The USA is made up of fifty constituent States, each being a political entity in its own right. Each territorial State administration and organisation is a legacy of its historical union under the United States Constitution which binds each into the Federal Republic of the USA and the shared sovereignty that we recognise today. The extent and nature of State’s powers in relation to the Federal government has been a constant source of debate and evolution ever since the first (Delaware 1787) and last (Hawaii 1959) States joined the union. This two tier structure; first Federal and then State subdivision has led to a complicated marriage with respects to all areas of governance; including today’s electrical power sector.

According to the BP Statistical review in 2016 (BPStats, 2016); In 2015 the USA consumed 17.3% of the worlds primary energy equal to 2281Mtoe, 2^nd place only to China (22.3%), and both well ahead of India in 3^rd place (5.3%).The USA is a key international energy market leader as well as arguably the only global superpower politically giving it a prominent role in developing and demonstrating successful energy market policies.

US Net annual electrical generation (all sectors) in 2015 was 4.09TWh (EIA_MER, 2016). The EIA identified coal (declining contribution since 2007) and natural gas (increasing contribution) generating 33% and 33% respectively of all US electricity (EIA, 2016), i.e. two thirds of all US electricity is generated from fossil fuels. The cheap shale gas boom started to contribute and displace coal fuel markedly from 2008 onwards. The remaining generation is made up from Nuclear (19.5%), Hydroelectric (6%), Wind (5%), Biomass (2%), Solar and Geothermal (<1%) generation.

Up until 2012 there had been no new licensing for new nuclear power stations since the 1979 Three Mile Island incident; the Nuclear Regulatory Council only approved five new reactors at existing plants in 2012 to compliment the hundred in operation (Rascoe, 2012). Given the unpopularity of nuclear power, and the negative impacts of burning fossil fuels to generate electricity has on the environment and national security; the future of electricity generation in the USA is steering towards energy conservation and the harnessing of more renewable resources to displace fossil fuels to meet the current, and the projected 1% growth in electricity demand between 2014–2040 (EIA, Annual Energy Outlook 2015, 2015). Looking at hydroelectricity and wind for example. The US DoE ‘Hydropower Vision’ low carbon future for hydroelectricity (48% of current renewables) was modelled and hypothesized to have the potential to increase installed capacity by 50%, from 101GW to 150GW by 2050, and including the growth of pumped hydro storage to enhance network delivery integrity (Jose Zayas, 2014). For wind, The US DoE stated technical feasibility in providing 20% of the nation’s total electricity by 2030 (Cooney, 2008). In the US; Geothermal, Biomass, Wind and Solar given their current penetration and market growth rates will all contribute massively to future electricity supply with each possessing unique power delivery characteristics requiring integration into electrical infrastructures.

Electricity supply must always provide and deliver exact amounts to customers in all locations and times within high quality specifications. Electricity is problematic to store and considered a public, economic and political necessity in Developed countries like the US. The complex infrastructure to deliver this falls into two subsets; generation and the power grid (transmission and distribution) – together constituting the bulk power system (BPS).

Furthermore, the amount of electricity consumed varies continuously. Key temporal demand variables include; the seasons which vary regionally (AC or space heating), the time of day – with later afternoon peaks and weekly variation between weekday and weekends. Large population movements (1980’s northern US rust belt migration to the South), climate/weather variations regionally (North American cold wave 2014) and national economic activity (US Great Recession 2007-2010) also had significant demand change impacts.

In 2014 the EIA identified that the major electricity consuming sectors in the US were Residential (36%), Commercial (35%), and Industrial (28%), with Transportation only using 0.2%. Considering transport alone; If some forecasts are to be believed – by 2040 Electric Vehicle growth could represent 25% of cars on the road, equivalent to 11% of 2015 global electricity demand and requiring a seismic shift in electricity delivery and generation strategies (Macdonald, 2016).

It’s evident that the US energy markets private and public players, and the politics of Federal and State policy makers today and in the future will need to be dynamic in reacting to the juxtapositions of possible increasing electricity demands, matching demand variability, increased renewables penetration and their obligations to a safer, more sustainable and secure supply. This study attempts to explain how the spider-web like current electrical market in the USA is economically structured to deliver this in response to competing demands and the challenges faced in achieving State aspirations within such a complicated market legacy of systems.

The characteristics and policies related to the delivery and storage of other forms of energy such as heat (geothermal, biomass CHPs) and chemical fuels (gasoline, biofuels, hydrogen) were not the focus of this study. These separate energy types have their own unique physical and market economy characteristics which differ greatly from electrical energy, and would better be served by individual studies on government interventions and incentives.

The History of Electricity Markets in the USA

In order to understand the current complex structure of the US electricity supply and markets, it’s necessary to review key historical events which drove modern power markets and regulatory evolution. Initially Utilities (vital service wholesale power generators and retail customer suppliers) were either unregulated ‘Not-for-Profit’ (NfP) services provided by municipal government in many cities, or private cooperatives (investor owned monopolies regulated by State). The first street lighting projects from the 1880’s grew rapidly to cover larger and larger areas allowing Utilities to achieve economies of scale and rapidly reduce production costs (FERC, 2015). The US electricity market quickly became dominated by a small number of companies as the retail market demand rapidly grew and diversified with new urban centric uses such as Industrial electric motors, municipal electric street cars and domestic hot iron technologies to name a few. The advent of long distance AC transmission and large scale steam turbine generators both stimulated further rapid demand growth beyond urban centres with established forward thinking Utilities such as Chicago Edison (one of many of Edison’s US franchises) realising natural monopolies of regional markets through consolidation. Monopolies were recognised as non-competitive and detrimental to the wider society at the time invoking a ‘Progressive Era’ shift towards regulation.

The first control exerted by the Federal government was to establish a regulatory body under the Federal Power Act 1935 – the Federal Power Commission (FPC). Originally set up in 1920, its remit was intended to regulate interstate electric transmission and wholesale power sales from Utilities; the FPC managed the early development of the nation’s hydroelectric resources. The first public NfP and private Utilities were vertically integrated in structure and competed together mostly in urban areas for wealthy customers. As production costs dropped – this economically self-perpetuated larger numbers and sizes of plants to provide greater capacity reserves to meet growing demand. The building of intra and inter State connecting transmission lines allowed Utilities to share reserves and initiated the formation of the first power grid as a way to maintain reliable reserves and realise decreased plant sizes, and hence lower production costs. Generation and transmission from then on was referred to as the bulk power system (BPS). This electricity interconnection encouraged the first operating Power Pool (PP) formation in 1927; (PJM) Pennsylvania-Jersey-Maryland (Wikipedia_PJM, 2016). Utilities, through multilateral arrangements acted as one common operator of generation and transmission assets to further reduce their capital and operating expenditures. Numerous other regional PPs followed.

