Ontario electricity policy

Ontario electricity policy refers to plans, legislation, incentives, guidelines, and policy processes put in place by the Government of the Province of Ontario, Canada, to address issues of electricity production, distribution, and consumption. Policymaking in the electricity sector involves economic, social, and environmental considerations. Ontario's electricity supply outlook is projected to deteriorate in the near future due to increasing demand, aging electricity supply infrastructure, and political commitments, particularly the phase-out of coal-fired generation. Policymakers are presented with a range of policy choices in addressing the situation, both in terms of overall system design and structure, and specific electricity generating technologies.
Ontario finds itself faced with choices that define energy policy debates throughout the western world: the role of markets vs. centralized planning and what Amory Lovins has termed "hard" versus "soft energy paths"; i.e. continued reliance on large, centralized generation, particularly nuclear and coal, or moving towards decentralized technologies, including energy efficiency and low impact renewables. As such, how Ontario electricity policy evolves in the near future will be of relevance to other jurisdictions facing similar options or challenges.
History of electricity demand planning in Ontario.
Early history.
In 1925, Ontario's public electricity utility, established in 1906, the Ontario Hydro Electric Commission (HEC) (later Ontario Hydro) constructed what was then the world's largest hydroelectric plant, Queenston-Chippawa (now Beck 1). From this early beginning until the postwar economic boom of the 1950s, Ontario Hydro was able to meet growing demand for electricity by expanding its network of hydraulic generating facilities. Planning for Ontario's electricity system was relatively simple for two reasons: 1) electricity was coming almost entirely from hydroelectric power; and 2) the electricity system consisted of several smaller systems, making management considerably easier.
Challenges to the system began to emerge in the 1950s: the accessible waterpower sites were exploited; and the province's electricity distribution system was limited in capacity. To address these problems, the HEC began constructing new coal-fired electricity generation plants near major sources of electricity demand and launched plans to build nuclear power plants across the province of Ontario. Between the early 1970s and early 1990s twenty CANDU power reactors were brought into service at the Pickering (8 reactors), Bruce (8 reactors) and Darlington (4 reactors) nuclear generating facilities.
Electricity demand planning 1970s–1990s.
The Power Corporation Act required Ontario Hydro, (formerly HEPCO, renamed in 1974) to provide "power at cost". This philosophy became part of the culture and lore of electricity supply in Ontario. The utility did not pay taxes, nor was it intended to generate profits.
Porter Commission.
Amid growing concern over the cost of nuclear power, coupled with inflation and recessions that reduced the demand for electricity, the Porter Commission (1975–1979) performed a detailed review on the problem of electricity supply. The Porter Commission's conclusions were simple: demand management, not supply planning, must be the focus of Ontario electricity planning.
Demand/Supply Plan (DSP) Report.
It was not until 1989, however, that Ontario Hydro published its first Demand/Supply Plan (DSP) Report, "Providing the Balance of Power". The plan projected a supply/demand gap would open up in the mid-1990s, reaching 9,700 MW by 2005 and 21,300 MW by 2014. To address this gap, Ontario Hydro proposed building several additional nuclear and coal-fired generation plants. In 1992, Ontario Hydro issued a revised Supply/Demand Plan Report. As a public body, all Ontario Hydro projects, including the DSP, were subject to the province's Environmental Assessment Act. By 1993, however, faced with increasing criticism from the province's independent, quasi-judicial Environmental Assessment Board, a recession and economic restructuring that dramatically reduced industrial electricity demand, and an oversupply of electricity as the Darlington nuclear power plant came into service, the DSP was withdrawn by Ontario Hydro and no additional generating facilities were built.
Ontario's short experiment with competitive retail markets.
In the 1990s, Ontario Hydro's enormous debt from the building of the Darlington nuclear generating station became a major political issue. Ontario Hydro was becoming financially and operationally dysfunctional. The situation forced Ontario Hydro to dramatically reduce staff and transmission investments. Ontario Hydro also published a document called Hydro 21. This report suggested that electricity system in Ontario should be restructured in a more market oriented direction.
The political impetus for restructuring increased with the 1995 election of the Mike Harris government. In that year, Mike Harris commissioned the Macdonald Committee. The committee recommended the elimination of Ontario Hydro's monopoly on managing generation capacity and that the electricity market be opened up to competition. In response to the Macdonald Committee's recommendations, the Ontario government released "Direction for Change: Charting a Course for Competitive Electricity and Jobs in Ontario" in 1997, detailing the government's plans to open the market for electricity supply.
The competitive market did not actually open until May 2002. Participation in the retail market was voluntary, with customers having the option of entering into contracts or rates being set in the five-minute spot market. Retail consumers were also free to enter fixed-rate contracts. For those that opted out of the contract option, electricity rates passed through a smoothed spot market price. When the market opened in May, wholesale prices averaged 3.01 cents per kWh. For a number of reasons, however, including an especially hot summer, a reduction in domestic generating capacity, and an increasing reliance on a limited import capacity, prices began to rise sharply. In July, average wholesale price was 6.2 cents per kWh. Under surmounting pressure from consumers, the government adopted the Electricity Pricing, Conservation and Supply (EPCS) Act in December 2002. The legislation capped retail prices at 4.3 cents per kWh and Ontario Power Generation (the successor of Ontario Hydro's electricity generation division) was to provide customers with a rebate for 100% of all electricity charges above that mark, retroactive to the market opening and continuing until 1 May 2006. Transmission and distribution rates were also frozen at their existing levels and would remain unchanged until 1 May 2006. The net result was a complete cessation of new investment in generation capacity and a significant cutback in new investment in transmission and distribution.
Concerns regarding aging nuclear plants.
In 1996, major questions arose regarding the status of Ontario's nuclear plants. The oldest of these plants built in the 1970s were aging and in the early 1990s reliability began to decline significantly. The situation drew the attention of the federal nuclear regulator, the Atomic Energy Control Board of Canada (AECB) (now Canadian Nuclear Safety Commission), and was acknowledged by Ontario Hydro. In 1996, the AECB judged the situation at Pickering A to be particularly critical and issued the plant a six-month operating license. The following year a review board of industry experts concluded that the operations of Ontario's nuclear plants were "below standard" and "minimally acceptable". The Ontario government responded by approving a Nuclear Asset Optimization Plan proposed by Ontario Hydro. The plan had three major objectives: 1) the closure of the seven oldest of the utility's 19 operational nuclear reactors for rehabilitation; 2) the redeployment of staff; and 3) the spending of between $5 and $8 billion to implement the plan. In order to replace the lost capacity by the reactor closures, Ontario Hydro relied on its five coal-fired generation facilities. The result was a doubling of greenhouse gas emissions, smog, and acid rain precursors from these facilities between 1997 and 2001. This development occurred at a time when poor air quality was already a growing public health concern in southern Ontario. In response to the concerns of the public health impacts of increased coal-fired generation, all three major provincial political parties included a coal-phase out plan in their 2003 election platforms. The winner of the election, the Ontario Liberal Party, led by Dalton McGuinty, had committed to a phase-out by 2007.
Electricity Conservation and Supply Task Force.
The August 2003 blackout in eastern North America reinforced concerns over the future of electricity supply in Ontario. In response an Electricity Conservation and Supply Task Force (ECSTF) was formed, submitting its recommendation in January 2004. The task force concluded that "the market approach adopted in the late 1990s needs substantial enhancement if it is to deliver the new generation and conservation Ontario needs, within the timeframes we need them". The task force also suggested that a long-term plan for generation and conservation was needed.
Creation of Ontario Power Authority.
Following the recommendations of the ECSTF, the new provincial government, elected in October 2003, enacted the Ontario Electricity Restructuring Act. The legislation provided for the creation of the Ontario Power Authority (OPA). One of the four mandates of the OPA was to address the power system planning issues.
Green Energy Act.
Ontario's Green Energy Act (GEA), and related amendments to other legislation, received Royal Assent on 14 May 2009. Regulations and other tools needed to fully implement the legislation were introduced through the month of September 2009, as part of a ten step plan to bring the GEA to life. The GEA will attempt to expedite the growth of clean, renewable sources of energy, like wind, solar, hydro, biomass and biogas, with the ambition to make Ontario become North America's leader in renewable energy.
Specifically this would be attempted by, creating a Feed-in Tariff that guarantees specific rates for energy generated from renewable sources, establishing the right to connect to the electricity grid for renewable energy projects that meet technical, economic and other regulatory requirements, establishing a one stop streamlined approvals process, providing service guarantees for renewable energy projects that meet regulatory requirements, and hopefully implementing a 21st-century "smart" power grid to support the development of new renewable energy projects, which may prepare Ontario for new technologies like electric cars.
Integrated Power System Plan (IPSP).
Over the next 20 years, it is expected that approximately 80% of the province of Ontario's existing electricity generation capacity will need to be replaced. In May 2005 the Minister of Energy, Dwight Duncan, asked the OPA to provide recommendations on what would be the appropriate mix of electricity supply sources to satisfy the expected demand in 2025, taking into account conservation targets and new sources of renewable energy.
Ontario faced three major electricity challenges: 1) the phasing-out of coal as a generation capacity source by 2007; 2) the impending end-of-life shutdown of nuclear generation capacity from 2009 to 2025; and 3) the steady increase of summer peak-demand in normal weather patterns.
IPSP evaluation and development process.
In December 2005, the OPA issued the "Supply Mix Advice Report" in response to the Minister's request. The report's principal recommendation was the retention of a major role for nuclear power in Ontario, with the implication of the refurbishment of existing facilities and even new build plants, while coal generating capacity would be replaced with renewable energy sources (principally wind) and gas-fired generation. The proposal's failure to incorporate significant improvements in the province's overall energy efficiency and continued heavy reliance nuclear power was the subject of widespread criticism from the province's environmental movement, and members of the public who participated in consultations on the OPA's report.
On 13 June 2006 Dwight Duncan, Ontario's Minister of Energy, issued a directive for the preparation of a 20-year integrated power system plan for the province. IPSP. The Minister's directive included minimum goals for conservation (increased substantially from the Supply Mix Advice report) and renewable energy, and a maximum limit for nuclear power production at approximately the capacity of the existing 20 reactors. Since then, the OPA has published eight discussion papers, as well as a preliminary version of the IPSP. It is expected that the OPA will submit the IPSP to the Ontario Energy Board (OEB), a regulatory body who will review and then either accept or reject the plan based on whether or not it complies with the Minister's directives and the IPSP regulations, and whether or not it is prudent and cost effective. If the OEB does not approve the IPSP based on these evaluation criteria, then the IPSP is sent back to the OPA for revision. If the OEB approves the plan, then the OPA will put the IPSP into effect.
On the same day (13 June 2006) that the Ministry of Energy issued its directive, the Government of Ontario passed a regulation exempting the IPSP from being subject to an environmental assessment (EA) under the Ontario Environmental Assessment Act. This has been met with opposition from environmental groups, who argue that an EA of the IPSP is the "best way for Ontarians to understand the risks and costs of the government's electricity plan".
Existing environmental policy process.
Instead of an environmental assessment of the plan, as had been the case 1989 DSP, a regulation made under the Electricity Act, 1998, the OPA was instructed to "[e]nsure that safety, environmental protection and environmental sustainability are considered" in the development of the Integrated Power System Plan (IPSP). The OPA's approach to sustainability is outlined in IPSP Discussion Paper #6: Sustainability.
