Public Service Enterprise Group Incorporated

Ladies and gentlemen, thank you for standing by. My name is Julie and I'm your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group, Fourth Quarter 2018 Earnings Conference Call and Webcast. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session for members of the financial community. At that time, if you have a question, you will need to press star and the number one on your telephone keypad. To withdraw your question, please press pound and the number one. As a reminder, this conference is being recorded Wednesday, February 27th, 2019, and will be available for telephone replay beginning at 1 p.m. Eastern today until 11.30 p.m. Eastern on Thursday, March 7th, 2019. It will also be available as an audio webcast on PSEG's corporate website at .pseg.com. I would now like to turn the conference over to Carlotta Chan. Please go ahead.

Thank you, Julie. Good morning and thank you for participating in our earnings call. We released our fourth quarter and full year 2018 earnings results earlier today. The earnings release, attachments, and slides detailing operating results by company are posted on the IR website at .pseg.com and our 10K will be filed later today. The earnings release and other materials we'll discuss during today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. We also discussed non-GAAP operating earnings and non-GAAP adjusted EBITDA, which differ from net income as reported in accordance with generally accepted accounting principles in the United States. Reconciliation of our non-GAAP financial measures and a disclaimer regarding forward-looking statements are posted on our IR website and are included in today's slides and in our earnings release. I would now like to turn the call over to Ralph Izzo, Chairman President and Chief Executive Officer of Public Service Enterprise Group. Joining Ralph on today's call is Dan Craig, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions. Ralph?

