Nextera Energy Partners LP

NYSE:NEP

Earnings Call Transcript 2018-Q4

[Operator]

Good morning, and welcome to the NextEra Energy, Inc. and NextEra Energy Partners, LP Q4 and Full Year 2018 Earnings Conference Call. [Operator Instructions] Please note that this event is being recorded. And now I would like to turn the conference over to Matt Roskot, Director of Investor Relations. Please go ahead.

[Matthew Roskot, executive]

Thank you, Kathy. Good morning, everyone, and thank you for joining our fourth quarter and full year 2018 combined earnings conference call for NextEra Energy and NextEra Energy Partners.

With me this morning are Jim Robo, Chairman and Chief Executive Officer of NextEra Energy; John Ketchum, Executive Vice President and Chief Financial Officer of NextEra Energy; Armando Pimentel, President and Chief Executive Officer of NextEra Energy Resources; and Mark Hickson, Executive Vice President of NextEra Energy, all of whom are also officers of NextEra Energy Partners; as well as Eric Silagy, President and Chief Executive Officer of Florida Power & Light Company. Jim will provide some opening remarks and will then turn over the call to John for a review of our fourth quarter and full year results.

We'll be making forward-looking statements during this call based on current expectations and assumptions, which are subject to risks and uncertainties. Actual results could differ materially from our forward-looking statements if any of our key assumptions are incorrect or because of other factors discussed in today's earnings news release, in the comments made during this conference call, in the Risk Factors section of the accompanying presentation, on our latest reports and filings with the Securities and Exchange Commission, each of which can be found on our websites, nexteraenergy.com and nextenergypartners.com. We do not undertake any duty to update any forward-looking statements.

Today's presentation also includes references to non-GAAP financial measures. You should refer to the information contained in the slides accompanying today's presentation for definitional information and reconciliations of historical non-GAAP measures to the closest GAAP financial measure.

With that, I'll turn the call over to Jim.

[James Robo, executive]

Thanks, Matt, and good morning, everyone. As John will detail later in the call, 2018 was a terrific year for both NextEra Energy and NextEra Energy Partners. By successfully executing on our plans at both FPL and Energy Resources, NextEra Energy was able to achieve our target 2018 adjusted EPS of $7.70, an increase of approximately 15% over our 2017 results. Dating back to 2005, we've now delivered compound annual growth and adjusted EPS of over 8.5%, which is the highest among all top 10 power companies, who have achieved on average compound annual growth of roughly 3% over the same period.

We delivered a total shareholder return of over 14% in 2018, outperforming the S&P 500 by nearly 19% and the S&P 500 Utilities Index by more than 10%. Since 2005, we have outperformed 86% of the S&P 500 and 100% of the other companies in the S&P 500 Utilities Index, while continuing to outperform both indices in terms of total shareholder return on a 1-, 3-, 5-, 7-, and 10-year basis. We're once again honored to be named for the 12th time in 13 years, #1 in the electric and gas utilities industry on Fortune's list of World's Most Admired Companies and to be among the top 25 of Fortune's 2018 Change The World list.

During 2018, FPL successfully executed on its ongoing capital plan, including a continuation of one of the largest solar expansions ever in the U.S. And achieved its O&M efficiency targets to further improve its already best-in-class customer value proposition.

As a result of continued smart investments to benefit our customers, FPL's typical residential bill is more than 30% below the national average, the lowest of all 54 electric providers in the State of Florida, and nearly 10% below the level it was in 2006. In addition to low bills, FPL delivered its best ever service reliability performance in 2018 and was recognized for the third time in four years as being the most reliable electric utility in the nation.

Throughout the year, we were fortunate to be in a position to assist other utilities across the country in their recovery from natural disasters. And we remain grateful for the support that others have given us over the years. After a nearly 10-year process, last month FPL closed on the purchase of the City of Vero Beach's municipal electric system. We look forward to extending FPL's value proposition to Vero Beach's approximately 35,000 customers, while also generating significant long-term savings for FPL's existing customers. The benefit to both new and existing customers is reflective of FPL's collaborative efforts with city, local and regional leaders as well as other state authorities to find the best outcome for all stakeholders.

Earlier this month, we were pleased to close on the purchase of Gulf Power and excited to welcome our new colleagues to the NextEra Energy family. We've now successfully completed all three transactions with Southern Company that we announced in the middle of last year. The acquisitions are an excellent complement to our existing operations and further expand NextEra Energy's regulated business mix through the addition of attractive, electric and natural gas franchises.

By executing on the same long-term strategy that we've deployed at FPL, we expect the acquisitions to benefit customers, shareholders and the Florida economy.

The Energy Resources team also continued its long track record of strong execution in 2018. The renewables origination success was particularly strong, as the team added approximately 6,500 megawatts, including storage and repowering to our backlog over the past year. This represents the most successful origination year in our history and is nearly twice as many megawatts as we originated in 2017, our prior record year. Our ongoing renewable origination success results from operating in what we believe to be the best renewables development environment in our history and our ability to leverage Energy Resources' competitive advantages. These competitive advantages include our best-in-class development skills, strong customer relationships, purchasing power, best-in-class construction expertise, resource assessment capabilities, strong access to and cost of capital advantages, and the ability to combine wind, solar and battery storage into integrated nearly firm low-cost products.

During the year, we were pleased to receive the IRS start of construction guidance on the solar ITC, which we believe positions us well for substantial solar and storage growth well into the next decade. In 2018, more than 40% of the solar projects that were added to our backlog included a battery storage component, highlighting the beginning of the next phase of renewables development that pairs low-cost wind and solar energy with a low-cost battery storage solution.

With continued technology improvements and cost declines, we expect that without incentives, wind is going to be a $0.02 to $0.025 per kilowatt hour product, and solar is going to be $0.025 to $0.03 per kilowatt hour product early in the next decade. Combining these extremely low costs with a $0.005 to $0.0075 adder for a 4-hour storage system will create a nearly firm renewable generation resource that is cheaper than the operating cost of coal, nuclear and less fuel-efficient oil and gas-fired generation units. We continue to believe that this will be massively disruptive to the nation's generation fleet and create significant opportunities for renewable growth well into the next decade.

