2-Year Budget Bill Extends Nuclear Production Tax Credit by Norris McDonald

The 2-year budget bill passed last night extends the Nuclear Production Tax Credit.

The 2005 Energy Policy Act provided a tax credit of 1.8 cents per kilowatt-hour for electricity produced from new reactors, but set a deadline of 2020 for the plants to be in service. The new bill removes that deadline, which would ensure that the two Westinghouse AP1000 reactors being built at Southern Nuclear Operating Company's Vogtle site in George could benefit from the credit. 

Center President Norris McDonald at signing of Energy Policy Act of 2005

Center President Norris McDonald at signing of Energy Policy Act of 2005

[Note: The Center worked diligently for the passage of the Energy Policy Act of 2005 and particularly for the inclusion of the Nuclear Production Tax Credit.  It was for this work that Center President Norris McDonald was invited to attend the signing of the legislation as a Special Guest of The White House in Albuquerque, New Mexico].

Unforeseen events—the Chapter 11 filing by Westinghouse, regulatory delays associated with first-of-a-kind engineering projects, and Fukushima—will result in the units coming online after 2020, therefore missing the opportunity to receive the PTC.

The tax credit is applicable to the first 6,000 megawatts of new nuclear capacity that come online. The completion of Vogtle 3 and 4 will leave a significant amount of remaining capacity that future small modular or advanced reactor projects will be able to access.

The small modular reactor design closest to construction is from NuScale Power LLC, which in January became the first to submit a design certification application to the U.S. Nuclear Regulatory Commission. NuScale plans to build a first commercial power plant at the U.S. Department of Energy’s Idaho National Laboratory, owned by Utah Associated Municipal Power Systems and operated by Washington state-based utility Energy Northwest. It is expected to begin commercial operations by 2026.  (NEI, 11/2/2017, Background/NEI, Greentech Media, 2/9/2018)

Wind Power Rivaling Hydropower As Clean Energy Source by Norris McDonald

Wind power is forecast to surpass hydroelectricity for the first time as the nation’s top source of renewable electricity sometime in the next year, according to the U.S. Energy Information Administration.

The sector is expected to produce 6.4 percent of utility-scale electricity in 2018, and 6.9 percent in 2019, propelled by a construction boom of new turbines across the country.

EIA: A chart from the Energy Information Administration shows the rapid growth of wind energy generation since the early 2000s.

EIA: A chart from the Energy Information Administration shows the rapid growth of wind energy generation since the early 2000s.

Few new hydropower plants are in the works, so new electricity generation depends on how much rainfall and water runoff pools in existing dams and reservoirs. Hydropower provided 7.4 percent of utility-scale generation in 2017 ― a particularly wet year ― but that figure is projected to fall to about 6.5 percent in 2018 and 6.6 percent in 2019.

The news marks a new milestone in wind’s steady rise. Wind energy usurped hydropower’s generating capacity for the first time in February 2017 as turbine installations tripled from 2008. 

The United States is projected to gain 37 gigawatts of new wind capacity between 2017 and 2020, according to Bloomberg New Energy Finance. The share of capacity increases each year, from 7 gigawatts in 2017 to a projected 11 gigawatts in 2020.

Part of what’s driving the boom is a rush to build turbines to get the full benefits of the production tax credit. Congress extended the subsidy, which has been in place since the early 1990s, for five years in 2015. But the credit began phasing down by 20 percent in 2017, kick-starting a dash to build as many turbines as possible before the federal benefit expires.

Yet states are expected to continue providing incentives for wind energy long after 2020. The offshore wind industry ― a popular form of energy in Europe, though currently limited in North America to five turbines off the coast of Block Island, Rhode Island ― is only expected to gain steam after 2021, according to BNEF. For example, in New York, where the state plans to get half its electricity from renewables in 12 years, a series of projects off the coast of Long Island are expected to provide 2.4 gigawatts of energy by 2030, enough to power 1.25 million homes.  (Huff Post, 11/24/2018)

Block Island Wind Farm by Norris McDonald

North America’s first offshore wind farm, Block Island Wind Farm, started operations in November 2016 and includes five wind turbines that tower 589 feet above the sea and power the homes of the island’s 1,000 year-round residents. . When it is running at full capacity, the farm will generate enough electricity to power 17,000 homes, or about 4 percent of all households in Rhode Island.

Block Island Wind Turbine.png

Cape Wind, a 130-turbine offshore wind farm planned five miles to the north off the coast of Massachusetts, was supposed to be the first in the country. That project was proposed in 2001 ― but for numerous reasons, has never actually gotten started and probably never will. Cape Wind’s struggles provided an instructive example of what not to do for Deepwater Wind, the Providence-based developer behind Block Island farm.

Where Cape Wind’s blueprints went big with 468 megawatts of power, Deepwater aimed for a more modest 30 megawatts. Cape Wind estimated its costs at $2.5 billion, while Deepwater came in at about $300 million. Block Island Wind Farm also had a smaller footprint and fewer, less powerful opponents to win over. Cape Wind has famously drawn opposition from people with surnames like Kennedy and Koch, who didn’t want windmills obstructing their beachfront views. Environmentalists, too, feared noise from the construction could disturb migrating whales.

Deepwater Wind also had another advantage over Cape Wind: Its CEO, Jeff Grybowski, was previously chief of staff to former Rhode Island Gov. Donald Carcieri (R) and had access to state officials he’d later court for his wind project. It took seven years to complete the project, and Grybowski said he spent six of them navigating the Byzantine web of government agencies whose approval he needed.

Grybowski did have obstacles. Environmentalists had some of the same concerns about Block Island Wind Farm that they had about Cape Wind, and the project was halted for weeks to avoid harming right whales swimming north in the early spring months. Some on Block Island still complain that the turbines, roughly twice the height of the Statue of Liberty, are an eyesore. 

Block Island Wind Turbine 1.jpeg

There was also deep skepticism from Rhode Island’s fishing industry. Overfishing and climate change had already hammered local populations of winter flounder and lobster ― leading to strict new catch limits to preserve the future of those species and new struggles for the industry. The proposed wind farm seemed like another unwelcome development that could interfere with fishing.

