exelon family of companies.
We continue to make gains as we share best practices across all utilities. We also continue to focus on helping customers and communities becoming more energy efficient, saving energy, and money. I'm happy to once again announce that EPA named all five of our eligible companies, BGE, ComEd, Delmarva, Pepco, and PECO, as 2018 ENERGY STAR Partners of the Year. Our companies also received a Sustained Excellence designation for being named partners three or more years in a row. Safety is always our highest priority. We reviewed our OSHA recordables in the first quarter. We've identified a number of areas for improvement and have implemented a series of actions to get those numbers back on track. At ExGen, nuclear generation this quarter was 40 terawatt hours with capacity factor of 96.5%.
Our Texas CCGTs continue to perform very well with an economic dispatch match rate of 96.6%, ramping up and down to optimize by hour by hour the variability in ERCOT pricing. Turning to slide seven. I'd like to take a moment to highlight our utilities performance and the outstanding work from our crews as they battled three consecutive nor'easters in March. These storms blanket our East Coast utility with heavy, wet spring snow and high winds were especially hard on the system. Over the span of these storms, we faced $1.7 million cumulative customer outages and shared over 1,600 Exelon employees and contractors with our sister utilities. ComEd alone provided an additional 1,200 workers and contract crew members. We also incurred, as I said, $200 million of operating capital expenses. To help put this in context, we replaced approximately 1,200 power poles and handled more than 1.8 million customer calls.
With that context, let me share with you the success story of the combined Exelon utility families. Because of our employees are trained on common practices, we're able to seamlessly incorporate workers from different utilities more quickly to get work and return service to our customers. Each storm impacted the service territories differently, but the last of the three storms significantly impacted Atlantic City Electric. We were able to bring in crews and contractors from ComEd, PECO, Pepco, Delmarva, and BGE to assist in the restoration effort. Our scale and performance notably sped up the recovery and allowed us to send over 250 employees and contractors into New Jersey to aid in the restoration effort. The storms that occurred this quarter provide a great example of how our model directly benefits our customers.
The scale of the Exelon utilities and how we run these businesses continue to contribute to higher quality, more responsive, and cost-effective service for our customers. Turning to slide eight. Last call, we provided an update on the impact of tax reform, I want to revisit it as we have been working with our regulators to pass these savings on to customers. We've identified over $500 million in savings to be returned to our customers related to lower corporate tax rate from our distribution utility operations. As we've said from the start, the benefit of the lower income tax rate will provide a meaningful savings to our 10 million utility customers. We appreciate the constructive relationship with our state regulators in that are allowing us to pass along these benefits to our customers in a timely fashion.
Turning to slide 9, we made additional progress in establishing compensation for our nuclear generating fleet that recognizes the value of their emission-free generation and the underlying deficiencies in market design. The most significant development was the New Jersey legislation, as I spoke, of enacting the ZEC program into law, establishing a path forward to preserve the at-risk nuclear plants in New Jersey. I want to thank our team and our partners at PSEG leadership, the leadership in the Senate and the Assembly, and the governor for working together to pass this important legislation. Once the governor signs the bill, the ZEC program will go to the BPU for its review of the applications. There is a 330-day deadline for completing the process, putting the program implementation likely at the end of the first quarter in 2019. At that time, we will start realizing the New Jersey ZEC revenues.
We are pleased that New Jersey has joined New York and Illinois and Connecticut in recognizing the clear environmental attributes of the nuclear generating fleet. We still see need for more comprehensive solutions to compensate for this clean energy, we think expanding the ZEC program is a key interim step to preserving our most challenged assets, extending their useful lives, and the long-term value of this fleet. Turning to the existing ZEC programs in New York and Illinois, we have had oral arguments in both cases at the federal appellate court levels. In Illinois, the court requested and is now waiting for the U.S. government to provide a view on the case. In New York, the decision is with the judges, as they had no outstanding items following the oral argument. We remain confident in our legal position in both cases and continue to collect the ZEC revenues.