Consistent with our focus on growing our rate-regulated and long-term contracted business operations, during the fourth quarter, NextEra Energy transmission announced an agreement to acquire Trans Bay Cable, a 53-mile high-voltage direct-current underwater transmission cable system with utility rates set by FERC, which provides approximately 40% of San Francisco's daily electric power needs. Subject to regulatory approvals, the approximately $1 billion acquisition, including the assumption of debt is expected to close later this year and to be immediately accretive to earnings.

The proposed acquisition combined with the mid-continent independent system operator selection of NextEra Energy Transmission to develop the approximately 20-mile single-circuit 500-kv Hartburg-Sabine Junction transmission line is East Texas furthers our goal of creating America's leading competitive transmission company.

In addition to successfully growing our regulated operations, both organically and through acquisitions during 2018 we further strengthened Energy Resources' existing portfolio during the year. In December, The Connecticut Department of Energy and Environmental Protection selected approximately 20% of the Seabrook nuclear plants generation and 80 megawatts of new solar projects, which are not yet included in our backlog for long-term contracts. By operating one of the top performing nuclear plants in the nation, Energy Resources expects to provide significant amounts of carbon-free energy at prices generally in line with current forward curves, while generating attractive shareholder returns.

As a result, Seabrook's contract pricing is expected to be roughly 50% lower than the cost of offshore wind, generating significant savings for Connecticut customers over the 8-year contract term.

The Seabrook award complements Energy Resources exit of the merchant business, which we began back in 2011 and essentially completed in 2016, with the sale of our Forney, Lamar and Marcus Hook natural gas generation assets. Excluding Seabrook, the remaining merchant generation assets contribute less than 1% of NextEra Energy's consolidated adjusted EBITDA. Going forward, we expect this contribution to decline as the focus remains on regulated and long-term contracted opportunities and renewables, natural gas pipelines and regulated transmission. As always, we'll continue to opportunistically evaluate recycling capital through sales of nonstrategic assets in our portfolio, including the remaining fossil generation assets to fund the additional growth of the long-term contracted businesses.

As a result of increasing the expected adjusted earnings contribution from rate-regulated businesses to roughly 70% and the steps that we have taken to further de-risk the Energy Resources portfolio, S&P announced earlier this month that they have revised their assessment of NextEra Energy's business risk profile upward from strong to excellent. As a result of this improvement, S&P reduced NextEra Energy's FFO-to-debt downgrade threshold from 23% to 21%. This follows Moody's announcement last year that with the expansion of the company's regulated operations to roughly 70% following the Gulf Power transaction, NextEra Energy's CFO pre-working capital-to-debt downgrade threshold would be reduced from 20% to 18%.

At these revised rating agency thresholds and following some utilization of balance sheet capacity for the Trans Bay transmission acquisition, we now expect to maintain $4 billion to $6 billion of excess balance sheet capacity through 2021. While we have multiple alternatives for utilization, we expect to use approximately $2 billion of this capacity in the near term to support additional regulated capital investments at FPL.

Consistent with the significant incremental smart investment opportunities that exist at FPL, last week we announced FPL's groundbreaking 30-by-30 plan to install more than 30 million solar panels by 2030, resulting in an incremental 10,000 megawatts of solar projects versus what is in operation at FPL today. We will give further details on these and other potential investments, which are mostly expected to help maintain our long-term adjusted EPS compound annual growth rate beyond 2021, at our investor conference, which we plan to hold on June 20 in New York City.

Following the strong results from 2018, I continue to believe that we have one of the best organic opportunity sets and execution track records in the industry. I remain as enthusiastic as ever about our long-term prospects and based on the strength and diversity of our underlying businesses, I will be disappointed if we are not able to deliver financial results at or near the top end of our 6% to 8% compound annual growth rate range through 2021, plus the expected deal accretion from the Florida transactions, while at the same time maintaining our strong credit ratings.

Let me now turn to NEP, which also had a terrific year of execution in 2018. As John will describe later in the call, NEP successfully delivered on its growth objectives for adjusted EBITDA, CAFD and LP distributions. During the year, we recycled the proceeds from the sale of NEP's Canadian portfolio into a higher yielding U.S. portfolio that benefits from a more favorable tax position. As a result of this accretive transaction, NEP extended its expectations for 12% to 15% per year DPU growth by one additional year to 2023.

The 1.4-gigawatt renewable portfolio that was acquired from Energy Resources further enhanced the diversity of NEP's existing portfolio and was financed through a combination of the Canadian asset sale proceeds and a $750 million convertible equity portfolio financing with BlackRock. The financing demonstrates NEP's ability to access additional low-cost sources of capital to finance its growth and with the right to convert a minimum of 70% of the portfolio financing into NEP units issued at no discount, the transaction further reduces NEP's equity needs going forward.

NEP grew the LP distribution by 15% year-over-year and delivered a total unitholder return of approximately 4% in 2018, which is on the heels of a total unitholder return of over 75% the year prior. NEP outperformed both the S&P 500 and the other yield cos by 7% on average, and its total unitholder return was more than 15% higher than the Alerian MLP Index. I continue to believe that the combination of NEP's growth visibility, along with its flexibility to finance that growth offer unitholders an attractive -- offer unitholders an attractive investor value proposition.

For these reasons, NEP is well positioned to continue executing on its growth objectives and delivering strong performance going forward.

Before turning the call over to John, I'd like to announce some important organizational changes. Armando Pimentel, President and Chief Executive Officer of NextEra Energy Resources and President and a member of the Board of Directors of NextEra Energy Partners, will retire from each of his positions on March 1 of this year, as part of a planned leadership succession process that began when Armando shared his plans with me more than a year ago. John Ketchum, currently Executive Vice President and Chief Financial Officer of NextEra Energy, will replace Armando as President and Chief Executive Officer at NextEra Energy Resources. As part of John's new responsibilities, he will continue to serve as a member of the Board of Directors of NEP and will be appointed President of NextEra Energy Partners. Rebecca Kujawa, currently Vice President, Business Management NextEra Energy Resources will succeed John as Executive Vice President and Chief Financial Officer of NextEra Energy. Rebecca will also become a member of the Board of Directors of NEP. Each of these changes will become effective on March 1 of this year.

Armando has been an enormous contributor to NextEra Energy's success during his more than 10 years with the company, helping to build an industry-leading business during his tenure as CEO of Energy Resources. His leadership, his commercial judgment, his financial discipline have all guided Energy Resources through a period of a truly unprecedented growth and financial success.

Armando's contribution set the company on a path to become what it is today, the world's leading renewable energy company. He's been a great friend, colleague and a truly valued counselor to me personally. And it's an understatement to say I'll miss him, but I'm also excited for Armando and what will come next for him and his family in retirement.