Thank you Carlotta and thank you all for joining us today to discuss our fourth quarter and full year 2018 financial results. Earlier today we reported non-GAAP operating earnings for the fourth quarter of 56 cents per share versus non-GAAP operating earnings of 57 cents per share in the fourth quarter of 2017. Non-GAAP operating earnings for the full year were $3.12 per share, up .5% over 2017's non-GAAP operating earnings of $2.93 per share. Now GAAP results for the full year of $2.83 per share include the recognition of net unrealized losses on nuclear decommissioning trust equity securities as a result of new accounting rules, -to-market losses and a gain related to the sale of the retired Hudson and Mercer generating units. Details on the results for the quarter and the full year can be found on slides five and six. PSEG had a successful year in 2018, continuing our long-term strategy of investing in PSEG's infrastructure and growing the percentage of our earnings coming from the regulated business. We put $3 billion of capital to work at PSEG, constructively settled our first distribution-based rate case in eight years, obtained approval for the next phase of our gas system modernization program, which I'll refer to as GSMP2, and filed two other significant regulatory programs. The first filing, Energy Strong 2, will enhance system reliability and resiliency, and the second filing, our Clean Energy Future, or CEF, support New Jersey's clean energy goals and give every customer the opportunity to reduce their energy bill while lowering emissions. You may recall that New Jersey passed clean energy legislation in 2018, which requires utilities to implement energy efficiency measures to reduce electricity usage by 2% and natural gas usage by 3 quarters of a percent. Our CEF proposals are aligned with the objectives outlined by Governor Murphy and the legislature and designed to advance energy efficiency, electric vehicles, and energy storage, as well as smart electric meters, or otherwise referred to as Advanced Metering Infrastructure, AMI, to a broad group of customers in a least-cost manner. We consider our proposal to be the best way to achieve the state's energy efficiency savings targets, as it accomplishes this while limiting the growth in the customer bill and providing fairer, broad-based access to such benefits. Speaking of the customer bill, PSE&G was the first utility in New Jersey to return the benefits of lower corporate income tax rates, which totaled approximately $262 million in customer savings last year. In addition, in 2019, we have implemented the return of $380 million of additional tax reform savings related to accumulated deferred income taxes that will further moderate customer bills going forward. We also made major progress at PSE&G Power, with last May's legislation that recognized the zero carbon attributes provided by New Jersey's nuclear generation and established the Zero Emission Certificate Program. In addition, power completed and placed into service 1,300 megawatts of new, highly efficient combined cycle gas units, or CCGTs, into our PJM fleet. With two of the three CCGTs now online, power is expecting to complete its multi-year construction program in the middle of 2019. That will also bring an improvement in its free cash flow as power's ongoing capital needs decline. PSE&G's operations performed with high reliability in 2018 when it mattered most, during critical times when our service territory experienced extreme weather events that included a cyclone bomb, a polar vortex, multiple nor'easters, an extended summer heat wave, and the wettest year on record. In addition to safely operating our TND system throughout the year, our associates shared their expertise and provided mutual aid to many of our neighboring utilities. At PSE&G Power, our Hope Creek nuclear plant achieved its first ever -to-breaker continuous run in April of 2018, helping deliver carbon-free energy in support of the state's clean energy goals. Non-GAAP operating earnings at PSE&G grew by .5% to $2.10 per share in 2018, benefiting from incremental investments in transmission and distribution programs that expanded rate base by $2 billion to end the year above $19 billion for an increase of 13%. This growth is consistent with the approximate 12% compounded annual growth rate in PSE&G's earnings over the past five years, and reflects the record $14.4 billion of capital invested in the reliability and resiliency of our system over the same period. Of note, PSE&G achieved this growth in earnings and rate base through constructed regulatory mechanisms that allow for contemporaneous or clause-based recovery for the majority of those important infrastructure investments. Moreover, PSE&G's efficiency and discipline in managing costs enabled it to operate without a base rate increase since 2010. And our recent distribution base rate review was completed with customer rates remaining basically flat. We will continue to drive this disciplined approach to efficient growth and earnings in rate base, along with a continued focus on the customer bill. Our investments in system reliability continue to be recognized for the value brought to our customers. For the 17th year in a row, PSE&G was recognized as the most reliable electric utility in the mid-Atlantic region, and was also awarded the 2018 Outstanding Customer Reliability Experience Award highlighting our outage reporting and restoration communications. Last May, the New Jersey Board of Public Utilities approved a $1.9 billion five-year investment plan to extend PSE&G's innovative gas system modernization program, modeled after the infrastructure investment program process established by the BPU to incentivize investments in critical utility infrastructure. PSE&G recently began this next stage of accelerated replacement of up to 875 miles of aging gas pipe, which will carry us through 2023. In the coming months, we will strive to make progress on both the Energy Strong II filing and the Clean Energy Future Energy Efficiency Program, with anticipated decisions on both programs sometime in the third quarter. Now let me turn my attention to PSE&G Power. Power's non-GAAP operating earnings for the full year of $502 million, or 99 cents per share, were 1% below last year. Power continues to exercise stringent cost discipline while producing solid operating results that included higher generation from our gas and coal-fired units over the prior year. As I mentioned previously, PSE&G Power is nearing completion of its construction program, related to its three new natural gas combined cycle generation stations, with the last unit, Bridgeport Harbor 5, expected to be completed in the middle of this year. The Keys and Seawarren stations completed last year have operated well since coming into service. Together, these three units represent 1800 megawatts of new, efficient, clean gas-fired capacity that will replace some older units and improve Power's competitive position. On the policy front, I want to bring you up to date on our efforts to secure recognition for the value of the environmental, fuel diversity, and resiliency attributes provided by our three New Jersey nuclear units. Nuclear generation is a critical component of New Jersey's generation portfolio, and it provides approximately 40% of New Jersey's electric power needs and over 90% of its carbon-free electricity. The legislation created a zero-emission certificate program that is being administered by the VPU, which is now in the process of evaluating the three applications submitted by Power in December of 2018. If awarded the New Jersey zero-emission certificate, it will be set for a three-year period at .004 cents per kilowatt hour, which allows for approximately $10 per megawatt hour in payments to any selected nuclear plant. The legislation requires a VPU decision by April 18th. Any plant receiving a ZEC award starts accruing benefits in April, with the first award period ending in May of 2022. The legislation requires nuclear plants to reapply for any subsequent three-year award period. In December 2018, Power submitted ZEC applications to the VPU for the Salem 1 and 2 and Hope Creek nuclear plants. These were the only applications submitted. As required, the three applications included a certification in which Power confirmed that each of the Salem 1, Salem 2, and Hope Creek plants will cease operations within three years absent a material financial change. While we are fully confident that each of our three ZEC applications demonstrates conclusively that the financial and environmental standards required under New Jersey's legislation have been met, we cannot predict what the VPU will decide. As a result, we have continued contingency planning to shut down the units. In the event that any of the Salem 1, Salem 2, or Hope Creek plants is not selected to receive zero-emission certificates starting in April of this year and don't otherwise experience a material financial change, Power will then take all necessary steps to retire all three plants at their next refueling outages. With respect to FERC's pending rule on the PGM capacity auction design, an interim decision remains pending. As you know, last June, FERC issued an order finding that PGM's current capacity market construct is unjust and unreasonable because it allows state-supported resources to suppress capacity prices. FERC suggested alternative approaches which included modifying its minimum offer price rule to apply to new and existing resources that receive -of-market payments. FERC's other directive was to establish an option that would allow on a resource-specific basis state-supported resources to be removed from the PGM capacity market along with a commensurate amount of load for a period of time. PGM submitted its recommendation for a two-stage capacity auction which would leave in state-supported resources and load during the initial auction to determine capacity obligations. PGM would then remove the state-supported units and rerun the auction with the remaining supply stack. The fill-in generation that replaced the removed resources sets the final capacity market clearing price for all resources. These fill-in resources aren't needed for the overall capacity obligation. They don't receive the market clearing price but instead they get what's referred to as a lost opportunity payment equal to the difference between their bid and the market clearing price. We believe that either PGM's two-stage repricing proposal or the FERC's suggested resource-specific FRR alternative can work with New Jersey's existing ZEC structure. Alternatively, if all of our New Jersey nuclear plants are selected to receive zero-emission certificate payments in April 2019, but the financial condition of the plants is materially adversely impacted by potential changes to the capacity market construct being considered by FERC and in the absence of sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC authorized capacity mechanism, then power would still take all necessary steps to retire all of these plants. With respect to energy, the PGM board recently decided to submit a section 206 filing to FERC covering PJM's reserve price formation proposal