The OPA defines sustainable development according to the definition agreed upon by the World Commission on Environment and Development's 1983 report, "Our Common Future ": "Sustainable development is development that meets the needs of the present without compromising the ability of future generations to meet their own needs."
The OPA states that it has based its consideration of sustainability in the IPSP on Robert B. Gibson's "Sustainability Assessment: Criteria and Processes". Six context-specific criteria were identified by the OPA: feasibility, reliability, cost, flexibility, environmental performance, and societal acceptance.
The OPA's approach has been criticized for a number of reasons. The OPA's discussion paper on sustainability was published both after the supply mix advice was given to the Ontario Government and after the supply mix directives were given to the OPA by Ontario's Minister of Energy. Also, several elements of Gibson's sustainability assessment framework were not implemented or discussed in "Discussion Paper #6: Sustainability".
The IPSP regulation mandates that the OPA consider environmental sustainability in the IPSP. The OEB, the body responsible for evaluating the IPSP, defines "consider" as meaning "weighed and evaluated". Thus, the OPA is only liable for evaluating the sustainability of the IPSP rather than for the incorporation of sustainability into the IPSP.
Central planning and traditional regulation versus competitive markets.
Although the provincial government officially describes the system it has established as a 'hybrid' of planning and market models, debates on the merits of a centrally planned system versus a competitive market approach persist.
Central planning and traditional regulation.
Central or traditional electricity planning is designed to expand supply resources to meet demand growth and to minimize the economic costs of this expansion by improving economies of scale in electricity generation. Economies of scale exist for a vertically integrated electric utility because a larger generating system can provide power to many users, and additional users can be accommodated with small increases in power costs.
Centrally planned systems are usually accompanied by a regulatory framework intended to restrict or replace competition with administrative restraints on profits. In Ontario, electricity rates were typically set by Ontario Hydro as an approximation to its long-run average cost of service, plus a mark up to recover capital investment costs, although rates were never subject to formal approval by the Ontario Energy Board.
Howard Hampton, former leader of the Ontario New Democratic Party, argues that this averaging out of the cost of power ensures supply meets demand in a cost-effective manner. For example, to ensure overall system reliability, a considerable portion of generation capacity from peaking plants must remain idle most of the time. Operating costs for peaking plants, however, are usually expensive because they inefficiently convert costly fossil fuels to electricity.
In Ontario's public monopoly system, costs were averaged out between base load and peaking stations. In other words, the insurance cost of reliability is spread out and shared equitably by all customers. Under a deregulated system, in which each generating station "must stand on its own two financial feet", the cost of ensuring such reliability would be considerably higher, as peaking plants would charge as much as the market will bear, as they are rationally expected to do.
Those who defend the combination of traditional regulation and central planning for the electricity sector, like Hampton, often base their arguments on the basic premise that electricity is an essential good required for consumer well-being. According to Hampton, central planning and regulation are required to ensure reliability in both the supply and delivery and the generation and infrastructure aspects. Whereas planning under a market regime is profit-driven, central planning can ensure that Ontario's best interests are being attended to and not just the interests of private investors. Stephan Schott, for example, has stated that, at least theoretically, state ownership of the electricity sector could satisfy all of the criteria for socially efficient and environmentally sustainable electricity production. This includes fully internalizing external social costs of electricity production and pricing electricity according to demand fluctuations, even while maintaining stable supply.
Central planning, however, is not without limitations. Central planning has the disadvantage of the risk of political interference. The tendency for governments has been to avoid creating policies that could make electricity consumption more expensive or that would require citizen to adjust their consumption habits.
Furthermore, central planning, which seeks to improve economies of scale, has historically "led to a nearly universal strategy of rapid capacity expansion and promotion of demand growth, with little consideration of the necessity or efficiency of energy use". This is true of Ontario Hydro, which, faced with the threat of cheap natural gas in the late 1950s, made the ill-fated decision to protect its market share by encouraging consumers to use more electricity. Ontario Hydro was forced to build new, more expensive generating plants and transmission and distribution infrastructure to keep up with demand.
Although signs were present by the early 1970s indicating that consumer demand growth was falling, Wayne Skene argues that "Ontario Hydro's board and management had remained locked in megaproject mode, persisting in the belief that demand would continue to double every decade". Therefore, simply in terms of scale of operations, it can be argued that central planning in Ontario, by overestimating future demand and building unnecessary capacity, has been economically inefficient and has imposed unwarranted costs upon the environment.
Deregulation and competitive markets.
Proponents of deregulation and restructuring of the electricity sector used these limitations to strengthen their case, arguing that such flaws are typical of regulated/centrally planned systems. Ronald Daniels and Michael Trebilcock, for example, argue that a premium should be placed on incrementalism and decentralization in terms of decision-making, rather than planning for "some once-and-for-all, system-wide set of collective decisions as to the future of the [electricity] industry". Moreover, they argue that competitive markets have the added advantage of being able to rely on the knowledge and expertise possessed by investors to generate a more rational assessment of the alleged merits of a given project.
Deregulation would ensure that rates would no longer be based on long-term average costs, as determined by a central regulating entity, to pricing based on short-term marginal costs. A plant's marginal cost varies considerably based on age, technology, fuel conversion efficiency, and so on. Both regulated and deregulated systems operate to minimize the avoidable costs of meeting instantaneous demand.
As demand is communicated to a power system dispatcher, this least-cost operating principle requires the dispatcher to first employ plants with the lowest marginal costs. In other words, rates in a deregulated system are "determined by hungry competitors contending for the last megawatt of demand in a market that clears every five minutes". Eliminating average cost of service rates creates the need for a market to determine electricity rates.
The term restructuring generally refers to the creation of these markets and the disintegration of vertically integrated utilities. The theoretical gains from restructuring are numerous. Competition, coupled with freeing electricity generators from cost of service rates, ought to give generators powerful incentives to cut costs, which will lower consumer prices in the long-term. In other words, deregulation is said to subject the electricity sector to the "innovative and productive forces of competition".
Competition would require generating facilities to assume a much tougher stance in negotiating contracts for fuel sources, labour, and maintenance. It would also require utilities to focus on innovation to increase technological efficiency in order to remain competitive. In addition, Timothy Considine and Andrew Kleit argue that competition would improve the efficiency of allocating electricity.
As Don Dewees explains, investors in a competitive market will build new capacity when they expect to recover "all capital and operating costs from the expected markets price. If market prices will not cover the cost of the investment, that investment is socially excessive". In theory, this particular aspect of deregulation should correct the systemic over-expansionary tendencies of centrally planned regimes.
However, competitive markets are not without limitations. Basic economic theory dictates that for competition to exist, a large number of market participants are required. Experience with deregulation in the United States and the United Kingdom, however, has shown that competitive markets can lead to market power concentration and market manipulation. In these jurisdictions, the market has been threatened by the strategic behaviour of incumbents and new entrants that have too large a market share. The case of Enron in California is a prime example. For a competitive market to function, firms cannot significantly influence prices by adjusting or shutting down supply individually.
Furthermore, the promise of competitive markets to lower consumer prices, for the most part, has yet to materialize. Data from the United States, for example, indicates that while Pennsylvania and Connecticut have fairly stable residential prices since restructuring, most other states have witnessed price increases after the year 2000. While this may be good news in terms of conservation and demand-side management (C&DM) objectives, it has made competitive markets unpopular among consumers and politically troublesome. For example, as consumer prices rose during Ontario's experiment with deregulation, Premier Ernie Eves, under surmounting political pressure, intervened into the market by freezing retail prices in November 2002.
This is because electricity is different from all other products in that it must be produced and distributed at the exact moment that it is consumed, and in that it is essential for the functioning of a modern, industrial nation. Thus a market in electricity does not respond in the same way as the market for products which can be stored, whose purchase can be deferred, or which are not essential. Naing Win Oo and V. Miranda used intelligent agent simulation to show that in moving from a vertically integrated to a competitive electricity market, retail consumers were heavily disadvantaged and suppliers used this to steadily increase both prices and profits. This occurred even with a large number of suppliers, and in the absence of any active collusion between them. However, in practice collusion and exploitative behavior by suppliers have been found in real markets when they have been deregulated. S. David Freeman, who was appointed Chair of the California Power Authority in the midst of the power crisis in that state, testified on Enron's role in creating the crisis to the Subcommittee on Consumer Affairs, Foreign Commerce and Tourism of the Senate Committee on Commerce, Science and Transportation on 15 May 2002:
There is one fundamental lesson we must learn from this experience: electricity is really different from everything else. It cannot be stored, it cannot be seen, and we cannot do without it, which makes opportunities to take advantage of a deregulated market endless. It is a public good that must be protected from private abuse. If Murphy's Law were written for a market approach to electricity, then the law would state 'any system that can be gamed, will be gamed, and at the worst possible time.' And a market approach for electricity is inherently gameable. Never again can we allow private interests to create artificial or even real shortages and to be in control.
Market manipulation for private profit thus creates government intervention into the marketplace. This intervention, although certainly supported by electricity consumers, creates doubt in the minds of potential investors, who then begin to question the government's commitment to restructuring. An unattractive environment for private investors, in turn, threatens overall supply in a competitive market regime, as planning for and building new generating capacity becomes an increasing risk. This is why some supporters of restructuring, like Dewees, admit "[t]he greatest risk to competitive markets may not be power shortages or heat waves but government intervention ..."
Conservation and demand management.
Electricity use can be divided into three main sectors:
Electricity demand can also be separated as base load and peak demand. Base load refers to constant, or unvarying, demand for electricity. In Ontario, base load amounts to approximately 13,000 MW and is met by nuclear and hydroelectric power. These supply options generally have low operating costs. Nuclear stations are limited in their capability to rapidly change their output. Hydroelectric stations can rapidly change their output and are typically used to adjust grid supply to match instantaneous demand.
Peak demand refers to fluctuating, or varying, needs for electricity above and beyond base load levels. Added to this base load, the peak load raises Ontario's maximum electricity demand to 27,000 MW. This peak is typically met by oil/natural gas-fired, coal and select hydro-electric power plants. These plants can respond to changes in demand rapidly, but have higher operating costs.
Average demand in Ontario is currently 17,500 MW.
