The main culprit, according to the study, is the patchwork of renewable energy mandates across 29 states, D.C. and Puerto Rico. These states require a percent of their electricity to be generated from various renewable sources by a certain year. For example, New York requires 29 percent of electricity to be generated by renewables come 2015, Texas requires 5,880 MW by 2015, while Rhode Island requires 16 percent by 2020. The definition of renewable resource can vary but most states include solar, wind, and biomass sources.

In 2010, the average price of residential electricity in states with Renewable Portfolio Standards (RPS) was 31.9 percent higher than rates in non-RPS states. Commercial electricity rates were 27.4 percent higher, and industrial rates were 30.7 percent higher. Of the ten states with the highest electricity prices, eight have RPS mandates.

The recent surge in rates reverses a decades-long trend. In 1960, the inflation-adjusted cost of residential electricity was $0.14 per kilowatt-hour. By 2005, the average cost of a kilowatt-hour was down to $0.09, but by October 2011 the average cost climbed to more than $0.12.

However, RPS mandates aren’t the only force pushing up electricity rates. Increasingly stringent federal environmental rules are forcing dozens of coal-fired power plants, recently the cheapest form of electricity, to retire. Bryce finds coal-dependent states with RPS mandates have residential rates 37.6 percent higher than those in coal-dependent non-RPS states.

Another source of higher rates is the installation of “smart” meters in distribution networks. Residential consumers in the Houston area are getting smart meters that will cost an additional $3 per month for the next 12 years. In Pittsburgh, smart meters are costing consumers about $5 a year for at least five years.

Expansion of transmission lines is also responsible for higher costs. According to the Edison Electric Institute, companies will spend about $61 billion on transmission projects from 2010 through 2021. Some of that money is being spent to accommodate renewables. For instance, wind power in west Texas is far away from the urban areas in need of power, requiring companies to run long lines to transmit the power. The cost of the new transmission lines for renewable energy projects will be about $126 for each American, but Texans will pay about $270 each because the cowboy state has more wind-generation capacity than any other state.

While many factors are contributing to rising electricity prices, it appears RPS mandates are the main factor. While outright appeal isn’t likely, reforming the standards to account for recent developments like the shale boom, or publicizing their contribution to higher electric rates can go a long way towards preventing future mandates and cost spikes.

ElectricChoice.com helps homes and business make educated choices when it comes to buying electricity in deregulated states. Start saving in less than 5 minutes. Start here.

Renewable energy in Ohio is promoted through the Renewable Energy Portfolio standards(RPS) which require 12.5 percent of the state’s power to come from alternative sources like wind and solar by 2025. An additional 12.5 percent is supposed to come from “advanced” energy sources like nuclear and fuel cells. In past, the Kasich administration has been accused of wanting to repeal these energy mandates. But instead of ending subsidies for renewables that are too expensive to compete in the market, the new energy policy seeks a softer approach.

The Governor wants to expand the use of co-generation, or the use of waste heat from industrial processes, such as blast furnaces, to generate electrical power. This would be accomplished by adding co-generation to the list of energy sources that are mandated under the RPS.

Transmission improvements are also being considered to encourage the use of renewables. The administration is seeking better integration of renewable sources with the electric grid by identifying and fixing transmission line inadequacies.

Renewable electricity isn’t the state’s only concern. The plan is also designed to address the needs of the growing shale drilling industry. Apart from updating health and safety regulations, new regulations are being designed to ensure there is adequate power for shale gas processing facilities that will soon appear in eastern counties.

Kasich wants to jump start the demand side of the shale boom too by encouraging the use of compressed natural gas, or CNG, as a fuel for cars and trucks. His administration is assessing the conversion of all or part of the state fleet to CNG. The Governor’s office is also proposing a revolving loan fund to help build a network of natural gas as well as biodiesel and ethanol fueling stations.