also known

as ORDC or operating reserve demand curve. This effort is intended to improve scarcity price formation and overhaul operating reserve levels and energy prices to better reflect system conditions and appropriately value scarcity. PJM expects to submit the filing within the next few weeks, but the timing and ultimate implementation remain uncertain. And in fact, if implemented, any revenue recognition could be well into the future. The state of New Jersey has also made progress in its efforts to become a leader in offshore wind. Following Governor Murphy's executive offer directing the BPU to move the state toward a 2030 goal of 3,500 megawatts of offshore wind energy generation, an initial solicitation was established for 1,100 megawatts of offshore wind and the state received three bids just this past December. In connection with the bids submitted by Ocean Wind LLC, a subsidiary of Orsted US Offshore Wind, we agreed to provide energy management services and the potential lease of land for use in project development. We also retain an option to acquire an equity interest in the project. If Orsted's bid is selected, we would expect to make a decision regarding what, if any, investment we may have in the Ocean Wind project in the second half of 2019. Our financial condition remains a competitive advantage and we continue to benefit from the financial flexibility that a healthy balance sheet provides. We end the 2018 with solid credit metrics that will enable us to finance our considerable capital plans over the coming five years and provide the opportunity for growth in our dividend without the need to issue equity. Our total capital program for the years 2019 through 2023 is now 12 to $17 billion, with over 90% of that amount directed at regulated utility growth that improves the reliability and efficiency of our operation and supports New Jersey's energy policy goals. Over the coming five years, PSE&G plans to invest approximately $11 to $16 billion on programs which are expected to provide annual rate-based growth of 7 to 9%, starting from the higher 2018 year-end base of $19 billion. Our CCGT program is largely complete with just the commercial operation of the 485 megawatt Bridgeport Harbor unit remaining. PSE&G's continuing long-term strategy to transition our business to a mostly regulated company with predictable cash flows is on track. Our regulated utility, PSE&G, is projected to represent nearly 75% of our consolidated non-GAAP operating earnings this year. PSE&G Power, our high-quality generation business, will see its free cash flow improve and will continue to support our investment programs and dividend growth. So as for 2019 guidance, the conclusion of our distribution base rate case and incremental investments in transmission and distribution infrastructure, combined with the relentless approach to minimizing O&M growth, have offset the expected declines in energy and capacity prices in 2019. PSE&G's business mix is expected to produce growth in 2019, consolidated non-GAAP operating earnings. So for this year, we are forecasting consolidated non-GAAP operating earnings of $3.15 to $3.35 per share, which at the midpoint represents over 4% growth in earnings over 2018 results. This increase is led by a higher contribution from regulated earnings at the utility, moderated by the expected decline in powers results that reflect market prices for energy and capacity, and also includes the benefit from a partial year of zero-emission certificates for all three of our New Jersey nuclear plants. The board of directors' recent decision to increase the company's common dividend by 8 cents per share to the indicative annual level of $1.88 per share is the 15th increase in the last 16 years and reflects our financial strength, business mix, and confidence in our outlook. Let me also acknowledge and thank all of our employees in both New Jersey and on Long Island for the outstanding contributions made over the past year in utility operations and construction, in nuclear and fossil operations, and all the support organizations that enabled us to execute on a full regulatory and policy agenda in 2018. Oh, and I should not admit, obviously, our employees in Connecticut and upstate New York as well. As we enter our 116th year, PSEG remains committed to our strategy to build long-term value for our shareholders as we meet the evolving needs of our customers and the diverse communities we serve. I'll now turn the call over to Dan for more details on our operating results and will be available to answer your questions after his remarks.