With respect to PJM work on price formation, FERC is committed to ruling on PJM's Fast-Start price formation by September, if not sooner, as many parties have requested. PJM is committed to operationally implement the rule as soon as FERC gets approval. FERC's decision on Fast-Start will dictate the process for additional reforms aimed at eliminating flaws in the current pricing formation rules that currently prevent some units from setting price. PJM has now set deadlines for stakeholder reviews of reforms to its shortage pricing rules, including those related to reserve and operating reserve demand curves. We see these price formation changes as essential to preserving an effective competitive market in PJM and applaud the ongoing efforts to design and implement these changes. Just yesterday, PJM committed to study fuel supply vulnerabilities that could arise if the grid became dominated by natural gas generation.
In its white paper, PJM called for reforms of its capacity market to better value fuel secure resilient resources. We have seen this as a positive first step, but we urge PJM to model the carbon and air pollutant implications of greater reliance on fossil fuels, particularly oil-fired power plants, to meet electrical demand. Our states and customers' communities expect us to develop policies that will lead to less pollution, not more, so we believe PJM should study emissions consequences as well. Now I'll turn it over to Jack to walk through some of the numbers.
In New Jersey and Maryland, excluding BGE, we have a tracking mechanism for major storms, the costs incurred during the first quarter are deferred as a regulatory asset and will be recovered in the future, thereby not impacting our reported earnings. In Delaware, Pennsylvania, Washington, D.C., for BGE in Maryland, when we file rate cases, we use an average of major storm costs from previous years that is included in our rates and assumed in our budgets. In years when major storms exceed the historic average, Exelon absorbs the additional storm costs, future rates will be adjusted to reflect these costs. With March's winter storms, we exceeded our storm budgets, which left us $0.06 per share behind plan in the first quarter of 2018.
In New Jersey and Maryland, excluding BGE, we have a tracking mechanism for major storms, the costs incurred during the first quarter are deferred as a regulatory asset and will be recovered in the future, thereby not impacting our reported earnings. In Delaware, Pennsylvania, Washington, D.C., for BGE in Maryland, when we file rate cases, we use an average of major storm costs from previous years that is included in our rates and assumed in our budgets. In years when major storms exceed the historic average, Exelon absorbs the additional storm costs, future rates will be adjusted to reflect these costs. With March's winter storms, we exceeded our storm budgets, which left us $0.06 per share behind plan in the first quarter of 2018.
As we look out to the remainder of the year, we will have to find offsets at the utilities to mitigate any additional major storm expenditures, which historically have come in the first and third quarters. Looking beyond the storm impacts, our utility results did benefit from additional revenues associated with resolved rate cases. We would also expect PHI to catch up on some of their normal course O&M expenses over the balance of the year. Generation had a strong quarter relative to plan, earning $0.49 per share. We had good performance from our nuclear assets with better capacity factors than budgeted. We also benefited from lower O&M expenses and favorable spot market prices.
We're reaffirming our full-year guidance range of $2.90 to $3.20 per share, which you can see on slide 19, and expect to deliver operating earnings of $0.55 to $0.65 per share in the second quarter, compared with $0.54 last year. Turning to slide 11. The $0.96 per share in the first quarter of this year was $0.32 per share higher than the first quarter of 2017. Generation earnings were up $0.32 per share compared to last year, with ZECs representing the most significant source of uplift. As we recognize the true-up of the 2017 Illinois ZEC revenues in the first quarter, which added $0.11 per share, and we realized full quarter contributions from Illinois and New York ZEC programs, including the acquisition of FitzPatrick, which were not in effect during the first quarter of 2017.
Relative to the first quarter of 2017, Generation also benefited from higher capacity pricing in New England, the Midwest, and the Mid-Atlantic regions. As a whole, the utilities were largely impacted by higher storm costs, which was partially offset by increased electric distribution and transmission revenues due to higher rate base at ComEd, increased transmission revenue at BGE, rate increases at PHI, and favorable weather at PECO. Moving to slide 12. On a trailing 12-month basis, our overall earned ROEs slipped modestly from last quarter but are near the midpoint of our targeted 9%-10% earned ROEs that underpin our target returns for 2019 and beyond. The biggest drag in overall ROEs compared to last quarter came from the increased major storm expenses that I discussed earlier. In total, the storms reduced earned ROEs by 10 basis points for our total utility businesses on a trailing 12-month basis.