A further Federal regulatory Act was implemented in response to the Great Depression in 1935; the Public Utility Holding Company Act. The Act aimed to limit a Utilities influence to a single States regulation as a Federal control measure (amongst others) to counter natural monopolies by forcing them to divests their operations (In 1932, the largest eight Utility Holding companies controlled 73% of investor owned electricity!). The PUHCA lasted until it was replaced in 2006 with the passing of the Energy Policy Act of 2005 (Wikipedia_PUHCA, 2016).

To share and extend to rural areas electricity access and its associated prosperity, the 1936 Rural Electrification Act provided federal loans for the installation of distribution networks using member organised Cooperatives as funding conduits – a lot of these cooperatives still exist today in rural America (Wikipedia_REA, 2016).

From 1929 to 1967 – national average electricity costs plummeted; partly through improved plant efficiencies, but also through a growing customer base improving each company’s economies of scale as well as the formation of Utility power pools to more efficiently share interconnected reserves and transmission capacity. Interconnection efficiency was exemplified by the long distance transmission of lower relative cost, seasonal peak snow melt hydroelectricity from the NW and SW to California – with bilateral returns in other seasons (FERC, 2015).

As a result of the 1965 black out which affected 30 million people in the North East of the US, the next key energy sector milestone was cemented in place. The blackout led directly to the setting up of the North American Electric Reliability Council (NERC) in 1968 as a voluntary, Utility managed BPS reliability focused organisation which still exists and exerts oversight controls today (FERC, 2015).

The 1973 oil embargo had massive implications and influences on today’s US energy market (Wikipedia_OilCrisis, 2016). The embargo occurred just as US oil imports and consumption was increasing sharply. The embargo raised fuel prices and had an inflationary effect on the US economy, including consumer retail electricity prices. Raised oil prices and dwindling gas reserves due to under investment led Utilities to construct new power plants relying on domestically available coal and uranium (Figure 1). However these plants were more capital intensive, further increasing the electricity costs passed onto the consumer. Inevitably this lead to public dissatisfaction and the government introducing new regulations. The Public Utility Regulatory Policies Act (PURPA) was introduced as part of the National Energy Act of 1978 to promote energy conservation and promote more secure domestic and renewable (hydroelectricity) energy sources (Wikipedia_PURPA, 2016). PURPA regulated Utility monopolies as an efficiency measure through State run Public Utility Commissions (PUC’s). Existing and new power plants now came under new legislation as ‘qualifying facilities’ (QF), and were required to meet statutory standards to gain access to QF market transmission capacity. States now set the ‘avoided cost’ electricity rates (cost avoided by Utilities by purchasing power rather than self-generation). Importantly, the Act also introduced new competition – independent power producers (IPPs) and non-utility generators (NUGs) who diversified power generation and watered down the existing monopolies influences (IPPs/NUGs did not automatically qualify for QF status). This ushered in a move towards competitive generation and open market access – independent of regulated monopolies.

Figure 1 – Changing US electricity generation fuels (EIA Monthly Energy Review, 2016)

Importantly, from 1977 onwards the Federal Energy Regulatory Commission (FERC) succeeded the FPC to independently regulate the transmission of wholesale electricity between Utilities as part of the Department of Energy Organisation Act (1977). The Act aimed to consolidate energy-related agencies into one department (Wikipedia_FERC, 2016). Electricity distribution regulation to retail customers remained at State level control via PUC’s.

In the 1980’s, Regulators began to take a more active role in Utility planning and restructuring markets in response for the need to improve integrated economic efficiencies, reduce unexpectedly high nuclear development costs and counter the 1970s oil embargoes problems – ultimately aimed at reducing consumer retail prices (Girouard, 2015). The introduction of Integrated Resource Planning (IRP) allowed formal road maps to be constructed by Utilities and lodged with State PUCs to perform cost-benefit analysis and identify all risks of held resources with the ultimate goal of identifying a lowest cost/risk future resource plans (Bolinger, 2005). IRPs proved successful in stimulating consumer choice and stabilising retail prices rises, but were expensive and time consuming with significant differences among adjacent Utilities.

Further competition enhancement and deregulation followed. The FERC in 1988 proposed that the PURPA applied QF State set ‘avoided cost’ of generation, should instead be competitively auction based to realise further cost savings to customers. Furthermore it should be opened up to IPPs/NUGs to further develop competitive markets. A significant barrier to overcome to realise deregulated markets at the time was the Utilities sole ownership and access control of State transmission infrastructure. The Energy Policy Act of 1992 expanded the FERCs authority to grant transmission access upon request. The Act also amended PUHCA and PURPA Acts to help smaller Utility competition growth and broaden Utility resource choices (Wikipedia_EPA, 2016). Both resulted in partially improved transmission access. Moves to open up transmission further fully followed with FERC order no.888 in 1996. This required all public Utilities to open up transmission access on a tariff and cost recovery basis to remove barriers to competitive wholesale markets (FERC_888, 2010). Order no.889 followed shortly after in 1997 to establish an internet based Open Access Same Time Information System (OASIS) for posting transmission capacities (FERC_889, 2010). Notably, these orders limited each Utilities own power market data transfer and required significant control room operation changes.

From the start of the 21^st century, the US Electricity market structure began to more closely resemble today’s, more openly competitive Utilities power market system and had largely moved away from traditional bilateral transactions, power pool agreements and natural monopolies of the 20^th Century. This historical evolution has created a patchwork of regulated versus deregulated markets (Figure 2), public versus private Utilities and interconnected versus isolated BPS creating a complex and constantly evolving quasi-competitive system.

Figure 2 – Deregulated Energy markets by State (www.electricchoice.com, 2016)

The structure of current Electricity Markets in the USA

Today the US electricity sector is regulated by the Federal government through the Department of Energy. Economic Utility regulation is State controlled via PUCs, with intra/interstate transmission regulation overseen by FERC and NERC (Wikipedia_ES, 2016). The Environmental Protection Agency (EPA), Federal Trade Commission (FTC) and Nuclear Regulatory Commission (NRC) safeguard the environment, consumer protection and nuclear generation plant safety respectively.

