Joseph Krist

Publisher

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NOT JUST THE HOUSE WINS IN NEVADA

The Nevada Gaming Control Board announced that the state’s more than 400 largest casinos won more from players in 2021 than in any year in history. Blackjack continues to be the most popular table game in the casino. The No. 2 game is roulette. Statewide, win on all slots was up 0.25% and on tables, up 0.65%. The slot win percentage has decreased only three times in the past 25 years.

The state’s 1,958 blackjack tables won $1.13 billion from players for the calendar year. That was 75.8% more than the prior year. Roulette’s 424 units statewide generated revenues of $428 million, a 103% increase over last year. Roulette hold by the casinos was at 19.87 percent.

Slots are a whole category of their own. The most popular slot machine denomination in 2021 – the penny slot. There were 47,822 units across the state which won some $3.758 billion from players. That is a 59.7% increase over 2020. That produced a win rate for the house of 9.85% of the money put into them. The best slot for players were the nickel slots which the casinos only kept less than 6%.

That is where the state wins, Gaming tax collections are up 31.1% versus the first six months of the 2020-21 fiscal year. The first half of the 2021-22 fiscal year, through January 31, saw the state collect $570.8 million in percentage-fee collections.  For states generally, there is good news in the sports betting market. Nevada sportsbooks generated 5.46% of money wagered in 2021. The state’s books won $445.1 million from the 176 places in operation. Sports betting revenue was up 69.4% over the previous year.

NUCLEAR NORTHERN LIGHTS?

Alaska Governor Mike Dunleavy is asking the legislature to pass S.B. 177. The bill “would allow Alaskan communities to pursue the use of nuclear microreactors in Alaska by excluding local microreactor projects from the legislative designation siting requirement, exempting microreactors from the ongoing study requirement of AS 18.45.030 in recognition of the extensive research taking place both inside and outside of Alaska, and adopting the federal definition of a “microreactor.”  

Proponents are looking at two potential landing spots for micro reactors. One would be owned by Copper Valley Electric Association (CVEA) located in Glennallen, Alaska. CVEA is a cooperative utility that provides electrical and heat services to more than 3,800 business and residential customers stretching north 160 miles from Valdez to Glennallen and spanning 100 miles east to west from the Tok Cutoff highway into the northern reaches of the Matanuska Valley. CVEA is not interconnected to any other electric utility. It is that isolation that makes the concept attractive.

The other potential site would be located at Eielson Air Force Base and could be completed by 2027. There is a history of nuclear power associated with military facilities in Alaska. The SM-1A Nuclear Power Plant is located in central Alaska, approximately 6 miles south of Delta Junction on the Fort Greely Military Reservation. Fort Greely is approximately 100 miles southeast of Fairbanks and 225 miles northeast of Anchorage. The construction of the SM-1A at Fort Greely began in 1958 and was completed in 1962 with first criticality achieved on 13 March 1962. The final shutdown was performed on the SM-1A Reactor in March 1972.   

Ironically, this legislation could be enacted just as final decommissioning of the Fort Greely site begins. It is also accompanied by another bill the Governor seeks approval for which would require 80% of the Railbelt’s electricity to come from renewable sources by 2040, with penalties for electric companies that fail to meet the requirement. That would put the Alaska Energy Authority at the center of efforts to move to renewable power.

Between Homer and Fairbanks there are five interconnected utilities that distribute electricity to customers in six separate service areas in what Alaskans call the “Railbelt.” Four of those utilities also own and operate generation, and all five, plus the State of Alaska, own parts of the transmission system. The Alaska Energy Authority (AEA) owns the Bradley Lake Hydroelectric Project, the largest hydroelectric facility in the state. The proposed bill would also move forward with new hydro sources. In 2011, AEA received authorization to pursue a FERC license for the Susitna-Watana Hydroelectric Project. Financial constraints halted the project.

YOU CAN GO HOME AGAIN

For many years, the Commonwealth of Pennsylvania has run a program for oversight and assistance to municipalities in an effort to avoid defaults or Chapter 9 filings by those entities. Under Act 47 as the authorizing legislation is known, the Department of Community and Economic development provides fiscal management oversight and planning, technical assistance, and financial aid. The program has been successful in achieving those goals. Nonetheless, there has been criticism of the program reflecting the fact that some municipalities seem to never exit the program.

One such city was Scranton, the former railroading and mining center in northeastern Pennsylvania. It was designated as distressed on Jan. 10, 1992. And some 30 years later, the DCED announced the city’s status under the law was terminated on Jan. 25. The city had taken a number of steps under the oversight of the DCED to stabilize the city’s finances. It sold its sewer system in 2026 to generate monies for pension funding. One additional source of support for the city was the fact that support from the American Rescue Plan Act of $68 million could be applied to the City’s fund budget.

The city also benefitted from the resolution of litigation challenging taxes and fee increases imposed by the city. That resolution not only upheld the legality of prior collections but also allowed for their continuing collection, Late in 2021, the DCED audited the city’s finances as part of the process of determining whether the city could leave the program.

