FERC on Thursday approved a settlement on financial terms for three transmission projects intended as contingencies for the potential closure of the Indian Point nuclear power plant in New York (ER15-572).
Indian Point Nuclear Power Plant (Source: Wikipedia)
Joining in the partial settlement were the state Public Service Commission, the Department of State Utility Intervention Unit, the New York Power Authority, New York City, the New York Association of Public Power, the Municipal Electric Utilities Association of New York and about 60 industrial, commercial and institutional energy consumers.
The commission judged the settlement, which was uncontested, as “fair and reasonable and in the public interest.”
It provides a total ROE of 10% for the TOTS projects, below the 10.6% base ROE the transmission owners originally sought. The agreement leaves intact the 50-basis-point adder granted by FERC, for costs up to $228 million.
Still pending in the docket are issues relating to the alternating current transmission projects that were first discussed in the state’s plans to address transmission needs in the New York City area. Those AC projects were split off by the New York Public Service Commission and settlement negotiations for them will resume in the coming months. (See NYPSC Directs NYISO to Seek Tx Bids.)
FERC Office of Enforcement staff said last week that the presence of flaws in the CAISO market is irrelevant to their market manipulation case against ETRACOM and principal trader Michael Rosenberg.
FERC accused the company of submitting uneconomic virtual supply transactions at the New Melones intertie at the CAISO border to affect power prices and benefit its congestion revenue rights in a scheme that allegedly generated $315,000 in profits in 2011.
In their reply to the allegations last month, the company said “staff has no basis for claiming that ETRACOM defeated or obstructed a well-functioning market,” because of market design flaws and software pricing and modeling errors that scrambled trading at the intertie. (See “Traders to Seek De Novo Review in CAISO Manipulation Case,” Federal Briefs.)
Staff rejected ETRACOM’s “market flaw defenses,” saying the commission’s definition of fraud as including actions “for the purpose of impairing, obstructing or defeating a well-functioning market” does not absolve the company (IN16-2).
“Staff construes the use of ‘well-functioning market’ to refer to any commission jurisdictional market operating under a tariff that the commission has found to be just and reasonable and not, as respondents suggest, a qualitative limit on the reach of the Anti-Manipulation Rule to only those commission jurisdictional markets without flaws,” staff said.
“Indeed, not only is there no perfect market, but even a well-functioning market can have flaws and be susceptible to manipulation. Otherwise, no claim for manipulation could exist because any market susceptible to manipulation could, by implication, be considered not ‘well-functioning.’”
In a press release, ETRACOM attorneys Robert Fleishman and Paul Varnado challenged what they called staff’s “cursory dismissal” of the design flaws. “The alleged harms would not have occurred but for the phantom congestion caused by these flaws,” they said.
The federal government on Wednesday designated about 127 square miles off Long Island as a wind energy area that could produce as much as 900 MW of power for New York.
The area designated by the Interior Department’s Bureau of Ocean Energy Management, about 11 miles south of Long Island, comprises 81,130 acres.
The announcement — which came a day after Interior withdrew plans to allow oil drilling off Virginia, North Carolina, South Carolina and Georgia — was cheered by environmentalists.
“The offshore wind industry is critical to the ultimate success of Gov. [Andrew] Cuomo’s call for the generation of 50% of New York’s energy from renewable sources by 2030,” said Anne Reynolds, executive director of the Alliance for Clean Energy New York. (See Cuomo: 50% Renewables by 2030, Keep Nukes Going.)
Offshore wind also is crucial to the U.S. Energy Department’s “wind vision,” which set a goal of capturing a 20% share of U.S. electricity production by 2030 (including 22 GW of offshore wind) and 35% by 2050 (with 86 GW of offshore wind).
BOEM has already issued 11 commercial wind energy leases off the Atlantic coast, but development of them has been slowed by high costs and local opposition.
Projects off New Jersey also have stalled, although state legislators are trying to revive them.
Deepwater Wind began work last July on the first demonstration project in the country, a 30-MW project off Rhode Island’s Block Island. The project, which had to withstand court and regulatory challenges to its above-market contracts with local distribution company National Grid, could go into service as soon as this year. (See FERC Won’t Investigate Offshore Wind Contract.)
Shallow Waters
If the U.S. is to enter the offshore wind industry, it will likely happen first on the Atlantic. The coastline’s shallow waters are similar to those in Europe, which has been building utility-scale offshore wind for more than a decade.