In the US, a large number of stakeholders provide wholesale electrical generation, transmission and retail distribution services to electrical customers. In 2013 there were 3306 Utilities providing these services, with only a small fraction providing all three functions (QER, 2015). FERCs oversight of wholesale transmission system and reliability is overseen by the NERC who adopt mandatory and enforceable standards. The NERC remains a non-profit corporation overseeing eight regional reliability entities spanning the USA’s entire interconnected grid system (Figure 3). In 2007, the FERC granted NERC legal authority to enforce mandatory Reliability standards (NERC, 2010).

Figure 3 – NERC reliability regions in the USA (NERC, 2010)

Broadly speaking the countries 640,000 miles of high voltage AC transmission lines (QER, 2015) are divided into two major Eastern and Western interconnections (ICs), and three minor grids – Texan. Alaskan and Hawaiian ICs. Eastern, Western and Texas ICs are tied together (Wikipedia_ES, 2016). Transmission System Operators (TSOs) control transmission independently on a competitive market basis.

Deregulation of markets which began in earnest in the 1970s has proven to be an effective measure in dropping wholesale, and thus retail electricity prices through enhanced interconnection and competitive free market practices. Deregulated markets can be defined as a multiple Utilities market place, each divesting ownership in generation and transmission to then only be responsible for distribution between the grid and meter point, as well as retail sales billing and acting as Providers of Last Resort supply (POLR), i.e. standby by back-up (Deliso, 2014). Independent Transmission System Operators (TSOs)/FERC/NERC operate transmission, capacity and ancillary services with a continuing view to further deregulation improvements such as Smart Grids (FERC_SG, 2016). The NE, California and Texas are the best examples of progressive deregulated markets (Figure 2).

Transmission System Operators (TSOs) are termed either Independent System Operators (ISOs) or Regional Transmission Organisations (RTOs). The concept of ISOs accompanied FERC Order no.888. ISOs independently operate the transmission system and aim to foster competition among wholesale participants. Groups of transmission owners formed ISOs including some of those within traditional Power Pools (FERC, 2015). The order however did not mandate the establishment of ISOs. In 1999, FERC amended this with Order no.2000; this did directly specify that Utilities should join RTOs (Wikipedia_ROCs, 2016). Both RTOs and ISOs were intended to be voluntary and independent operators, coordinating generation and transmission across geographically diverse regions using a wide range of Utility assets to balance supply instantaneously with load demand. The difference between RTO’s and ISOs is minimal; essentially they operate in the same ways. Both were conceived to handle increased numbers of competitive market transactions and each ensures open access, system reliability and transmission charges savings are passed onto retail customers. Some of the largest Utilities owning transmission assets include ITC Holdings and AEP.

Both RTOs and ISOs coordinate power delivery to two thirds of the electricity used in the US (Wikipedia_ROCs, 2016). Seven RTOs/ISOs currently exist (Figure 3). US mainland located electric Utilities fall under FERC authority, but not all Utilities are RTO/ISO members. All however do fall under NERC regulations which overlays FERC authority as well as covering some Mexican and Canadian import Utilities. Two Canadian Electric System Operators (ESOs) voluntarily accept FERC rules and recommendations and are considered as ISOs (Figure 4).

Figure 4 – US Electricity market RTOs/ISOs (FERC, 2015)

Some legacy anomalies exist with this RTO/ISO structure however. The ERCOT ISO and its Utilities are located solely within Texas State. It does not fall under FERC authority, but does however comply with NERC regulations. ERCOT is not synchronously interconnected to the rest of the US (FERC_ERCOT, 2015), but does on its own form the most deregulated, self-contained market in the US. Additionally, large regional swathes of the US electrical markets remain operated by traditionally unregulated vertically integrated Utilities, i.e. owning generation, transmission and distribution to serve end use customers and retaining elements of natural monopolies. These regions choose to exchange power through bilateral agreements called purchase power agreements (PPAs). Regions include the Pacific NW, the majority of SE States and inland States between CAISO and SW Power Pool ISOs (white blank areas in Figure 4).

Given today’s complex market structure, it’s worth gaining an appreciation of the massive scale involved in delivering electricity to distant and sometimes remote parts of the country. Utilities are defined differently between States. The main two types are Private Investor Owned (IOUs) and Publicly Owned Utilities (POUs). IOUs (including IPPs/NUGs) are private investor owned and regulated by State PUCs which set retail prices, regulations and ensure proper infrastructure maintenance. Three of the largest IOUs are Pacific Gas & Electricity and Southern California Edison in California, and Florida Power & Light. POUs on the other hand are cooperatives or government/municipal owned and generally exempt from State regulation because it’s believed they have customers best interests at heart. Other smaller legacy public sector power organisations include Power Marketing Administrations (PMAs), Rural Utility Cooperatives (RUCs) and a small number of Federal Power Agencies (FDAs). Four DoE wholesale PMAs are responsible for marketing 42% of US hydropower over thirty three States (Figure 5); Bonneville(BPA), South-eastern (SEPA), Southwestern(SWPA) and Western Area (WAPA),(EIA_PMA, 2013). In addition, PMAs include various Power Authorities (PAs) such as the New York and Tennessee PAs who still retain largely State bound, vertically integrated services (Wikipedia_NYPA, 2016). RUCs are generally split into Distribution and Generation/Transmission and made up of residences and businesses members. These RUCs have their roots in the 1936 Rural Electrification Act and are now administered by Rural Utilities Service (DoA, 2016).

Figure 5 – Federal Power Marketing Agencies (www.EIA.gov )

Published by the American Public Power Association, Figures 6, 7, 8 and 9 illustrate the massive scale of the US electrical market. The key facts from the 2013 charts include;

There are 3306 Utilities functioning in the US, 87.4% are Public POUs/Cooperatives.
Utilities together deliver instantaneous electricity to 148 million customers.
Private IOUs responsible for 69% of customer sales (e.g. EXcel Energy, Duke Energy).
Private IOUs/NGUs responsible for 79% of generation and 78% of nameplate capacity.

Figure 6-US Utility electricity providers 2013; (American Public Power Assoc. 2015-2016)

Figure 7-US Utility electricity customers 2013; (American Public Power Assoc. 2015-2016)

Figure 8-US Utilities generation 2013; (American Public Power Assoc. 2015-2016)

Figure 9-US Utilities nameplate capacities 2013; (American Public Power Ass. 2015-2016)

The US also has a rapidly growing Distributed generation sector. Distributed generation is off-grid generation used at source and avoiding transmission and distribution losses – largely from the uptake of rooftop Solar PV. Excess electricity can be exported back to the grid and managed by Utilities employing Net Metering (NM) systems to track net energy flows. Key US distributed generators include Ameresco Inc. and NORESCO (Booher, 2016).