With regard to John's promotion, I've had the chance to work closely with John for more than 16 years, as he has successfully progressed through a variety of different roles in our company. We're fortunate to have a person of his capabilities, vision and experience. He's an exceptional leader who's emerged as one of the premier CFOs in our sector. And I've tremendous faith that John is the ideal successor to lead the Energy Resources team into the future due to his strong financial acumen, knowledge of the sector and passion for building a world-leading energy company.

Likewise, Rebecca has distinguished herself as a well-rounded executive with a proven track record of execution, outstanding finance and commercial skills and an unparalleled understanding of the NextEra Energy enterprise. She has been instrumental in helping Armando lead Energy Resources and develop our strategy for NEP over the last several years and her innovative, analytical and strategic mindset will serve us well in her new role. I'm very happy to have Rebecca as our new Chief Financial Officer.

I'll now turn the call over to Armando, who would like to make some personal remarks.

[Armando Pimentel, executive]

Thank you, Jim. First I want to thank Jim for providing me the opportunity to lead Energy Resources for the last 7.5 years. And I want to thank those of you on the phone today who I've had the privilege of meeting and interacting with since I began at NextEra Energy in 2008. I thank you for the interactive dialogue and the opportunity to continue to tell our story. And today there is no doubt that Energy Resources is not only the largest developer, operator, and owner of renewable energy in the world, but also is most profitable and innovative. And as I tell our employees and customers, I believe we're just getting started. I strongly believe that the renewable energy opportunity is actually just beginning, the combination of energy storage with wind and solar is a revolution, which will expand the opportunities for renewables and is very exciting. I'm profoundly comfortable in the continued success of Energy Resources, NextEra Energy Partners and NextEra Energy.

I want to thank all of our employees at NextEra Energy for providing me the opportunity to work alongside them. I have learned and laughed much over the years and will miss the innovative, fast-pace environment in which we work. I have no concrete plans as of now, but I'm excited about pursuing new adventures and honing old skills. At the very least, retirement will allow me to pursue one of my great passions, fishing. Thanks, again, to all of you who have helped guide me and our company successfully over the years. Our company is in terrific shape, and I congratulate and applaud John and Rebecca on their new roles. Well deserved.

I will now turn the call over to John.

[John Ketchum, executive]

Thank you, Armando and Jim. Let's now turn to the detailed results beginning with FPL. For the fourth quarter of 2018, FPL reported net income of $407 million or $0.85 per share, up $0.01 per share compared to FPL's adjusted earnings in the prior year period. For the full year 2018, FPL reported net income of $2.2 billion or $4.55 per share, an increase of $0.46 per share versus FPL's adjusted earnings in 2017. Regulatory capital employed increased by approximately 12.4% for 2018 and was a principal driver of FPL's adjusted net income growth of 12.5% for the full year. FPL's capital expenditures were approximately $1.5 billion in the fourth quarter, bringing its full year capital investments to a total of roughly $5.1 billion. FPL's reported ROE for regulatory purposes was 11.6% for the 12 months ended December 31, 2018, which is at the upper end of the allowed band of 9.6% to 11.6% under our current rate agreement.

During the fourth quarter, we restored an additional $240 million of reserve amortization, leaving FPL with a year-end 2018 balance of $541 million. We continue to expect that FPL will end 2020 with a sufficient amount of reserve amortization to operate under the current base rate settlement agreement for up to two additional years, creating further customer benefits by potentially avoiding a base rate increase in 2021 and perhaps 2022.

Before moving on, let me now take a moment to update you on some of our key capital initiatives at FPL. During 2018, FPL completed construction on schedule and on budget for the first 8 74.5-megawatt solar energy centers, developed under the Solar Base Rate Adjustment, or SoBRA, mechanism of the rate case settlement agreement. In 2018, we also deployed the first two projects under FPL's 50-megawatt battery storage pilot program, pairing battery systems with existing solar projects and highlighting FPL's innovative approach to further enhance the diversity of its clean energy solutions for customers. The next 300 megawatts of solar projects being built under the SoBRA mechanism remain on budget and on track to begin providing cost-effective energy to FPL customers in early 2019.

To support the significant solar expansion that FPL is leading across Florida, we have secured sites that could potentially support more than 7 gigawatts of future projects. Beyond solar, construction on the approximately 1,750-megawatt Okeechobee Clean Energy Center remains on budget and on schedule to enter service in the middle of this year. Additionally, the roughly 1,200-megawatt Dania Beach Clean Energy Center received siting board approval during the quarter to support its projected commercial operation date in 2022. We continue to expect that FPL's ongoing smart investment opportunities will support a compound annual growth rate in regulatory capital employed, net of accumulated deferred income taxes, of approximately 9% from the start of the settlement agreement in January 2017 through at least December 2021, while further enhancing our customer value proposition.

The economy in Florida remains healthy. The current unemployment rate of 3.3% remains below the national average and at the lowest levels in a decade. Florida's consumer confidence level remains near 10-year highs. The real estate sector also continues to show strength, with new building permits remaining at healthy levels and the Case-Shiller Index for South Florida home price is up 4.8% from the prior year.

FPL's fourth quarter retail sales increased 4% from the prior year comparable period. We estimate that weather-related usage per customer contributed approximately 0.6% to this amount. On a weather-normalized basis, fourth quarter sales increased 3.4%, with positive contributions from both weather normalized usage per customer and ongoing customer growth, including the addition of Vero Beach's customers.

For 2018, we estimate that FPL's retail sales on a weather-normalized basis increased by 2.6%. Continued customer growth and an estimated 1.7% increase in weather-normalized usage per customer, both contributed favorably.

While we were encouraged by the growth in underlying usage in 2018, which was a consistent benefit during all four quarters. As we have often discussed, this measure can be volatile and we are not yet ready to draw any firm conclusions about long-term trends.

We'll continue to closely monitor and analyze underlying usage and will update you on future calls.

Let me now turn to Energy Resources, which reported fourth quarter 2018 GAAP earnings of $263 million or $0.55 per share. Adjusted earnings for the fourth quarter were $317 million or $0.66 per share. For the full year, Energy Resources reported GAAP earnings of $4.66 billion or $0.0975 per share and adjusted earnings of $1.46 billion or $3.05 per share. In the fourth quarter, Energy Resources contribution to adjusted earnings per share increased by $0.18 from the prior year comparable period. Positive contributions from new investments, customer supply and trading, our gas infrastructure business, including existing pipelines and the reduction in the corporate federal income tax rate, all supported the strong year-over-year growth.