More than a quarter of the U.S. wind capacity in shallow water — depths of 30 meters or less — is along New Jersey, Delaware, Maryland, Virginia and North Carolina. The Mid-Atlantic region has almost 300 GW of potential wind capacity in shallow waters, more than enough to supply all of the region’s power needs. (See PJM States Seek ‘First Mover’ Status.)
2011 Proposal
The creation of the New York Wind Energy Area was prompted by a 2011 proposal by the New York Power Authority on behalf of itself, the Long Island Power Authority and Consolidated Edison. The NYPA proposal estimated a cost of $2 billion to $4 billion for up to 200 turbines generating about 700 MW.
BOEM, which oversees development of the nation’s energy resources on the Outer Continental Shelf, responded by issuing a notice in 2013 to determine if other developers were interested in the area. After issuing an environmental assessment, possibly by the end of this year, BOEM could move forward to offer leases under competitive bidding.
Five companies, Fishermen’s Energy, Energy Management, Deepwater Wind, EDF Renewable Energy and Sea Breeze Energy, have expressed interest in developing the site. Deepwater Wind is reportedly considering a Brooklyn waterfront site as a staging ground for the project.
The New York site is attractive to prospective developers for several reasons. New York City Mayor Bill de Blasio issued a request for information last year to identify new renewable energy generation capacity, with a goal of powering 100% of city government operations with renewables.
“Given the site’s proximity to load centers in New York and Long Island, it has the potential to be a very desirable location,” Thomas Brostrom, of Denmark-based Dong Energy A/S, the world’s largest offshore wind developer, told Bloomberg.
At the EUCI US/Canada Cross-Border Power Summit in Boston last week, Dennis Duffy, vice president of regulatory affairs for Cape Wind Associates, cited a New York study that showed onshore wind capacity factors in the state were only 10% during peak hours for electric use, while offshore wind reached 40%.
University of Delaware professor Willett Kempton has estimated the New York wind area is large enough to generate as much as 900 MW. His estimate is based on the use of 6- or 8-MW turbines, rather than the 3.6-MW turbines in the NYPA proposal.
Larger Turbines, Higher Costs
Offshore wind turbines are larger and thus generate more power than land-based turbines. But offshore turbines, which must be robust enough to withstand salt water and hurricane-force winds, are more expensive and also have higher operations and maintenance and financing costs.
The Energy Information Administration says the levelized cost of energy from offshore wind is $197/MWh (2013$), more than double the $74/MWh for onshore wind and the $73/MWh for natural gas advanced combined cycle plants. (EIA’s figures exclude any savings from government incentives.)
In Europe, which has about 90% of the 8.8 GW of offshore wind installed worldwide through 2014, the resource has benefited from government subsidies.
Patrick Woodcock, director of the Maine Governor’s Energy Office, told the EUCI conference that the New England states made a mistake by each trying to establish a foothold for the nascent offshore wind industry.
“What we really should have been doing is collaborating from the start. It never really made a lot of sense that one project, one group of utility ratepayers, would be the only class of ratepayers to bear the … huge burden for a demonstration project, when the dividends for bringing a new technology to the region is [shared] across the entire Northeast.”
Cape Wind Prospects Revived?
Cape Wind, a 130-turbine, 468-MW project planned for Nantucket Sound, is still trying to obtain financing after losing its PPAs with National Grid and NSTAR in January 2015. The utilities said the developers failed to meet deadlines to secure financing and begin construction by the end of 2014.
Duffy said Cape Wind’s hopes have been revived unexpectedly by a Massachusetts proposal to import Canadian hydropower under long-term contracts. Prospects for offshore wind and hydropower, he said, are “joined at the hip.”
“Sometimes politics makes strange bedfellows, but the future of both large imports of Canadian hydropower and offshore wind in New England depend largely upon Massachusetts legislation,” he said. An omnibus energy bill in the legislature is likely to include both.
A report released last week by the University of Delaware predicted that a commitment by Massachusetts to develop 2,000 MW, and anticipated technological advances, will lower previously projected costs by as much as 55% by 2029.
Newer wind farms would rely on larger, more efficient turbines than the older turbines for which Cape Wind is permitted.