Wind industry leaders hope Block Island Wind Farm signals the beginning of a boom offshore. There are already 13 other projects in various stages of development around the country, most of them in federal waters far offshore rather than in areas under state control. Massachusetts Gov. Charlie Baker (R) signed a bill in August that requires utilities in that state to buy up to 1,600 megawatts of power from offshore wind developers. That same month, New York Gov. Andrew Cuomo (D) announced plans for his state to draw half of its power from renewable sources by 2030. Both of those policies are expected to help the offshore wind industry take off.

Deepwater Wind is already leasing two more parcels of land totaling 164,750 acres off the coast of Rhode Island and Massachusetts, which it plans to develop into a much larger, utility-scale farm with up to 200 turbines. By next spring, it also plans to send oceanographers to survey an area off the coast of Long Island where they hope to build a 15-turbine, 90-megawatt farm.

The firm wants to connect the Long Island farm to its bigger farms to the north through a transmission cable, creating a wind energy network along the Northeast coast. Unlike Block Island Wind Farm, which is nestled close to Block Island, the other farms will be located up to 25 miles offshore, where winds tend to be much stronger and more reliable.

The biggest obstacle to developing offshore wind energy may be its price. Deepwater Wind chose the site three miles off Block Island in part because of the island’s high energy prices. Residents had relied on electricity produced from burning diesel, paying upward of 50 cents per kilowatt hour in the summer  ― 287 percent more than the average American.

Deepwater Wind estimates that drawing from their power will lower residents’ power bills 40 percent. But that’s partly because mainland Rhode Islanders are footing the bill.

The company brokered a 20-year deal to sell National Grid wind power at 24.4 cents per kilowatt hour ― more than twice the price the utility pays for energy now. What’s more, the deal is written to allow a price increase of 3.5 percent per year. By the time the agreement expires, National Grid will be paying a rate of 50 cents per kilowatt hour to Deepwater Wind, a cost likely to be passed on to ratepayers in the state as a price increase.

For Deepwater Wind and its chief investor, that means a handsome payday. The project could generate more than $900 million in profit, according to calculations by Forbes, and that’s before you factor in $100 million in federal tax credits allotted to clean energy projects.

Another challenge may be the supply chain for turbine components, most of which did not come from Rhode Island. For these five turbines, Deepwater Wind enlisted General Electric to build the 240-foot blades in Denmark, while the nacelles, which house the gears and engines, are built in France. About 300 laborers from Rhode Island were joined by offshore rig workers from Louisiana, where the steel bases for the towers were built. The cable that connects the farm to shore came from South Korea.

Still, tiny Rhode Island — and its total population of 1 million; eight times smaller than New York City ― wants to be a pioneer in the U.S. offshore industry.  (Huff Post, 11/3/2016)

 

https://www.huffingtonpost.com/entry/deepwater-offshore-wind-farm_us_581a311fe4b0c43e6c1d9715

New California Public Utilities Commission Fire Safety Regulations by Norris McDonald

On December 14, 2017, the California Pubic Utilities Commission (CPUC) adopted new fire-safety regulations designed to require the state’s electric utilities to:

  • Increase clearances between vegetation and power lines,
  • Conduct annual patrol inspections of overhead distribution facilities,
  • Prepare fire prevention plans, take other steps to mitigate fires in high-risk zones, and
  • Establishes a High Fire-Threat District map to inform where these actions are needed most.

This new policy includes significant new fire-prevention rules for utility poles and wires, including major new rules for vegetation management.  The map includes a broader definition of fire threat and also shows how dramatically climate impacts are increasing fire risks -- land that is covered in the elevated, high and tree mortality fire hazard areas has grown from 31,000 square miles to 70,000 square miles. That’s 44 percent of California’s total land area.

Utilities would also be given greater authority to disconnect customers who refuse to allow crews to remove trees on their property that pose a fire risk.  The new regulations will affect a newly established designation of land in California, the “high fire-threat district.” A detailed map, developed in concert with the California Department of Forestry and Fire Prevention, will show areas of the state with an elevated fire risk. The maps are expected to be finalized sometime next year.

Utilities will be required to increase the minimum clearance between electrical equipment, including power and transmission lines, and trees and other vegetation.  Utilities would also be given greater authority to disconnect customers who refuse to allow crews to remove trees on their property that pose a fire risk.  

Southern California has been under siege from multiple wildfires, pushed by the fiercest Santa Ana winds to hit the region in a decade.  The Thomas Fire -- the largest and most destructive fire currently raging in the region -- grew to 250,000 acres and claimed the life of a young fire engineer.  

SDG&E sought to recover $379 million, which represents a portion of the $2.4 billion in costs and legal fees the utility incurred to resolve third-party damage claims from the Witch, Guejito and Rice wildfires. In all three cases, SDG&E was found guilty of imprudent management.

For investor-owned utilities, the inability to recover costs from a natural disaster presents a fundamental business risk.  How can California utilities continue to attract smart investment if there’s a fear in the investment community that there might be an undue risk associated with their ability to recover a fair rate of return because of wildfires?

It is unfair to put the burden squarely on energy companies for this reason because fires are a societal issue. It’s an issue that involves better forest management, more resources and training for the first-responder community, and possible changes to building codes and land-use planning. Utilities also need to come up with new ways to prevent fires and ensure grid resilience.  (Green Technology Media, 12/18-2017, San Francisco Chronicle, 12/28/2017)

Southern California Edison Under Investigation For Causing Wildfires by Norris McDonald

Wildfire4.jpg

SoCal Edison has admitted they are under investigation for possibly being the cause of one or more wildfires around Southern California that broke out last week.  Investigators say the utility company had equipment near where one of the fires started and are not ruling it out as a cause. The Thomas Fire near Santa Barbara is in its second week and still only 25 percent contained. Cal Fire and other agencies are not yet giving details into the probe.

Socal Edison released this statement:

The causes of the wildfires are being investigated by Cal Fire, other fire agencies and the California Public Utilities Commission…SCE believes the investigation now includes the possible role of its facilities.

A Socal Edison spokesperson would not say which fires they are under scrutiny for but said it’s more than one.

Investigators will go over 911 calls and backtrack to where the fires started.  They’re acknowledging their equipment is in those areas, but they’re not acknowledging they started those fires.