These favorable contributions were partially offset by lower contributions from our existing generation assets as a result of particularly poor fleet-wide wind resource, which was the lowest fourth quarter on record over the last 30 years and higher interest in corporate expenses due to growth in the business.

Energy Resources full year adjusted earnings per share contribution increased $0.45 or approximately 17% versus 2017. For the full year, contributions from the new investments declined by $0.04 per share, due in part to the expected smaller-than-usual 2017 renewable build.

In 2019 and beyond, we expect meaningful growth from new investments as we continue to execute on our renewables development backlog. Increased PTC volume from the approximately 1,600 megawatts of repowered wind projects that were commissioned in 2017, helped to increase contributions from existing generation assets by $0.10 per share. Contributions from our gas infrastructure business, including existing pipelines increased by $0.17 per share year-over-year. As expected, the reduction of corporate federal income tax rate was accretive to Energy Resources, increasing adjusted EPS by $0.45 compared to 2017. All other impacts reduced results by $0.23 per share primarily as a result of higher interest and corporate expenses driven largely by increased development activity to support the favorable renewables development environment. Additional details are shown on the accompanying slide.

In 2018, Energy Resources continued to advance its position as a leading developer and operator of wind, solar and battery storage projects, commissioning nearly 2,700 megawatts of renewable projects in the U.S., including an additional 900 megawatts of repowered wind. Since the last call, we have added 1,791 megawatts of renewable projects to our backlog, including 680 megawatts of wind, 797 megawatts of solar and 215 megawatts of battery storage, all of which will be paired with new solar projects. Included in the solar megawatts we added to backlog this quarter is a 150-megawatt solar build-owned transfer project with a 10-year O&M agreement that will allow the customer to leverage Energy Resources best-in-class operating skills, while providing meaningful ongoing revenue through the contract term.

During the quarter, Energy Resources signed an additional 99 megawatts of wind repowering and successfully commissioned approximately 600 megawatts of repowering projects. For 2017 and 2018, this brings the total repowering projects placed in service to roughly 2,500 megawatts, near the top end of the previously outlined range for this period. We continue to expect to be in the upper half of the $2.5 billion to $3 billion in total capital deployment for repowerings for 2017 through 2020.

Following the record origination year in 2018, and with nearly two years remaining in the development period, we are now within the previously outlined 2017 to 2020 ranges for U.S. wind, solar and wind repowering. For the post 2020 period, our backlog is already nearly 2,000 megawatts, placing us well ahead of our historical origination activity at this early stage. The accompanying slide provides additional detail on where our renewables development program now stands.

Beyond renewables, we completed construction of approximately 175 miles of the Mountain Valley Pipeline during 2018. As planned, MVP is continuing with its scaled-back construction efforts for the winter. While we continue to target our previously announced full in-service date for the pipeline during the fourth quarter of 2019 and revised overall project cost estimate of $4.6 billion, we also continue to work through the project's outstanding legal challenges and to closely monitor developments related to the Atlantic Coast Pipeline and the current government shutdown, as the outcome of any one of these issues could impact MVP's project schedule and cost estimate.

We also continue to evaluate mitigation alternatives to address potential adverse outcomes should they arise. MVP's expected annual contribution to NextEra Energy's ongoing adjusted EPS is approximately $0.07 to $0.09. We do not expect any material adjusted earnings impacts nor any change in NextEra Energy's financial expectations as a result of the ongoing challenges. We'll provide further updates as those proceedings evolve.

Turning now to the consolidated results for NextEra Energy. For the fourth quarter of 2018, GAAP net income attributable to NextEra Energy was $422 million or $0.88 per share. NextEra Energy's 2018 fourth quarter adjusted earnings and adjusted EPS were $718 million or $1.49 per share respectively. For the full year 2018, GAAP net income attributable to NextEra Energy was $6.64 billion or $13.88 per share. Adjusted earnings were $3.67 billion or $7.70 per share reflecting growth of 15% off our 2017 adjusted EPS including approximately $0.45 benefit from lower federal income taxes.

For the corporate and other segment adjusted earnings for the full year increased plus $0.09 per share compared to 2017 primarily due to lower interest and certain favorable tax items. We continue to expect NextEra Energy's adjusted EPS compound annual growth rate to be in a range of 6% to 8% through 2021 of our 2018 adjusted EPS OF $7.70 plus accretion of $0.15 and $0.20 in 2020 and 2021, respectively, from the Florida acquisitions.

For 2019, we continue to expect our adjusted EPS to be in the range of $8 to $8.50. From 2018 to 2021, we expect that operating cash flow will grow roughly in line with our adjusted EPS compound annual growth rate range. We're closely following the recent developments with Pacific Gas and Electric. Projects directly affected by the potential PG&E bankruptcy have an expected annual adjusted EPS contribution of roughly $0.13 to $0.15 for NextEra Energy. Regardless of the outcome of PG&E's anticipated bankruptcy proceedings, we expect to achieve NextEra Energy's adjusted EPS expectations that I just outlined and will be disappointed if we are not able to deliver growth at or near the top of our 6% to 8% compound annual growth rate range off our 2018 base of $7.70, plus the expected deal accretion from the Florida transactions.

We continue to expect to grow our dividends per share 12% to 14% per year through at least 2020, of 2017 base of dividends per share of $3.93. As always, our expectations are subjected to the usual caveats, including, but not limited to, normal weather and operating conditions.

Let me now turn to NEP, which also had a strong year of operational and financial performance in 2018. Yesterday, the NEP board declared a quarterly distribution of $0.4650 per common unit or $1.86 per unit on an annualized basis, up 15% from the comparable quarterly distribution a year earlier and at the top end of the range we discussed going into 2018. For the full year 2018, adjusted EBITDA and CAFD increased 18% and 36%, respectively, primarily as a result of portfolio growth. In addition to meeting NEP's growth objectives with the acquisition from Energy Resources, during 2018, we were also pleased to announce the execution of a long-term contract that enables an expansion investment in the Texas pipeline. The opportunity, which is subject to regulatory approval, is expected to be in service during the fourth quarter of 2020, demonstrates the organic growth potential of NEP's underlying portfolio.