We'll remain diligent in managing our operating expenses to dampen the effects from the storm costs. Turning to the PHI utilities, the absolute levels of earned ROEs still have room for improvement, even when we adjust for the 60-basis-point drag from the fourth quarter's FAS 109 write-off. That said, the recently filed settlements at Pepco D.C. and Pepco Maryland should start to lift Pepco's earned ROEs in the second half of 2018. We also experienced higher O&M in the first quarter than budgeted, which is due to timing issues and should reverse over the remainder of the year and help to lift earned ROEs.
We look at our earned ROEs for the rest of 2018 for the overall utility, tax reform is positive to earnings but also creates ROE headwinds this year due to the timing of equity injections to fund deferred tax returns before the higher equity is reflected in rate cases. The ROE impact is primarily a 2018 timing issue and is already captured in our earnings outlook. We still expect earned ROEs in 2019 to be solidly in the 9%-10% range. Turning to slide 13, we've had a constructive regulatory quarter. Starting with the most recent developments, we were pleased to reach settlement agreements in April at both Pepco D.C. and Pepco Maryland, providing revenue decreases of $24.1 million and $15 million, respectively. The decreases include adjustments for forecasted tax benefits to customers with the recent tax reform legislation.
The settling parties have proposed a procedural schedule that would place rates in effect by June 1st for Pepco Maryland and July 1st for Pepco D.C. We are happy to have reached constructive settlements with key interveners in both jurisdictions that provide bill relief for customers while also providing a return on our investments and being resolved months earlier than if the cases had been fully litigated. On March 29th, we filed our first case at PECO in three years, where we requested an $82 million rate increase with a scheduled completion by December 31st. The filing is focused on supporting PECO's strong reliability performance, strengthening system resiliency, and supporting physical security and cybersecurity.
I should also note that the $82 million is net of $71 million tax credit for 2019 tax reform benefits, and that the five-year average storm cost in the filing includes the costs incurred in the first quarter. On April 16th, ComEd filed its annual distribution formula rate update with the ICC, seeking a $22.9 million decrease to distribution base rates. The decrease is primarily driven by an adjustment for forecasted tax benefits resulting from the recent tax reform legislation. On February 9th, we closed out the Delmarva Maryland rate case with a $13.4 million revenue increase effective immediately. Finally, we have outstanding cases in Delaware at Delmarva Electric and Gas that are scheduled for completion in the third and fourth quarters respectively. More details on the rate cases and their schedules can be found on slides 22 through 27 in the appendix. Turning to slide 14.
In the first quarter, we invested $1.2 billion of capital at the utilities and are on track to meet our $5.5 billion budget to the benefit of our customers. Considering the significant number of projects that go into our overall capital budget, we thought a more regular update on specific projects would be useful to appreciate how these investments are benefiting our customers and communities. Today, I'd like to highlight two projects. The first is DPL's Cedar Creek to Milford transmission rebuild. This $75 million project entails replacing approximately 43 miles of 230 kV transmission poles, as well as new conductor and optical ground wiring. The 230 kV line is critical for the transmission network in the Delmarva region and will improve reliability by eliminating the potential for outages due to structural failure of the line.
The second project I'd like to highlight is ComEd's future new substation in Elk Grove. The $90 million Greenfield substation is expected to be in service by the third quarter of 2021. The project will support transmission line reliability and projected load growth primarily from data centers in the Elk Grove Village area by adding over 300 MW of additional new capacity. Slide 15 provides our gross margin update for ExGen, which saw some movement within the buckets, but total gross margin in each year is unchanged from our last update. For 2018, open gross margin was up $250 million, primarily due to strengthening ERCOT spark spreads offset by our hedges. We also had a strong quarter in execution, creating $200 million of power new business. 2019 and 2020 gross margins are also flat relative to our last disclosure.