California has a history of wildfires started by winds pushing trees into power lines. In 2007, SoCal Edison was fined for the Malibu fires. In Northern California, PG&E is being investigated for the possible cause of recent fires.  (CBS Los Angeles, 12/12/2017)

Electric Utilities Key To Wildfire Protection? by Norris McDonald

Electric utilities in California want ratepayers to pay for lines destroyed by wildfires but do not appear to be in a hurry to share their transmission and distribution line maps.  We think a nice compromise might be to share those maps in exchange for ratepayer support for line replacement and a utility-led wildfire prevention program that would use firebreaks because they already have the right-of-ways.  State legislation would still be needed to expand cutting in these utility line right-of-ways (we need about a one-mile firebreak in wildfire areas.  Professionals in the wildfire area could work with utilities to prepare a grid that would be effective in preventing these very destructive wildfires.

TransmissionWind.jpg

The Center has a Wildfire Mitigation Program that provides a road map for how the State of California could design a program for wildfire prevention.  Because of the convoluted nature of such a program, state legislation is needed to design such a complex program.  This is because there is no profit for insurance companies in wildfire prevention and only budget cuts for state agencies that would reduce wildfires.

Utilities should embrace wildfire prevention as part of their utility line replacement.  This support could also be an important pathway for wildfire prevention legislation approval since utilities are already lobbying to get approval for line replacement.  Utilities also already have the equipment in place to implement expanded firebreaks along their transmission and distribution line network.  Their efforts could be supplemented by state program equipment and personnel.

We can prevent these devastating wildfires, but there is no incentive to do so.  All of the incentives are on the fire fighting side of the equation.  Yet that equation is devastating for the residents of California who live in wildfire areas.

Wildfire3.jpg

California Wildfires Can Be Prevented With Firebreaks by Norris McDonald

NorrisGreenLeaf.jpg

PRESIDENT'S CORNER

By Norris McDonald

The 2017 wildfire season in Northern California has led me to address the unwillingness of the state to adequately address wildfire prevention.  The Center thoroughly researched this issue in 2011 and found that wildfire prevention falls between the cracks, particularly in comparison to the Wildfire Industrial Complex (WIC), which includes the insurance companies, state agencies and fire departments.  The primary attention is placed on fighting fires and not on preventing them.  The Center Wildfire Mitigation Program is designed to address uncontrollable wildfires.  We were promoting a wood chip to energy program that would utilize the cut wood in wildfire areas to produce electricity.  In meeting with the California Department of Insurance, we realized that there was no practical way to include wildfire prevention in the rate approval process.

Our primary solution to wildfires is the firebreak.  Strategically placed firebreaks could prevent the vast majority of wildfires.  We discovered that there is no institutional structure or combination of institutional structures that can approve a firebreak prevention program.

The California Department of Insurance regulates insurance rates through its Rate Regulation Branch.   The Rate Regulation Branch (RRB) determines whether rates charged to consumers in California are fair (not excessive, inadequate or unfairly discriminatory).  RRB analyzes filings submitted by property and casualty insurers and other insurance organizations under California's prior approval statutes for most property and casualty lines of business. In addition, the RRB analyzes filings submitted by property and casualty insurers and other insurance organizations under California's file and use statutes for a limited number of property and casualty lines of business.

Unfortunately, there appears to be no incentive for insurance companies to engage in wildfire prevention,.  Where is the constituency or client base requesting or willing to pay for such a service.  It does not exist.  In other words there is no profit in wildfire prevention.  And this is tragic considering that this year's wildfire season took an number of lives and property, it is amazing that there is little to no efforts being given to preventing these disasters.

Approximate 40 lives have been lost, hundreds of people are still listed as missing, hundreds of thousand of acres have been scorched, and thousands of homes and businesses have been lost.  One would think that there would be more serious consideration given to preventing these disasters than sitting back and preparing to go through it all over again.  State agencies address fire prevention efforts but the firebreak solution does not appear to be seriously considered.

Wildfire3.jpg

The California Department of Forestry and Fire Protection (CAL FIRE) is dedicated to the fire protection and stewardship of over 31 million acres of California's privately-owned wildlands. In addition, the Department provides varied emergency services in 36 of the State's 58 counties via contracts with local governments.  The Department's firefighters, fire engines, and aircraft respond to an average of more than 5,600 wildland fires each year. Those fires burn more than 172,000 acres annually.

As part of the CAL FIRE team since 1995, the Office of the State Fire Marshal (OSFM) supports the CAL FIRE mission to protect life and property through fire prevention engineering programs, law and code enforcement and education. The OSFM provides for fire prevention by enforcing fire-related laws in state-owned or operated buildings, investigating arson fires in California, licensing those who inspect and service fire protection systems, approving fireworks as safe and sane for use in California, regulating the use of chemical flame retardants, evaluating building materials against fire safety standards, regulating hazardous liquid pipelines, and tracking incident statistics for local and state government emergency response agencies.  The OSFM, State Fire Training, and CAL FIRE Academy programs provide training education and certification programs for the California Fire Service. 

We understand that hundreds of miles of one mile wide firebreaks is well beyond the powers of any one or even multiple agencies to regulate,  so the state legislature needs to design and pass legislation to design a wildfire firebreak program that can prevent these devastating wildfires.  

 

Electricity Supply Rates By State by Norris McDonald

Electricity Rates By State

In recent years, many states have adopted a deregulated energy market that allows residents to shop for the supply portion of their energy rather than automatically getting it from their utility – a right known as energy choice. Deregulation changed the world of energy, which is reflected in price differences across regulated and deregulated energy markets. Here, we’ve compiled data to show you just how much energy costs can vary, including historical energy supply prices from the U.S. Energy Information Administration (EIA) in all 50 states. Information on recent rates and fluctuations may help you understand your bill or decide to change your energy supply plan.

Familiar with energy choice and want to sign up for a new plan? Enter your ZIP code above for rates you can secure today. 

Residential Rates by State | Commercial Rates by State | States with Lowest Rates

Vogtle Plant In Georgia Might Not Be Completed by Norris McDonald

With a multibillion-dollar nuclear project in South Carolina dead, the fate of America’s nuclear renaissance now rests on one utility: Southern Co.

Vogtle Plant Construction Site

Vogtle Plant Construction Site

Scana Corp. dropped plans for two reactors Monday, leaving the two that Southern is building at the Vogtle plant in Georgia as the only ones under construction in the U.S. And even they are under threat: The utility had to take over management of the project from its bankrupt contractor Westinghouse Electric Co., and the plant is still years behind schedule and billions over budget. Now it must decide whether to finish them.