Beyond the attractive low-cost convertible portfolio of equity financing with BlackRock, NEP took additional steps to further enhance its financing flexibility during 2018. In the fourth quarter, NEP entered into an additional $1 billion interest-rate hedge agreement to help mitigate interest rate volatility on future debt issuances. NEP's hedge agreement has a fixed rate of approximately 3.95% and could be flexibly utilized in any date until December 11, 2028. The swap is incremental to the $5 billion hedge agreement that we announced last year, providing significant protection against interest-rate risk and NEP executes on its long-term growth plan -- as NEP executes on its long-term growth plan.

Additionally, during 2018, we successfully raised approximately $85 million through the sale of roughly 1.8 million common units under NEP's ATM program. Going forward, we will continue to flexibly seek opportunities to use the ATM program depending on market conditions and other considerations.

Now let's look at the detailed results. Fourth quarter adjusted EBITDA was $165 million and cash available for distribution was $44 million, a decrease of $35 million and $33 million from the prior year comparable quarter, respectively. The decline was primarily driven by the sale of a Canadian portfolio earlier in the year, with those assets not replaced until the late December closing on the 1.4-gigawatt acquisition from Energy Resources. For the full year 2018, adjusted EBITDA and CAFD were $881 million and $339 million, up 18% and 36%, respectively, primarily driven by growth of the underlying portfolio. Existing projects benefited from increased contributions from Texas pipelines versus the prior year.

For adjusted EBITDA, this benefit was offset by the year-over-year reduction in the pretax value of NEP's tax credits as a result of the decline in the federal income tax rate. This change has no income -- no impact on CAFD. Cash available for distribution from existing projects also benefited from reduced debt service, which was roughly offset by higher corporate level interest expense. As a reminder, these results include the impact of IDR fees, which we treat as an operating expense. Additional details are shown on the accompanying slide.

For NEP, absent any impact from a PG&E bankruptcy filing, our December 31, 2018, run rate expectations for adjusted EBITDA of $1 billion to $1.15 billion and CAFD of $360 million to $400 million are unchanged, reflecting calendar year 2019 expectations for the portfolio, with which we ended the year. Our previously announced December 31, 2019, run rate expectations for adjusted EBITDA of $1.2 billion to $1.375 billion and CAFD of $410 million to $480 million are also unchanged. Our expectations are subject to our normal caveats and include the impact of anticipated IDR fees as we treat these as an operating expense.

From an updated base of our fourth quarter 2018 distribution per common unit at an annualized rate of $1.86, we continue to see 12% to 15% per year growth in LP distributions as being a reasonable range of expectations through at least 2023. We expect the annualized rate of the fourth quarter 2019 distribution as payable on February 2020 to be in the range of $2.08 to $2.14 per common unit. NEP expects to be able to manage through the impacts of the anticipated PG&E bankruptcy and to achieve the growth expectations that I just outlined. As we have previously disclosed, the 420 megawatts of projects that are contracted with PG&E represent 15% to 18% of NEP's expected year-end 2018 run rate cash available for distribution.

As a result of the PG&E Board of Directors authorizing the commitment -- commencement of a bankruptcy filing, we believe an event of default has likely occurred under the Genesis financing. The administrative agent for the Desert Sunlight 300 financing has notified us that an event of default has occurred under those agreements, which we dispute, and they are currently withholding the January distribution.

For any financing or an event of default is determined to have occurred, cash distributions can be restricted and other remedies could be exercised, including acceleration of the debt. Additionally, due to provisions in the financings, an event of default under the Desert Sunlight 300 financing can prevent distributions from Desert Sunlight 250, which is contracted with SCE. We expect the combination of Desert Sunlight 250 and the PG&E projects to contribute roughly 18% of NEP's year-end 2019 run rate CAFD. As we execute on NEP's growth strategy, we expect this to further decline over time and that the PG&E projects and Desert Sunlight 250 will not represent a significant percentage of NEP's 2023 cash available for distribution.

For projects where cash distributions are restricted, we expect that over time these funds will go toward paying down the principal on existing financings, which would potentially result in more distributable cash flow to NEP in the future. In each of these projects, we're reviewing our alternatives and will pursue all options to protect our interest, including vigorously defending our contracts and working with key stakeholders of each financing. Even in a worst-case scenario where we receive no further contributions from projects that are contracted with PG&E or Desert Sunlight 250, we continue to expect that NEP will achieve its annual 12% to 15% growth in distributions per unit through 2023 without the need to sell common equity until 2020 at the earliest of the modest at the market issuances.

We're pleased with NEP's strong performance in 2018 and believe it continues to provide a best-in-class investor value proposition. With the flexibility to grow in three ways: Acquiring assets from Energy Resources organically or acquiring assets from other third parties, NEP has clear visibility to support its growth going forward. Following a new record renewables origination year by Energy Resources and the continued strength of the best renewables development environment in our history, NEP's growth visibility further improved in 2018. Additionally, NEP's cost of capital and access to capital advantages further improved over the past year, providing flexibility to finance its growth over the long term. When NEP's growth potential and financing flexibility are combined with its favorable tax position and enhanced governance rights, we believe NEP is well positioned to meet its financial expectations and we look forward to delivering on NEP's strategic and growth initiatives in 2019 and beyond.

That concludes our prepared remarks. And with that, we will open the lines for questions.

[Operator]

[Operator Instructions] And we will go first to Stephen Byrd of Morgan Stanley.

[Stephen Byrd, analyst]

Armando, congratulations on your retirement, and John and Rebecca, congratulations on your new role. All very well deserved.

[John Ketchum, executive]

Thank you, Stephen.

[Stephen Byrd, analyst]

I wanted to just talk, as you can imagine, about California for a minute. If all of the project debt essentially withheld cash to the -- arguably to the extent that they were -- would be permitted, I wanted to make sure I was clear how much CAFD would be restricted? You mentioned 18% related to several projects. But I wanted to check if every single piece of debt relating to PG&E sort of exercised their cash drop right. What amount of CAFD will be impacted?

[John Ketchum, executive]

Yes. So again, it would comprise roughly 18% of our run rate CAFD for 2019. We have included a page in our investor materials that -- Page 41, Page 41 that details the CAFD from each of these projects, totals about $90 million.

[Stephen Byrd, analyst]

Understood.