Electricity demand is greatly affected by seasonal variations. A recent trend has developed whereby summer peak demand has grown to outpace winter peak loads. This is primarily the result of increasingly warm summer conditions. The highest load recorded in Ontario occurred on 1 August 2006, when peak demand for electricity reached 27,005 MW. The highest winter peak demand occurred 13 February 2007, when peak demand was 25,868 MW.
Peak demand also varies by the time of day. The daily peak period refers to the time of the day when demand is at its high. In winter, there are generally two peaking periods: around 10:30 a.m. in the morning and around 6 p.m. in the evening. In summer months, demand peaks in the late afternoon, when temperatures are at their hottest.
Current and expected future electricity demand.
Current annual electricity demand in Ontario is 151 TWh. In other words, on average, Ontarians consume 12,750 kWh per person per year. Based on 2003 information, this figure is approximately 25% lower than the Canadian average, roughly equal to U.S. rates, and about twice as high as European consumption levels (see: electricity consumption by country). In order to supply such demand, Ontario counts on 31,000 MW of installed power capacity, broken down as follows: 37% nuclear, 26% renewable (including hydro-electric power), 16% natural gas and 21% coal.
Total electricity demand has been increasing in Ontario over the last decades. In particular, during the period 1993–2004, it increased at a rate of approximately 0.5%.
Several factors affect how much energy is consumed by Ontarians. These include:
All of the above variables affect the forecasting of future electricity demand. The uncertainty embedded in these factors accumulates and makes it difficult to determine how much electricity will be consumed in the future.
In its 2005 "Supply Mix Advice Report", the OPA estimated that electricity demand will grow at a rate of 0.9% annually between 2006 and 2025, rising to approximately 170 TWh per year by 2025. This OPA estimate is nearly double the actual rate of electricity demand growth between 1990 and 2003 of 0.5% per year. In fact, the rate of growth in electricity demand in Ontario has been in decline since 1950. This was a result of the structural changes in the Ontario economy over this period, particularly the decline of heavy manufacturing and increased growth in the service and knowledge sectors.
The OPA projections are controversial. Organizations like Pollution Probe, the Pembina Institute, and the Ontario Clean Air Alliance claim that the OPA Supply Mix is fundamentally supply oriented and overestimates future electricity demand. They base their claims on several reports that estimate lower demand projections.
Conservation and demand-side management initiatives in Ontario.
Demand-Side Management (DSM) consists of the implementation of different policies and measures that serve to influence the demand for a product. When talking about electricity, it is often referred to as Conservation and Demand Management (C&DM or CDM), as it aims to reduce electricity demand, either by using more efficient technologies or by changing wasteful habits. C&DM also addresses reductions in peak demand via Demand Response (DR) programs. Demand Response does not lower total electricity demand; rather, it shifts demand out of the peak times.
Economically rational and technically feasible conservation is considered by some to be the cheapest, cleanest way to bridge the gap between supply and demand. For example, load reductions are vital in achieving the goal of shutting down Ontario's coal plants and in avoiding imports of US coal-fired power, which entails important health and environmental benefits. Moreover, the implementation of aggressive C&DM mechanisms would lower consumers' bills while increasing the province's energy productivity. Ontario's economy currently reflects relatively low electricity productivity levels, measured as GDP per electricity use. The state of New York has an electricity productivity rate that is 2.3 times higher than that of Ontario. C&DM programs are also advantageous in that they can be implemented within limited time horizons and budgets relative to the huge lead times and financial risks involved in the installation of new generation plants.
It is also important to adapt and use the successful C&DM policies of other jurisdictions. Moreover, it is vital to develop and use energy efficiency models to accurately estimate energy efficiency potential, to determine the most effective conservation policies, and to set the maximum priority for energy efficiency and conservation.
Based on their estimates of future demand, the OPA has recommended 1,820 MW as a target for peak demand reduction to be achieved by 2025. After consultation with stakeholder groups who deemed this target too low, Ontario's C&DM goals were eventually adjusted to reflect a new target of 6,300 MW of conservation by 2025 (1,350 MW by 2007, an extra 1,350 MW by 2010, and an additional 3,600 MW by 2025). This target was set by Ministry of Energy's supply mix directive, which provides direction for preparation of Integrated Power System Plan (IPSP) for Ontario Power Authority. This target was based on "economically prudent" and "cost effective" conservation and renewables, and by setting a lower priority for both options in comparison to nuclear.
Based on models and estimation by several Ontario's energy consultant companies and independent agencies, Ontario has a saving potential of almost twice the Ontario's target for energy efficiency. The gap between the Ontario's potential savings and its current target could be the result of: a) inadequate coordination between the Ontario government and OPA; b) lack of public information regarding incentives and energy efficient measures; c) insufficient long-term energy efficiency planning and funding; and e) lack of good institutional, delivery and market transformation. The largest potential for energy savings in Ontario has been identified in lighting, space heating, air conditioning, manufacturing machinery, and commercial equipment. According to an assessment commissioned by the OPA, this potential applies to all three electricity sectors:
Government actors involved in conservation and demand management.
The Ontario Conservation Bureau is a governmental organization established by the Ontario government as a division of OPA in 2005. Its mandate is to promote C&DM programs that defer the need to invest in new generation and transmission infrastructure. Programs managed by the Conservation Bureau include:
The Ontario Ministry of Energy (MOE) is responsible for ensuring that Ontario's electricity system functions at the highest level of reliability and productivity. This includes establishing energy efficiency standards, including Energy Star standards for appliances and windows. The Ministry has recently begun a program to remove T12 (tubular 1.5 inch fluorescent) commercial lamps by 2011.
The Ontario Ministry of Municipal Affairs and Housing has begun encouraging private sector housing developers to increase the energy efficiency standards of new homes. Other programs include:
The Office of Energy Efficiency (OEE) was established in April 1998 as part of Natural Resources Canada and is the primary federal office for energy efficiency. OEE responsibilities include: the promotion of energy efficiency in major energy sectors (industrial, residential, commercial, and building); the provision of energy efficiency information to the public; the collection of data and publication of energy efficiency trends.
Since 2005, the Ontario Energy Board (OEB) put into place two mechanisms to create incentives for local distribution companies (LDCs) to promote C&DM program: a Lost Revenue Adjustment Mechanism (LRAM), by which utilities recover all of the revenues that they would have collected had they not promoted sales reductions through conservation and energy efficiency; and a Shared Savings Mechanism (SSM), by which consumers and utilities share the benefits associated with the implementation of C&DM program.
Since 2009, the Environmental Commissioner of Ontario (ECO) has had the statutory responsibility to report on "the progress of activities in Ontario to reduce the use or make more efficient use of electricity, natural gas, propane, oil and transportation fuels." The ECO produces two-part annual reports on energy conservation, the first part on the broader policy framework affecting energy conservation in Ontario, and the second part on the results of initiatives underway.
Supply options.
Electricity supplies can be classified as either distributed or centralized in nature. Whereas conventional, centralized generation involves few generation facilities connected via high-voltage transmission lines spanning long distances, distributed generation facilities are located close to the load—or in technical speak, on the customer side of the meter—although not necessarily restricted to local uses. In this scheme, distributed energy sources are more numerous and sufficiently smaller than central generating plants so as to allow interconnection at nearly any point in the electricity system.
Distributed generation—sometimes known as 'dispersed' or 'embedded' generation when referring to small-scale wind generation—generally describes only renewable electricity sources with capacities less than 10 MW. Technologies often associated with distributed generation include cogeneration—also known as combined heat and power (CHP) generation—as well as micro-turbines, fuel cells, and gas generators used for on-site or emergency backup power.
Renewables can also be considered distributed technologies, depending on their application. Typically, community wind farms, solar photovoltaic arrays, geothermal installations, and biomass-fuelled power facilities are typically sufficiently limited in their generation capacity that they qualify as distributed energy sources. Conversely, large hydropower plants and offshore wind parks, with substantial production capacities of 50–100 MW or more which feed into high-voltage transmission grids, cannot be considered distributed generation.
Coal.
Coal-fired electricity generation is currently inexpensive relative to other energy sources. In 2005, the average price of coal power in Ontario was C$46/MWh, compared to $89/MWh and $107/MWh for hydropower and oil/natural gas generation, respectively. However, coal is believed to cost 3 billion in additional health costs to Ontario every year, accounting for this, it is twice as expensive as wind.
Ontario's coal plants emit large quantities of greenhouse gases and smog-causing pollutants each year. The Ontario Clean Air Alliance is perhaps the loudest critic of coal-fired generation in this regard. The latest figures, from 2005, reported in the Canadian Government's National Pollutant Release Inventory and the Greenhouse Gas Emissions Reporting Program, show that the Nanticoke Generating Station is the single largest emitter of greenhouse gases (CO2) (17,629,437 tonnes) and fifth largest emitter of air pollutants (107,689,470 kg) in Canada. Nevertheless, thanks in part to acid rain controls implemented in the 1980s and 1990s, coal emissions have been dropping. In total, Ontario's coal plants emitted 14% (37,000 tonnes) of all NOx, 28% (154,000 tonnes) of all SO2, and 20% (495 kg) of all Hg (mercury) emissions in 2003, respectively.
A cost-benefit analysis released by the provincial government in April 2005, found that emissions from all Ontario coal-fired stations are responsible for up to 668 premature deaths, 928 hospital admissions, 1,100 emergency room visits, and 333,600 minor illness (headaches, coughing, respiratory symptoms) per year.
New 'clean coal' technologies—such as Flue Gas Desulphurization (FGD) "scrubbers" for SO2 removal and Selective Catalytic Reduction (SCR) for NOX—can be used to reduce toxic releases, but have no effect on carbon emissions and are expensive to install. Testifying before a legislative committee in February 2007, Jim Hankinson, chief executive of Ontario Power Generation, estimated the cost of installing new scrubbers on Ontario's coal plants between C$500 million and C$1.5 billion.
As of 2007, two of the four smokestacks at Lambton and two of eight stacks at the Nanticoke station are currently equipped with scrubbers. The OPA is expected to recommend whether or not to install scrubbers at remaining coal facilities in Spring 2007.
In 2007, coal-fired power plants made up about 21% of Ontario's existing energy supply (6,434 MW) and 19% of total Ontario electricity production (30.9 TWh). at the time, Ontario had four coal-fired power plants in operation:
In April 2005, the government of Ontario closed the Lakeview Generating Station in Mississauga, Ontario, representing 1,140 MW of generating capacity.
The Ontario Liberals came to power in 2003 promising to phase-out and replace all of the province's coal stations by 2007. In 2005, the Government pushed back the target date to 2009, citing reliability concerns. It has since revised this plan once more, maintaining its political commitment, but refusing to set a specific deadline for a complete phase-out. Instead, it instructed the OPA to: "Plan for coal-fired generation in Ontario be replaced by cleaner sources in the "earliest practical time frame" that ensures adequate generating capacity and electric system reliability in Ontario." [Emphasis added]
The OPA has subsequently published preliminary plans for a complete coal phase-out by 2014, to begin in 2011. Coal generators are expected to be replaced by new renewable energy and natural gas generation facilities, as well as conservation measures. Thunder Bay Generating Station, the last coal-fired electricity plant in Ontario was shut down in April 2014, completing the phase-out. The plant has since been restored to service fueled by biomass.
Natural gas.