Southern calling it quits could prove to be the final nail in the coffin for the long-awaited U.S. nuclear renaissance that has failed to materialize in the aftermath of Japan’s Fukushima nuclear accident. In 2012, Southern and Scana became the first companies to gain approval to build U.S. reactors in more than 30 years -- only to find themselves in troubling times for the industry.

On top of construction setbacks and ballooning costs, nuclear plants are reeling under intense competition from cheap natural gas and renewables that have spurred states led by New York to go as far as offering subsidies for existing reactors to keep them open.

Although Southern faces many of the same challenges that led Scana and Santee Cooper, the state power authority with a 45 percent stake in the project, to shelve their reactors, the company was quick to put some distance between the two. 

In scrapping the South Carolina project, Santee Cooper said an analysis showed the plant would not be completed until 2024, four years after the most recent target provided by Westinghouse, and would end up costing its customers a total of $11.4 billion.

Meanwhile, Georgia’s utility regulator is keeping up the pressure on Southern to make a final decision on whether to go forward with the reactors by the end of the year.  Southern secured a $3.7 billion payment guarantee from Westinghouse’s parent, Toshiba Corp., dwarfing the $2.2 billion guarantee for Scana’s project.  Southern also has more co-owners on the project, and the rate impact is spread across a bigger customer base.  (Bloomberg, 7/31/2017)

SCANA Abandons Nuclear Power Plant Construction Project in SC by Norris McDonald

VC Summer construction site

VC Summer construction site

One of the co-owners of the SCANA V.C. Summer nuclear power plant has announced that halting work would save customers almost $7 billion.  The bankruptcy of nuclear-plant builder Westinghouse Electric Co. led to this announcement.  Scana Corp., which has a 55 percent stake in the project, said it will ask the Public Service Commission of South Carolina to approve its abandonment plan, according to a statement on Monday. 

The decision to halt the expansion of the V.C. Summer plant comes four months after Westinghouse filed for bankruptcy and underscores the financial challenges facing U.S. nuclear power. 

Scana’s decision threatens to weaken the business case for the Vogtle reactors as the two companies could have sourced materials and services together. Scana slumped the most in more than two years late last week after the utility said the V.C. Summer expansion faced “significant challenges.”

Just last week, Scana and Santee Cooper secured a $2.2 billion payment guarantee from Toshiba Corp., the parent of Westinghouse. Still, Scana said the plants would face additional costs, casting doubt over whether they would be completed. That marked a shift from the end of March when Scana Chief Executive Officer Kevin Marsh said that scrapping the project would be the “least preferred option.” 

Monday’s decision came after Santee Cooper, the state power authority with a 45 percent stake in the new reactors which came up with the $7 billion estimate, said it wouldn’t be in the best interests of its customers to continue. Scana cited Santee Cooper’s decision to halt work, as well as uncertainty over the availability of production tax credits and the amount of payments guaranteed from Toshiba.

Westinghouse is “disappointed” by Santee Cooper’s decision to halt work at both reactors, the Cranberry Township, Pennsylvania-based Toshiba unit said in a statement. The company said it will work with Scana to close out the project.  (Bloomberg, 7/31/2017)

Green Banks by Norris McDonald

Center Green Carbon Bank

Center Carbon Mercantile Exchange

One permutation of the green bank is a public-private institution that helps private-market participants reduce greenhouse gas emissions through projects by stepping in to support projects that might get a pass from a traditional lender. 

State-formed green banks are creating new ways to finance renewable energy and energy efficiency projects that previously have gone under-served.

One example is NY Green Bank, a $1 billion state-sponsored entity that mobilizes clean energy investment and projects within New York state.

NY Green Bank deals with providing financing to developers of solar projects that are selling to commercial, industrial and other institutional organizations. It also deals with providing financing to commercial and multi-family building owners  seeking to make renewable or energy efficiency improvements. 

The NY Green Bank shows that despite President Donald Trump’s support for fossil fuel projects, state and municipal governments are playing a larger role in furthering clean-energy policies and reducing greenhouse gas emissions. In addition, they support New York Gov. Andrew Cuomo’s Clean Energy Standard, which requires that 50 percent of New York’s electricity come from renewable sources by 2030.

In New York, the green bank projects that the funds ultimately will create between $1 billion to $1.4 billion in investment in clean energy projects in New York state.

Green banks use public dollars to encourage deeper private investment in clean energy. And they can provide financing in different ways, including through credit enhancements, directly investing in clean energy projects and even originating and financing loans through a process known as warehousing.

Connecticut established the first green bank in the United States in 2011. Today there are six in states including Michigan, Hawaii, New York and Rhode Island.

Connecticut Green Bank, the oldest state-formed U.S. green bank, has created over $1 billion of total clean energy investment in the state, using less than $200 million of public capital for project investment. By the end of the 2016 fiscal year, the green bank had deployed $164.9 million in public capital and leveraged $755 million in private capital.

Green banks exist to fill financing gaps in the clean energy marketplace that exist, in part, because of a lack of standardization in the process. That fragmentation, along with the relatively short track record for such investments, may make it difficult for traditional commercial banks to offer developers terms that are economically viable. This is where green banks step in and can provide financing.

According to the Coalition for Green Capital (PDF), a green bank may provide debt or equit in a project, which can then be paired with a private investment. For example, a green bank and a private investor could both take a 50 percent debt stake in a specific project or installation.   (Green Biz, May 7, 2017)

Ivanpah Solar Power Tower Plant by Norris McDonald

Located in the Mojave Desert,California’s Ivanpah solar plant is the world’s largest solar power facility plant using concentrated solar technology, also known as solar thermal technology. Unlike the more familiar solar photovoltaic panels, concentrated solar works more like a conventional steam power plant. Instead of using fossil fuels or controlled nuclear reactions to convert water into steam, concentrated solar uses mirrors that focus the sun’s energy on a water source, creating steam that powers turbines.

The Ivanpah facility covers five square miles, uses three 450-foot towers to trap sunlight focused from an array of mirrors, and cost $2.2 billion to build, including a federal loan guarantee of $1.6 billion. A joint venture of NRG Energy, Google, and Brightsource Energy, the state-of-the-art plant was supposed to produce a net of 392 megawatts of electricity, enough power to supply 140,000 homes. 