[John Ketchum, executive]

So let's go back to what I just said, which is that, first of all, even if all of that cash is trapped, we expect to be able to meet our financial expectations, 12% to 15% growth and distributions per unit through 2023. We expect we'll not have a need to issue common equity until 2020 at the earliest. So our financial expectations are not impacted by any means by this. Second, the impact of PG&E and SCE cash flow, it's going to diminish over time. So by the time we get to the end of the period of our financial expectations, the cash flows from these projects is not going to be a significant contributor to the overall CAFD. And then I think you have to take a look too, Stephen, as to what is happening in California. I mean, obviously we're not going to sit on our heels. We're going to pursue all avenues with our note holders to try to free up that cash. And we'll work vigorously to do that as I said in the prepared remarks.

[Stephen Byrd, analyst]

That all makes sense. And John, in terms of any exposure to other California utilities? I'm thinking of Edison International and Sempra. Just wanted to check both at NEP and NextEra. Would you mind just speaking briefly to your other California exposure?

[John Ketchum, executive]

Yes. So on our other California exposures with SCE, I mean, right now we don't have any because there is -- none of those financings are in default other than the SCE contract that I mentioned, which is about 250 megawatts on Desert Sunlight because that's part of the portfolio financing. But again, the impacts of that are included in the numbers that I gave you earlier, so the 250 impact is included in the $0.13 to $0.15 at NextEra Energy. It is also included in the roughly 18% of total CAFD for 2019.

[Stephen Byrd, analyst]

Okay, but do you have any CAFD exposure, not in default, but where the off-taker is a subsidiary of either Edison International or Sempra?

[John Ketchum, executive]

No, 0.

[James Robo, executive]

At NEP.

[John Ketchum, executive]

At NEP. Zero.

[Stephen Byrd, analyst]

Okay, great, just wanted to check -- at NEP. And at NextEra, is that significant or is it relatively small?

[John Ketchum, executive]

It's relatively small. I mean, the contributions that we would have from SCE contracts are roughly $0.08. And that includes the Desert Sunlight 250. So without it, it's about $0.06. So small.

[Stephen Byrd, analyst]

Understood. Sorry for all the questions on California. Maybe just one last one, you filed at FERC to sort of secure your legal rights under the contracts, would you mind just to kind of briefly talking through your legal arguments around ensuring that you protect your rights under your contracts?

[John Ketchum, executive]

Yes. The bottom line is we think majority of those contracts have Mobile-Sierra provisions and that these contracts are in the public interest and that the Federal Power Act preempts what the bankruptcy court can do. And the FERC has the final say on assumption or rejection.

[Operator]

We'll now go to our next question and that will come from Steve Fleishman of Wolfe Research.

[Steven Fleishman, analyst]

So just first on the NEP plan, I assume you're -- embedded in there, you're assuming that you can continue to get financing other than equity, I assume, including some of the like private financings, converts and such that you've gotten in the past. How do you feel about the ability to get those with this California uncertainty?

[John Ketchum, executive]

First of all, on the financings, like the BlackRock financing, still feel good about our ability to be able to execute against those types of financings. And again, we also have a lot of debt capacity at NEP that we can always fall back on as well.

[Steven Fleishman, analyst]

Okay. And then just separate question, off-topic. Could you update your interest in -- thoughts and interest in Santee Cooper?

[James Robo, executive]

Yes. Thanks, Steve. This is Jim. We did put a proposal in to acquire Santee Cooper. I think I've been very clear that we have been interested in pursuing Santee Cooper over the last 18 months or so. And we did put a proposal in to acquire it. And we look forward to the next steps of the process that the committee is going to be going through.

[Steven Fleishman, analyst]

Do you have any idea when you will get an answer?

[James Robo, executive]

I think this is a process that ultimately has to -- if the legislature decides to sell Santee Cooper, it's going to have to actually pass a law to do so, essentially, and the legislative session ends at the end of May or early June, in that time period. So it's going to play out over the next several months, is the bottom line, Steve.

[Operator]

And now we will go to Julien Dumoulin-Smith of Bank of America Merrill Lynch.

[Julien Dumoulin-Smith, analyst]

Congrats, Armando. Can you hear me?

[John Ketchum, executive]

Yes.

[Julien Dumoulin-Smith, analyst]

Just one quick clarification on the FERC strategy under NEP and then I'll move away from it. But just, if there is indeed some kind of stay, how does that impact the technical defaults on the possibility of distribution? Just want to clarify that. Or cash in PG&E for that matter?

[John Ketchum, executive]

Yes, from a FERC standpoint, if there were a FERC -- well, first of all, if FERC were to ramp the release that we're seeking by the end of the week, I think it just would grant FERC the final say and what happens to the contract. So I don't think it really has any impact on the status of the existing financings.

[Julien Dumoulin-Smith, analyst]

Got it. Okay. Fair enough. Excellent. And then I just want to turn back to FPL real quickly. Specifically, on the last call you talked about having, should we say, adequate reserve amortization. You also talked about usage trends, et cetera, and the ability to potentially avoid base rate increases in '21 and '22. Where does that stand now? How, if at all, is that impacted by some of the latest events? Just curious on how you're positioning FPL into the longer term here?

[John Ketchum, executive]

Yes. I don't think it's impacted by any of the current events. We feel very good, very good about our position in front of the OPC, if that Julien was what you're referring to as other events. We've ended the year...

[Julien Dumoulin-Smith, analyst]

Or maybe to be more specific, would you be expecting to pen something more formal about a further rate stay-out?

[John Ketchum, executive]

Well, here is where we are right now. We have $540 million of surplus ending the year. We have -- we believe and expect to have enough surplus to potentially stay out of a rate case for '21 and '22. We will make those strategic rate case decisions later. But we have a lot of flexibility and that flexibility is very good for Florida customers because the longer we are able to stay out, the longer period of time that bills stay where they are and they don't see a bill impact from another rate case.

[James Robo, executive]

Julien, this is Jim. I think you can expect us to give you all some more thoughts on that front in the June investor conference.

[Julien Dumoulin-Smith, analyst]

Excellent. And then maybe, Jim, this is a quick question in your direction. But as you've been kind of conceptually, especially given the commitments in the last analyst day around midstream, potentially some of the latest developments you've already alluded to around renewables, especially some of the RPS expansions that might be coming in the next 6 months prior to the June Analyst Day. Could you give us a little bit of your latest thought process around your future investment prospects, just a little bit more holistically?