Natural gas is a fossil fuel composed mainly of methane, which can be burned to release heat that is then used to produce electricity. It contains very little sulphur, no ash and almost no metals; therefore, unlike with coal, heavy metal and SOx (sulphur dioxide and sulphur trioxide) pollution is not a major concern. In the United States the average natural gas-fired plant emits 516 kg of carbon dioxide, 0.05 kg of sulfur dioxide and 0.8 kg of nitrogen oxides (NOx) per megawatt-hour of energy generated. Compared with coal, natural gas generates about half as much carbon dioxide, one-third of the nitrogen oxides, and one one-hundredth of the sulfur oxides.
Natural gas is most commonly used for heating applications in homes and businesses but natural gas-fired power generation is also a significant component of the power supply mix, accounting for 8% of Ontario's power generation capacity, with 102 natural gas generating stations. This capacity is set to increase from 5,103 MW to 9,300 MW by 2010.
In 2006, the Ontario government directed the OPA to use natural gas to meet peak time energy demand. The OPA was also instructed to develop high efficiency and value use options for natural gas. The OPA has therefore decided to use natural gas for two applications: (1) local area reliability and (2) system capacity.
By 2025, installed natural gas and cogeneration capacity is targeted to increase from the current 4,976 MW to 11,000 MW—roughly 27% of system generation capacity. That said, due to its predominant use only in high-value energy applications, natural gas is only expected to account for 6% of Ontario's overall electricity production.
Cogeneration.
Cogeneration, or combined heat and power (CHP), refers to the concurrent generation of power and heat from the same energy source. The heat is then used in local applications such as heating homes.
Cogeneration can be applied to any fuel which is combusted for energy. Fossil fuels, biomass and biogas can all be used in CHP plants. Transporting heat over long distances is impractical, so cogeneration plants are usually small and located close to the energy load. Hence, cogeneration is inherently linked to distributed generation. The urban location of CHP plants makes them very compatible with clean-burning fuels such as natural gas. The health concerns associated with other fossil fuels (see coal above) make them less suitable for areas with high population densities.
Cogeneration can dramatically increase the efficiency of fuel use, as 48–64% of the energy from conventional combustion can be recovered as heat, while only 25–37% is converted into power. The combined efficiency of heat and power use can be up to 91%. High efficiencies translate into much lower fuel costs as well as much lower [greenhouse gas] and other emissions.
There are 110 CHP generating plants currently in operation in Ontario, with a total capacity of approximately 2,300 MW. Of these, 82 burn natural gas and the rest use biomass. Only 50 of these facilities are connected to the grid. (See: Simon Fraser's Cogeneration Database).
The Ontario Power Authority anticipates that the contribution of cogeneration to electricity conservation will be between 47 and 265 MW depending upon how aggressively it is pursued in Ontario. However, these projections are controversial, as there is still much debate about the real-life potential of widespread cogeneration projects.
A request for proposals was sent out by the OPA in 2005 for up to 1,000 MW of new cogeneration. As a result, seven new CHP generating stations are currently being developed in Ontario under contracts executed in 2006 with a combined total capacity of 414 MW.
Nuclear.
Nuclear power accounts for almost half of Ontario's power generation. The government plans to maintain nuclear power's role in energy generation through to 2025. Ontario currently has 18 nuclear units in operation. These reactors amount to 11,400 MW of generation capacity and are located at three sites: Pickering, Bruce and Darlington. Approximately one half of Ontario's power was generated from nuclear energy sources in 2005.
The Canadian Energy Research Institute (CERI) prepared a report for the Canadian Nuclear Association in 2004 comparing environmental impacts of nuclear generation to other base load generation technologies in Ontario. They found nuclear power to be almost cost-comparable with coal generation. However, groups such as the Pembina Institute and the Ontario Clean Air Alliance criticize nuclear power because of the impact of uranium mining operations, the long-term effects of radioactive waste and the potential terrorism and disaster risks of nuclear energy.
As of December 2004 there were more than 1,700,000 used fuel bundles stored on-site at both operational and decommissioned nuclear generating stations around Ontario.
Nuclear facilities have long lead times for both environmental and other approvals, as well as actual construction. Ontario's nuclear history is also chequered with budget overruns and delays in new build and refurbished plants. Nuclear has high capital costs and lead times, but low operational costs, making it suitable only for base load applications. In comparison, natural gas plants have short lead times but high operational and fuel costs. However, recently a range of economic factors have had a major impact on the cost of nuclear power. Groups such as the Ontario Clean Air Alliance are quick to point out that fluctuations in uranium prices have made operational costs associated with nuclear generation rise higher than those of natural gas plants and renewables.
The OPA has been directed by the government to use nuclear energy to meet the base load of energy demand in Ontario, but that nuclear generation capacity should not exceed 14,000 MW. The result is that nuclear is projected to make up approximately 37% of generation capacity in Ontario and produce 50% of the power in 2025, similar to its role in the current supply mix.
To achieve this mix, more nuclear units will need to either be built or refurbished, as most of the reactors currently in service will exceed their useful lifetime before 2020. In response, the OPA has entered into an agreement with Bruce Power to refurbish two units at Bruce, which are anticipated to add 1,540 MW of generating capacity by 2009. Bruce Power also plans to refurbish a third unit in future. The Auditor General of Ontario released a report on 5 April 2007, criticizing the high costs associated with the Bruce Power refurbishment agreement.
Ontario Power Generation (OPG) is currently conducting an environmental assessment for refurbishment of four operational units at Pickering B.
Renewables.
As a strategy to cut down greenhouse gas emissions, the Ontario government is planning to phase out coal-fired electricity generating plants and increase the proportion of electricity generated from renewable sources as well as promoting strategies to reduce electricity demand through CDM. It is estimated that 30% of Ontario electricity demand will be produced from these sources by 2025. Compared to fossil fuel sources, generating electricity from renewable sources such as water, wind, and biomass has the following advantages:
Hydroelectricity.
Hydropower currently accounts for approximately 21% of the current electricity supply in Ontario. This capacity is estimated to rise to 30% by 2025 as new sites are added to the current installed capacity and the existing ones are refurbished. Particular emphasis will be placed on developing hydroelectric plants with large storage capacities that can be used to provide dispatchable energy, which are equally capable of meeting peak electricity demand or offsetting the intermittent nature of other renewable sources such as wind.
Wind.
Ontario, especially the southern part, has abundant wind potential that can be harnessed to generate renewable electricity. It is estimated that Ontario has an area of about 300,000 km² within the reach of the transmission system that can be used for generating electricity from wind energy. This area approximates the size of Germany, which is the leading country for producing electricity from wind energy. If Ontario could intensively use wind energy like Germany, wind-based electricity would contribute up to 13% of the province's demand. Generating electricity from wind energy is considered cost-effective in southern Ontario because of closeness to transmission lines and load centres.
Wind may be considered an unreliable source of electricity due to its intermittent nature. However, integrating wind energy with hydroelectric systems or biomass ensures stable renewable electricity supply. Integrations of wind and hydro have been successfully practiced in the state of Oregon and may be used to provide reliable electricity in Canada.
In 2015 Canada's installed wind capacity was 11,205 MW, with Ontario leading the country in installed capacity at 4,361 MW. OPA estimates this capacity will increase to 5,000 MW by 2025, but other studies estimate the capacity to reach 7,000 MW by 2020 and 8000 MW by 20XX.
Biomass.
Biomass refers to organic matter from plants or animals that can be converted to energy. Bioenergy, in turn, is any form of energy (heat or electricity) generated from biomass.
The development of a bioenergy industry in Ontario faces many challenges including, but not limited to, high costs owing to the small-scale nature of technologies used to convert biomass to energy and environmental issues (e.g., declining soil productivity and increased fertilizer and pesticides use) related to intensive harvesting of biomass for energy production. That said, research that has been carried out to address some of these concerns suggests that the adoption of sustainable management practices that aim at maintaining ecological functions of forest and agro-ecosystems may sustain biomass production without adverse impacts to the environment.
The dual role of biomass as a substitute for fossil fuels and as a sink for atmospheric carbon is the main advantage for its use in energy generation. Bioenergy production from sustainable biomass sources is considered to be carbon neutral because CO2 emitted during combustion or natural degradation processes is captured by growing plants. Although biomass-based Integrated Gasification Combined Cycle (IGCC) and Combined Heat and Power (CHP) with carbon capture storage (CCS) may be promising technologies for reducing GHG emissions from electricity generating plants, these technologies are small-scale and not well developed in Ontario. The movement in favour of generating bioenergy from municipal waste appears to be a strategy to mitigate trash management; many municipal landfills are approaching capacity. There is a potential to generate income from methane emissions from municipal waste.
According to the IPSP, a total of 1,250 MW may be generated from biomass by 2027, but only 856 MW has been considered in plans thus far. Other reports suggest that biomass has the potential to produce about 14.7TWh (2,450 MW) of electricity and 47.0 TWh of heat in 10 – 20 years time.
At present, forest biomass is the main source of biomass used for energy production, followed by agriculture biomass as well as municipal solid waste and waste water.
Solar and geothermal.
Southern Ontario, in particular Toronto, receives as much summer solar radiation as the city of Miami, Florida, indicating that Ontario has sufficient solar energy that can be harnessed to generate electricity or heat. Unlike solar energy, geothermal heat pumps (GHP) produce heat energy that is mainly used for space and hot water heating. GHPs operate like refrigerators to transfer absorbed heat energy from below the frost line (about 1.2m soil depth for Southern Ontario) to connected buildings.
The OPA estimates that these technologies will contribute about 1,000 MW to Ontario electricity capacity by 2025. Although this estimate was used for planning purposes, it is possible that the capacity will increase in future as respective technologies develop. Some studies suggest that installed capacity of solar photovoltaic systems alone may be as much as 5,000 – 6,200MW by 2015.
Imports.
Ontario has an interconnection capacity totalling 4,000 MW. Connecting jurisdictions include: New York, Michigan, Quebec, Manitoba and Minnesota. The provincial grid is connected to the Eastern Interconnection managed by the Northeast Power Coordinating Council.
The OPA "Supply Mix Advice Report" recommends 1,250 MW of imports for Ontario. This figure is derived mainly from short-term hydropower projects planned in Quebec. Hydro-Québec TransEnergie and Ontario's Hydro One, each province's electricity delivery company, signed a C$800 million agreement in November 2006 to construct a new 1,250 MW Quebec-Ontario interconnection by 2010.
There is also potential for new interconnections to Manitoba and/or Labrador. But due to cost and siting challenges, these plans remain tentative and are considered long-term possibilities (2015–2025).
Manitoba is planning two new hydropower projects, known as Conawapa Generating Station and Keyask (Gull) Generating Station, in northern Manitoba. Conawapa, located on the Lower Nelson River, is planned to have a projected capacity of 1,380 MW when it comes online in 2017. Keeyask, initially projected to be in service in 2011/2012, is expected to generate 600 MW. New long-distance high-voltage transmission lines will have to be built to the support the projects, as the existing interconnection line between Manitoba and Ontario is too small to allow for adequate upgrades.
Newfoundland and Labrador is planning to build two major generating stations, capable of generating roughly 2,800 MW on the Lower Churchill River in Labrador. The Muskrat Falls facility is to have a planned capacity of 824 MW, while the Gull Island project is expected to generate 2,000 MW. Any interconnection to Ontario, however, would need the support of both the Quebec Government and the federal government, as the transmission of electricity generated in Labrador must run through Quebec.
Most imports from the United States are based on nuclear, natural gas, or coal-fired generation facilities. As such, the Government of Ontario has expressed little interest in increasing electricity imports from the United States.