Ivanpah was a real disappointment in terms of its actual electrical output. It also may have caused more environmental problems than it solved.

For starters, Pacific Gas & Electric (PG&E) signed a contract to buy electricity from Ivanpah, but the facility failed to produce enough electricity to fulfill its obligations to PG&E. This put California regulators in a tough spot, especially given the fact that customers of PG&E pay about $200 per megawatt hour for electricity generated by Ivanpah, making it some of the nation’s most expensive electricity.  In its first year, Ivanpah produced failed to generate even half of its expected output.

Ivanpah has been responsible for the deaths of thousands of birds, most which are scorched to death while flying through the super-heated air surrounding the plant. Construction of the plant also involved the attempted relocation of the local population of endangered tortoises, several of which were killed in the process.  (Pace Energy Fairness, 3/16/2016)

Trump Executive Order on Energy Independence by Norris McDonald

BACKGROUND BRIEFING ON THE PRESIDENT'S ENERGY INDEPENDENCE EXECUTIVE ORDER - MARCH 27, 2017

REMARKS BY PRESIDENT TRUMP AT SIGNING OF EXECUTIVE ORDER TO CREATE ENERGY INDEPENDENCE

Presidential Executive Order on Promoting Energy Independence and Economic Growth

EXECUTIVE ORDER

PROMOTING ENERGY INDEPENDENCE AND ECONOMIC GROWTH

By the authority vested in me as President by the Constitution and the laws of the United States of America, it is hereby ordered as follows:

Section 1.  Policy.  (a)  It is in the national interest to promote clean and safe development of our Nation's vast energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation.  Moreover, the prudent development of these natural resources is essential to ensuring the Nation's geopolitical security.

(b)  It is further in the national interest to ensure that the Nation's electricity is affordable, reliable, safe, secure, and clean, and that it can be produced from coal, natural gas, nuclear material, flowing water, and other domestic sources, including renewable sources. 

(c)  Accordingly, it is the policy of the United States that executive departments and agencies (agencies) immediately review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise, or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law. 

(d)  It further is the policy of the United States that, to the extent permitted by law, all agencies should take appropriate actions to promote clean air and clean water for the American people, while also respecting the proper roles of the Congress and the States concerning these matters in our constitutional republic.

(e)  It is also the policy of the United States that necessary and appropriate environmental regulations comply with the law, are of greater benefit than cost, when permissible, achieve environmental improvements for the American people, and are developed through transparent processes that employ the best available peer-reviewed science and economics.  

Sec. 2.  Immediate Review of All Agency Actions that Potentially Burden the Safe, Efficient Development of Domestic Energy Resources.  (a)  The heads of agencies shall review all existing regulations, orders, guidance documents, policies, and any other similar agency actions (collectively, agency actions) that potentially burden the development or use of domestically produced energy resources, with particular attention to oil, natural gas, coal, and nuclear energy resources.  Such review shall not include agency actions that are mandated by law, necessary for the public interest, and consistent with the policy set forth in section 1 of this order. 

(b)  For purposes of this order, "burden" means to unnecessarily obstruct, delay, curtail, or otherwise impose significant costs on the siting, permitting, production, utilization, transmission, or delivery of energy resources.

(c)  Within 45 days of the date of this order, the head of each agency with agency actions described in subsection (a) of this section shall develop and submit to the Director of the Office of Management and Budget (OMB Director) a plan to carry out the review required by subsection (a) of this section.  The plans shall also be sent to the Vice President, the Assistant to the President for Economic Policy, the Assistant to the President for Domestic Policy, and the Chair of the Council on Environmental Quality.  The head of any agency who determines that such agency does not have agency actions described in subsection (a) of this section shall submit to the OMB Director a written statement to that effect and, absent a determination by the OMB Director that such agency does have agency actions described in subsection (a) of this section, shall have no further responsibilities under this section.

(d)  Within 120 days of the date of this order, the head of each agency shall submit a draft final report detailing the agency actions described in subsection (a) of this section to the Vice President, the OMB Director, the Assistant to the President for Economic Policy, the Assistant to the President for Domestic Policy, and the Chair of the Council on Environmental Quality.  The report shall include specific recommendations that, to the extent permitted by law, could alleviate or eliminate aspects of agency actions that burden domestic energy production.  

(e)  The report shall be finalized within 180 days of the date of this order, unless the OMB Director, in consultation with the other officials who receive the draft final reports, extends that deadline.  

(f)  The OMB Director, in consultation with the Assistant to the President for Economic Policy, shall be responsible for coordinating the recommended actions included in the agency final reports within the Executive Office of the President.

(g)  With respect to any agency action for which specific recommendations are made in a final report pursuant to subsection (e) of this section, the head of the relevant agency shall, as soon as practicable, suspend, revise, or rescind, or publish for notice and comment proposed rules suspending, revising, or rescinding, those actions, as appropriate and consistent with law.  Agencies shall endeavor to coordinate such regulatory reforms with their activities undertaken in compliance with Executive Order 13771 of January 30, 2017 (Reducing Regulation and Controlling Regulatory Costs).

Sec. 3.  Rescission of Certain Energy and Climate-Related Presidential and Regulatory Actions.  (a)  The following Presidential actions are hereby revoked: 

(i)    Executive Order 13653 of November 1, 2013 (Preparing the United States for the Impacts of Climate Change); 

(ii)   The Presidential Memorandum of June 25, 2013 (Power Sector Carbon Pollution Standards);

(iii)  The Presidential Memorandum of November 3, 2015 (Mitigating Impacts on Natural Resources from Development and Encouraging Related Private Investment); and

(iv)   The Presidential Memorandum of September 21, 2016 (Climate Change and National Security).

(b)  The following reports shall be rescinded: 

(i)   The Report of the Executive Office of the President of June 2013 (The President's Climate Action Plan); and

(ii)  The Report of the Executive Office of the President of March 2014 (Climate Action Plan Strategy to Reduce Methane Emissions).

(c)  The Council on Environmental Quality shall rescind its final guidance entitled "Final Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in National Environmental Policy Act Reviews," which is referred to in "Notice of Availability," 81 Fed. Reg. 51866 (August 5, 2016).