Finally, the most controversial part of the energy strategy is an across-the-board income tax cut for all Ohioans financed through a tax horizontal “shale wells.” Natural gas wells would be taxed at 1 percent and oil wells initially at 1.5 percent. The crude oil tax would increase to 4 percent in later years. Budget advisors are confident the tax can generate as much as $500 million a year, allowing the administration to reduce income taxes by 5 percent.

The Kasich energy plan faces an uphill battle in the Ohio General Assembly where lawmakers are reluctant to consider sweeping changes in an off-budget, not to mention election year. The bigger question, however, is if the energy scheme will really accomplish lower rates for Ohio consumers. Transmission and system upgrades are often needed investments to maintain the reliability and efficiency of the grid, however, encouraging the construction and integration of renewable energy sources that cannot compete directly with traditional energy sources often ends up increasing electricity rates.

Plant closures are a result of the short implementation time period, combined with the high cost of retrofits. First Energy is closing nine plants in Ohio, Pennsylvania and Maryland, including the Albright Power Station, the Willow Island Power Station, and the Rivesville Power Station managed by subsidiary Mon Power; Bay Shore Plant, Eastlake Plant, Ashtabula Plant, and Lake Shore Plant in Ohio; Armstrong Power Station in Pennsylvania, and R. Paul Smith Power Station in Maryland. Collectively the plants are capable of generating 3,350 MW.

All of these plants are coal fired generation units that run primarily during peak periods, or when the demand for electricity is very high. The highest peak periods are usually during the dog-days of summer when everyone cranks up their air conditioning. The National Electrical Reliability Council has expressed concern that the reliability of electricity could be threatened by the large amount of near simultaneous plant closures.

What does this all mean for electricity consumers shopping for the lowest price? In most cases it means higher rates. With less supply available in eastern Ohio and western Pennsylvania, electricity prices in the First Energy territory are expected to nearly double at a power auctions in May. Analysts predict rates will rise from $126 for every megawatt available per day to $200 or even $500.

In states without electric competition, utilities can pass on the costs of installing new equipment to meet to ratepayers- increasing rates. If state regulators refuse to allow utilities to pass on the cost of the upgrades, more plants will close leaving even less power available to meet demand.

All this sounds like bad news but the Ohio Republic points out there is a silver lining . . . for utility companies. First Energy and other companies divesting large amounts of coal-fired generation could see record profits from capacity auctions.
Apart from selling power, generators in a state with electric competition can make money by selling capacity or making power plants available for use during peak periods.

With fewer generation plants operating, prices for capacity will rise.
Until electric companies can build new, cleaner generating capacity, consumer in the First Energy footprint should brace themselves for higher rates.

What Are Electric Delivery Charges?

These charges are known by many different names: Demand charges, transmission charges, TDSP (Transportation Distribution Service Provider) charges, and poles and wires charges. TDSP charges are the fees associates with servicing and delivering power to your meter from the generation source. The TDSP, sometimes called your Transmission and Distribution Utility (TDU), is the utility company that manages the energy grid in your area of the state. The TDSP is responsible for maintaining the poles, wires, meters, and other transmission equipment relating to the distribution of energy from the power production plant to the final delivery point. The primary charges that fall under TDSP fees are: Distribution, Transmission, and Transition Charges. These fees are based on your meter’s “Peak Demand” which is the maximum electricity that you use at a given point in time. The grid has to work harder to have the capacity available for your peak demand at all times because that is the worst case scenario. If the grid doesn’t prepare accordingly, users could be forced to have rolling black outs. Although there are fixed costs and other components associated with your TDSP charges, higher demands are generally the primary cause of higher TDSP fee charges. Some examples of other fees included are Metering Charge, Advanced Metering Fee, and Nuclear Decommissioning Fee.

Demand Versus Consumption

Demand is the measure of the level of power you require at a single point in time, measured in kilowatts (kW) or kilovolt amperes (kVa) as recorded in 15-minute intervals. In contrast, consumption is the quantity of energy you use over a period of time, measured in kilowatt-hours (kWh). For example, ten 100-watt light bulbs “demand” 1,000 watts, or 1 kW of electricity from the power grid. If you leave all ten lights on for two hours, you would “consume” 2 kWh of electricity over that given time.