Double diode triode

A double diode triode is a type of electronic vacuum tube once widely used in radio receivers. The tube has a triode for amplification, along with two diodes, one typically for use as a detector and the other as a rectifier for automatic gain control, in one envelope. In practice the two diodes usually share a common cathode. Multiple tube sections in one envelope minimized the number of tubes required in a radio or other apparatus.
In European nomenclature a first letter "E" identifies tubes with heaters to be connected in parallel to a transformer winding of 6.3 V; "A" identifies similar 4 V; "U" identifies tubes with heaters to be connected in series across the mains supply, drawing 100 mA; "H" identifies similar 150 mA, "C" identifies similar 200 mA, and "P" identifies similar 300 mA series-connected tubes. Following the voltage letter, "A" stands for a low-current (signal) diode section, "B" for a double diode with common cathode section, "C" for a triode section, "F" for a pentode section, "H" for a hexode or heptode section, and "L" for a power tetrode or pentode section. The first number identified the base type, for example 3 for Octal base; 9 for B7G sub-miniature 7 pin. The remaining numbers identified a particular tube type; tubes with all characters except the first identical had identical electrodes but a different heater; e.g. the EBC81 and UBC81. Generally, odd numbers identified tubes / valves with variable mu characteristics and even numbers straight, or sharp cut-off types.
American nomenclature, also used in Europe, used a number to identify the heater voltage, then one or two sequentially assigned letters, then a number specifying the total number of electrodes plus one. The 6.3V EABC80 has 7 electrodes; the US equivalent are 6AK8 and 6T8, where the "AK" and "T" have no particular meaning; the 6N8 (EBF80) is a dual diode+pentode with 7 electrodes.
There are many double diode triode tubes, including EBC81 (6BD7), EBC90 (6AT6), EBC91 (6AV6) and the older EBC1, EBC2, EBC11, EBC21, EBC33, EBC41 (identical to EBC81 but Rimlock (B8A) socket instead of noval), ABC1 (EBC1 with a 4 V heater), CBC1 (EBC1 with a 200 mA heater). The commoner tube line-ups of an AM-only radio set with mains transformer having a double diode-triode were one of the following: ECH11+EF11+EBC11+EL11 Y8A Base -"or"- ECH42 (or 41)+EF42 (or 41)+ EBC41+ EL41 (or 42) Rimlock Base -"or"- ECH81+EF80 (or 85 or 89)+ EBC81 (or 91)+ EL84 (noval Socket) + rectifier and magic eye indicator (depending on the radio class and manufacturer). AC/DC sets without mains transformer would use "U" tubes of the same types, e.g. UCH42+UF41+UBC41+UL41+UY41 rectifier.
There was also a tube with a double diode and a triode sharing a common cathode, and an additional, independent single diode section, named EABC80 or 6AK8 or 6T8 (with a shorter glass envelope) and its versions for AC/DC transformerless receivers with series heater chains, named PABC80 (9AK8, 300 mA for TV sets), HABC80 (19T8, 150 mA for radios) and UABC80 (27AK8, 100 mA for radios). This tube was designed for early AM/FM (MW/VHF) radio sets and was widely used until the end of the tube era; the double diode was used for FM demodulation, the third, independent diode for AM detection and/or automatic gain control (AGC).
The main configurations for an early tube AM/FM set using EABC80 in the 1950s and '60s were:
EC92+EF80 (or 85 or 89)+ECH81+EF80 (or 85 or 89)+EABC80+EL84 (or 95) -"or"- ECC85+EF80 (or 85 or 89)+ECH81+EABC80+EL84 (or 95)+ rectifier (tube or solid state) and indicator, depending on the radio class and manufacturer. For AC/DC radios, UCC85+UCH81+UF80 (or 85 or 89)+UABC80+UL84+ rectifier and indicator. These configurations were kept until semiconductor (germanium) diodes became available, making this type of tube obsolete.
References.
RCA Receiving Tube Manual, Series RC-12, RC-19, RC-25 - Published by RCA.


Fortis Inc.