(d)  The heads of all agencies shall identify existing agency actions related to or arising from the Presidential actions listed in subsection (a) of this section, the reports listed in subsection (b) of this section, or the final guidance listed in subsection (c) of this section.  Each agency shall, as soon as practicable, suspend, revise, or rescind, or publish for notice and comment proposed rules suspending, revising, or rescinding any such actions, as appropriate and consistent with law and with the policies set forth in section 1 of this order.  

Sec. 4.  Review of the Environmental Protection Agency's "Clean Power Plan" and Related Rules and Agency Actions.  (a)  The Administrator of the Environmental Protection Agency (Administrator) shall immediately take all steps necessary to review the final rules set forth in subsections (b)(i) and (b)(ii) of this section, and any rules and guidance issued pursuant to them, for consistency with the policy set forth in section 1 of this order and, if appropriate, shall, as soon as practicable, suspend, revise, or rescind the guidance, or publish for notice and comment proposed rules suspending, revising, or rescinding those rules.  In addition, the Administrator shall immediately take all steps necessary to review the proposed rule set forth in subsection (b)(iii) of this section, and, if appropriate, shall, as soon as practicable, determine whether to revise or withdraw the proposed rule.

(b)  This section applies to the following final or proposed rules:

(i)    The final rule entitled "Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units," 80 Fed. Reg. 64661 (October 23, 2015) (Clean Power Plan);

(ii)   The final rule entitled "Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units," 80 Fed. Reg. 64509 (October 23, 2015); and

(iii)  The proposed rule entitled "Federal Plan Requirements for Greenhouse Gas Emissions From Electric Utility Generating Units Constructed on or Before January 8, 2014; Model Trading Rules; Amendments to Framework Regulations; Proposed Rule," 80 Fed. Reg. 64966 (October 23, 2015).

(c)  The Administrator shall review and, if appropriate, as soon as practicable, take lawful action to suspend, revise, or rescind, as appropriate and consistent with law, the "Legal Memorandum Accompanying Clean Power Plan for Certain Issues," which was published in conjunction with the Clean Power Plan.  

(d)  The Administrator shall promptly notify the Attorney General of any actions taken by the Administrator pursuant to this order related to the rules identified in subsection (b) of this section so that the Attorney General may, as appropriate, provide notice of this order and any such action to any court with jurisdiction over pending litigation related to those rules, and may, in his discretion, request that the court stay the litigation or otherwise delay further litigation, or seek other appropriate relief consistent with this order, pending the completion of the administrative actions described in subsection (a) of this section.  

Sec. 5.  Review of Estimates of the Social Cost of Carbon, Nitrous Oxide, and Methane for Regulatory Impact Analysis.  (a)  In order to ensure sound regulatory decision making, it is essential that agencies use estimates of costs and benefits in their regulatory analyses that are based on the best available science and economics.  

(b)  The Interagency Working Group on Social Cost of Greenhouse Gases (IWG), which was convened by the Council of Economic Advisers and the OMB Director, shall be disbanded, and the following documents issued by the IWG shall be withdrawn as no longer representative of governmental policy:

(i)    Technical Support Document:  Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866 (February 2010); 

(ii)   Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis (May 2013);

(iii)  Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis (November 2013); 

(iv)   Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis (July 2015); 

(v)    Addendum to the Technical Support Document for Social Cost of Carbon:  Application of the Methodology to Estimate the Social Cost of Methane and the Social Cost of Nitrous Oxide (August 2016); and

(vi)   Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis (August 2016). 

(c)  Effective immediately, when monetizing the value of changes in greenhouse gas emissions resulting from regulations, including with respect to the consideration of domestic versus international impacts and the consideration of appropriate discount rates, agencies shall ensure, to the extent permitted by law, that any such estimates are consistent with the guidance contained in OMB Circular A-4 of September 17, 2003 (Regulatory Analysis), which was issued after peer review and public comment and has been widely accepted for more than a decade as embodying the best practices for conducting regulatory cost-benefit analysis.

Sec. 6.  Federal Land Coal Leasing Moratorium.  The Secretary of the Interior shall take all steps necessary and appropriate to amend or withdraw Secretary's Order 3338 dated January 15, 2016 (Discretionary Programmatic Environmental Impact Statement (PEIS) to Modernize the Federal Coal Program), and to lift any and all moratoria on Federal land coal leasing activities related to Order 3338.  The Secretary shall commence Federal coal leasing activities consistent with all applicable laws and regulations. 

Sec. 7.  Review of Regulations Related to United States Oil and Gas Development.  (a)  The Administrator shall review the final rule entitled "Oil and Natural Gas Sector:  Emission Standards for New, Reconstructed, and Modified Sources," 81 Fed. Reg. 35824 (June 3, 2016), and any rules and guidance issued pursuant to it, for consistency with the policy set forth in section 1 of this order and, if appropriate, shall, as soon as practicable, suspend, revise, or rescind the guidance, or publish for notice and comment proposed rules suspending, revising, or rescinding those rules. 

(b)  The Secretary of the Interior shall review the following final rules, and any rules and guidance issued pursuant to them, for consistency with the policy set forth in section 1 of this order and, if appropriate, shall, as soon as practicable, suspend, revise, or rescind the guidance, or publish for notice and comment proposed rules suspending, revising, or rescinding those rules: 

(i)    The final rule entitled "Oil and Gas; Hydraulic Fracturing on Federal and Indian Lands," 80 Fed. Reg. 16128 (March 26, 2015);

(ii)   The final rule entitled "General Provisions and Non-Federal Oil and Gas Rights," 81 Fed. Reg. 77972 (November 4, 2016);

(iii)  The final rule entitled "Management of Non Federal Oil and Gas Rights," 81 Fed. Reg. 79948 (November 14, 2016); and

(iv)   The final rule entitled "Waste Prevention, Production Subject to Royalties, and Resource Conservation," 81 Fed. Reg. 83008 (November 18, 2016).

(c)  The Administrator or the Secretary of the Interior, as applicable, shall promptly notify the Attorney General of any actions taken by them related to the rules identified in subsections (a) and (b) of this section so that the Attorney General may, as appropriate, provide notice of this order and any such action to any court with jurisdiction over pending litigation related to those rules, and may, in his discretion, request that the court stay the litigation or otherwise delay further litigation, or seek other appropriate relief consistent with this order, until the completion of the administrative actions described in subsections (a) and (b) of this section.  