In both years, open gross margin increased by $50 million on strengthening ERCOT spark spreads, which was offset by our hedges. We were also able to execute $100 million and $50 million of power new business in 2019 and 2020 respectively. We ended the quarter approximately 6%-9% behind our ratable hedging program in 2018 and 8%-11% behind ratable in 2019 when considering cross-commodity hedges. We remain comfortable being more open when we look at market fundamentals. Turning to slide 16. We remain committed to maintaining a strong balance sheet and our investment-grade credit rating. We are forecasting ExGen's leverage to be 2.5x debt to EBITDA at year-end 2018, which is below our long-term target of 3x debt to EBITDA. On a recourse debt basis, we are at 2.1x, which is well below our target.
We will continue to manage our balance sheet at ExGen over time to the 3x debt to EBITDA level. Look for us to focus on debt reduction at both Holdco and Genco. I'll now turn the call back to Chris.
Thanks, Jack. Turning to slide 17. We remain firmly committed to our strategy and see progress in the first quarter. Whether it be the rate case settlements at PHI, the benefits of the scale in our storm restoration, or establishing ZEC programs in New Jersey, our financial footing is very strong. Here again is our value proposition. We will continue to focus on growing our utilities, targeting 7.4 rate base growth and 6%-8% EPS growth through 2021. We continue to use free cash flow from ExGen to fund incremental equity needs at the utilities, pay down debt over the next four years at ExGen and the Holdco, and part fund a faster dividend growth rate.
We continue to focus on optimizing value for ExGen business by seeking fair compensation for our carbon-free generation fleet in Pennsylvania, as we have done with the ZECs in New Jersey, Illinois, and New York. This adoption of price formation in PJM and resiliency initiatives at FERC will also benefit. We continue to close uneconomic plants, sell assets where it makes sense to accelerate our debt reduction plans, and maximize value through the gen to load match strategy. We continue to sustain strong investment-grade credit metrics and grow our dividend consistently at 5% through 2020. With that, Operator, we can now open it up for questions.
As a reminder, ladies and gentlemen, that is star one to ask an audio question. Our first question comes to the line of Greg Gordon with Evercore.
Thanks. Good morning. Great quarter, considering all the storms you had. I've got a few questions.
Sure.
The first is, looking at your gross margin slide, you did comment that you had some puts and takes and that the total expected gross margins are the same. I see from looking at the prior quarter's deck that NYHub's around-the-clock pricing is down. Mid-Atlantic's a little better. ERCOT sparks are a lot better. When you show us the open gross margin, and you roll down to the total expected gross margin, how are you thinking about current forwards in ERCOT rolling into spot pricing? Are you just giving us sort of a theoretical naked mark, assuming you can roll all the current run-up in spark spreads into spot? Or is there some sort of a holdback there given the uncertainty with regard to summer volatility?
Hey, Greg. Good morning. It's Joseph Nigro. It's a good question, Greg. As you've mentioned, there is a lot of volatility expected in ERCOT this summer. For us, it's not as simple as just selling the generation output. As you know, we have a very big load book of business, so we have to take that into account as well. We look at those scenarios under a lot of different outcomes, be it higher prices and/or lower prices, and we try to set up the book accordingly. When you look at the disclosure here, we're simply mark-to-marketing the value of our open position in the open gross margin calculation, there was a large uptick to the tune of about $300 million if it had been a fully open book.
Offsetting that, obviously, is the mark-to-market of our hedges that are on the book, given the strong move and the sales we've made. That nets to a gain in the portfolio of about $50 million. As for a holdback, any holdback would be relatively small in the overall total gross margin of the over $8 billion that's expected. We would do that given some of the uncertainty of outcomes that we expect.
Okay, great. Thanks. Jack, I've got a couple questions for you. Looking at the slide where you give the projected sources and uses of cash. As I compare that to the last quarter disclosure, it looks like regulated utility investments, expected investments are up a little bit. The overall free cash flow profile into the end of the year actually looks like it's still net improved even after a slightly higher CapEx. Is that a fair synopsis? I know it's a small increase, but what are those capital expenditures being directed to?