[James Robo, executive]

Yes, sure. I mean, when you look at our capital investment plans, I think they are over $12 billion this year. When you look at what we're doing at FPL, Gulf and Energy Resources combined, something in that range. We're as of the year before last, we don't have the details yet on last year, we were the fourth largest investor of capital in The United States in any industry. Only AT&T, Verizon and Amazon invested more in this country than we did in terms of capital investment. And we're going to continue to do what we have done for more than a decade, which is invest smart capital at FPL to improve the value proposition for customers. And we're going to -- we're very excited about and we'll have more to say about what we're doing at Gulf in our June meeting. But we have hit the ground running, very excited about what we're doing in terms of what investment prospects there are on the Gulf front, and we're moving aggressively forward on that pretty much on day one. And at Energy Resources it is the best renewable environment that we've ever seen and we're going to continue to invest in renewables going forward and as we see pipeline opportunities, contracted pipeline opportunities, we will continue to invest in those as well. So I don't think you should expect a big change in our thinking in June, I think you'll just see us, frankly, roll forward our vision for the amount of investment and the amount of customer improvement that we're going to bring to our customers as well as the amount of -- what we're going to do in terms of earnings going forward.

[Operator]

We'll now go to Greg Gordon of Evercore ISI.

[Greg Gordon, analyst]

Yes, congratulations to all three of you, it goes without saying you're all terrific at your jobs, and Armando someone asked me to ask you, if you could get -- circle back with people and tell us where you like to fish, that would be good. Now that you're going to have all this free time.

[Armando Pimentel, executive]

Terrific, that's coming.

[Greg Gordon, analyst]

Couple of questions. Can you just go back over what you said about the levelized cost of energy for battery with storage? And what I am particularly interested other than just a restatement of that is, what delivery year you see that crossover happening on sort of a large enough scale to tip this sort of disruptive transition that you're talking about?

[John Ketchum, executive]

Yes. So what we covered in Jim's remarks, we'll start with the wind. So wind, we are expecting to be right around $20, $25 a megawatt hour. I'd kind of put that, we're going to have some PTC help in there, this is a no-incentive look. So call it when those incentives expire, more towards the middle of the decade that 2024 time frame. So $20, $25 a megawatt for wind. And we think batteries are going to be about $0.005 to $0.0075 adder. And so that's how we're able to -- I'm sorry, per megawatt. That's how we're able to get to the ranges that Jim provided for wind. So just take the $20 to $25 add-on $0.005 to $0.0075 for battery storage. For solar, don't forget, we have the solar ITC at 30% through the end of 2023. And so when those ITC's go away, and they don't ever go away, right, they go from 30% to 10%, we're expecting that we -- solar, given how quickly panel costs are coming down, balance of plant costs are coming down, solar is a product we're going to be selling in $25 to $30 megawatt hour range and then the same adders for batteries is how you get to the math that were in Jim's remarks. And those are the expectations we have. And the solar pricing isn't really all that far off from what we're doing today. So that's not much of a leap of faith.

[Greg Gordon, analyst]

Yes, okay, that makes sense. Last question. You didn't mention it explicitly anywhere in your comments, but the balance sheet capacity of $5 billion to $7 billion, I mean, your credit metrics and the position on the balance sheet seems unchanged from last quarter. So I would assume that you still feel like that balance sheet capacity is in place?

[John Ketchum, executive]

Yes, Greg, one of the things that we said there is that, we had $5 billion to 7$ billion, right. We bought Trans Bay that was $1 billion. So we took that down, call it $4 billion to $6 billion. And we're earmarking probably another $2 billion of CapEx opportunities for FPL. We'll update where exactly that will be used at our June conference, but certainly some of that money is going to go towards the 30-by-30 initiative that we already announced earlier last week.

[Operator]

We now will go to Michael Lapides of Goldman Sachs.

[Michael Lapides, analyst]

Obviously, Armando, congrats on your announcement and to the rest of the team, to John and Rebecca as well, great to see people move around and get new opportunities. One question about Florida, ballot initiative that is being pushed right now. Can you just talk about what is actually in that ballot initiative? What it would mean if it were to garner the votes and what's the process from here?

[James Robo, executive]

Yes. I'm going to turn that question over to Eric.

[Eric Silagy, executive]

Yes. The ballot initiative, it's being framed it's about helping Florida customers, but it's not about that at all. When you look at it, it's really about furthering the business interests of a few folks, including a retail electric provider that's located and based out of Gainesville, that markets power currently outside of Florida. This is a group, they have tried unsuccessfully to get this proposal in front of voters through the Constitution Revision Commission and also through the -- unsuccessfully they've tried through legislation in Tallahassee. Their efforts have been unsuccessful in the past because, frankly, Florida's regulated electricity market works really well. It's our -- when you look at the state, the power prices are among the lowest in the nation with electricity that's among the cleanest and most reliable in the country. As an example, Florida Power & Light offers our customers' bills that are more than 30% lower than the national average, lower than bills in 45 states. And as John said earlier, we're just recognized third time in four years as the most reliable electric provider in the country which, as you could appreciate, in a state like this is important when our customers need us most particularly during times of storms and hurricanes. So plain and simply it's a proposal that it just -- it actually will lead to increases in electric rates across the state, reduce reliability, particularly during periods of storms, hurricanes, things of that nature, and I think it's going to compromise the clean energy goals that have been announced, including the one we just did on FPL's 30-by-30 initiative, as the unregulated power producers would -- they would have no restrictions on the type of generation that they would build. Also, I think it's important to understand on these type of things that consumer protections are removed. You'll no longer have Florida Public Service Commission role in determining what rates are. They would no longer be viewed as being just and reasonable, if that's the standard, it would go out the window, and that's going to impact reliability as well. The ability of the customers -- this language would actually prohibit customers from being able to buy power from the existing utilities, so Florida Power & Light customers would not be able to continue to be customers of Florida Power & Light. There are some other areas too that I think there could be a lot of focus on, including the fact that franchise fees, which we collect and pay to municipalities across the state would be eliminated. And that is a significant amount of revenue that would no longer be available to pay for things like first responders, firefighters, police, hospital employees of these municipalities that everybody counts on. Even if you look at it now, Attorney Generals in a number of other states have called for the end of deregulation due to all the consumer complaints and the deceptive trade practices. So there are a lot of reasons why these proposals have failed across the country since, frankly, the early 2000s. You look at, including even recently in Nevada, where it failed. There's -- when you look at other states that look at this, a lot of them backed away, particularly after the California crisis, when Enron moved into California to take advantage of their so-called market-based model, which was ultimately the catalyst for that crisis, and helped contributing to state having some of the highest power prices in the country. So I don't think it's by accident that there hasn't been a state that's passed deregulation since the California power crisis which occurred now nearly 20 years ago. So there's a number of hurdles, to answer your question that have to be cleared for this proposal to go forward, to be placed on the ballot. We're going to be very actively engaged, we're going to be educating Floridians on the true motives of the special interest groups, and we're going to also spend a lot of time educating folks on the significant negative impacts that this failed idea would have on the state and on their pocketbooks.