Block Island turbine installations Source: Deepwater Wind
The study says costs for the first installations in a 2,000-MW commitment would be about 16.2 cents/kWh and that costs could drop to a “very competitive” 10.8 cents/kWh by the project’s completion. By comparison, the Block Island project has a PPA with National Grid that includes a fixed price of 24.4 cents/kWh with an annual 3.5% escalator.
“The key is making a firm commitment to scale so the market can do its work,” said Kempton, the study’s lead author. “By providing market visibility — the state’s commitment to a pipeline of projects over a set period — the offshore wind industry in the U.S. can deliver energy costs on the kind of downward trajectory seen in Europe.”
Renewed Hopes for NJ Project
Legislators in New Jersey, meanwhile, may have improved the prospects of a demonstration project near Atlantic City that has been blocked by the state Board of Public Utilities.
The New Jersey General Assembly last week voted 53-21 to approve legislation that would require the BPU to reopen a 30-day period for Fishermen’s Energy to resubmit an application for the five-turbine, 25-MW project. The bill cleared the state Senate on Feb. 11 by a 23-11 vote.
Gov. Chris Christie vetoed a similar bill in January by not taking action.
Fishermen’s Energy CEO Chris Wissemann said the legislation “cannot be ignored” by the governor this time around. He said Fishermen’s has secured federal funding from the Energy Department and switched to Siemens turbines, rather than the previously proposed Chinese windmills.
MISO received its first expedited project review request since replacing its former out-of-cycle review process, Senior Manager of Transmission Expansion Planning Thompson Adu told the Planning Advisory Committee on March 16.
Michigan Electric Transmission is seeking accelerated consideration to construct two 138-kV feeds to a new substation in Coldwater, Mich., with an in-service target of April 2017. The company said the upgrade is needed to serve 83 MW of load, including 33 MVA of new industrial and commercial load.
The company maintains that waiting until December for 2016 MISO Transmission Expansion Plan approval would not give the project enough time to meet the in-service date requested by its customers.
Transmission Planning BPM Advances to full PAC
The Planning Subcommittee has approved MISO’s Transmission Planning Business Practices Manual 020, moving the document to the PAC for consideration.
Matthew Tackett, a MISO principal adviser, said the BPM language was modified to include NERC transmission planning standards and Order 1000 cost-sharing provisions. Tackett said additional text also addressed the NERC MOD-032 standard, which establishes reliability planning modeling data requirements and reporting procedures.
Tackett said the edits do not represent policy changes.
“As the planning process evolves over time, it makes sense to incrementally make these changes,” Tackett said.
MISO’s second round of stakeholder input on the BPM yielded fewer comments, indicating consensus is near, Tackett said. The changes have been vetted through three PSC meetings, and MISO said it was not aware of unresolved issues or dissenting opinions from stakeholders. (See “Expedited Review Process Nears Approval with ‘Good Consensus,’” MISO Planning Subcommittee Briefs.)
Tackett submitted the nearly finalized language for a third round of comments through April 11.
Attachment Y Tariff Filing Moved Back Again
A proposed MISO Tariff revision requiring generation resources to submit Attachment Y notices at least 26 weeks prior to a planned suspension or retirement has been delayed by another month.
Joe Reddoch of MISO’s System Support Resource Planning Group said short intervals between meetings precluded a planned filing with FERC later this month, following another postponement in February. (See “Attachment Y Adjustments Put on Hold for a Month,” MISO Planning Advisory Committee Briefs.)
The Tariff revisions also stipulate that generators provide written notification when canceling or changing notices, as well as requiring owners rescinding an approved Attachment Y to re-enter the generator interconnection process. Additionally, MISO wants to relax confidentiality provisions surrounding Attachment Y information after a retirement date has passed.
Reddoch said MISO was not attempting to “overhaul” the system support resource program with the changes. He asked stakeholders to provide feedback by April 16 to facilitate a FERC filing late next month.
Twenty-two Heartland Consumers Power District customers will transfer their obligations to purchase energy and capacity from qualifying facilities while assuming Heartland’s duty to sell power to the QFs under a FERC order last week (EL16-1).
The commission granted a requested waiver of Public Utilities Regulatory Policies Act (PURPA) obligations for 22 Heartland customers while denying relief to six other customers — Truman, Minn., and the South Dakota cities of Howard, Aurora, Sioux Falls, McLaughlin and Tyndall — that did not agree to adopt Heartland’s QF-interconnection policy.