Ownership of electrical Utilities is almost completely held by US companies since market assets are considered critical infrastructure and a national security concern; GDF Suez IPP is one, large foreign company exception. Although cross border interconnectors do exist, for example Canada has at least thirty active interconnections in 2014 (QER, 2015), the US is largely a self-sufficient electricity market and power exporter.

The high capital costs and number of regulatory barriers to entry means a large portion of generation capacity is held by relatively few Utilities. In 2013, the five largest IOUs generators accounted for almost one quarter of US Utility scale power production (Booher, 2016); IOUs like Exelon Corp and Energy Future Holdings Corps for example. Retail prices (Tariffs) vary greatly across the US and are heavily influenced by the mix of generation assets in or near the State. The Columbia River Basin centred around Washington, Idaho, Oregon and Montana States for example supplied 44% of the countries low cost, hydroelectric power in 2012 and supplies significant electricity to California State (EIA_Hydro, 2012). Residential electric tariffs across the US (Figure 10) reflected these generation plant costs, as well as other influences such as transmission tariffs (published by Utilities Open Access Transmission Tariff system), climate impacts and State regulations like energy conservation and policy interventions. State PUCs regulate consumer retail prices, whilst the Federal Power Act of 2012 granted the FERC authority over ensuring just and reasonable wholesale costs.

Figure 10 – USA average annual Retail residential electrical rates (NREL, 2013)

Regional Electricity markets ran by TSOs dispatch electricity based upon transmission reliability and constraints, as well as the least cost pathway. Dispatching occurs in two stages; day-ahead unit commitments in hourly slots and real time system dispatch to optimise actual load and grid conditions. The NYISO ISO for example uses a Market Supply Curve (Figure 11) to first call on wind generation, then hydro, nuclear, coal, gas and finally oil to minimise retail costs through optimising production costs (FERC, 2015). TSOs also oversee two other important markets; Capacity Markets which ensure adequate available generation to meet peak demand, and Financial Transmission Rights contracts allowing Utilities to hedge against transmission congestion in day ahead markets (FERC, 2015). Traditional Electricity market PMAs/RUCs abide by similar codes of conduct largely through bilateral transaction contracts.

Ancillary services to maintain reliability and transmission support are overseen by NERC and regional entities, and provided by market Utilities – with costs passed onto retail customers. Operating reserves include spinning, non-spinning and supplemental reserves as well as ‘Black start’ (e.g. grid independent quick start hydroelectricity) capabilities (FERC, 2015).

Figure 11-NYISO ISO least cost path Market Supply Curves (FERC Energy Primer, 2015)

Pricing of wholesale electricity in both traditional and TSO regions utilise both cost-of-service (CoS) and market based (MB) rates in over the counter (OTC) and bilateral transactions with Utility suppliers providing retail distribution termed ‘load-serving entities’ (LSEs may also provide self-supply). CoS rates are enforced by FERC when MB rates are not appropriate or the Utility does not seek MB rate authority. Utilities are allowed to recover production costs and receive a fair return on their capital. The FERC grants MB rate authority to Utilities who prove competitive market approaches only, i.e. minimal horizontal and vertical integration monopolies (FERC, 2015).

The Incentivisation of renewables in energy markets

Federal promotion of renewables started back in 1935 with the Federal Power Acts encouragement of hydropower. Through various Acts since, efficiency gains, deregulation and renewable technology development have had a long history in the USA, leading to a proliferation of incentive policies at State level. Given that energy is recognised as an essential good in the US, it has a low elasticity to price changes which means consumers will bear most of the burden of any direct taxation if implemented. To avoid negative popularity consumer cost increases, the US instead implements financial incentive/subsidy schemes for renewables to realise new technology economies of scale and reduce production costs. Subsidies do not however promote conservation. These subsidies have been applied to a diverse mix of generation assets and have evolved dynamically as the marginal costs of each technology moved toward the optimal mix of regional ‘equimarginal’ competitive markets, within the longer term aim of deregulation and conservation.

To briefly touch on energy efficiency and conservation as an example of this strategy. Whilst the subject does not fall directly under renewables policies; energy conservation in the US is recognised as a key platform for achieving climate change, energy security targets and reduced infrastructure costs, e.g. the National Action Plan for Energy Efficiency 2008 (EPA_GOV, 2016). Gillingham and Palmer studies highlighted potential CO2 emissions savings through energy conservation (McKinsey & Co. equal to 835 megatons of CO2 by 2030), suggesting that the present discounted value of future energy saving greatly exceeds the cost of energy efficient products. They also examined why the ‘energy efficiency gap’ exists; i.e. the “slower than socially optimum rate of diffusion of energy efficient products” caused by the failure of consumers to make economically logical energy saving decisions because of a large number of unaddressed market externalities, market information failures and behavioural anomalies.

To address the renewables take up ‘efficiency gap’ and avoid politically challenging taxation or emissions cap policies aimed to even out consumer private and social costs, a reliance on Federal subsidies to encourage investment has traditionally been taken by the US, with debates on policy efficacy through distortionary taxation, leakage effects, ‘free-riders’ and ‘free drivers’ competing for economic attention (Gillingham & Palmer, 2013). Four key Federal financial subsidy and renewable support policies appearing at State level under a multitude of different names and designations currently exist (Booher, 2016);

Production Tax Credits (PTCs – enacted by Energy Policy Act 1992);
- Production based incentive providing tax credits for renewable generation.
- 10 year duration after facility start (past August 2005) – inflation adjusted basis.
Investment Tax Credits – in lieu of PTCs (ITCs-enacted by Energy Policy Act 2005);
- Incentivise renewable capacity construction in service between 2008 and 2015.
- Allows taxpayers 1 tax credit against project tax basis-equal to 30% of first year.
- Election of QFs to be eligible for 10%-30% ITC (technology dependent).
Grants and Loans under American Recovery and Reinvestment Act (2009; ARRA);
- Projects eligible for grants in lieu of PTCs/ITCs.
Renewable Portfolio Standards (RPS);
- Obligates State Utilities to increase electricity usage from renewable sources.
- No Federal national renewable goals have been set.
- Includes Solar renewable energy certificates (SRECs).