[Michael Lapides, analyst]

I have one other for either Jim, John or Armando. And this is more longer term. When you're watching what's happening in California with PG&E, with Edison International or SoCal Ed and put California in the context of being the nation's largest renewable market and with the most aggressive renewable target, how do you think this impacts the broader U.S. development of renewables, if one of the largest markets is going through some turmoil? And how do you think about that kind of longer term?

[James Robo, executive]

Great question, Michael. I think one of -- the first thing I would say is, California has some very aggressive renewable targets and some very aggressive climate change goals. The turmoil around the credit of the most important counter-parties in the state is, to say the least, is not conducive to continued capital investment to continue to further those goals. And so I think it's from an energy policy standpoint in the State of California, it's going to be very important for the state to recognize that and to recognize that there's been significant capital investment by companies from around the world to make that happen and to the extent that, that investment is somehow diminished by these credit issues. I think that's going to have a real impact on their market going forward. And I think the state understands that. And it's one of the elements of the things that they are grappling with now as they deal with the fallout from the tragic fires as well as some of the other issues that they've been facing. So the good news from a market standpoint is, California was obviously the biggest market in the country 10 years ago in the renewable business, it isn't anymore. It's an important market, but it's no longer the most important market in the country. And with the cost declines in renewables, nearly every state in the country is in the -- we have an opportunity to do business in. I mean, we have -- my last count, we have development going on in 48 states right now. We don't have operating projects in 48 states, but we have development going on in 48 states. So while I think it's very important for the state to address these issues from a climate change standpoint going forward, I think the renewable market is going to be robust going forward because it has just gotten so big, and the cost declines have expanded the market to such a dramatic fashion.

[Operator]

And with that we'll go now to Jonathan Arnold of Deutsche Bank.

[Jonathan Arnold, analyst]

Quick question. This is how I think about your -- you talked about managing through other situations at NEP in context of the growth rate. So as we think about things you might do that would fall under that header, you mentioned pushing to have the cash released. I guess, you could drop down on other assets more quickly. You could let the dividend drift down in the range and still be within 12% to 15%. Is there anything else I'm missing, and which of those kind of alternatives would you either be planning to use or not use?

[John Ketchum, executive]

I think I'll go first of all back to the prior -- one of the prior questions about are there other attractive financing vehicles available. One, yes. We think there are. But two, even if we had the finance additional drops to meet our financial expectations with existing debt capacity that we have, we can do that. We're fine. And so really the way I would answer that question is that obviously we'll vigorously try to put -- to negotiate something with the holders that would allow us to, and the DOE, don't forget the DOE, is in all of -- is in these projects, that would allow us to free up the cash, we can't do that. We have debt capacity, plenty of debt capacity at NEP. Energy Resources is coming off the best development year in its history. We have very clear visibility to growth prospects going forward. And there are many levers in the vehicle. So we are comfortable in our ability to manage through even a worst case scenario, which would be where the cash is trapped until a final call is made on the contracts.

[Jonathan Arnold, analyst]

Okay, but John, I think to be clear, you said in some of them the cash is trapped just by virtue of PG&E saying that it may file, is that correct?

[John Ketchum, executive]

Yes, not to get into the technicalities but one of the financings has a provision that basically just says if there is corporate action taken in furtherance of a bankruptcy, which our lawyers view the filing of the 8-K to be that, that would constitute -- potentially constitute an event of default.

[Jonathan Arnold, analyst]

So that was just on one of them.

[John Ketchum, executive]

That's on the Genesis financing. It's on some of the other NEE financing, but the NEE financings are small, it's a series of four or five projects that don't have any meaningful contribution or earnings at NEE.

[Jonathan Arnold, analyst]

So there would be sort of a judgment as to what would definitively constitute that not occurring, presumably.

[John Ketchum, executive]

Yes. I mean, if it doesn't happen then I think it's back to business as usual.

[Armando Pimentel, executive]

Jonathan, let me just add -- just let me add something. Obviously I think it's appropriate to focus on the PG&E assets and the cash flows, but we still have both at NextEra Energy Resources and at NextEra Energy Partners, we still have a lot of projects that are not PG&E as Southern California Edison Projects that have significant cash flows. And there are still many parties that are interested in attractive financings, attractive for us, and presumably for them that we're talking to. And it's not necessarily about what's the risk of PG&E in Southern California Edison, it's about what, hey, what other assets are available for us to be able to enter into those types of financing. So I think, while it's appropriate to have some focus on what's going on with PG&E we got to remember that NextEra Energy Resources has had its -- we had 6,600 megawatts of origination this year, which is a record year and that's twice the amount we had last year, which was a record year. And I got to tell you, we feel, at least internally, very comfortable. As John said, that even if these PG&E cash flows are tied up in these debt financings that we can meet our current expectations. And one of the reasons that we feel that way is because we're talking to the market, and two, origination is going very well in Energy Resources.

[Jonathan Arnold, analyst]

Could I just -- one other thing, with the Gulf and Florida acquisitions having closed sooner, I think, than maybe you thought, is there -- but you're not talking of any accretion in '19 that would just sort of help us understand the bump in '20, what's driving that? And why nothing there yet?

[Armando Pimentel, executive]

So Jonathan, obviously, we got it done a little earlier than we thought, but we also always assume we would have some cost to achieve this year to get there. So we're being conservative as we always are. And we feel very good about our plans at Gulf. And you can bet I am pushing the team very hard to get things done even faster than we've laid out. And so I'm really optimistic about the future for Gulf in this company, and in our ability to bring real value to their customer and real value to shareholders. So very excited about it. We'll have more to talk about it in June. But remember we don't have any cost to achieve in any of these numbers in '19.

[Operator]

And with that ladies and gentlemen, that does conclude today's conference. We want to thank you, again, for attending today's presentation.