FERC found Heartland’s request for the 22 customers appropriate because the “QFs will retain the same ability to sell power and receive backup power as is currently the case. … Thus strict adherence to … regulations, under these circumstances, is not necessary to encourage QFs.”
The Truman Public Utilities Commission objected to Heartland’s request, saying the utility has “no authority to require Truman to adopt the [QF-interconnection] policy or any other policy.” It also pointed out Heartland does not yet have any QFs on its system.
Heartland said that because it acquires the bulk power resources to meet its customers’ loads, it is better suited to purchase energy offered from QFs.
Conversely, the company said, it is more appropriate for its customers to provide interconnection service required by QFs because the customers provide retail electric services. Heartland said South Dakota law does not allow it to sell electricity at retail prices.
It said its waiver request was intended “to clearly define the responsibilities for purchases from QFs, and sales to QFs, in accordance with statutory and contractual obligations.”
The commission also said one of the 22 customers, the city of Volga, S.D., must provide supplementary power, backup power, maintenance power and interruptible power to a South Dakota Soybean Processors cogeneration facility that is not yet operational.
The Nuclear Regulatory Commission said it wants Tennessee Valley Authority managers to outline how they would respond to safety concerns voiced by the operations staff at the Watts Bar nuclear generating station after inspectors found some employees “did not feel free to raise safety concerns.”
“It is extremely important that all nuclear plant employees feel free to raise safety issues with their managers and with the NRC without fear of retaliation,” NRC Region II Administrator Cathy Haney said in a statement.
Inspectors at Watts Bar, where the TVA is about to bring Unit 2 into commercial service, said “there were indications that license operators may have received undue influence and direction from TVA staff outside the control room.”
Reversing its earlier position, the Obama administration is not going to allow drilling for oil and natural gas in the Atlantic Ocean off several southern states. The Department of the Interior had earlier defined a lease area on the continental shelf about 50 miles offshore, stretching from Virginia to Georgia.
While many governors of the impacted states supported drilling, environmentalists were opposed. More than 1 million comments flooded the Interior Department during the public comment session.
Jacqueline Savitz, vice president of advocacy group Oceana’s U.S. Oceans Executive Committee, said that “with this decision, coastal communities have won a ‘David vs. Goliath’ fight against the richest companies on the planet, and that is a cause for tremendous optimism for the well-being of future generations.”
The rise of rooftop solar among residential customers will cost power generators $2 billion in revenue by 2019, according to a recent study by industry consultant ICF International.
ICF said that grid operators in the eastern U.S. plan on cutting the amount of electricity they purchase from conventional generators by about 1,400 MW beginning in 2019. A similar trend is happening in Germany, where E.ON SE and other companies are scrapping fossil-fueled plants and dropping plans for new ones in response to a renewable-energy building boom.
PJM and ISO-NE have included solar generation growth in their system estimates for 2019, the first year they have done so. The loss by traditional generators to solar is estimated to be about $716 million in 2019 in ISO-NE, $754 million in PJM and $523 million in NYISO.
Mass. Officials Ask NRC for Local Voice in Pilgrim Decomm
William Keating
The Massachusetts congressional delegation has asked the Nuclear Regulatory Commission to provide an opportunity for state and local officials to comment on the decommissioning procedures at nuclear generating stations, especially Entergy’s Pilgrim station.
Entergy announced in the fall that it would be closing the plant by June 2019. Decommissioning plans need to be filed with and approved by the NRC. But the delegation, led by Rep. William Keating, said local officials should have a say in the plans.
“The decommissioning of a nuclear power plant has an enormous impact on the state and communities hosting the plant,” the elected officials wrote in a letter to NRC Chairman Stephen Burns.
Obama Administration to Send Relief for Coal Areas
The federal government and the Appalachian Regional Commission announced they will spend $65.8 million in areas hit hardest by the decline of the coal industry.
The funds will be disbursed in grants of $500,000 to $1.5 million and are earmarked for creating jobs, workforce training and economic partnerships. About $45 million is expected to be handed out in fiscal year 2016.
The initiative is being funded by the Partnerships for Opportunity and Workforce and Economic Revitalization (POWER), created by the Obama administration.
Feds to Boost Pipeline Safety in Wake of Accidents
The Department of Transportation is proposing regulations designed to further improve natural gas pipeline safety in the wake of a number of accidents, including a 2010 California explosion that killed eight and injured more than 50. The rules would increase the number of mandatory inspections for rural lines and for new lines in gas-drilling fields.