Across the fifty States today, there are 2604 individual Federal and State policy incentives currently enshrined in total (US_DoE_State_Incentives_For_Renewables_&_Efficiency, 2016). California alone has the largest number with 187 currently active.

To avoid an exhaustive policy study; policies for energy efficiency improvements – Energy Efficient Resource Standards (EERS), further consumer deregulation – Green Button Initiative, 3^rd party Solar power purchase agreements (PPAs) and Feed in Tariff (FiT) programs can all be referred to in Appendix A & B. A wealth of other State policies such as Clean Energy Funds, mandatory purchase quota ‘Green Power Options’ and ‘Modified Accelerated Cost Recovery’ Systems have not been covered here – just the key policies.

How successful have the PTC/ITC schemes been at introducing renewables competitively? “Historically, federal tax policy expiration has highly correlated with year to year renewables installations, particularly for wind (Figure 12). The year before expiry, Utilities have ramped up installations in anticipation of PTC alteration/removal creating a boom-bust cycle. Using empirical analysis, the PTC alone between 1990 to 2011 promoted 1.4GW per year on average of new wind deployment across the US, overcame technology entry barriers and non-addressed externality advantages of conventional generation (unregulated pollution). PTCs were also found to be a catalyst for more effective State policies. In addition, the renewables installation responsiveness of a given State was found to be dependent on its resource potential “(Shrimali, 2014). The latter point indicating greater PTC flexibility is needed in future to focus upon State relevant technologies.

Figure 12 – PTC versus Annual Wind Installations (Shrimali et al 2014)

Similarly with Solar ITC policies, “Financial incentives have been a driving force for residential/non-residential Solar PV growth in the US (Figure 13). Incentives have been a combination of State/Utility cash, ITCs, as well as RPS SRECs and distributed net metering. Cash based incentives in 2014 had largely been phased out in response to declining PV prices as SRECs gained more prominence in key markets like California and New Jersey (Figure 14). Solar PV Median prices dropped between 6% to 12% per year on average (Figure 15)” (Dargouth & Barbose, 2015).

Figure 13 – Growth of Solar PV capacity additions in the US (Berkeley Lab 2015)

Figure 14 – Solar PV capacity split geographically in the US (Berkeley Lab 2015)

Figure 15 – Median installed Solar PV price drop over time (Berkeley Lab 2015)

It’s clear that government intervention in markets to nurture emerging technologies through subsidies, a continued drive to deregulate and encourage competition, and continued support to new technology research and development is key in normally functioning markets to successful renewables penetration. As technology production economies of scale kick in and company’s expertise increases, lowering prices perpetuate a domino effect in growth which then involves an evolution in support policies. “60% of Fortune 100 companies have renewable-electricity or climate change policies in place in 2016 (Figure 16), eighty one have committed to sourcing 100% of their energy from renewables in future” (Philips, 2016).

Figure 16 – Greener Company wind and solar (Bloomberg 2016)

These policy successes have encouraged Congress recently to extend Federal tax credits; “In December 2015, Congress agreed to extend the 30% ITC for solar, and 2.3cent/kWh PTC for wind power to 2020 (Table 1), whilst geothermal, marine and small hydro received a one year ITC extension (Cusick, 2015).

Table 1 – Post Appropriations Act 2016 PTC/ITC extension scheme (NREL, 2016)

In times of abnormally functioning markets, like the 2007 US ‘sub-prime’ mortgage led recession; greater government intervention was deemed required under Keynesian economic theory to preserve jobs and promote economic recovery. This was the reason for the US Governments one-off ARRA stimulus Act in 2009, with an estimated $819 billion committed between 2009 to 2019 to a wide range of employment sectors. For renewables this meant a tax credit extension to 2014, $21.5 billion for energy infrastructure improvements and $27.2 billion for energy efficiency, research and investment (Wikipedia_ARRA, 2016). Controversy exists on how many jobs were created but Figure 17 displays the impact the Act had on employment. Clean energy related funding supported roughly 900,000 jobs in the years between 2009 and 2015 in innovative, clean energy fields and laid further groundwork for US clean energy growth into the future (US_President_EO, 2016).

Figure 17-US National Job loss/gains 2007 recession (US Bureau of Labour Statistics 2010)

Financial incentives are gradually being superseded by green certificate strategies. Renewable portfolio standards are State/local-level policies that require all electricity producers to supply a minimum share of their electricity from designated renewable resources. RPSs use ‘Green Certificates’ called Renewable Energy Certificates (REC), which are available for geothermal, biomass, wind and solar generation. Currently twenty nine States have adopted RPS targets (Figure 12). Green certificates are essentially ‘proof’ of generating green electricity and creating capacity from renewable resources. “RPS policies currently apply to 55% of total US retail electricity sales, 60% of renewable generation and 57% of new capacity (Figure 13) since 2000, associated with it. Primarily from new wind, but more lately with solar resources in-line with each technologies more market competitive costs. The vast majority of States met 95% of RPS targets between 2012-2014, with compliance costs in 2014 being $2.6B, and equating to 1.3% of average retail bills without busting State set cost caps. Importantly, as States reach final term targets, they have largely extended and expanded future targets, e.g. California to 50% by 2030 (Figure 14)” (Barbose, 2016). Its clear RPSs have been an affordable success in the implementation and cost competitiveness improvement of wind power, with a similar effect now occurring with solar technologies in 2015. It remains to be seen if Biomass and Geothermal follow the same pattern as States independently look to largely advance their RPS targets and policies – for example Hawaii in 2015 set a 100% RPS by 2045 (EIA_RPS, 2015).

Figure 18 – State Adopted US RPS (US DoE 2016)

Figure 19 – Renewable Capacity additions by State as a result of RPS (Berkeley Lab 2016)

Figure 20 – RPS target deadline expiry and extensions (Berkeley Lab 2016)

It’s briefly worth highlighting State Net Metering programs which allow distributed generators to sell excess electricity to a Utility for credits. Net metered solar saw significant growth in 2015 for the 4^th consecutive year, with the addition of 2100MW of capacity. Certain States can use NM to meet RPSs. The majority of States have adopted NM (Figure 15) whilst taking different policy approaches to capacity limits, eligible technology, REC ownership and NM credit retention (NCSL, 2016). Distributed ‘Load Defection’ growth represents a real challenge to the Utilities traditional model of centralised power generation and distribution.