The reality is that Scranton is the 16^th city to participate in the program and strengthened and the regional tax base accessed. It came under supervision in 2004. So, the idea that cities check in but don’t check out of the program becomes more of a myth over time.

PUERTO RICO ELECTRIC

The U.S. Departments of Energy (DOE), Homeland Security (DHS), Housing and Urban Development (HUD), and the Commonwealth of Puerto Rico are moving forward on a structure for the development of a 100% renewable energy system for Puerto Rico. The announcement comes amidst continuing service issues with the current system. Reliability and cost remain basic issues for consumers. Labor unions oppose virtually any effort to move away from the current generating base.  The politics of the Commonwealth do not provide a solid environment for change.

Puerto Rico has committed to meeting its electricity needs with 100% renewable energy by 2050, along with realizing interim goals of 40% by 2025, 60% by 2040, the phaseout of coal-fired generation by 2028, and a 30% improvement in energy efficiency by 2040 as established in Puerto Rico Energy Public Policy Act (Act 17). A Memorandum of Understanding (MOU) will bind PREPA to sign contracts for at least 2 GW of renewable energy and 1 GW of energy storage projects. 

The memorandum accomplishes two things in the near term. It establishes a clear role for the expertise of DOE in the process and it kicks starts some needed fixes.  It is expected that at least 138 projects will be under construction bidding or have begun initial construction activities, including island-wide substation repairs, the replacement of thousands of streetlights across five municipalities, and the creation of an early warning system to improve dam safety.

Ratepayers currently pay twice the national average. Microgrids and renewables are achievable goals which will yield tangible benefits from both economic and reliability standpoints. It is something we have been advocating as the only rational response to the entire range of options and challenges confronting the island’s electric grid.

UNDERPOWERED AUTHORITY IN NY

New York State Comptroller Thomas DiNapoli released the results of an audit of the efforts of the New York Power Authority to install electric vehicle (EV) charging infrastructure throughout the state. The Charge NY program was announced in 2013 as a statewide network of up to 3,000 public and workplace charging stations to be ready in five years. It was followed in 2018 by Charge NY 2.0, a plan to install 10,000 public charging stations by the end of 2021. That same year, NYPA also announced EVolve NY, a $250 million project to put high-speed chargers at airports and along major highways. 

As of June 2021, there were 46,608 EVs registered in New York, but NYPA had installed just 277 public EV charging ports, or one for every 168 EVs registered in NY. The shortfalls are across all areas of the state. Suffolk County has 7,916 registered EVs, which is more than any other county and about 17% of the statewide total. It has three NYPA public charging stations, 1.2% of the total and just one charger for every 2,639 electric cars.

Nassau County has 5,947 registered EVs, about 13% of the statewide total, but only five NYPA public charging ports, 1.8% of the total or one port for every 1,189 electric cars. Westchester, where NYPA is based, has more NYPA public ports than any county. It has 4,844 registered EVs, about 10% of the statewide total, and 44 public ports or about 16% of the total.

Erie County has 1,898 registered EVs, about 4.1% of the statewide total, and 42 NYPA public charging ports, or one public port for every 45 vehicles (about 15% of the total). 30 counties with 6,189 EVs have no NYPA-placed public charging ports. There were only 28 high speed chargers at 18 locations as of September 2020. Not one of the EVolve NY’s Phase 1 projects, including installing 200 high speed chargers, were completed by their deadline of the end of 2019. As of March 5, 2021, NYPA had installed only 29 high speed chargers at seven locations, putting it on track to finish more than two years behind schedule.

INDIANA TRIES TO INDUCE PREEMPTION

After efforts last year in Indiana to impose state standards on localities governing the siting of commercial solar and wind generation infrastructure failed, another effort to accomplish the goal is underway. SB 411 establishes within the Indiana economic development corporation (IEDC) the commercial solar and wind energy ready communities development center (center). The center shall create and administer: a program to certify a unit as a commercial solar energy ready community; and a program to certify a unit as a wind energy ready community.

If a unit receives certification as a commercial solar energy ready community; and after the unit’s certification, a project owner submits a commercial solar project to be approved under standards that comply with the default standards; the IEDC shall authorize the unit to receive for a period of 10 years, beginning with the start date of the commercial solar project’s full commercial operation, $1 per megawatt hour of electricity generated by the commercial solar project.

The prior effort took power away from local zoning and land use boards and gave it to the state with no control over the economic benefits. That did not get a lot of support from the local government units. Now, the state would be offering a direct financial consideration to motivate adoption of the state standard.

EMINENT DOMAIN

It is a tool which has long been used throughout the nation’s history to acquire land from unwilling owners to facilitate larger development. The tool of eminent domain has been used to cover a variety of projects in locations large and small, metropolitan and rural. Lost in the debate over infrastructure of all kinds are many of the issues associated with land rights in connection with a variety of infrastructure projects.

This year, eminent domain is at the center of two projects where it may be the issue on which their success stands or falls. One is the issue of whether Texas landowners may face eminent domain over the proposed high speed rail line between Houston and Dallas. The issue is the subject of litigation in the Texas courts.