While the rules would also expand pressure testing requirements for older gas lines that had been exempt, the department stopped short of requiring automatic emergency cut-off valves. While such valves could prevent some catastrophic events, such as the San Bruno, Calif., break that destroyed 38 homes, the natural gas industry argued that it would be too expensive to outfit lines with such valves. The cost would be between $100,000 to $1 million per valve.
The rules would expand federal regulation to cover “gathering lines,” or lines that collect oil or gas from wells and delivers them to storage facilities or transmission systems. Nearly 70,000 miles of gathering lines are currently exempt from federal oversight.
Twenty states have joined in a brief that asks the U.S. Supreme Court to strike down EPA’s Mercury and Air Toxics Standards. The court has already found that the rules were improperly implemented but let them stand while it ordered the Obama administration to find a way to fix them.
States, led by Michigan, say EPA is illegally and prematurely enforcing the rules before a final decision has been made on them. “What happens when a federal agency promulgates a rule without first receiving authority from Congress?” the states ask in their brief.
Some coal-fired plants have already shut down in anticipation of being unable to meet the stringent standards.
Poll Finds Americans Turning Against Nuclear Power
A Gallup survey released Friday shows that 54% of American’s dislike nuclear energy, the first time a majority has weighed in against atomic power. Anti-nuclear sentiment is up 11 points compared to last year, when 43% were opposed.
The Gallup poll has tracked American views on nuclear energy since 1994. The high point was in 2010, when 62% favored it.
MISO on Monday updated the competitive solicitation for the Duff-Coleman transmission project in response to stakeholder questions about the 345-kV line proposed for southwestern Indiana and western Kentucky.
The changes address the binding cost cap, revenue requirements, planning participation and respondent liability. MISO also added a requirement that bidding developers disclose their project-specific common stock costs and debt-to-equity ratios.
The update — the second since MISO released the RFP in January — comes as MISO fine-tunes Business Practice Manual 027, which outlines transmission developer qualifications and the selection process for competitive projects.
(Click to zoom.)
The 30-mile, single-circuit line would connect Vectren Energy’s Duff substation in Dubois County, Ind., with Big Rivers Electric’s Coleman substation in Hancock County, Ky., crossing mostly farmland and a portion of the Ohio River. MISO says the $67 million project will alleviate congestion and strengthen transmission capabilities near a MISO-PJM seam. RTO staff last week told the Planning Advisory Committee that stakeholders have needed clarification that the Rockport segment of the line is not included in the competitive solicitation.
Vectren and Public Service Enterprise Group were the first to step into the ring last week, announcing that they intend to jointly bid on the project.
“Vectren has a proven track record to successfully complete such large-scale transmission projects, having completed a nearly 65-mile 345 kV line in southwestern Indiana and western Kentucky four years ago,” Brad Ellsworth, president of Vectren South, said in a statement.
MISO planners are considering a study on the benefits of expanding flows on the constrained transmission interface linking the RTO’s North/Central and South regions, including the option of building its own additional transmission.
Dubbed the Footprint Diversity Study, the proposed initiative would look beyond just the impact of increased energy flows at the interface to examine the “widespread” economic factors related to expanding the North-South tie, such as system-wide capacity benefits, settlement cost savings and savings in adjusted production costs when flows exceed settlement limits.
“There’s going to be multi-value associated with such a line and it needs to be looked at from all aspects,” MISO Director of Policy Studies J.T. Smith said at a March 16 Planning Advisory Committee meeting.
Smith said the study would also consider the economic implications of the flow limits in the settlement agreement allowing MISO to use a portion of SPP’s system to facilitate transfers with Entergy’s former service territory. MISO estimates the system’s actual transfer capability is greater than current market flow limits, which restrict southbound flows across SPP’s network to 3,000 MW while capping northbound flows at 2,500 MW.
Depending on usage levels at the interface, use of SPP’s network can cost MISO up to $38 million per year, according to the RTO.
Smith said MISO would specifically examine the feasibility of building its own transmission to handle increased transfers between the sub-regions.
If the study is greenlit, MISO will rely on its 2017 Transmission Expansion Plan to inform any proposals to develop a new line. Smith also noted that future changes to MISO’s market efficiency project rules could influence a potential project.