Since TDSP charges are based predominately on “how” you use your electricity and not exactly “how much” you use, it is important to understand your facility’s electricity profile. You can have two facilities in the same congestion zone that consume the same amount of electricity over a year but can be charged very different TDSP charges. To explain this, we will look at two examples, a diner and a church. Justin’s Diner is a small mom and pop café open seven days a week, twenty-four hours a day, consuming 100,000 kWh of electricity annually. Since the diner is always consuming electricity, it is flowing in small consistent intervals causing the demand to remain relatively low. On the other hand, there is First Church of Example, Texas that also consumes 100,000 kWh of electricity annually. The church only meets a few days a week when the majority of the electricity is consumed. The meter is barely active the rest of the week. When a facility has an immediate increase of usage, similar to a surge or a spike, the grid must be able to react instantly to the demand. Because the church uses the same amount of electricity in a shorter time span and due to the spike in demand when the meter goes from inactive to heavy use, the TDSP charges of the church will be considerably higher than that of the café.

How Are They Calculated?

TDSP charges are calculated according to the rate tariff set forth by your specific Utility Provider. These tariffs have to be approved by the state Public Utility Commission (PUC). Please click the link below to view the tariffs for a specific utility zone.

Texas: Oncor, Centerpoint, AEP Central, AEP North, Texas-New Mexico Power

New Jersey: ACE, JCPL, PSE&G, ORU

New York: ConEd, National Grid, ORU, Central Hudson, NYSEG, NIMO

Pennsylvania:West Penn Power, PECO, PPL, Pennelec, Duquesne, Met-ED

Why Are My Demand Charges So High?

There are a few reasons why it might seem like you are paying too much for your TDSP charges.

1.) You may have a faulty meter or have just received a new digital “Smart Meter.” If you previously had an analog meter, there is a high possibility it was not accurately reading your demand and consumption. With the replacement of a new digital Smart Meter, your utility provider is now able to more accurately read your demand and consumption.

2.) For customers with minimal usage, TDSP charges can be proportionately larger than your energy consumption charges. The reason for this is because there are fixed components associated with the cost to deliver your power. It can cost more to deliver your electricity and to serve your meter than to pay for the actual commodity itself.

3.) Your demand may be abnormally high due to “Ratchet Charges.” Utilities assess a “ratchet” charge by levying a constant fee, based on an annual peak-demand level from an earlier month, for up to a year after it occurred. The utility must have resources available for the worst-case scenario and since you have used that peak previously, they have to charge you for your capability of demand. A customer is usually charged either the monthly peak or 80 percent of the peak demand based on the last 12 months of usage.

4.) Larger customers may receive penalties for congestion if their power factor is a low percentage.

5.) You may be using a provider that is marking up your TDSP charges.

What Can I Do to Save Money on TDSP Charges?

As a customer you have many options to ensure that you are not being charged too much on TDSP charges.

1.) Contact the utility provider for your area and have them check for a faulty meter.

2.) Understanding your bill and how you are being charged is key. Give us a call if you would like some guidance.

3.) Ramp up your usage slowly, waiting more than 15 minutes to bring each large component online. Limit the equipment running simultaneously if possible, or at least the level at which they operate. Also have your HVAC checked regularly. Heating and cooling equipment usually starts using considerably higher demand when it is in need of maintenance or replacement.

4.) For large commercial accounts, the Energy Consultant can check your Power Factor and determine if your facility needs Power Factor Correction. The Power Factor is the ratio of true power or watts to apparent power or volt amps.