Great, thank you, Ralph, and good morning, everyone. As Ralph said, we reported non-GAAP operating earnings for the fourth quarter of 2018 of 56 cents per share, and that's versus 57 cents per share for the fourth quarter of 2017. Our earnings in the quarter brought non-GAAP operating earnings for the full year to $3.12 per share, a .5% increase over 2017's non-GAAP operating earnings of $2.93 per share. And on slide five, we've provided you the reconciliation of non-GAAP operating earnings to net income for the quarter. We've also provided you with information on slide 11 regarding the contribution to non-GAAP operating earnings by business for the quarter, and slides 12 and 14 contain waterfall charts that take you through the quarter over quarter and year over year net changes in non-GAAP operating earnings by major business. And I will now review each company in more detail, starting with PSEG. PSEG reported net income for the fourth quarter of 2018 of 47 cents per share, compared with 43 cents per share for the fourth quarter of 2017. PSEG's full year 2018 net income was $1.067 million, or $2.10 per share, compared with net income of $973 million, or $1.92 per share in 2017, which included two cents per share of benefits from tax reform. Non-GAAP operating earnings for the full year 2018 represented a .5% increase over 2017's results. As shown on slide 16, PSEG's net income in the fourth quarter increased as a result of expanded investment in transmission and distribution infrastructure and rate relief put into effect on November 1st, which more than offset an increase in distribution O&M. Growth in PSEG's investment in transmission improved quarter over quarter net income comparisons by four cents per share. Gas margin improved by six cents per share as a result of rate relief and recovery of investment in gas distribution made under the gas system modernization program. Electric margin improved by two cents per share reflecting rate relief, as well as higher volumes in demand. Changes to the accounting treatment of the non-service component of pension and other post-retirement benefit, or OPED, resulted in a favorable two cents per share comparison over 2017's fourth quarter. These positives were partially offset by five cents of higher O&M expense in the quarter associated with increased tree trimming and higher corrective maintenance. And in addition, depreciation expense increased by two cents per share reflecting the higher plant balances. Taxes and other were one cent per share higher compared to 2017's fourth quarter. For the full year, weather normalized residential electric sales were six tenths of a percent higher, and weather normalized residential gas sales rose by 3.3%. PSC&G's October 2018 distribution base rate settlement provides a balanced and constructive framework for regulatory stability over the next several years. PSC&G anticipates its next distribution base rate review by the end of 2023, and that's based on terms reached in the GSMP-2 settlement last May. The rate settlement recognized the inclusion of capital spending that was not recovered via clauses, deferred storm costs, and an equity percentage of 54% offset by a lower return on equity of 9.6%. PSC&G also updated its transmission formula rate filing for 2019 to pass through additional tax benefits related to accumulated deferred income taxes. This latest update reduced the annual revenue requirement by approximately $155 million from the original filing amount which called for revenue increase of $100 million. PSC&G's investment of $3 billion in its transmission and distribution infrastructure in 2018 helped drive a 13% growth in rate base to approximately $19 billion a year end. Of this amount, PSC&G's investment in transmission represents 45%, or about $8.7 billion of the company's consolidated rate base at the end of 2018. For 2019, we forecast PSC&G's net income at $1 billion, $200 million to $1 billion, $230 million reflecting incremental investments in transmission and distribution and a full year of rate relief. Now let's turn to power. As shown on slide 24, PCG Power reported non-GAAP operating earnings of 11 cents per share compared with non-GAAP operating earnings of 20 cents per share a year ago. The results for the quarter brought Power's full year non-GAAP operating earnings to $502 million, or 99 cents per share, compared to 2017's non-GAAP operating earnings of $505 million, or $1 per share. Power's non-GAAP adjusted EBITDA for the quarter and for the year amounted to $176 million and $1 billion, $59 million respectively. This compares with non-GAAP adjusted EBITDA for the fourth quarter of 17 of 196 million and for the full year 2017 of $1 billion, $172 million. The earnings release as well as the earnings slides on pages 12 and 14 provide you with a detailed analysis of Power's operating earnings quarter over quarter and year over year from changes in revenue and cost. Power's results for the quarter were down from the year ago period, largely reflecting a $6 per megawatt hour decline in the average price received on energy hedges, as recontracting led to a nine cent reduction in net income compared to last year's fourth quarter. This was partially offset by a scheduled increase in capacity prices in New England and PJM, which improved comparisons by four cents per share. An increase in generation output for the quarter improved comparisons by three cents per share. Gas operations declined by two cents per share as higher natural gas prices lowered commodity margin and impacted off-system sales following the startup of the Atlantic Sunrise gas pipeline and has enabled price convergence of lighted gas with higher prices at Henry Hub, as expected. In addition to decline in Power's O&M expense improved net income comparisons by a penny per share. An interest expense of three cents per share and depreciation expense of two cents per share both rose as a result of two new combined cycle units in service at mid-year. And higher taxes reduced net income comparisons by a penny over the prior year's fourth quarter as the absence of investment tax credits and other items offset the benefit of tax reform. Risk margins in the fourth quarter declined to $31 per megawatt hour from $38 per megawatt hour in the year ago quarter, largely the result of a step down in power prices from recontracting. Power prices in the quarter improved slightly as gas prices rose in response to a long cold snap that lasted through most of November to mid-December. For the year, gross margins declined to $33 per megawatt hour from $38 per megawatt hour, reflecting the decline in average hedge prices for energy. Now let's turn to Power's operations and we've provided you with some detail on generation for the quarter and for the year on slides 25 and 26. Output from Power's generating facilities in the fourth quarter increased by 19% over the fourth quarter of 2017, and that's mainly from new capacity additions at Seaworn and Keyes, but also from higher output at our other New Jersey combined cycle units. Quarterly comparisons were also influenced by increased demand in response to the extended period of cold weather for most of the quarter. Our output of 56 terawatt hours was at the high end of our forecast provided at the end of the third quarter, which called for a full year output of 54 to 56 terawatt hours. The nuclear fleet operated at an average capacity factor of .9% in the quarter, resulting in a full year capacity factor of 91.4%, which included, as Ralph mentioned, Hope Creek's first uninterrupted -to-breaker run going into last spring's refueling. For the year, nuclear production totaled 31.2 terawatt hours. Power's gas-pired combined cycle fleet operated at an average capacity factor of approximately 51% in the quarter, resulting in a full year capacity factor of 52%, producing 18.5 terawatt hours of electricity for the year, up approximately 36% year over year. For the quarter, output from the coal fleet was up 10%, primarily from the Pennsylvania units, which was in response to higher weather-related demand. For the full year, output from the coal fleet increased 7% to 5.7 terawatt hours, as an increase in gas prices improved coal's competitiveness. An update of power's hedge position is provided on slide 29. For 2019, with a full year of the Keys and Sea Warren combined cycle units and an expected half year of production from Bridgeport Harbor 5, power's forecasting an increase in output to 60 to 62 terawatt hours. That's up two terawatt hours since the third quarter 2018 update. Following completion of the recent basic generation service, or BGS auction in New Jersey, approximately 80 to 85% of production for 2019 is hedged at an average price of $37 per megawatt hour. As a reminder, our average hedge prices tend to skew higher after we layer in hedges from the BGS auction. For 2020, power has had 55 to 60% of forecast production of 60 to 62 terawatt hours at an average price of $38 per megawatt hour. And power's also forecasting output for 2021 of 60 to 62 terawatt hours. Approximately 15 to 20% of power's output in 2021 is hedged at an average price of $42 per megawatt hour. The forecast for the 2019 to 2021 period includes generation associated with the full year contribution of 1,300 megawatts of gas fired combined cycle capacity at Keys and Sea Warren. The mid 2019 commercial operation of the 485 megawatt gas fired combined cycle plant in Bridgeport and the mid 2021 retirement of the 383 megawatt Bridgeport Harbor coal fire generating station. Consistent with our hedging practice, the gas fired combined cycle assets remain more open to the market in the out years and can take advantage of spark spread opportunities within our RADDable hedging program. Power's 2019 non-GAAP operating earnings and non-GAAP adjusted EBITDAW forecast is projected to be 395 million to 460 million. And 1 billion 30 million to 1 billion $130 million respectively. The operating earnings guidance for 2019 reflects the benefits of including a partial year of ZECs and the incremental contributions from three new CCGT units. Offset by lower pricing on re-contracting, lower capacity revenues, higher interest expense due to the absence of capitalized interest on construction and higher taxes due to the absence of the nuclear carry back benefit we received in 2018. Now moving on to PCG Enterprise and other. We reported a net loss for the fourth quarter of 2018 of $5 million or a penny per share compared to net income of $126 million or 25 cents per share for the fourth quarter of 2017. For the full year, PCG Enterprise and other reported net income of 6 million or a penny per share compared to net income in 2017 of 122 million or 24 cents per share. The results for 2018 reflect the absence of the one-time non-cash earnings benefit of $147 million related to tax reform and a decrease in energy holdings deferred tax liabilities partially offset by an after-tax charge related to REMA in 2017. Enterprise and other reported a non-GAAP operating earnings loss for the fourth quarter of $12 million or two cents per share compared to non-GAAP operating loss of 21 million or four cents per share in the year ago quarter. The results for the fourth quarter brought PCG Enterprise and other non-GAAP operating earnings for the full year to 13 million or three cents per share versus 20 million, which also equated to three cents per share in 2017. The decline in the fourth quarter non-GAAP operating earnings loss versus the fourth quarter 2017 primarily reflects the absence of certain tax charges at holdings taken in the fourth quarter of 2017, lower overall tax expense in 2018 as a result of tax reform and higher interest expense mostly offset by some lower donations in 2018. The 2019 non-GAAP operating earnings for PCG Enterprise and other are forecast to be five to $10 million. This guidance reflects the continued PCG Long Island results largely offset by some higher interest expense. PCG's business mix continues to make us a beneficiary under the Tax Act of 2017 and our financial flexibility remains strong. Our net income for power and for enterprise will realize an ongoing benefit from the decline in federal tax rate overall. However, recently updated rules proposed by the IRS could limit the amount of interest that can be deducted in a given year by non-regulated businesses. If as proposed, depreciation is excluded from the definition of adjusted taxable income in 2018 and 2019, the bonus depreciation related to the new CCGT units in service during 18 and 19 will cap the amount of deductible interest in both years. However, any amount of interest expense disallowed can be carried forward indefinitely and therefore we do not expect this to have an earnings impact for us in either year. PCG ended 2018 with $177 million of cash on hand and debt representing 52% of our consolidated capital position. Power's debt was 32% of its total capital base and its year in debt position was just over 2.6 times 2018 non-GAAP adjusted EBITDA. Given the strength of our balance sheet and internally generated cash flow from both businesses, we are able to fund our capital program and manage the cash impacts of tax reform without the need for additional equity. To recap, we're guiding to non-GAAP operating earnings for 2019 of $3.15 to $3.35 per share, a 4% increase over 2018 with nearly 75% of that amount being generated by PSE&G, our regulated utility. And the common dividend recently was increased eight cents to the indicative level of $1.88 per share. This level represents a 58% payout of earnings at the midpoint of our 2019 guidance and has contributed to a .9% annual rate of growth in the dividend over the last five years. And Julie, we are now ready for questions.