Sec. 8.  General Provisions.  (a)  Nothing in this order shall be construed to impair or otherwise affect:

(i)   the authority granted by law to an executive department or agency, or the head thereof; or 

(ii)  the functions of the Director of the Office of Management and Budget relating to budgetary, administrative, or legislative proposals.

(b)  This order shall be implemented consistent with applicable law and subject to the availability of appropriations. 

(c)  This order is not intended to, and does not, create any right or benefit, substantive or procedural, enforceable at law or in equity by any party against the United States, its departments, agencies, or entities, its officers, employees, or agents, or any other person.

DONALD J. TRUMP

THE WHITE HOUSE 
March 28, 2017

Levelized Cost of Electricity by Norris McDonald

The Levelized Cost of Energy (LCOE) is a way to combine all the construction, fuel and operational costs into a form that can be compared among all energy sources. The LCOE also has assumptions about financing periods, taxation, depreciation and owner costs that are hard to compare between short-lived systems like wind and long-lived systems like large hydro and nuclear.

LCOE offers an apples-to-apples comparison of the costs of financing, building, operating, and maintaining a power plant. The values are expressed in dollars per megawatt-hour or cents per kilowatt hour.

The following table compares the levelized cost of electricity (LCOE), in U.S. 2013 dollars per megawatt-hour, from different generation sources.

Generation Type          LCOE of Existing          LCOE of New*          LCOE of New**

Conventional coal                39.9                             N/A                        95.1

Combined Cycle Gas           34.4                             55.3                       75.2

Nuclear                               29.1                             90.1                        95.2

Hydro                                  35.4                           122.2                        83.5

Combustion Turbine Gas      88.2                           263.0                      141.5

(peaking)

Wind                                    70                              107.4                         73.6

PV Solar                               85                           140.3                        125.3

* This column shows the LCOE of new generation sources at actual 2015 capacity factors and fuel costs.

** This column shows the LCOE of new generation sources at the EIA-assumed capacity factors and fuel costs.

Source                     LCOE-existing (¢/kWh)        LCOE-new (¢/kWh)        

Coal                                      3.8¢                                       9.8¢

Natural Gas                           4.9¢                                       7.3¢

Nuclear                                  3.0¢                                       9.3¢

Hydro                                     3.4¢                                      11.7¢

Wind                                       NA                                        11.3¢

Biomass                                  NA                                        10.3¢

Solar                                       NA                                        13.0¢

All existing power plants have lower costs compared to their most likely replacements. New plants start their life cycle with a full burden of construction debt and equity investment that they have to pay off in their first ten years or so, while existing plants have already paid most of those debts. Once power plants pay off their original debts, they have far lower fixed operating costs and are capable of supplying electricity at lower costs, often at significantly lower costs.  (Forbes, 7/9/2015, Friends of Science Calgary, 8/29/2016)

SIMPLE LEVELIZED ENERGY COST CALCULATOR

LAZARD'S LCOE

Trump Approves Keystone XL Pipeline by Norris McDonald

President Trump approved a permit for construction of the Keystone XL pipeline on Friday. The $8 billion project would span 1,200 miles, connecting Alberta’s massive tar sands crude with pipelines and refineries on the Texas gulf coast would carry up to 830,000 barrels of crude oil a day.

TransCanada, the Calgary-based firm that has been trying to win approval for the pipeline for nearly 10 years, announced earlier Friday morning that the State Department has signed and issued a construction permit for the project.

As a result of the approval, TransCanada will drop an arbitration claim it filed for $15 billion in damages under the North American Free Trade Agreement.

In a statement Friday, the State Department said that in reviewing TransCanada’s application in light of Trump’s recent executive order, officials determined that issuing a permit “would serve the national interest.” The undersecretary who signed the permit, Thomas A. Shannon Jr., had “considered a range of factors, including but not limited to foreign policy; energy security; environmental, cultural and economic impact; and compliance with applicable law and policy.”

Keystone Pipeline Interconnection

Keystone Pipeline Interconnection

Secretary of State Rex Tillerson, the former chief executive of ExxonMobil, had recused himself from the decision.

The State Department, as instructed in Trump’s presidential memorandum of Jan. 24, relied on the supplemental environmental impact statement issued in January 2014. In that analysis, the State Department, which oversees applications for cross-border pipelines, had concluded that the tar sands would be developed with or without the pipeline and that as a result the decision would not affect climate change. 

Construction will not start just yet, the company said. It still needs a permit from Nebraska’s Public Service Commission.  The company last month filed for the Nebraska PSC permit, which is necessary for construction and in cases in which the company resorts to using eminent domain because landowners refuse to let construction take place. TransCanada has agreements covering 90 percent of the route in each of the three states the pipeline will cross.

The pipeline also traverses Montana and South Dakota. In Nebraska, it would connect with other pipelines linked to oil refineries along the Texas Gulf Coast. (Washington Post, 3/24/2017)

Billion Dollar Pipeline Upgrades by Norris McDonald

California NatGas Utilities Continue Pouring Billions into Pipeline Upgrades

California's extensive utility-operated natural gas transmission/distribution pipeline network will continue to receive billion of dollars in enhancements this year, according to the state's two main operators -- Sempra Energy's Southern California Gas Co. (SoCalGas) and Pacific Gas and Electric Co. (PG&E).

SoCalGas and PG&E have had pipeline safety enhancement programs on a multi-billion-dollar scale since the rupture and explosion of the PG&E transmission pipeline in San Bruno, CA, more than six years ago. State regulators and stepped-up federal pipeline requirements are both in play in the ongoing annual programs.

With the added safety focus on its closed Aliso Canyon underground gas storage facility near Los Angeles, SoCalGas plans to spend about $1.2 billion for improvements to its distribution, transmission and storage systems along with various pipeline safety programs. SoCalGas operates 101,000 miles of gas pipelines.

California regulators last year approved nearly $950 million in increased rates to support PG&E gas storage and transmission pipeline operations. The approval, however, did not include a pending $850 million disallowance associated with the combination utility's identified shortcomings in handling the San Bruno pipeline failure.