Fortis Inc. is a St. John's, Newfoundland and Labrador-based international diversified electric utility holding company. It operates in Canada, the United States, Central America, and the Caribbean. In 2015, it earned $6.7 billion CAD.
Fortis was formed in 1987, when shareholders of the regulated transmission and distribution utility Newfoundland Light & Power Co. voted to form a separate holding company. NL&P shares were exchanged for Fortis shares on a one-to-one basis, with the regulated NL&P becoming a 100% owned subsidiary.
Fortis currently owns the following regulated utilities:
Fortis also operates three non-regulated companies:
Expansion.
The company expanded into Western Canada in 2003 with its purchase of Aquila, Inc.'s Canadian assets, formerly owned by TransAlta, Canada's largest publicly traded utility. As a result of this acquisition, Fortis became one of Alberta's major regulated electrical distribution companies, serving 415,000 Albertans in 2005. ATCO Electric is Alberta's other regulated distribution company. Also as a result of the 2003 acquisition, Fortis owns regulated generation, transmission, and distribution assets in British Columbia.
In 2007, Fortis acquired Terasen Gas from Kinder Morgan, which had sold the BC gas utility as a non-strategic asset included in its 2005 acquisition of Terasen Inc.
In addition to its regulated Canadian assets, Fortis also owns unregulated assets in Ontario, British Columbia, and Newfoundland. The majority of its unregulated business consists of hydroelectric generating plants.
Fortis' interests in the Caribbean include a 67% interest in Belize Electricity Limited (BEL) and a 95% interest in Belize Electric Co. Ltd. The Belize Association of Non-Government Organisations took Fortis to the Judicial Committee of the Privy Council in 2003 to have a new environmental assessment of the Chalillo Dam on the Macal River which was a hydroelectricity development project. Ecologists were concerned over the future of species such as the scarlet macaw, the tapir and the black howler monkey as the project would flood 10 km2 of rainforest in Belize. Celebrities such as Harrison Ford and Cameron Diaz supported a movement to stop this dam. Fortis and the Government of Belize supported the project.
On May 30, 2011, it was announced that Fortis has plans to acquire Central Vermont Public Service, an electric utility in the US state of Vermont, for US$700 million, pending stockholder and regulatory approval; this acquisition would be Fortis' first utility acquisition in the United States. Gaz Métro offered a higher price and acquired CVPS.
On February 21, 2012, CH Energy Group (a holding company for Central Hudson Gas & Electric, an upstate New York utility), announced a pending acquisition by Fortis valued at $1.5 billion. On June 27, 2013, Fortis Inc. closed on its acquisition of CHG.
In 2013, Fortis announced its acquisition of UNS Energy, an Arizona utility company.
On February 9, 2016, Fortis announced an agreement to acquire ITC Holdings Corp., the largest independent transmission utility in the United States, for US$11.3 billion in cash and stock.


Abel Pifre

Abel Pifre (1852–1928), was a French engineer who developed the first solar power printing press. He was initially an assistant to Augustin Bernard Mouchot who developed the first solar engine, but later developed solar technologies independently of his mentor.
Pifre demonstrated his press at a meeting of the Union Francaise de la Jeunesse at the Jardin des Tuileries in Paris on 6 August 1882.
The device consisted of a concave mirror 3.5 meters in diameter centering on a cylindrical steam boiler, which powered a small vertical engine of 2/5 horse power, and then driving a Marioni type printing-press.
Even under semi-overcast conditions, the press operated continuously from 1:00 pm to 5:30 pm, producing approximately five hundred copies per hour of a journal which was produced specifically for the event with the appropriate name "Soleil-Journal".
References.
Tissandier G. Utilization de la Chaleur du Soleil—Imprimerie Solaire. La Nature Journal 1882 Aug 26; No. 482, pg.193
http://cnum.cnam.fr/PDF/cnum_4KY28.19.pdf Note: scroll to page 198 of the CNUM PDF.


Cobb Electric Membership Corporation

Formed in 1938,
Cobb Electric Membership Corporation, more commonly known as Cobb EMC, is a non-profit electric utility company serving parts of Cobb, Cherokee, Bartow, Paulding, and small sections of Fulton counties in Georgia. In 2009, it had total sales of over 3.8 billion kilowatt-hours (13.7 billion megajoules).
It was founded in 1938 with 489 residential members and 14 business accounts, and now serves about 200,000 homes and businesses (including over 180,000 in northwest metro Atlanta), making it one of the largest electric membership corporations in the state and country. However, most residents in Cobb and other counties are customers of Georgia Power, while those within the city limits of Marietta (the Cobb county seat) are customers of Marietta Power, a municipal utility run by the city.
Cobb EMC participates in a rebate program for customers who install solar panels. In January 2009, the company joined with Green Power EMC to buy 17 megawatts of electric power from a company which upgraded the power plant at the former Fruit of the Loom factory in Rabun Gap to use logging biomass as a fuel.
Cobb Energy.
Cobb Energy Management Corporation, usually known as Cobb Energy, was created as a for-profit subsidiary in 1997.
It eventually sparked a lawsuit by Cobb EMC members, charging that their money was being funneled into the new company, after a 2007 exposé by the "Atlanta Journal-Constitution". Shareholders prevailed, and won again on appeal to the Georgia Court of Appeals in April 2010. Cobb Energy was folded back into the non-profit cooperative. Co-op board elections, delayed by the litigation since 2007, were scheduled to resume in the fall of 2011.
In early January 2011, the CEO of Cobb EMC was arrested and charged with 31 counts of racketeering and theft after his indictment by a county grand jury in the matter, citing more than 50 million dollars taken from or not paid to the EMC by Cobb Energy.
Prior to these events, the company purchased naming rights to the new Cobb Energy Performing Arts Centre, which still bears the name.


Easy Energy of Massachusetts

Easy Energy of Massachusetts, commonly referred to as Easy Energy, is an approved participant in the New England Power Pool and is licensed by the State Department of Public Utilities, Electric Power Division to sell electricity in Massachusetts. The company is headquartered in Bolton, Massachusetts and supplies electricity to residential, industrial and commercial customers in the parts of Massachusetts that fall within National Grid or NSTAR service territory.
Easy Energy founders, Margaret Campbell and Stan Smith, are 20 year veterans of the electric power industry with a mission to bring electricity options to all consumers. Consumers may choose between fixed and variable price as well as standard electricity generated by a mix of fossil fired and hydro power plants or a premium "green" electricity product that is sourced from 100% solar power generation.
Easy Energy provides electricity to more than 5,800 customers in Massachusetts. Approximately 40% of these customers are small businesses. Easy Energy has also signed four cities and towns that purchase electricity for municipal use. In July 2009 Selectmen of the town of Bolton, Massachusetts voted to switch the electricity supplier for municipal buildings and streetlights from National Grid to Easy Energy.


Panel generation factor

Panel generation factor (PGF) is used while calculating the size of solar photovoltaic cells. It is a varying factor depending upon the climate of the site location (depending upon global geographic location).
For example, in Thailand it is 3.43, in EU countries it is 2.93, etc. This factor is used in calculation of "Total Watt-Peak Rating" while designing the size of solar photovoltaic cells.
Therefore, "Total Watt-Peak Rating" = "Total Watt-hours per day needed/generated from the PV modules" divided by "PGF". "Total Watt-Hours per Day" = "Total Watt-hours per day needed by appliances" Multiplied by "1.3 times" (the energy lost in the system). Now, to calculate "size of PV cells" OR "number of PV cells" just divide the above obtained "Total Watt-Peak Rating" by "Watt-Peak of each cell OR Watt-Peak of each square meter size", whichever is convenient.


David Mills (solar researcher)

David R. Mills (born 1946) is a researcher who has been active in solar energy research in Australia since 1975, working at the University of Sydney as a Principal Research Fellow till 2005.
Mills specializes in solar thermal electricity development, which he believes is one cornerstone of the future sustainable energy economy. His work is predominately in the field of solar spectrum selective materials and non-imaging optics. The prime focus of his research is planning 24-hour solar plants to eliminate coal use.
In 2002 Mills became chairman of "Solar Heat and Power", an Australian company he co-founded with Professor Graham Morrison (UNSW) and Peter Le Lievre. "Solar Heat and Power" went on to develop innovative CLFR type line focus solar thermal power systems in Australia, Europe, and North America.
Mills is a former President of the International Solar Energy Society, and was the first Chair of the International Solar Cities Initiative.
He is currently chief scientific officer and co-founder at Ausra Inc.


OGK-2

OGK-2 is a Russian power generation company. Majority of the company's stock is owned by Gazprom.
History.
In 2005, five thermal power plants with installed capacity about 8,700 MW were merged into single company. The power output of these plants in 2007 was around 48 TWh.
In April 2010, Gazprom, the major shareholder of OGK-2 and OGK-6, announced a plan to merge these companies. OGK-2 issued 26.59 billion new shares (81.2% of existing share capital) which were used for conversion of OGK-6 shares at a ratio of 1.2141 OGK-6 to 1 OGK-2 share. The merger was completed by 1 November 2011.
Operations.
OGK-2 operates following power stations:
Installed capacity of the company is 17,750 MW.