Certainly, ladies and gentlemen, we will now begin the question and answer session for members of the financial community. If you have a question, please press star and the number one on your telephone keypad. If your question has been answered and you wish to withdraw your polling request, you may do so by pressing the pound key. If you're on a speakerphone, please pick up your handset before entering your request. One moment for our first question. Your first question comes from a line of Julian Dumoulin-Smith from Bank of America. Please go ahead with your question.

Hey, good morning, everyone.

Good morning, Julian.

Hey, so perhaps let's just start out with some of the conversations we left off with on third quarter. Can you perhaps revisit just in brief a little bit more on the Lighty Hub conversation with respect to 2019 expectations? And obviously, given substantial amount of gyrations and gas basis in the quarter here, I know you reviewed to a certain extent your power guidance already, but just how does that, what is reflected with respect to basis and how have you seen that even evolve in the last few months since the last update in November? I just wanna make sure we put this one to rest as one of these lingering concerns out there from third quarter.

Sure, Julian. I don't think we've seen a tremendous amount of change since the third quarter. I think we talked about some takeaway capacity coming from the Marcellus and having a little bit of a tightening between some of the gas basis, and that could have some compression on spark spreads. We also talked a little bit about some of the electric basis. And I think both of those things, we will remain somewhat open to and are reflected in the guidance that we have provided. I think even as you look through the fourth quarter, we saw a fairly consistent story with what we told in the third quarter. We did see some uptick during that quarter related to some incremental volume at power, largely weather related, and also some O&M benefits. But I think what we talked about and expected in the third quarter, we've seen through the fourth quarter and will continue to rely upon what forward prices show us as we go through 19 and beyond.