SoCalGas plans to upgrade or replace up to 60 pipeline valves this year to further modernize its pipeline system using remote control valves (RCV) and/or automatic shutoff valves (ASV).

The new valves would allow gas control operators at the Los Angeles-based Sempra Energy gas-only utility to "respond more quickly if gas flow needs to be shut off in an emergency.  The effort is part of the pipeline safety enhancement plan.  SoCalGas has replaced or retrofitted more than 100 valve locations since the stepped up pipeline safety effort was launched five years ago.

SoCalGas deploys five pipeline safety enhancement teams for valve upgrade and retrofit work on an ongoing basis, and is continuing this program through 2022. The teams completed 56 valve upgrade projects last year.  (NGI's Daily Gas Price Index, 2/22/2017)

SDG&E Unveils 30MW Lithium Ion Battery by Norris McDonald

SDG&E, in partnership with AES Energy Storage, has unveiled a 30MW lithium-ion battery energy storage facility in California, US.  Located at Escondido in California, the energy storage facility is claimed to be the world's largest of its kind and is intended to enhance regional energy reliability while maximizing renewable energy use.

The facility is designed to store up to 120MWh of energy, equivalent of serving 20,000 customers for four hours.

The batteries will act like a sponge, soaking up and storing energy when it is abundant – when the sun is shining, the wind is blowing and energy use is low – and releasing it when energy resources are in high demand.

The facility features about 400,000 batteries which are installed in nearly 20,000 modules and placed in 24 containers.

In 2016, SDG&E awarded a contract to AES Energy Storage to build two lithium ion battery energy storage arrays totaling 37.5MW.

As part of the contract, the firms developed the 30MW facility in Escondido, and a smaller 7.5MW array in El Cajon.

The contract follows direction by the California Public Utility Commission (CPUC) to the Southern California utilities to develop additional energy storage options to enhance energy reliability.  (Energy Business Review, 2/27/2017)

SCE Automated Switches Can Reduce Outage Times by Norris McDonald

Remote Integrated Switches On A Power Pole at the Crossarm

Remote Integrated Switches On A Power Pole at the Crossarm

When a fault is detected on a power line, the line is immediately de-energized. In most of Southern California Edison’s service area, all affected customers will remain without power until portions are restored on other power lines, or the cause is determined and the fault is fixed.  

Now, a new technology that SCE has installed as part of a pilot project can restore most customers within five minutes after an outage occurs.

The technology is called the Remote Integrated Switch. This switch can detect a fault on a line and isolate it, so most customers can automatically be restored. In effect, it cuts the line into segments so customers on the unaffected segments can stay online or be rerouted to new lines. 

At the base of the pole is a control cabinet that uses decision-making logic to operate the switch.

At the base of the pole is a control cabinet that uses decision-making logic to operate the switch.

The new switches also provide information on the status of the line by assessing the voltage, current and directional power flow. This information can help SCE safely and reliably operate power lines with and without new distributed resources, and restore power more quickly.

This technology gives SCE the capability to restore power more quickly, increase reliability and integrate more renewable power. 

The pilot project is in Santa Ana and includes five switches, providing services to around 2,500 customers, both residential and commercial. Each switch comprises a set of sensors and transformers that sit on a brace and is attached to an existing pole, at the crossarm. At the base of the pole is a control cabinet that uses decision-making logic to operate the switch. A centrally located router communicates wirelessly between all of the associated switches. 

SCE hopes to increase the number of switches installed in the same area by the end of the year. Depending on the results of the pilot project, rollout to all SCE service areas could begin as early as 2018. Areas where the technology could have the most impact will be first on the list for the new technology.

This technology is also providing support to customers wanting to use new renewable technologies by better enabling the two-way flow of electricity from home solar and energy storage. (SCE Inside Edison, 3/14/2017)

Concerns About State Subsidies For Nuclear Power Plants by Norris McDonald

The Center supports Zero-Emissions Credits(ZEC).

Critics of state support for struggling nuclear power plants are warning that state plans to subsidize unprofitable generating resources present “a very real threat” to wholesale electricity markets.  The subsidies in question come in the form of zero-emission credits for uneconomic nuclear plants, which were included as part of New York’s Clean Energy Standard and are intended to aid the state’s transition away from fossil fuels and into renewables.

Exelon has been pushing for similar treatment for its nukes in Illinois, while FirstEnergy has said it will seek financial assistance for its Ohio plants.

The subsidies aren't being driven initially by state policy, but are being driven by the specific requests of generation owners about particular units because those units are not profitable.

These same critics believe that social goals, such as the reduction of carbon emissions to reduce the effects of climate change, can be accomplished through market-based solutions, such as a price on carbon.  Many economists agree that the most cost-effective way to do that is have a carbon price, not by picking individual power plants that are low carbon.

The FitzPatrick nuclear power plant on Lake Ontario was due to close in 2015, but remained open under new ownership and a state-sponsored 'zero-emission' production credit program. (Nuclear Regulatory Commisison)

The FitzPatrick nuclear power plant on Lake Ontario was due to close in 2015, but remained open under new ownership and a state-sponsored 'zero-emission' production credit program. (Nuclear Regulatory Commisison)

To protect the markets from the effects of the subsidies, these critics advocate for applying PJM’s Minimum Offer Price Rule (MOPR) to all existing resources. The rule currently covers only new subsidized gas-fired plants.  They believe action is needed to correct the MOPR immediately.  They believe an existing unit MOPR is the best means to defend the PJM markets from the threat posed by subsidies intended to forestall retirement of financially distressed assets. Opponents also believe the role of subsidies to renewables should also be clearly defined and incorporated in this rule.”

Opponents are expressing concern that Illinois and Ohio could set a precedent for other states, calling the subsidies “contagious.  One opponent views the threat as so severe that in January filed as an intervenor in support of independent power producers opposing New York’s ZEC program.

These opponents believe the ZEC program is not consistent with the operation of a competitive wholesale electricity market.  They believe the program would artificially suppress NYISO, dissuade the construction of new generation and, if extended, “result in a situation where only subsidized units would ever be built.”

These opponents believe new combined cycles have been added because of competitive markets. They’ve been added because of the fact that we have a capacity market. … But for PJM overall markets, we probably would not have seen that level of entry of highly efficient combined cycles.”  (RTO Insider, 3/9/2017)