5.) Marking up the cost of TDSP charges is completely legal and some retail energy providers do this to increase profits. We and many others in the industry frown on this practice because it makes it hard for consumers to get a good apples to apples comparison. To ensure that this is not the case for you, Eisenbach Consulting can conduct a bill audit free of charge. Your Energy Consultant would need three months of bill copies and a Letter of Authorization allowing the Consultant to pull your facility’s past usage history which reflects demand and charges. If it is determined that your retail electric provider is marking up your TDSP charges, your consultant will suggest a provider that will not. Eisenbach Consulting screens all of our providers to ensure we serve the best interest of our customers.

To create a competitive market place, New Hampshire’s law required divestiture of generation capacity by the state’s utility companies. By 2003, Unitil and National Grid had completed divestiture but the process was temporarily halted for Public Service of New Hampshire (PSNH) due to volatility in the marketplace and the Enron disaster in California that caused rolling blackouts and outages across the county. The PUC held that divestiture would continue once sale of the assets was deemed to be in the economic interest of retail customers.

Now Rep. Frank Holden has introduced HB 1238 to spur the divestiture of PSNH generation assets. Rep Holden and proponents of electric competition believe now is the time to complete divestiture as customer migration from PSNH default service increases, additional costs to update PSNH’s generation assets loom, and the risk of volatile energy prices is low.

One third of consumers in the PSNH territory are now shopping and receiving power from competitive suppliers. As PSNH’s consumer pool continues to decrease, each consumer is bearing a larger share of legacy costs, making the utilities rates even less competitive and spurring further switching. The status quo is unfair to those who have not shopped and is it sustainable.

PSNH was struggling to finance expensive new retrofits even before new more stringent EPA emission standards were approved last December. The utility applied for a non-by passable charge to help offset a $440 million scrubber at the Merrimac generation plant, (originally estimated to cost $250 million) but was denied. Instead, the utility is instituting a temporary rate increase to pay for the project. If PSNH divested its generation assets these costs would be the responsibility of shareholders, not captive ratepayers.

Finally, the volatility of electricity rates in New England is low as natural gas rates are expected to remain low for the foreseeable future. These market conditions should placate any concerns over rate volatility in the near future.

New Hampshire residents already have been waiting over a decade for full competition. Today, PSNH’s base residential rates are higher than those paid by the other utilities in New Hampshire and its sister companies. It’s time to finish the transition; it’s time for cheaper energy.

Recent changes in the market have led us to change our long standing view favoring shorter-term fixed-rate energy agreements, in favor now of longer-term fixed-rates. Although the market is bearish short-term, we feel that the very small premium between a 12 month term and a 60 month term is justified by the risk of price increases going forward. We believe the upside to be in the 3-cent/kWh range. Upward movement in short-term pricing will largely be based on weather (if it gets cold suddenly, prices will go up). So, a strategy to pay 1/2–cent/kWh more long-term to avoid a potential 3 cents/kWh of upside risk both short and long term seems prudent. Conversely, the downside opportunity in the current bearish market is ½-1 cent/kWh at best. That is, we feel prices are near the floor and could fall no more than 1 cent, in a best case scenario.

The chart below will help you visualize how significantly the price of natural gas generated electricity for a 5-year term has fallen in the last 12 months.

Summary – Electricity prices are currently very low, upside-risk is medium, downside opportunity is very low. The conclusion to be drawn is that it is advantageous to now lock-in energy prices for a long term (four to five years). Price certainty through 2016 is currently available at a very slight premium to short-term prices.

Factors

• Prices near record lows for calendar year 2012 – 2016
• EPA and other regulatory factors loom and could change prices significantly as regulatory pressures on the market mount. The EPA has delayed it’s cross-states air pollution rule, which has helped prices come down, but as soon as an announcement is made about when this rule will be implemented, prices could rebound.
• Winter weather – to this point forecasts continue to predict a mild winter.  Colder winters cut into reserves driving prices up.
• As of December 23, domestic inventories are at 3,848 Bcf, which is 9.1% above the same time a year ago and 13.7% above the 5-year average. It’s hard to imagine it getting much better (limited downside opportunity).
• Wednesday, January 19, 2012, natural gas closed at a 10 year low settle price of $2.32.