It is a fair synopsis, I think the CapEx is really related to storm investment. Christopher talked about the significant investments that were made in the Mid-Atlantic utilities during that storm. That's why you see the increase in CapEx there. To your point, the overall cash flow profile of the company looks quite strong.
Right. My last question actually goes, because you didn't put it in this deck, back to the Q4 deck where you had EPS sensitivities related to interest rates. It looks to me like the 30-year is up about 37 basis points since year-end. You guys put in here the interest rate sensitivity for common ROE and pension expense is $0.03 in each instance for every 50 basis points, at least looking at 2019. Is it fair to say that these sensitivities still hold? Because that would mean you might be as much as a nickel ahead of where you were in 2019 at the beginning of this year.
I think the nickel sounds a little high, but they do hold. As you know, we benefit from rising interest rates relative to other utilities because of the tie to the formula rate in Illinois, but also because of our significant pension liability. As interest rates increase, the liability shrinks. No question, this rising environment is helping our costs as well as our revenues and EPS. A nickel does seem a little bit aggressive.
Okay. Thank you, Jack. That's all I've got.
Our next question comes on the line of Jonathan Arnold with Deutsche Bank.
Well, good morning, guys.
Great.
I was hoping to follow up on the ERCOT comment just now. I think I heard you say $300 million is roughly the gross margin, and then with the hedging value, it sort of offset down to $50 million. Was that a 2018 comment? If so, could we get some sort of sense on 2019 and 2020? Those sort of hedge sparks numbers that you give, finding it a little difficult to unpack those.
Yeah. The comment I made was in relation to 2018, Jonathan, but you could think similarly, not in magnitude of dollars, because we haven't seen the absolute price change that we saw in 2018.
Yeah.
You had a pickup in open gross margin in 2019 and 2020. Similarly, we had a mark-to-market drop in 2019 and 2020, given that we sold in, obviously, at lower prices. Given that those market prices haven't moved nearly as greatly on the back end in 2019 and 2020, just the absolute value of the dollars isn't going to be as great. I think the other element to that, though, is you've seen this market move pretty appreciably in the front end, and rightfully so, given where reserve margins are in the announcements of the retirements. I think you could expect some extreme volatility this summer, and that will be obviously weather dependent and dependent on unit performance as well as wind performance.
I think the other element, though, is if we see some of that volatility that's expected, it wouldn't be unreasonable to think that you would see price appreciation in 2019 and 2020 on the back of it just because it hasn't moved. As you could see from our disclosures, we're not only carrying a long position in 2018, we have quite a bit of power still open in 2019 and 2020 as well.
Sure. Thank you, Joe. Can you just when you look first quarter versus year-end, the effective realized energy price spark number you gave is down. Just give us a reminder sort of how that works. I think the message is the margin's up, but somehow that indicator goes down.
It's slightly different for the baseload regions, I'll call the Midwest and the Mid-Atlantic, versus the calculation in ERCOT. As you know, ERCOT, we're trying to give you a view of a spark spread, which is more relevant to our machines. The formula is laid out here. It's very simple. We take a gas price using Houston Ship Channel, multiply it by a heat rate, and add some variable O&M to set the reference price. What we then do is we got to add back or subtract from the mark-to-market value. The way to think about that is that's a dollar amount. We calculated the reference price in a unit of dollars per megawatt hour.
We've now got a bucket of dollars on a mark-to-market basis that we need to divide by the volume sold to bring it back to that same unit of dollars per megawatt hour. It just so happens in 2018, when you look at the effective realized energy price, it nets to zero. We've seen it in the past actually go negative in ERCOT, if we have a large mark-to-market loss with very small volumes sold. Then you could see in the out years 2019 and 2020, that's a positive outcome or a positive spark.
The net is that your expected margin is higher, correct?
Yes. Our expected margin in ERCOT is higher in each year, given that we're carrying an open position in all those years and the market has gone higher. That was offset, as we mentioned in the first question from Greg, with some of the changes on the rest of the portfolio to keep the gross margin on the bottom line balanced.