Wind power in China

China is the world leader in wind power generation, with the largest installed capacity of any nation and continued rapid growth in new wind facilities.
With its large land mass and long coastline, China has exceptional wind power resources: it is estimated China has about 2,380 gigawatts (GW) of exploitable capacity on land and 200GW on the sea. Wind power remained China’s third-largest source of electricity at the end of 2020, accounting for 12.8% of total power generation capacity.
In 2020, China added 71.6 GW of wind power generation capacity to reach a total capacity of 281GW. Both China's installed capacity and new capacity in 2020 are the largest in the world by a wide margin, with the next largest market, the United States, adding 14 GW in 2020 and having an installed capacity of 118 GW.
Wind power in the United States has however a much higher capacity factor.
China is forecast to have 1200 GW of combined wind and solar capacity by 2030 as part of the government's pledge to produce increase the share of non-fossil fuels in primary energy consumption to around 25% by that year.
In late 2020, the Chinese government set out a road map for total installed capacity of wind and solar to be 1,200 gigawatts by 2030.
China has identified wind power as a key growth component of the country's economy.
Experts say that China can achieve carbon neutrality before 2060 and peak emissions before 2030.
The largest domestic wind turbine manufacturer in China is Goldwind from Xinjiang province.
Established in 1998, Goldwind aggressively developed new technology and expanded its market share, though this then decreased from 35% in 2006 to 19% in 2012.
In 2019, Goldwind was one of the first partners to sign up for a wind-to-hydrogen project in northeast China, in the hopes of putting China's currently unused wind generation potential to good use and turn stranded wind power into a cheap energy source for hydrogen production. The China Longyuan Electric Power Group Corp., another subsidiary of China Guodian Corporation, was an early pioneer in wind farm operation; at one point it operated 40% of the wind farms in China.
According to new calculations by Fitch Solutions, wind generation is expected to reach approximately 1,000TWh in China by 2028 compared to previous forecasts of 870TWh, due to reduced project cost made feasible by upgrades in the efficiency of technology.
History.
In 2005, the standing committee of the National People's Congress passed a law that requires Chinese power grid enterprises to purchase all the electricity produced by the renewable energy sector.
Chinese developers unveiled the world's first permanent Maglev wind turbine at the Wind Power Asia Exhibition 2006 held in Beijing.
The Zhongke Hengyuan Energy Technology company invested CN¥400 million in building the base for the maglev wind turbine generators, in which construction began in November 2007.
Zhongke Hengyuan expects a yearly revenue of CN¥1.6 billion from the generators.
In 2006 the Shanghai Power Company purchased 64.485 gigawatt-hours (GWh) of green energy (primarily from wind farms), yet the amount of renewable energy which was subscribed by customers from Shanghai Power Company was only 23% of that total. In 2006 there were just 6,482 households in Shanghai that subscribed to renewable energy in part because the cost of wind power is 0.53 Yuan/kWh higher than power produced from coal plants; in 2007 total output of wind farms in Shanghai will total 100 GWh, which is sufficient to power 120,000 households.
Though there were 22 entities that purchased renewable energy in Shanghai, though with the exception of 1/3 of that total being state owned enterprises, the remainder was foreign invested enterprises. Shanghai's city government did not purchase any renewable energy. Of the top ten power customers in Shanghai, only Bao Steel purchased renewable energy; in 2006 Bao Steel entered into an agreement to purchase 1.2 GWh over three years.
By the end of 2008, at least 15 Chinese companies were commercially producing wind turbines and several dozen more were producing components.
Turbine sizes of 1.5 MW to 3 MW became common.
Leading wind power companies in China were Goldwind, Dongfang Electric, and Sinovel along with most major foreign wind turbine manufacturers.
China also increased production of small-scale wind turbines to about 80,000 turbines in 2008.
Through all these developments, the Chinese wind industry appeared unaffected by the global financial crisis, according to industry observers.
China became the largest wind energy provider worldwide in 2010, with the installed wind power capacity reaching 41.8 GW at the end of the year. However, about a quarter of this capacity was not connected to the grid.
In 2011, China put forth a plan to have 100 GW of grid-connected wind power capacity by the end of 2015 and to generate 190 terawatt-hours of wind power annually.
This target was reached in 2014, making China the first country in the world to reach 100 GW of installed wind capacity.
As of 2014, Goldwind remains the largest competitor in the Chinese wind energy market, with a 19% share of new installations.
It is followed by Guodian United Power Technology Company (a subsidiary of China Guodian Corporation) at 11%, and Mingyang Wind Power at 9%.
The Gansu Wind Farm Project in western Gansu province is one of six national wind power megaprojects approved by the Chinese government. It is the world's largest collective wind farm.
Offshore wind.
China set an ambitious goal of 5 GW of installed offshore wind capacity by 2015 and 30 GW by 2020.
However, development of offshore wind power did not come as fast as expected.
Construction of Donghai Bridge Wind Farm, the first offshore wind farm in China started in April 2009, close to Donghai Bridge, and commissioned in 2010 to provide electricity to the 2010 Shanghai Expo.
The wind farm consists of 34 Sinovel 3 MW wind turbines at a cost of US$ 102 million.
The next is the 150 MW Longyuan Rudong Intertidal Wind Farm costing 500 million ¥, operational in 2012.
By the end of 2012, China had only installed 389.6 MW offshore wind capacity, still far from the target goal of 5 GW by the end of 2015.
In May 2014, total capacity of offshore wind power in China was 565 MW,
which raised to about 900 MW in 2015, less than a fifth of the expected target.
Installations increased substantially in 2016, with 592 MW of offshore wind power capacity deployed, ranking third in the world behind Germany and the Netherlands.
By the end of 2016, the total cumulative offshore wind power capacity in the country was 1.9 GW.
Offshore wind development slower pace in China is mainly due to the lack of experience of domestic turbine manufacturers in the sector. This forces local development to use foreign products, resulting in Siemens being the largest supplier of offshore wind turbines in China. Another problem is the huge investment needed and associated risks of offshore development, which discourage private companies.
On 5 August 2020, a new report revealed by the Global Wind Energy Council stated that China is expected to host more than a fifth of the world’s offshore wind turbines, equating to 52 GW, claiming the top spot for the largest market for offshore wind by 2030.
Issues.
Areas with great wind power potential such as Gansu are sometimes far away from established industrial and residential centers. Coal-fired plants have a constituency of miners and local governments which wind-power projects lack. This has led to power generated by wind remaining underused.
Transmission capacity of the grid hasn't kept up with the growth of China's wind farms. In 2009, only 72% (8.94 GW) of China's total wind power capacity was connected to the grid. In 2014, 96.37 GW of China's capacity was connected to the grid, out of a total capacity of 114.6 GW. In the first half of 2015, 1.75 TWh of wind power was wasted according to China's National Energy Administration. The slowdown in the Chinese economy in 2015 also led to overcapacity in the power sector, reducing demand. In an effort to reduce excess power capacity and encourage greater use of renewables, the Chinese government halted approvals for construction of new coal power plants for the three-year period starting in 2016. Combined curtailment of North China wind power was nearly 34 TWh in 2015.
In 2014, the US generated more electricity from wind (167 TWh) despite a lower generating capacity because of China's connectivity and grid capacity problems. According to a 2013 report in The Economist, the US produced 40% more energy from a similar capacity of wind power, because Chinese wind farms are not efficiently connected to the power grid.
A potential solution will be to move wind turbines to urban areas, but not without challenges. Shen et al. (2019) discover that Chinese city-dwellers may be somewhat resistant to building wind turbines in urban areas, with a surprisingly high proportion of people citing an unfounded fear of radiation as driving their concerns. In addition, the study finds that like their counterparts in OECD countries, urban Chinese respondents are sensitive to direct costs and to wildlife externalities. Distributing relevant information about turbines to the public may alleviate resistance.


Second Wind (company)


6N2P

The 6N2P, (Russian: 6Н2П), also sometimes spelled in English "6H2Pi", is a miniature 9-pin dual triode vacuum tube manufactured in USSR, Russia and China with characteristics similar to the 12AX7. The most significant difference between the two is that 6N2P has its two filament elements connected in parallel, unlike the series filament connection of the 12AX7, and it is thus only possible to operate it from a 6.3 volt, 340 mA filament supply (whereas a 12AX7 may be operated from either 6.3 or 12.6 volts, at 300 mA or 150 mA, respectively.)
The 6N2P is not a pin-compatible replacement for the 12AX7 - an adapter (Or rewiring the valve socket) is required. The amplification factor of 6N2P is 98 which is marginally lesser than 12AX7, its higher heater current draw is similar to a 5751. The Chinese 6N4 (whose military issued variant is known by the designation 6N4-J) which is a pin-compatible replacement for the 12AX7 but has an amplification factor of 97.5 is the closest equivalent to the 6N2P.
In the 1970s an improved and more rugged version of the 6N2 was introduced, designated 6N2P-EV (Russian: 6Н2П-ЕВ). They also introduced a long life variant of the 6N2P-EV, designated 6N2P-ER (Russian: 6Н2П-ЕP). While the 6N2P-EV had a rated lifespan of ≥ 5,000 hours, the 6N2P-ER had a rated lifespan of ≥ 10,000 hours.
In the late 1980s Voskhod Sunrise produced a 12AX7 variant derived from the 6N2P-EV, under the designation 12AX7VKA. The Voskhod Sunrise 12AX7VKA tube used a larger bottle than other 12AX7s and did not fit in most Chinese shield bases. However, it did fit in most NOS and Korean made shield bases. Currently, a re-issue of the Voskhod Sunrise 12AX7VKA albeit with a smaller normal 12AX7 sized glass bottle is being produced by Sovtek, under the designation 12AX7WA.
A Chinese version of 6N2P exists, labeled in Latin lettering (instead of Cyrillic) 6N2. A Chinese version of the triple mica 6N2P-EV exists too, designated 6N2T. Currently a 12AX7 variant derived from the Chinese 6N2T is manufactured by the Shuguang tube factory exclusively for Tube Amp Doctor, under the designation ECC83 WA (7025 WA designation is used for the ones specially selected for high gain and low noise).
In the 1990s a (now extinct) line of "Red Bear" guitar amplifiers was being produced in Russia by Novik Ltd. and distributed in the United States by Gibson Guitar Corporation. These amplifiers used 6N2P-EV tubes instead of the much more common 12AX7, prompting user modifications of the amplifier to 12AX7, because the original Russian 6N2P-EV was scarcely available outside of Russia.