Figure 21 – Utility led Net Metering (US DoE 2016)

Federal and State division of responsibility for energy and climate change

The Federal and State structure of the US in all areas of policy setting and implementation overlaps to different degrees in theory and in practice. Franz T.Litz at the World Resource Institute assessed the issues pertaining to climate change policy specifically; this section largely summarises his assessment and debate on the topic (Litz, 2008).

Historically in the US, States have led renewables implementation. There exists a complicated patchwork picture of State energy deregulation (Figure 2), TSOs (Figure 4) and RPSs (Figure 18). How and to what degree Federal and State governments share responsibility in future however is open to debate.

A State led perspective would draw on States historically being first-movers on environmental issues, through policy innovation, testing, implementation and regulations later considered at the Federal level. Examples of these include; California’s Global Warming Solutions Act 2006 to set GHG emissions targets (Figure 22), Regional cap-and-trade Programs by groups of North-Eastern and Mid-Atlantic States in 2005 and State led RPSs programs. States have the advantage of understanding what policy structures suit their unique geographical and economic circumstances.

Figure 22 – State with GHG emissions targets (www.pewclimate.org 2008)

A Federal led perspective would unite the States against meaningfully challenging climate change. It would also provide business equality to contend with different State regulations presenting competitiveness issues and minimise ‘leakages’ of any emissions cuts to other States. International engagement for emissions reductions is a Federal responsibility, for example the recently ratified UNFCC Paris Agreement in 2016. Only a national GHG cap-and-trade program based upon a global market approach would sustain long term actions.

A shared responsibility perspective highlights that historically, climate change actions have been shared by both State and Federation. For example the Federal Clean Air Act of 1963 established national ambient air quality standards but largely relied on State development and implementation of those standards. More recently in 2009 a similar shared ownership of State tested RPSs at the Federal level was proposed by the American Clean Energy and Security Act and aimed to establish a national emission trading scheme, it however failed to pass Senate approvals committees (Wikipedia_ACES, 2016). Tables 2, 3 and 4 below identify some areas where shared ownership already exists in key areas affecting climate change and highlights each entities substantial overlap. With respect to carbon taxes; no State or Federal tax exists but both have the Authority to tax, which some local jurisdictions have enacted. What these tables demonstrate is that very few subject areas with respect to climate change are dedicated to one or the other government levels, but instead are universally shared.

The proposal put forward by Litz for future significant climate change policy – the Federal government takes ownership of setting a minimum uniformity levels across the country, whilst preserving room for State innovation and implementation to take effect – as is the case historically.

Table 2 – State vs Federal Pollution control policies (Litz 2008)

Table 3 – State vs Federal energy supply policies (Litz 2008)

Table 4 – State vs Federal energy efficiency policies (Litz 2008)

Key renewables energy controversies and divergent State approaches

With the USA in 2015 mining 11.9% and consuming 10.3% of the worlds coal, producing 22% and consuming 22.8% of the worlds gas, consuming 19.7%, producing 13%, and refining 20.4% of the world’s oil (BPStats, 2016) for only 4.4% of the world’s population– it’s a country with an addiction to fossil fuel and a public expectation of energy as an essential good. This creates strong regional political and economic divisions when balancing traditional fossil fuel employment with Federal and State policy trends to lower GHG emissions and grow a sustainable renewable energy industry.

The announcement of President Obama’s Clean Power Plan (CPP) in August 2015 and the future direction under a new administration is currently the US power sectors biggest controversy. The CPPs key aim is to reduce CO2 emissions from power generation by 32% of 2005 levels by 2030 (with associated SO2 and NOx reductions benefits also). The onus falls on State fossil fuel burning plants (31% of US CO2 emissions) complying with new Federal carbon pollution standards and plant efficiencies (heat rates), substituting natural gas for coal generation (Figure 23) and expanding support for renewables from 2022 onwards. Inter and Multi State substitution (emissions trading) is encouraged for States to implement plans to achieve CO2 performance cuts by 2030 (EPA_CPP, 2016). In States dependent upon cheap, nearby coal reserves for power generation, as well as producing States already experiencing dramatic declines in coal sector employment the implications are catastrophic (Table 5). Five leading coal ‘burning’ States that voted Democrat in 2012 elections aligned with the other top five coal using States to all vote Republican in 2016. Out of twenty one coal ‘producing’ States – all but New Mexico (10^th), Colorado (11^th) and Maryland (small amount of mining) in 2014 voted Republican. Whether the CPP had an impact on States voting is difficult to say. The dramatic decline in coal generation from its peak in 2007 – due to a combination of the shale gas boom in 2008 which drove down competing natural gas prices, the EPA introducing Mercury and Air Toxic Standards (MATS) in 2011 (EPA_MATS, 2016) and the decreasing cost of renewables was already an important political and social issue even before the CPP was announced (Figure 24). The 2016 Republican candidate ran on an anti-climate change agenda and may well have tipped coal States voting. With the CPP on hold whilst further debated in the upper levels of US legislature, the Plan faces a controversial and uncertain future as does the US coal industry itself (Holden, 2016). For some States like Texas, Illinois and maybe Pennsylvania with growing generation diversity the CPP may not be as critical, however States like W.Virginia, Ohio, Kentucky, Wyoming and Missouri which are heavily coal dependent – the CPP and how to evolve to meet Federal obligations is a key concern.

Table 5 – Largest US coal burners and producers in 2014 (Laurie 2016)

Figure 23 – CPP State capacity mix scenario 2016-2030 (NERC 2015)

Figure 24 – Actual, announced and proposed coal retirements (Sierra Club/EIA 2015)

Another keen area of debate is the division of subsidies between fossil fuels and renewables. Segments of US society argue about the continued subsidy support for an already well established and highly profitable fossil fuel industry, on top of the industries unaddressed externalities that mean the actual price of fossil fuels is not a true reflection of its costs to society. Renewables appear to be competing on an unbalanced and bias Federal playing field.

Tangibly, taxpayers support the fossil fuel industry through tax breaks incorporated into legacy standard parts of the American tax code. For coal this includes expensing exploration costs, claiming mine depletion deductions and preferential Capital Gains Tax treatment for Royalties (Goad & Stephen Lacy, 2012). Similarly for oil and gas; Intangible Drilling Costs reclaimations and Percentage Depletion taxes to name a few (Kraemer, 2015). Renewables qualify for stop-start PTC/ITC relief whilst fossil fuel tax breaks are permanently enshrined in law. Less transparent are preferential public land loopholes allowing cheaper and bureaucratically easier leasing for fossil fuel projects compared to renewables, e.g. Powder River coal basin in Wyoming land undervaluing and Californian land leases for oil and gas still being at 1920s prices in 2009! Even less apparent are federal loans and investment tax incentives for US railroads; in 2009 coal accounted for 47% of tonnage and 25% of US railroads revenue because coal is such an important US export commodity (Goad & Stephen Lacy, 2012).