“We also need to consider that the rules that exist today may not be the rules that exist tomorrow,” he said.
Consultant Roberto Paliza of Indianapolis said he was concerned that MTEP 17 would come too late to address increasing North-South tie flows. MISO shouldn’t assume SPP will provide the same amount of capacity after 2021, when the settlement agreement expires, he added.
“I wonder whether there’s going to be enough time to build the transmission to handle the capacity contract path,” Paliza said. “I wonder if we need to do something sooner than doing something at the overlay transmission stage of the MTEP 17.”
Paliza said he views the SPP-MISO settlement as a temporary fix for a problem that requires a long-term solution.
Minnesota Public Utilities Commission staff member Hwikwon Ham said he “didn’t necessarily disapprove of [the potential North-South] project” but noted it would involve a hefty price and wanted to know if MISO had explored possible cost allocations.
Smith said it was too early to identify such allocations, but that the issue would be taken up with the Regional Expansion Criteria and Benefits Task Force if a project is identified.
Smith did not provide a deadline for getting stakeholder approval for the study or a possible start date.
FERC last week approved an uncontested settlement agreement granting Public Service Company of New Mexico a 10% base return on equity on its transmission operations.
The settlement on PNM’s cost-of-service transmission formula rate was signed by Navopache Electric Cooperative, El Paso Electric, the Navajo Tribal Utility Authority, the Tri-State Generation and Transmission Association and the Western Area Power Administration (ER13-685, ER13-687, ER13-690).
FERC on Thursday denied a rehearing request from the Long Island Power Authority in a dispute with a power plant developer over interconnection requirements (EL15-84).
Caithness Long Island II Source: Caithness Long Island
The owner of Long Island’s transmission system had requested rehearing of a September 2015 order that granted Caithness Long Island II’s challenge to interconnection requirements that it said would cost “hundreds of millions” in unjust system upgrade costs. (See FERC Sides with Developer in NYISO Dispute.)
The developer of the 750-MW combined cycle plant in Brookhaven filed a complaint last July claiming that NYISO’s application of the Long Island local reliability interface transfer capability test, known as the Long Island Guideline, violates its Tariff and FERC Order 2003. Caithness said its energy resource interconnection request obligated it to meet only NYISO’s Minimum Interconnection Standard, which does not permit a deliverability test.
LIPA argued that the commission’s order erred by not directing NYISO to include the Long Island Guideline in its 2015 Class Year Deliverability Test. LIPA said that Caithness has told the ISO that it intends to seek interconnection as a capacity resource but that without transmission upgrades, the new plant could threaten the deliverability of generation east of Holbrook, N.Y.
“We find that LIPA’s request for rehearing is beyond the scope of the issues raised in Caithness’ complaint,” FERC wrote.
“The changes LIPA seeks are neither necessary to grant proper relief on Caithness’ complaint, nor supported by LIPA’s effort to establish — through a few sentences in its comments rather than a properly filed complaint — that NYISO’s existing tariff is unjust and unreasonable without LIPA’s requested revisions.”
The commission judged the settlement, which was uncontested, as “fair and reasonable and in the public interest.”
The area designated by the Interior Department’s 
The Nuclear Regulatory Commission said it wants Tennessee Valley Authority managers to outline how they would respond to safety concerns voiced by the operations staff at the Watts Bar nuclear generating station after inspectors found some employees “did not feel free to raise safety concerns.”
Reversing its earlier position, the Obama administration is not going to allow drilling for oil and natural gas in the Atlantic Ocean off several southern states. The Department of the Interior had earlier defined a lease area on the continental shelf about 50 miles offshore, stretching from Virginia to Georgia.
The rise of rooftop solar among residential customers will cost power generators $2 billion in revenue by 2019, according to a recent study by industry consultant ICF International.
The federal government and the Appalachian Regional Commission announced they will spend $65.8 million in areas hit hardest by the decline of the coal industry.
The Department of Transportation is proposing regulations designed to further improve natural gas pipeline safety in the wake of a number of accidents, including a 2010 California explosion that killed eight and injured more than 50. The rules would increase the number of mandatory inspections for rural lines and for new lines in gas-drilling fields.
A Gallup survey released Friday shows that 54% of American’s dislike nuclear energy, the first time a majority has weighed in against atomic power. Anti-nuclear sentiment is up 11 points compared to last year, when 43% were opposed.