Compactron

Compactrons are a type of thermionic valve, or vacuum tube, which contain multiple electrode structures packed into a single enclosure. They were designed to compete with early transistor electronics and were used in televisions, radios, and similar roles.
History.
The Compactron was a trade name applied to multi-electrode structure tubes specifically constructed on a 12-pin Duodecar base. This vacuum tube family was introduced in 1961 by General Electric in Owensboro, Kentucky to compete with transistorized electronics during the solid state transition. Television sets were a primary application. The idea of multi-electrode tubes itself was far from new and indeed the Loewe company of Germany was producing multi-electrode tubes as far back as 1926, and they even included all of the required passive components as well.
Use was prevalent in televisions because transistors were slow to achieve the high power and frequency capabilities needed particularly in color television sets. The first portable color television, the General Electric Porta-Color, was designed using 13 tubes, 10 of which were Compactrons. Even before the compactron design was unveiled, nearly all tube based electronic equipment used multi-electrode tubes of one type or another. Virtually every AM/FM radio receiver of the 1950s and 60's used a 6AK8 (EABC80) tube (or equivalent) consisting of three diodes and a triode which was designed in 1954.
Compactron's integrated valve design helped lower power consumption and heat generation (they were to tubes what integrated circuits were to transistors). Compactrons were also used in a few high end Hi-Fi stereos. They were also used by the Ampeg guitar amplifier company in some of their guitar amps. No modern tube based Hi-Fi systems are known to use this tube type, as simpler and more readily available tubes have again filled this niche. One tube, the 7868, is used in some Hi-Fi systems made today. This tube is a Novar tube. It has the same physical dimensions as the compactron, but a 9 pin base. The exhaust tip is on the top or bottom of the tube, depending on the manufacturer's preference. It is currently in production by Electro-Harmonix.(The new power amp, Linear Tube Audio's Ultralinear, uses 4 17JN6 compactron tubes as the power tube in the amp.) The amp generates 20 watts of power with these inexpensive TV tubes.
Notable features.
A distinguishing feature of most Compactrons is the placement of the evacuation tip on the bottom end, rather than the top end as was customary with "miniature" tubes, and a characteristic 3/4" diameter circle pin pattern.
Examples.
Examples of Compactrons type types include:
Due to their specific applications in television circuits, many different Compactron types were produced. Almost all were assigned using standard US tube numbers.
Technological obsolescence.
Integrated circuits (of the analogue and digital type) gradually took over all of the functions that the Compactron was designed for. "Hybrid" television sets produced in the early to mid-1970s made use of a combination of tubes (typically Compactrons), transistors, and integrated circuits in the same set. By the mid-1980s this type of tube was functionally obsolete. Compactrons simply don't exist in any TV sets designed after 1986. Other specialist uses of the tube declined in parallel with the television set manufacture. Manufacture of Compactrons ceased in the early 1990s. New old stock replacements for almost all Compactron types produced are easily found for sale on the Internet.


Regional Power (Canadian company)

Regional Power, a subsidiary of Manulife Financial, has been developing and operating independent power projects since the mid-1980s. Currently, the firm operates six hydro plants on behalf of other developers with a total generating capacity of 36 megawatts.
Assets Operated for Others.
Regional Power operates the following assets on behalf of other hydro developers:
Development Projects.
Long Lake Generation Station.
BC Hydro awarded Long Lake Hydro a Power Purchase Agreement in the 2008 Clean Energy Call. This project is a retrofit of a decommissioned storage dam that was built in about 1938 and used to supply power to the nearby Premier mine. The mine, which was last operated by Westmin Resources, closed in the 1990s and has since been decommissioned. The dam was taken out around the time of the mine’s closure.
In the early 2000s, Stuart Croft of Summit Power became interested in this site as a potential retrofit project and established a joint venture with Regional Power. The developers planned to build a new dam and powerhouse in order to supply electricity to Stewart, BC and Hyder, Alaska.
As of May 2010, David Carter, Executive Vice President of Regional Power, estimated that construction would begin in Spring 2011 and the project would be operational in late 2012. Carter claimed that the engineering work was substantially completed, but very little permitting had been done.
Completed in 2014, the project is 17 km north of Stewart, BC. A new rock-filled dam was constructed at the western edge of Long Lake which holds up to 30 million cubic meters of water. A 7 km penstock, leads to the power station where two 15 MW Pelton turbines discharge into the Cascade River. The project is owned by Long Lake Hydro Inc.(LLHI) and the total cost is estimated at 90-million dollars. The expected annual 139GWh of electricity is sold to BC Hydro.


Lanco Infratech

Lanco Infratech (Lagadapati Amarappa Naidu and Company Infratech) was a large Indian conglomerate
involved in construction, power, real estate, and several other segments.
In 2010, the group of companies was listed among the fastest growing in the world. In 2011, the group became the largest private power provider in India. Lanco was one of the first Independent Power Producers (IPP) in India.
History.
Lanco was founded by a businessman
"Lagadapati Amarappa Naidu" and his nephew Lagadapati Rajagopal, who was a member of 15th Lok Sabha representing Vijayawada from Indian National Congress.
While Rajagopal remains inactive, his brother Lagadapati Madhusudan Rao is the executive chairman. Another brother Sridhar Lagadapati, was involved with the company in the early years, but now heads the related entertainment business, Larsco.
Lanco grew at a tremendous pace since the early 1991s. Initial growth was driven by large contracts primarily in construction. Later, other infrastructure areas such as power generation, transportation were also added.
Major operational power plants.
At this stage it has another 7000+ MW under construction and 10,000+ MW under Development and is heading towards successful completion of its Vision of 15,000+ MW by 2015. Major Power Projects under construction are:
Debt restructuring.
In June 2013, Lanco had won a contract for setting up two 300 MW power plants in Gujarat. However, the contract was cancelled in October 2013, when the company failed to put up the 10% guarantee required in the contract.
By July 2013, the company had filed for debt restructuring, citing a business slowdown.
In September, it was revealed that the company had cut down its employees by nearly half. In December 2006, the company won a large contract citing a collaboration with Singapore firm Globeleq.
In 2007, after winning the bid for the 1000 MW Anpara-C power plant, Lanco requested that the power output be re-negotiated. Some competing firms protested since the re-negotiation made the initial bidding meaningless. However, Lanco managed to retain the Anpara project. Repeatedly tarnished by charges of corrupt practices the company ran into financial trouble and has filed for Corporate Debt restructuring in
July 2013.
In late 2017 the company faced insolvency proceedings, with the National Company Law Tribunal suspending the board.


Monica Oliphant

Monica Viviene Oliphant (; born 4 August 1940 in Ilford) is a British–Australian research scientist, specialising in solar energy.
Career.
Oliphant began her scientific career with a master's degree in physics from the University of London and worked for almost 20 years as an energy research scientist for the Electricity Trust of South Australia, but since 2000 has been an independent consultant specialising in residential energy efficiency and renewable energy. Oliphant attributes her interest in solar energy from hearing Sir Macfarlane Burnet in the 1970s claiming that "if we used solar energy we would not need to fight over oil" – this sparked a career of over 40 years in the renewable energy industry. Key to her work was the belief that sustainable energy should be available to everyone and she claimed to be most proud of her work monitoring the effect of energy efficient devices on low income households in Australia, as well as being part of the Australian Federal Government’s first Mandatory Renewable Energy Target (MRET) which enabled Renewable Energy Certificates (RECs), helping make small scale renewable energy more affordable.
Oliphant was President of the International Solar Energy Society from 2008 to 2009 and is an adjunct associate professor at the University of South Australia.
Honors and awards.
2002 – South Australia Great Environmental Award

2012 – World Renewable Energy Network Pioneer Award

2011 – Most Outstanding Contribution to the Clean Energy Industry, Ecogen

2015 – Officer of the Order of Australia – presented for services to the renewable energy research in solar photovoltaics.

2016 – Senior South Australian of the Year


UGI Corporation

UGI Corporation (formerly United Gas Improvement Co.) is a natural gas and electric power distribution company headquartered in King of Prussia, Pennsylvania, with extensive operations in the United States and Europe.
UGI owns AmeriGas, the largest propane marketer in the United States. UGI also owns AvantiGas, Antargaz and Flaga in Europe.
UGI also operates interstate and intrastate transmission and natural gas storage assets in the Marcellus Shale.
History.
UGI was incorporated in 1882 as United Gas Improvement Co.
In 1903, the company owned the majority of the stock of the Equitable Illuminating Gas Light Company, which operated the Philadelphia Gas Works.
The company formed the United Electric Company of New Jersey in 1899. United Electric consolidated several electric and lighting utilities into a single holding company.
Public Service Corporation of New Jersey took over United Electric in 1907. United Electric was ultimately merged into Public Service Enterprise Group.
In October 1964, Industrial Gases, Inc., of Pittsburgh, Pennsylvania, filed an antitrust suit in United States district court charging the company with attempting to eliminate competition in sales of bottled propane gas in Pittsburgh. The Philadelphia Gas Works division of UGI challenged a ruling of the Federal Power Commission. The FPC lowered the maximum price that natural gas producers could charge to $0.16 per of gas. This mandate was upheld by the Supreme Court of the United States in May 1968.
In February 1968, the company changed its name to UGI Corporation.
In 1993, through its AmeriGas subsidiary, the company acquired Petrolane, which was in bankruptcy.
In 1999, the company offered to acquire Unisource Worldwide, a distributor of office paper, but it was outbid by Georgia-Pacific.
On April 1, 2013, John Walsh succeeded Lon Greenberg as president and chief executive officer.
In May 2015, the company acquired Totalgaz S.A.'s liquefied petroleum gas distribution operations in France for €423 million.
In October 2017, the company acquired Totalgaz Italia, a liquefied petroleum gas distribution business.
In December 2018, the company acquired South Jersey Industries’s retail natural gas business.
On August 1, 2019, the company acquired Columbia Midstream Group for approximately $1.275 billion.
On August 21, 2019, the company acquired the portion of AmeriGas that it did not already own.
On July 10, 2020, the company acquired GHI Energy LLC, a Houston-based renewable natural gas company.
On January 5, 2020, the company acquired "Mountaineer Gas Company" of West Virginia for $540 million.


Niagara Mohawk Power Corporation

Niagara Mohawk Power Corporation is a New York State utility company, which was acquired in 2000 by National Grid plc. The Niagara Mohawk Power Corporation designation was retired, using variations of NationalGridUS (such as National Grid Buffalo), though its official designation on annual reports is still Niagara Mohawk Power Corporation.
In 1929, 59 former companies were incorporated into the Niagara Hudson Power Corporation. In 1932 an Art Deco-style headquarters building was constructed in Syracuse. It was the main electric and natural gas provider for a large swath of northeastern, central and western New York, including the Capital District, Syracuse, Buffalo and Niagara Falls.
The statue on the front of the building is named “the Spirit of Energy” and was nicknamed “Iron Mike.”
The company adopted the name Niagara Mohawk Power Corporation in 1950. From 1950 to 2002 it owned the Rankine Generating Station in Niagara Falls, Ontario through its subsidiary Canadian Niagara Power. The station and Canadian Niagara Power were sold to Fortis Inc. in 2002.
The Nine Mile Point Nuclear Generating Station was erected by Niagara Mohawk. The first unit was completed in 1969, and was followed by a second unit in 1988.