Counter to this skewed argument, fossil fuel supporters highlight that renewable electricity subsidies increased by 54% between 2010 to 2013 to $13.2billion, whilst over the same period fossil fuel subsidies declined by 3% to $1.09billion, and by 20% to $2.35billion for coal and oil/gas respectively (IER, 2015). The recently released US EIA Federal subsidy evaluation update from 2013 (EIA_SUB, 2015) displays these subsidies and changes (Figure 25). Subsidies listed include direct expenditures, tax expenditures (reduced liabilities), research & development, PMA/RUCs support programs and Loans.

Whether the new Administration will continue with President Obama’s focus on repealing engrained tax laws for fossil fuels is unlikely (Barron-Lopez, 2015). Equally unlikely is whether the new Federal government will continue to support renewables to extent they have done over the last few years. Regardless of the Federal direction, critically government subsidies are no longer the key drivers of the emergent wind and solar sectors, economics are (Ryan, Polson, & Martin, 2016)!!

Figure 25 – Direct Federal subsidies in 2010 & 2013 (EIA 2013)

Whilst these two controversies hog the headlines, there are many others intimately linked to the rapid growth in renewables penetration and the dramatic challenge the trend has on the traditional way electrical Utilities have done business. Redefining the Utility’s new business model is a key research focus (Figure 26); Demand Response Managements and Smart Grid are two familiar strategies (See Appendix A for further DRM and SM explanation). It’s a time of dynamic change for Utility survival; increased Utility power storage investment threatens to transform the ancillary services market, Utilities are diversifying into embedded solar rooftop generation and load defection threatens a Utility ‘death spiral’ (Kind, 2013). It’s not just the fossil fuel generation Utilities that face controversial changes but the wholesale transmitters and retail distributors too.

Figure 26 – Projects underway around US to re-define the role of Utilities (GTM Research)

One final point of note that will lead to controversies because of the huge expense involved and fragmented, cross State shared nature of the US electrical transmission and distribution grid is modernisation. The EIA estimated the US would need to spend $2.1Trillion by 2035 on new grid technologies and infrastructure to handle higher renewables penetration (EIA_GRID, 2014). IOUs have been increasing grid investments, despite stagnating loads (Figure 27). Regulatory initiatives (RPSs) already order State Utilities to prepare the grid for increased embedded generation. However, with the sum of money involved and costs being passed onto consumers by IOUs – will there be a need for government intervention to control these retail rate rises in future.

Figure 27 – Investment estimate for IOU electrical infrastructure (EIA 2014)

Contrasting renewables and climate change approach in the UK

A comparison of the UK approach to renewables and climate change allows a valuable ‘Developed country’ policy contrast to the USA. The obvious difference between countries is scale and resources, with the US dwarfing the UK in every metric;

‘worldometers.info’ states 2016 UK population is 65.3million, US has 325.1miilion.
‘world.bymap.org’ states UK land area is 241.9k km², whilst USA has 9147.6 k km².
‘statisticstimes.com’ states 2016 GDP of $2.7trillion for UK, the USA $18.6trillion.
‘worldenergy.org’ states coal reserves of 108Mtoe in the UK (2011), the USA 113Gtoe.

The main impact of scale and resource differences between the two is the level of market complication and comparable ease with which the UK, being smaller and more manageable can react and change to new political directions on a unilaterally national, rather than regional State basis. With the UKs current affiliation with the EU, it’s probably more appropriate to compare UK policy making with a State like California rather than the US as a whole.

Apart from scale, the UK does share a wide range of relevant similarities with the US electrical market. Regionally fragmented national policies between the English and Scottish Parliaments and to a lesser extent the Welsh Assembly and Northern Irish Executive exist not unlike that between US States. The UK also has a capitalist population who view energy as an essential good, a comparable electrical power generation legacy mix (2015) – coal (23%), gas (30%) and nuclear (21%) fuels, and a politically supported, fast growing renewable energy sector (Energy-UK, 2016). Both countries have aging, centralised strategy power transmission and distribution systems requiring major modernisation both physically and strategically, along with a fast growing distributed energy sector. Both countries face very similar future energy and climate change challenges.

However even with these similarities, their respective renewables and climate change intervention policies fundamentally differ at the national level. The UK nationally has set, and continually revises mandatory targets. The Climate Change Act of 2008 laid the foundation for the formation of the Low Carbon Transmission Plan of 2009 in response to the EU Renewable Energy Directive 2009/28/EC. This plan aims to achieve a 50% and 80% cut of the UKs 1990s GHG emissions levels by 2025 and 2050 respectively, as well a 30% target for renewably sourced electricity by 2020, with the Scottish Government setting a 100% target for renewables (Wikipedia_UKEP, 2016). The UK Energy Bill 2012-2013 enforced these targets with similar aims to President Obama’s on-hold Clean Power Plan Act, namely the reduced dependence on fossil fuels and closure of polluting, coal powered electricity generation plants. No such targets have been set at the US Federal level, instead individual States via their own RPS commitments independently set renewable energy contribution targets.

Both countries implementation strategies do however partly employ similar traded ‘green certificate’ private market programs to promote competition, efficiency and innovation. Another key contrast between countries is the UKs participation in an emissions (EU ETS) trading scheme. The EU ETS aims to internalise the externality of carbon pollution from European electrical generation using a cap and trade system introduced in 2005, and a more recently introduced UK carbon price floor. The US has only two cap and trade systems in place currently; the Regional Greenhouse Gas Initiative (RGGI) covering nine NE States and a scheme in California. Congress failed to introduce a Federal cap and trade system in 2010 (Jopson, 2014).

However the proposed Clean Power Plan does effectively aims to encourage a carbon cap and trade system between all States apart from Hawaii and Alaska, by allowing States to swap carbon trade permits to meet State reduction targets (Upton, 2015).