Monopolies are notoriously inefficient because there is no incentive to improve productivity and reduce costs. Electricity monopolies are no exception to the rule. Allowing monopoly utilities to thwart competition, whether by imposing unreasonable costs on customers who shop for electric suppliers or negotiate bilateral agreements with favored suppliers, needlessly increases costs for businesses and slows economic growth.
Electric competition also offers transparent pricing, providing a measure of certainty, something that is sorely lacking in our economy today. Certainty is essential for capital-intensive, long-lived investments like power plants.

Additionally, lower energy costs have a positive ripple effect throughout the economy. Every business uses electricity, some more than others, making energy costs a key part of any budget and therefore a factor in a business’s ability to maintain employees and expand.

Some government agencies understand the relationship between energy prices and job creation. The Rhode Island Public Utilities Commission rejected a proposed power purchase contract between Deepwater Wind (a small offshore wind development) and National Grid in April 2010, because of the job?killing effects of higher electric prices. The Rhode Island PUC was not rejecting all wind generation, but rather a specific project that was far more expensive than other wind generation alternatives.

However, other government organizations still choose to ignore the benefits of market competition and risk losing jobs. The Massachusetts Department of Public Utilities approved a contract between National Grid and Cape Wind with a cost of over $250 per MWh. This despite lower contract bids from several companies. One offer was half the cost of Cape Wind’s bid.

Interventions in the market, like state policies that create subsidies for politically favored generators or mandate uneconomic investments, send a powerful do-not-invest signal to developers and drive out real competitors along with their job opportunities.

Regulators should not be fooled by promises of new jobs from these interventionist policies. The now well-known Solyndra debacle is a perfect example of how manipulating the market is detrimental to long-term job creation.  Such policies lead to higher long-term electric prices, slowing all parts of the economy.

By itself, electric competition cannot rescue a languishing economy, but combined with non-interventionist policies, electric competition can be a catalyst for economic growth throughout the nation.

ABACCUS ranks commercial and industrial markets as well as residential markets in North America. Illinois ranks second most competitive in the commercial market and seventh in the residential market. Pennsylvania ranks fourth in the commercial market and third in the residential market with an excellent rating, the same rating given to Texas and New York.

In Pennsylvania’s first full year of residential competition, 1.4 million customers began shopping for electricity. As of November, 92.3 percent of industrial customers are exercising electric choice with 33 providers. Almost 20 percent of residents in the Keystone state are shopping from the same 33 electricity suppliers with 55 different product offerings.

In Illinois, 94.4 percent of industrial customers are shopping from 26 suppliers. The residential market has lagged the success of Pennsylvania’s because of the state’s highly subsidized residential rates before rate caps expired. Today, real-time pricing is slowly strengthening competition.

Product differentiation in residential markets is beginning in Illinois and Pennsylvania. Constellation Energy, which Exelon is in the process of taking over, offers Consert a user-friendly residential energy management solution that allows consumers to conserve energy and offer it back as additional capacity. Direct Energy offers Comfort Club to residential Pennsylvanians to bundle electricity with heating and air conditioning tune ups and safety checks. And PPL EnergyPlus offers an online billing platform that puts customer hourly load and pricing information at the fingertips of its commercial and industrial customers.

Innovation in the electricity market isn’t just reserved for the most improved markets. New consumer products and services are a constant feature of the most competitive markets. Energy suppliers in Texas have developed prepay offerings coupled with the use of advanced meters and mobile communications. Direct Energy’s Power-To-Go offers prepaid electricity to residential Texans with a new payment channel, pay as you wish, and daily text updates. In New York, consumers can select fixed-price contracts with periods of two to 60 months and green content at levels of 25, 50 or 100 percent renewable content. Improvements in advanced metering, transmission system upgrades and continued innovation in internet and telecommunications products ensures consumers will continue to see steady stream of new products and services.