Got it, excellent. And then turning to the other side of the house, on the utility for the 19 guidance, can you talk through a little bit about the earnings components there? And obviously you provide projected rate base, but expected returns and equity ratios perhaps. Just in brief, really the return piece implied in guidance. Are you expecting to earn your authorized is basically a long and short way to ask that.

Yeah, Julian, it's Ralph. We're just two months out of a basis rate case. So we expect to earn .6% on the distribution rate base and the .68% on the transmission rate base at the 54% equity level. Yeah, no, I mean, the data was pretty current and the settlement is pretty current. So we should hit those numbers. We should be able to hit those numbers.

Excellent, and just a quick last one, just in terms of the offshore effort, there's been a lot of focus on this by your peers, but just with respect to the returns and risk profile of what you're contemplating to invest in, how especially with respect to the risk would it be different from just a straight equity investment in the project altogether? And obviously this is preliminary.

Yeah, no, so again, what we've been very clear about is that we know what we know and we fortunately do know what we don't know. And we know transmission, how to build that at a low cost and a reliable way. And we understand the PJM markets, but we've never built anything offshore and we're not eager to take any significant risk on offshore construction. So we're delighted to be part of the Orsted team in terms of them being the leading developer of offshore wind around the world, but there are certain strengths that we bring to the table that I think everybody on this call is aware of and those areas where we're not strong, we're not gonna take a big chance on.

All right, excellent, I'll leave it there. Thank you very much.

Thanks, Julian.

Your next question comes from the line of Jonathan Arnold from Deutsche Bank. Please proceed with your questions.

Oh yeah, good morning, guys. Hi, John. Hi, John. Can I just ask, so we look at the new rate base and capex outlook and as it often has, there's a little bit of a fade in the later years. Do you have a sense, Ralph, of what the likelihood is of filling some of that in and what kind of things and what the timing for some of that materializing might be or is it too early to be having that conversation?

Yeah, thanks, Jonathan. So what I tried to spell is that we have two major programs in front of the BPU right now, Energy Strong 2 and Clean Energy Future. I think in aggregate, they're over $6 billion and we think every penny of that would be money well spent on behalf of customers. It's not a surprise to you that typically when we work with the professionals at the BPU, we don't usually get a complete agreement on every dollar being well worth spending. But I know that zero is not the right answer as well. So those two programs will have the potential to fill in some of the later years.

Okay, and then just to your answer on the question on offshore and knowing what you know, is it safe to assume that whatever you did there would largely be within the utility footprint or is it the release that's happening? No,

that would not be the case, Jonathan. It would be on our unregulated side of the business that we would do that work. To the extent that there's any transmission implications that are in the utilities service territory, then that would be undertaken by PSE&G, but any connection on land or any improvements that needed to be made at the connection point would not be in PSE&G territory. So that would be a project responsibility that we could participate in. And by the way, Jonathan, I think I felt to answer your timing question. We do expect to have some resolution on these two filings in the third quarter of this year.

And to that, that would be incremental to the plan, what you're talking about. I thought that was.

Yeah, so what we've said is that based on currently approved programs, we'll achieve that 7% compound annual growth rate. And based upon the way in which we propose the spend for the new programs, if they were fully funded, we would achieve the 9%. But remember, both those programs take us outside the timeframe of the 7% to 9% that we're proposing. So both the rate at which the money is spent and the amount of money will probably land you somewhere in between those two numbers.

Yeah, and Jonathan, just as we think about it as a way of thinking about the update, we're at 7% to 9%, but really that's all about the increased base as we're jumping off end of 18 instead of end of 19, end of 17, I should say. So the kind of the embedded capital you can think about as being consistent and the update is more about updating off of the one year increased rate base. Right, yeah. We got the

math, it goes to the same place.

Right. Yeah, right, right.

Okay, and can I just on one other thing, just on the guidance for holdings, it seems to be quite a lower number than you've been talking about. And you talked about LIFA minus interest offset, but is there something else going on in there that's sort of structurally shifting holdings a little lower and will that continue?

No, Jonathan, really all it is is that the interest expense at holdings, if you think about shorter term rates coming up a little bit, you're seeing some of that effect come through at the parent level. So some of the debt at the parent being shorter term is seeing a little bit of an increase in rates, that's all. Nothing structural.

Okay, so we should probably just assume that that continues along.

Yeah, so there's an example. We've given you the guidance for 19 and we'll kind of go from there.

I

have

to plug

out folks down in Long

Island that are doing a great job,

so

there's

no issues

out there.

All right, thank you guys.

Your next question comes from a line of Paul Patterson from Glen Rock Associates. Please go ahead with your question.

Hey, good morning.

Good morning, Paul.

So, looking, I'm listening to your comments on the capacity market and I guess sort of concerns about if the nuclear plants are excluded from the market or if there's not sort of the adoption of something similar to the PGM proposal that you would still potentially have to look at closing the plants. Would there be no, what would the thought be in terms of perhaps doing a PPA or what alternatives might there be if in fact there isn't an effort to do a, if in fact you were excluded from the market, if you follow what I'm saying.

Would

you go back and do that?