The UK governments most recent Electricity Market Reform (EMR) aimed at decarbonising electricity supply and ensuring supply security came into action in 2015. The Contracts for Difference (CfD) scheme looks to replace green renewable obligations certificates and encourage low carbon generation growth by reducing wholesale electrical price volatility (Energy_UK_EMR, 2015). The schemes aim is to drive down wholesale electricity prices by having Utility scale, immature renewable technology companies compete via auctions for CfDs covering set periods with government determined administrative strike prices. Onshore wind and solar for example will not participate in the 2017 CfD allocation because they are considered mature technologies. This latest policy is yet to be considered as a dynamic price driving mechanism policy to replace GCs or FiTs in any US State to date. The second element of UK EMR is the creation of Capacity Markets (CM). CMs aim to ensure reliable supply capacity to meet demand whilst offering company’s predictable revenue inflows after a competitive auction process based upon set clearing prices (Energy_UK_EMR, 2015). The government set predefined capacity security targets with auctions held in 2014 and 2015. The newest policy faced severe criticism for continuing to subsidize existing fossil fuel generators that were likely to have stayed open anyway, with new capacity and demand response accounting for only a small portion of the allocated money (Orme, 2016). In the US, capacity markets have existed since 2003 but only concentrated in the NE wholesale markets of the country, e.g. ISO-NE, NY-ISO, PJM and Midcontinent ISO RTOs. Whilst they have been successful at keeping the lights on, they suffer from similar criticisms when it comes to encouraging new technology investments, with big price disparities existing between different grid connected ISOs (Maloney, 2013).

Whilst existing renewables and climate change policies do differ between countries, it’s apparent that successful schemes demonstrated by each have either been adopted, or at least debated at the National level at some point in time by both. Policy differences demonstrate the dynamic nature of policy making in a rapidly changing electrical market in response to climate change and energy security objectives. To some extent there is a relative natural convergence between the two countries electrical market policies as similar free market outlooks allows adoption of the more successful policies from each.

Final Remarks

Thomas Edison first invented the working electrical lightbulb in 1879, and went on to light up Pearl Street in New York City in 1882 using his Edison Illuminating Company Utility generation and distribution system (Wikipedia_Edison, 2016). The only capitalist thought in America’s mind after this was unregulated free market expansion and profiteering. It took almost a century before the National Energy Act of 1978 first introduced into the government vernacular ‘energy conservation’ in response to the 1970s oil embargo shocks and the realisation that America had developed an uncontrolled addiction to energy. Following the Three Mile Island incident of 1979, this energy habit was not going to be fed by new atomic power alone, and the US Government concentrated energy generation and distribution on the further development of easily accessible, cheap and centralised fossil fuel resources. Although the Mojave Desert pilot SOLAR Project started in the early 1980s, it wasn’t until Nevada Solar One in 2007 and after the second Energy Policy Act in 2005 that the first generation, large scale solar plant commercially harnessing the power of the sun began operating.

Thomas Edison famously said; “Someday, man will harness the rise and fall of the tides, imprison the power of the sun, and release atomic power”. Solar, wind and nuclear are now mainstream generation technologies today – will commercial tidal power be next? It’s clear that without vital government intervention policies to steer and correct free energy markets deficiencies – Edison’s prediction may still have been a long way off being realised and our climate change outlook far less optimistic.

Appendices

Appendix A: Assumptions & Further Notes

Timing: All researched information is correct at the time of writing. This is especially relevant to the USA (November 2016) given the recent changeover in governments, each of which have contrasting energy outlooks with regards to renewables. The most up to date information I have endeavoured to utilise.
Location: Energy Markets included are the 50 Federal recognised US states. The District of Columbia does not have Statehood status. The US Territories of Puerto Rico, Guam, North Mariana Islands and US Virgin Islands or other unincorporated territories are not included in this study focus (Wikipedia_US, 2016).
Energy Efficiency Resource Standards: EERS are state policies that require utilities to meet specific targets for energy savings according to a set schedule (Figure 28 Appendix B). EERS policies establish separate reduction targets for electricity sales, peak electric demand and/or natural gas consumption. In most cases, utilities must achieve energy savings by developing demand-side management (DSM) programs, which typically provide financial incentives to customers to install energy-efficient equipment (EEES, 2016).
Green Button Initiative: Utility suppliers are utilising consumer electrical metering data to calculate energy usage and costs (Figure 29), then making the data available to customers for planning and energy usage considerations (NM, 2015).
3^rd Party Solar Power Purchase Agreements: States have authorised residential customers to purchase solar PV generated power from a 3^rd party that that owns the installed PV system (Figure 30). Legal authority for residential PPAs lies with definition for ‘Utilities’ in State statutes/regulations (TP_PPA, 2016).
Feed in Tariffs: FiTs are used to limited extent in the US. FiT programs guarantee customers for 10-20 years owning ‘qualified’ self-generation such as rooftop Solar, a set price from their Utility for electricity generated and any excess supplied to the grid (Figure 31). FiT tariffs are usually set above the retail electricity cost in order to prove successful, with premiums depending upon program goals.
Demand Side Response; Programs fall into three categories; curtailing, shifting or on site generation. Curtailing is the reduction in use at peak, expensive times. Shifting involves moving high energy use times to off-peak periods like weekends or night times. On-Site generation involves turning on backup power sources to supply electricity needs. They can also be split into dispatchable (system centrally direct load controlled) or non-dispatchable customer decision controlled (FERC, 2015). DSR is a growing focus area in the USA.
Smart Grids; SM refers to the digital technology that allow two-way customer to Utility communications. SM consists of controls, computers and new technology working together in a digital format to respond more efficiently to quickly changing energy demands. The main aims are increased efficiencies, embedded power communication, reduced peak demand, reduced operating costs and better integration of large scale renewables (US_DoE_SM, 2016).

Appendix B: Support Material

Figure 28 – State led EERS (US DoE 2016)

Figure 29 – State Green Button data sharing Initiative (US DoE 2015)

Figure 30 – State 3rd party PPAs (US DoE 2016)

Figure 31 – US States with FiT programs (EIA 2016)

Appendix C: Project Task Sheet

In a speech on climate change in 2015 President Obama said:

“I’m convinced no challenge provides a greater threat to the future of the planet“.

The USA is one of the largest energy users, and producers, in the world. It is a country with divergent opinions on renewable energy and climate change. It is also a country with a high degree of autonomy at the state level. Your report should:

Describe how electricity markets function in the and how renewable energy is being incentivized. Identify the division of responsibility in energy and climate change policy/responsibility between state and federal government.
Also identify the key controversies and explain divergent approaches to their solutions. Finally contrast the approach taken in the US (to renewable energy and climate change) with that of another country of your choice.

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