The other is the proposed network of pipelines to transit carbon captured to proposed storage facilities in North Dakota and Illinois. Three companies have together proposed 3,650 miles of new pipelines to cut across the Midwest and eventually transport 39 million tons of captured carbon annually from ethanol and fertilizer plants to the storage sites. Iowa would get the bulk of pipeline miles – more than 1,600 miles.

One pipeline developer has submitted a request to the Iowa Utilities Board (IUB) which regulates pipelines. Twenty counties in Iowa have filed objections with the IUB opposing the use of eminent domain for the pipelines, including 52% of counties along one pipeline’s proposed route and 41% of the counties along a second proposed route. If carbon capture and storage is to become a real thing, then this issue will be replayed across the country.

The company operating the second pipeline also plans to solidify its final route the rest of this year and apply for a federal permit. If successful, it expects to receive permits in the second half of 2023 and start construction in 2024.

There are currently about 5,000 miles (8,047 km) of carbon dioxide pipelines in the United States, mainly in Texas and Wyoming. It is used by industry to be pumped under oil and gas fields to increase pressure and boost production. One White House estimate says the country would need to build another 65,000 miles for the country to permanently store enough carbon to reach net zero emissions by 2050.

SOLAR AND WATER

The Turlock Irrigation District is poised to be the first water agency in the nation to see if placing solar panels above irrigation canals is a viable option for producing power while also reducing water losses.  It is scheduled to vote to accept a $20 million grant from the California Department of Water Resources to fund a demonstration project. The project would effectively cover existing open aqueducts and irrigation canals. The panels would produce power which could be tied in directly to existing transmission lines which exist along the route.

The panels would be suspended over the canals in a way that does not interfere with operation and maintenance of the water system. The project includes batteries or another means of storing daytime power from the sun for use later. University of California. Researchers said installing canal panels throughout the Central Valley could get the state halfway to its goal for climate-safe power. University of California. Researchers said installing canal panels throughout the Central Valley could get the state halfway to its goal for climate-safe power.

Another California municipal utility is considering using irrigation canals to produce power using the flow of the water. The South San Joaquin Irrigation District provides drinking and irrigation water to Manteca, Lathrop and Tracy. It operates a water treatment facility powered by a combination of solar power and purchases from PG&E. It is considering whether to replace the PG&E power with energy produced by a hydro power company.

The district would buy power from the energy company EMERGY, which would install the turbines at their cost and enter into a 20-year power purchasing agreement with the irrigation district at a rate 30% lower than buying power directly from PG&E. The power would be produced from turbines installed in a main irrigation canal. Water would be directed to a flume which would power the hydro turbines.

CLIMATE LITIGATION

A continuing trend in the climate litigation arena is the finding that lawsuits filed by municipalities against fossil fuel companies in state court should be decided in state court. The latest example comes from Colorado. The city of Boulder, along with Boulder and San Miguel counties, sued Suncor and Exxon Mobil in Boulder District Court. The issues raised are consistent with other suits across the country alleging damage and non-disclosure of risks long after awareness of the risks occurred.

As was the case with the City of Baltimore, the defendant companies sought to have the cases heard in the federal courts. The Colorado case defendants petitioned the U.S. District Court to have the case heard there. That request was turned down. This decision came in the appeal of the District Court decision. Specifically, the Municipalities allege claims of public nuisance; private nuisance; trespass; unjust enrichment; violation of the Colorado Consumer Protection Act; and civil conspiracy. They do not allege any federal claims.

The decision also directly addresses one of the main pillars supporting the argument that federal law should prevail. “By winning bids for leases to extract fossil fuels from federal land in exchange for royalty payments, Exxon is not assisting the government with essential duties or tasks. Critically, the leases do not obligate Exxon to make a product specially for the government’s use,”. The oil companies claim that being allowed to produce oil from the Continental Shelf makes it a federal issue.

REGULATORY ROUNDUP

The week saw a variety of actions by municipal governments in the regulation of buildings and energy. Bellingham, WA joined the cities of Seattle and Shoreline in regulating the use of electrification to limit carbon emissions. Bellingham voted to require all new commercial construction and future residential buildings more than three stories tall to heat water and rooms with electricity. Natural gas for cooking would still be permitted. New buildings must be “solar ready” with enough roof space for future installation of solar panels. 

In CA, legislation is being reconsidered which would have slashed the value of net metering payments to residential customers with solar power. W VA enacted legislation which repealed limits on the siting of nuclear power generation in the state. Senate Bill 61 passed the Ohio Senate by a vote of 32 to 1 last month.  It would limit all but “reasonable restrictions” on solar installations by homeowner associations.

The big battle is underway in Florida. Legislation favored by large utilities to require future rooftop solar panel customers to pay higher rates passed its first vote hurdle in committee. Under current law, solar panel owners can pass excess energy generated by the panels back to the utilities at the retail rate the utilities charge other customers. The bill (HB 741) would require a cheaper wholesale price be charged to the utilities. 

Sponsors had to make some concessions as the committee amended the bill to increase the time current owners of solar panels are grandfathered in and exempted from the rate change from 10 years to 20 years. Homeowners with working solar panels as of Jan. 1, 2023 would qualify for the exemption.

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