It really depends on the nature of the proposal from FERC, right? I mean, what we rely upon is the fact that New Jersey demonstrated a commitment to nuclear power through passage of legislation. So, it's hard to imagine, although we'd have to work out the details, that FERC action, which is intended to allow states to continue to choose certain resources to achieve environmental or other objectives, that that mechanism would in some way preempt New Jersey's ability to pursue some options to keep the plants online. I mean, so I think if you've got the state saying we want these plants online as witnessed by the legislation, FERC saying we don't want to interfere with state's abilities to do that, and now it's of course somewhere between those two broad policy statements, we'll just have to wait to see what the order from FERC looks like to figure out the mechanics of how we achieve both of those objectives. But I've gotta believe that those objectives are sincere and we've demonstrated an ability in the past to meet policy objectives when they're articulated as clearly as those two are.

But in theory, the BPU or the state of New Jersey, I guess more generically, could just simply arrange a situation where the carve out load would simply provide a capacity payment in lieu of the fact that, you know, sort of mimicking what the PGM capacity market would have provided if you were part of it. Do you follow what I'm saying? So. Yes, I

do, and that's absolutely true, right? I just, I wouldn't want to be so presumptuous as to say what the BPU will do, except to say that the policy objectives of the state are very clear. And the BPU has a lot of professional expertise that will want to weigh in on what they think the right and creative solution is to meet that policy objective. And we'll certainly work as hard as we can to make sure the state achieves its goals.

Okay, great. And then on the energy efficiency and the legislation and your moves towards meeting those goals, what should we think about in terms of the retail sales growth in New Jersey? Going forward from here, is that negative 2% what we should be thinking about, or how should we be thinking about that?

No, so I think that 2% decline was off of a ratio, I forget what year it was. So I think we saw about .6% increase this year. So there's going to be some netting, right? I don't think it should be 2% plus the incremental increase. But remember, Paul, I know you know this, but forgive me for repeating it. The utility growth is not about load growth, right? Our utility growth is about an aging infrastructure that is in desperate need of replacement. And then on top of that, new technology that's needed to achieve some of the policy objectives, in particular the climate objectives of the state. So I'm not going to say that we're completely indifferent to what the load does, but that's really not at the heart and soul nor the foundation of what the utilities operations or investment or financial performance will look like in the future.

Sure, sure, I was just trying to get to a better market picture. Just, and then I think you might have said that that would offset sort of bill increases as well. Was that an offset from the cost to achieve through the energy efficiency, or is that just sort of, I mean, how should we think about customer bills? I know you guys are concerned about that and looking out on that end. How should we think about that in terms of your forecast? Yeah,

so first of all, the rate case result to basically no net change in customer bills because of the way in which we will flow back to customers with tax benefits. And we still are about 30% below for an average residential customer bill where we were in 2008. But the EE program is specifically proposed to regulators. Now, they have a lot to say about whether or not they agree with our proposal. Even those customers for whom this good cost control is too burdensome, right? So we've targeted low income customers, critical assets like hospitals that serve the public at large, municipal facilities, government facilities, schools, things of that nature. So we fundamentally do believe that the bill is what matters, not the rate, and that there are some customers even in this reduced bill environment that we've been operating on for the past decade that struggle. And so we've taken our best shot at saying to the BPU who we think we can help. And I'm sure that we'll have a great conversation with the staff over the next few months as to whether they agree with that or if they'd like to see it directed differently.

Okay, great. Thanks so much.

Your next question comes from the line of Greg Gordon from Evercore ISI. Please proceed with your question.

Thanks, good morning. Morning, Greg. Circling back to Julian's question, it just would appear on basic rate-based math, just looking at the slides and taking that income and dividing it into the rate-based, the ROE would appear to be a bit higher than the authorized return, but I presume that we're missing things like earnings on AFU-DC and other adjustments that you have to make to walk back down to a regulatory ROE. Is that a fair summary? Because if you just do the arithmetic, it seems high.

Yeah, not seeing your exact math, but I think that's right. There's a regulatory ROE that ultimately just came out of the rate case that we had and we're moving into that now. So I think it's a pretty clean number right now and then as we go through time, we'll continue to move forward.

So Greg, every time we have this call, we always sort of come out of here with like, okay, that made sense, we understood. But that's the second question on earning ROEs that is two questions, too many. I just don't know where that's coming from. I mean, if you were looking at this room right now, you'd see nothing but some really confused and quizzical faces. So we're fighting every day to control O&M to make sure we earn that allowed ROE. So I don't know where that's coming from, but no, we just came out of a rate case and we are at our allowed earnings and somehow we have to figure out how to increase salaries 3% this year with demand growing by .6% and still earn that allowed ROE. Completely understand, I'll talk

to Carlotta, figure it out. My second question.

The only thing that could be, if you look at the rate base, you've got a transmission component, right? You've got an ASP, an Applied Service Business, which is a piece of it. You've got some different treatment for some of the clauses, some of the Reggie clauses. So that may be coming into play and I think we can work through the math and bring it back to an understanding as to where we are with earning our allowed ROE.

Yeah, I'm sure that's gonna be easy to do. The second question was on the power side, the increase in fuel costs that sort of compress the spark spread in Q4, has there been some sort of a structural change in basis on delivered gas to your plants that we need to sort of extrapolate forward or was that just a demand driven surge in pricing that it will just, there was more weather and demand volatility?