Perfect. Thank you. Just one other little issue. We noticed that there were particularly low tax charges at both PECO and PHI in the quarter. Was there something unusual going on there? What should we be thinking as we sort of push those through the year?
PECO, I think is where it's specific, and it's tax repairs. As we invest capital for the storms, that shows up later as a benefit in tax repairs. Same is true in certain of the PHI jurisdictions.
What would be, should we see continued effect through the year, Jack, or is it really just like a Q1?
It's a Q1.
Okay.
Depending on what storm activity we see in Q3 or Q4.
Good. Okay. Thank you very much, guys.
Sure.
Our next question comes from the line of Steve Fleishman with Wolfe Research.
Yeah. Hi. Curious, just there's a lot of retail businesses it looks like are on the market these days. How interested might you be in expanding retail through acquisition?
Steve, we're always interested. Good morning, first of all. It's Joe. We're always interested in looking at whatever opportunities exist in the marketplace. As you know, we have a history of acquiring companies, in our recent past, when you look at Integrys and Con Edison, for example. We'll continue to do that. To the extent we can add something that we think will be accretive to the bottom line and fits with the value proposition that we're trying to bring both to our shareholders and our customers, we're going to be aggressive with doing that. There has been some change of hands with retailers in the near term here, we would expect that to continue given some that are on the market now, and we'll continue to hunt for them.
Okay. Then just the continued comment on staying more open, due to view that power prices are, I guess, upside you see in power prices. How much of that is the potential market reforms versus just expecting better price kind of without them? Is it a mix of both?
It's a mix of both. I think you have to take the whole picture into account. When you look at our portfolio, from my lens, I think about risk reward. When you look at where the power curve is, like for example, in the Midwest now, and where gas prices are, we think about it from a heat rate perspective, and we see upside to that. That's driven by some of the reforms that PJM themselves is talking about. Obviously, Joe and a number of folks here at Exelon are working on very closely, and we stay very tied to that. In addition to that, we look at history and changes in the composition of the generation stack and the transmission stack. I still go back to some of the easy examples, though.
We had gas prices two years ago at $1.70, and we had power prices that were only almost $26. You have gas curves that's $0.75 or $0.80 higher than that, you see power prices that are lower than where they were. It becomes a question of risk reward when you overlay just the fundamentals of the market itself, obviously some of the regulatory reforms that are out on the horizon.
Okay. Thank you.
Our next question comes from the line of Julien Dumoulin-Smith with Bank of America Merrill Lynch.
Hey, good morning.
Good morning.
Hey. Perhaps to follow up on Steve's question a little bit, can you talk a little bit about expanding margins on retail and just what you're seeing out there? Obviously, some of your peers of late have really been adamant in seeing an opportunity there. Just be curious to hear your latest assessment. I know you guys have seen a variety of different dynamics in the retail markets in recent months. I'll leave it there.
Yeah. Julien, good morning. It's Joe. I guess I really can't speak to what my competitors are actually achieving. I have an understanding of what they're saying, and we know how they're reacting in the market. What I would tell you is, we think about our load-serving business across the wholesale perspective when we think of POLR auctions, as well as our independent retail business. It's tied very closely, obviously, to our generation portfolio. I think, first of all, the volatility during the quarter, especially in New England and PJM, was good to see. We've got an expectation of volumes and margins that are in our disclosure, and we're comfortable with those, and the margins remain in line with what our expectations have been historically for C&I margins. We're comfortable with our projections overall. I will tell you, we've seen some competitive behavior change on the retail side.
Some folks, I think, were hurt last year with low volumes. When you get into some of the non-energy charges and how they're calculated on a volumetric basis. We've seen some of our competitors move away from fully fixed price contracts in certain markets. We'll continue to offer those products. We're going to remain disciplined to our approach. We spend a lot of time analytically evaluating data and using that data to inform our decisions, both from a generation to load matching strategy, from a pricing perspective, and a product development perspective. As you know, last year, we had some challenges in our retail business. We're comfortable where we are now.