I would answer that Greg, I'd say there's a little bit of both. I think what we saw in the third quarter and we talked about some of the weather related aspects. If you look at where things were for most of November and the first half or so of December, we also had some pretty cold weather and the back end of December, you start to run into holidays. So I think if you look at aggregate monthly or quarterly data, it may blur a little bit about the fact that when you had more of your core demand going on, you had higher weather during that period. And so that's gonna pull a little bit more on that price comparison that you see in addition to some of the takeaway capacity. So I think some of it is structural that we saw within the kind of the back half of 2018 and some of that is gonna be more weather and demand oriented as well.

Okay, final question. Ralph, if FERC comes back and rules that the unit specific FRR option is in fact part of the portfolio of options that PJM needs to use going forward to run its market, would you go to the New Jersey government and say you'd like to pursue the full FRR option to remove your units from PJM or would you consider other avenues?

I think it's safe to say we would consider a bunch of different avenues at that point. I would not at all want you to think that we would exclude that possibility, but we could still bid, who knows? We would take a look at that and we would consider other options as well.

Okay, so you wouldn't preclude pursuing the FRR option but you'd look at the whole decision before you'd make the call?

That's correct.

Okay, thank you Ralph, take care. Take care.

Your next question comes from a line of Steve Fleshman from Wolf Research, please proceed with your question.

Thanks, good morning. First, just a quick question on FERC. Do you have any updated sense on timing of when they might make a decision?

You know, I've got a little bit of Steve. I mean, our visits to FERC really have suggested that they are struggling with the capacity market decision. I had the sense that fast start might happen sooner, but September 30th, I thought was 2018, coming across as a smart aleck, I shouldn't do that. So I've kind of stopped predicting timing at FERC.

Okay, and then I guess Ralph, a high level strategic question. So if you look at New Jersey's obviously moving into kind of a trend toward a lot of clean energy, energy efficiency, offshore wind, et cetera, and then if you look at New England states, a lot of them are also doing the same thing. So how does that kind of, are you thinking strategically more about the power business in context of that? You know, what does that mean?

Oh, absolutely. So the question is what's the environmental footprint of the fleet and how does it fit in that? And then quite honestly, given market structures, that dispatch on a short run marginal cost basis and an increased willingness on the part of policymakers to fund the capital needs of assets that then did into that market of zero, you have to pay very serious attention to what that means to the dispatch queue and the profitability of plans in the future. So, you know, we've taken some actions, as you know, Steve, we shut our HEDD units, we shut Hudson and Mercer, we're gonna be shutting our Bridgeport coal facility, we've got some pretty impressive heat rates in our gas plants and we are looking at some role in offshore wind, but there's no doubt that one has to look at the power business in the context of an increasingly clean energy future.

Okay, thank you.

Your next question comes from one of Michael Lapitz from GS. Please go ahead, your line is open.

Hey guys, just Dan, real quick question on 2019 earnings expectations at the utility at ENG. The growth rate, if I just take actual in 18 versus 2019 is a pretty significant growth rate, it even appears higher than your rate-based growth. Can you just kind of walk me through the puts and takes? Is there something unusual with tax? Is there, and I'm not sure if you've heard and can you mention what tax rate that assumes, or is there something unusual that happened in 18 outside of the four or five cents from tree trimming we ought to think about?

No, I think maybe just if you put it in two big buckets, you've got your rate-based growth that's gonna be a part of it, but you also have a rate relief component that's going on on the distribution side. So if you think about a relatively flat overall rate case settlement, you've got an increment to your base rates that's come through and then you've got that being offset by some tax flowbacks and that tax piece is more balance sheet oriented, taking deferred taxes and flowing it back through cash and the base rates are more of that survives, so I think you're gonna get a little bit of a benefit coming through there in addition to what you're seeing from an investment and an overall rate-based perspective. So I'd look at those two components as being some of what's driving the delta as you look year over year.

Got it, and Ralph, just curious, I wanna come back on the offshore wind piece. If you take an equity stake in the project, how do you shield yourself from long-term construction risk? I mean, we know the Europeans have built a lot of offshore wind, there's been a small project built here, but there's not the same infrastructure and supply chain and some of the other kind of items that are necessary to build out lots of the first of a kind, large-scale offshore wind here. How do you kind of protect yourself from material construction risk because you've never really been a company that's liked to take that kind of risk?

Yeah, I mean, with all due respect, Michael, we're not in a position to kind of have a negotiation here with Orsted through you, but I mean, at the end of the day, if you can't shield yourself, then the ultimate shield is you don't invest,

right?

So we have some incredibly talented engineers and we have some equally talented contracts people and lawyers that if they can't figure it out, then the ultimate protection is we don't participate.

Got it, thank you, Ralph, much appreciated.

Mr. Izzo, Mr. Craig, there are no further questions at this time. Please continue with your closing remarks.

Thank you, Julie. So thanks everyone for joining us today and thank you for your continued interest and presumably confidence in us. We'll be on the road next few days and next few weeks. We look forward to seeing you in some of our upcoming meetings and conference appearances. And in the meantime, at the risk of stating the obvious, rest assured, we're gonna continue to work hard and smart every day and we're gonna meet the needs of customers in a safe, reliable, economic and environmentally protected way. And we think if we do that, which we've been pretty good at, then our shareholders will realize a fair return, an allowed return, sorry, Greg, on the infrastructure investments we've been making that allows us to achieve that best in class service level. So thanks everyone and we'll talk real soon. Take care.

Ladies and gentlemen, that does conclude your conference call for today. You may now disconnect and thank you for participating.