I will tell you, on the wholesale POLR auction side in the first quarter, we have had some success. I think it's directly attributable to the volatility that we saw in late December and early January, and quite frankly, in March as well in the Eastern PJM with higher prices. Overall with what's reflected in the disclosure, we're comfortable with the margins and the volumes. We'll continue to work hard. It is a very competitive marketplace.
Excellent. Just wanted to follow up on one specific plant here, Mystic in New England. A lot of different dynamics playing out right now. It would seem as if you need to clear your assets at all of the units, if you will, and then keep them around, or would you actually look to retire select units here if they don't actually get picked up with an RMR or otherwise?
I think we've been very clear, right? We announced the acquisition of the marine terminal. We have an obligation for capacity that we are going to honor. That's part of the reason that we're driving towards that acquisition of the terminal. We've also been very clear that absent market reforms, we don't see profitability for these units into the future. We're working very closely to try to rectify that. The ISO themselves put out a study recently saying that there were five assets in New England needed to ensure reliability into the future, one being the Everett Marine Terminal and the others being the Mystic assets.
Putting all that together, as we've done in PJM and other areas with the capacity market, I think we take a very prudent approach to how we manage this looking into the future, and we're going to do the same thing in New England. We'll honor the commitment for capacity, and we're going to look to get to the right reforms to make these assets more economic in the future.
All of it needs to clear, right?
Julien, this is Joe Dominguez. Actually, no. That's wrong. We don't have to clear the units to participate. In fact, absent a successful filing by the ISO on this waiver that they filed last night, to offer a cost of service rate to Mystic, we will not clear. We will not participate in future capacity auctions.
All right. Excellent. Thank you.
Our next question comes from the line of Stephen Byrd with Morgan Stanley.
Hi, good morning.
Hey, Steve.
I wanted to touch on your additional leverage capacity. I guess what I'm thinking about is as you continue to shift your earnings mix more towards regulated earnings, and you're certainly doing that organically, but I guess I'm also thinking about inorganic ways to do that as well. Could you talk at a high level in terms of what that might mean in terms of a different risk profile with rating agencies, a different targeted credit metrics, et cetera, if you pivot increasingly more towards regulated earnings?
Stephen, I think you know we've been incredibly conservative with our balance sheet in taking that approach, and I think it's worked well with the agencies. As we do get more regulated contribution, certainly the earnings mix of the company shifts, as does the risk profile. That married with the 3 times EBITDA target at the GenCo, which we're well below now, I think positions the company quite well. We have in the past spoken with the agencies, particularly S&P, about upgrading us at the holding company level. We will continue to pursue that. As the mix shifts occurs, I think our case strengthens. That's kind of the conservative approach we're taking.
Understood. Then shifting gears to the PJM White Paper, Chris, that you had mentioned in your prepared remarks and thinking about resiliency, fuel security. Procedurally, how do we think about how PJM might approach that from a process point of view? I know it could take quite a bit of time to do more work, more analytics around that at PJM. Is there anything you can tell us in terms of just thoughts on how that process might unfold?
Yeah, Stephen, it's Joe, let me just start off with an observation. It's interesting, Secretary Perry, in the 403 last fall, identified a resilience problem in these markets. As you know, that proposal was widely panned with a number of parties indicating that there is no resilience issue. Yet in the last 48 hours, we've seen a filing by the ISO New England to retain Mystic on fuel security resilience grounds. Of course, we saw this White Paper from PJM on Monday indicating that it too may have a resilience problem that would require capacity market changes. From our perspective, turning to that White Paper, the things that are going to be important is to understand the analytics, the inputs into the analyses that PJM runs. In particular, how they think about the unavailability of natural gas pipeline service and for what duration.
What Chris mentioned at the top of the call is that, in addition to those constraints or those modeling parameters, we'd like to see them model environmental impacts associated with this fuel mix. We kept the New England system running this year really on the back of oil-fired units. While we succeeded in keeping the lights on, it was a disappointing outcome for environmentalists in New England, where we burned 2 million barrels of oil. A disastrous, frankly, outcome for the stakeholder process in New England, where they want to get to lower air pollution, carbon, and conventional pollutant emissions. We think that needs to be incorporated as well into PJM's analysis. Until we get those environmental externalities incorporated, we're not going to have a complete market. We see this as a positive step forward.
We're going to look very carefully at how they intend to model this situation, again, the unavailability of gas and for how long. We think if they do that right, they're going to find that they too, like New England, have a significant number of fuel constraints on the system that will require them to preserve fuel-secure resources. That could be gas plants on Marcellus Shale storage. It could obviously be nuclear plants, and it could be coal plants. We need to take another look at that mix and make sure we're meeting the expectations of our customers and communities in terms of environmental impacts.
In 2018, emissions need to be going down. Any resolution of this issue that results in emissions going up is going to continue to create incentives for state actions and indeed for other federal actions to correct the flaws in this market.
I want to just follow up on one thing. I want to make it clear, we are not anti-gas. We think that the consumers in the country have really benefited from the plentiful low-cost gas. As we look at the transmission system designs in the country, the N-minus-one concept that coordinates power flows across our system in the loss of major lines is a design basis. What we need is a design-basis threat on the gas system to the electric system and ensure either redundancy in capacity for getting the gas to the plants or limit the dependency on the gas so we can keep the system up, along with what Joe said on the environmental attributes. We don't have a combined gas and electric day coordination.
We don't have a design-basis threat to the gas system that would affect the electric system properly. That needs to be worked out.
Very thoughtful response. It seems like the analysis, as you said, it's important to get the parameters set. That process could take a while, I appreciate your point about what that analysis could result in. Thanks so much for the color.
Sure.
Our final question comes from the line of Praful Mehta with Citigroup.
Hi, guys. Thanks so much.
Hi.
A quick question on price formation. Could you just remind us what is the impact that you see for price formation for your assets, and how does that net out against the assets that are receiving zero emission credits? Is there any net out of that as well?
I'll jump in. What we have talked about is really what PJM has modeled. As a grouping of two different initiatives, the Fast-Start initiative and the full integer relaxation for base load units, PJM has modeled a $3.50 impact to energy markets. We haven't published or discussed any numbers different from that. In terms of how it interfaces with the ZEC program, remember that the units that we presently have in the ZEC program are in New York, which would be unaffected by that change. Clinton, which is in MISO, again, unaffected by that change. The only unit presently we'd be talking about is Quad Cities. Yes, as energy prices go up
Either as a result of energy market dynamic changes, policy changes, carbon being in the market, there would be potentially an offset to the ZEC payment for the plants that are participating.
Got you. That's helpful. That'll apply to New Jersey as well?
In New Jersey, the mechanism is going to be different, but if prices recover for other reasons, the program also will have the BPU look at pricing in future years and potentially make adjustments. The key in all of these states is to preserve these zero emission resources for the customers.
Got you. That's helpful. Just quickly, connecting that with capital allocation, right? If you do have the upside from price formation and zero emission, potentially in Pennsylvania as well, you've already kind of laid out a plan which allocates all the capital into all the different kind of criteria you've mentioned, from debt reduction to dividend. Where do you see the incremental capital, if it does come through, get allocated in your plan currently?
Yeah. We have good capital resources today. We have good sources of investments to make for customer satisfaction and reliability. We'll continue on that path. We have to maintain a very strong sensitivity to the consumer impact on excessive capital going on the system. We can install $8 worth of capital, and keep rates the same by reducing O&M by $1. That's what we have to be focused on, is customer service, reliability, and the impact on our consumers. That would be our approach as we go forward.
Got you. Thanks a lot, guys.
I would now like to turn the call over to Chris Crane for closing remarks.
I want to thank everybody again for attending the call and the questions. We're always available for any further details that you want, going through Dan. We've had a good first quarter. We anticipate a good 2018. The work that's being done by all our operating groups continue to ensure that we maintain the strong balance sheet and deliver on the value proposition. I won't wear you out with my opinion of the valuation of the stock. We have had some improvement, but as we execute, we expect to see more improvement on that in the following quarters and year. With that, thank you very much.
Ladies and gentlemen, this concludes today's conference call. We thank you for your participation. You may now disconnect.