To continue improving the electricity marketplace in Illinois and Pennsylvania, the ABACCUS report recommends phasing out default electricity. Not surprisingly, the Pennsylvania PUC is already investigating the possibility of phasing out default service. If the PUC decides to pursue this policy Pennsylvania could be the most improved market again in the 2012 ABACCUS report.

A few months before rate caps expired, the Lancaster-Lebanon Intermediate Unit began searching for a way to lower electric bills for schools. They decided to form the Electricity Procurement Program and selected Direct Energy as their alternative supplier. Direct Energy was able to capitalize on their experience with schools and their unique needs; schools use little electricity during summer months when demand is high. Unfortunately, the majority of schools have not taken advantage of the available savings from electric choice in Pennsylvania.

Switching to a competitive electricity supplier has been a slow but steady process across Pennsylvania. Currently, the majority of industrial consumers are shopping, but the number of resident and business consumers remains in the 20 to 30 percent range. The worse shopping rates come from the Met-Ed utility region, where less than three percent of residential consumers are shopping.

Why the slow pace in Pennsylvania? That’s a question Public Utility Commission is trying to answer. Some of the sluggish growth may be due to slowly emerging competition. Beginning in November, Con Edison Solutions began serving Met-Ed residential customers with an offer of 8.05 cents per kilowatt-hour, a 11.5 percent savings compared with the current Met-Ed Price to Compare.

When polled about electric shopping, the vast majority of Pennsylvania residents know they have a choice when it comes to electricity generation, yet they still have not switched. When asked why they are not shopping, many said they didn’t think the amount of savings was worth the hassle. Others reported the switching process was overwhelming or too complicated with so many choices.

While there is little the Pennsylvania Public Utility Commission (PUC) can or should do about the low amount of savings in some areas, websites like ElectricChoice.com specialize in making the shopping process for homes and businesses simple and effective. The PUC will continue to work on other ways to facilitate easy shopping.

One suggestion is to change the frequency of rate recalculations. Instead of utility companies adjusting rates to reflect market prices every quarter, the PUC is considering limiting rate adjustments to twice a year. This policy could induce more shopping by giving consumers less data to consume, but it could also backfire.

Decreasing the amount of price adjustments could make electricity prices less reflective of the marketplace and prevent switching, or make it less likely consumers will be aware of lower rates since their utility bills will rarely change.

The PUC will continue to study this and other recommendations for improving the state’s electricity market, a process that won’t be completed anytime soon. Meanwhile, the electricity market will continue to grow and expand as new suppliers enter the marketplace.

The utilities involved, Pennsylvania Power and Light (PPL) and New Jersey’s Public Service Enterprise Group (PSEG), claim the line will relieve congestion in New Jersey. Congestion occurs when there are not enough lines to deliver the cheap power to areas where the electricity demand is high. This forces more expensive local electricity to meet the demand and customers end up paying higher rates.

In addition to lowering electric rates in New Jersey, the Susquehanna-Roseland line will improve the reliability of the grid. Reliability means fewer opportunities for brown outs as electricity use continues to surge. Reliability is something we take for granted today, but it is serious concerns as electricity usage continues to increase while many power plants near retirement and others may be forced into early retirement to comply with new EPA regulations. Transmission projects like the Susquehanna-Roseland line are critical to ensuring low-cost power in the future.

President Obama has designated the line as one of seven transmission projects that will receive special assistance from the “Rapid Response Team for Transmission.” The special designation is designed to expedite the permit process that can take years or even a decade to complete. The construction of the new line is expected to create 2,000 construction jobs and is the only project with a special federal designation in the heavily populated northeast.

Of the many state and federal agencies required to sign-off on the construction, only the National Park Service has not approved the Susquehanna-Roseland line. The line crosses about four miles of the Delaware Water Gap National Recreation Area, the Appalachian National Scenic Trail and the Middle Delaware National Scenic and Recreational River. The park service is expected to release a draft impact study this fall and give a final decision next fall.

Environmental groups are against the new transmission line, voicing concerns about land disturbance and aesthetics. For example, the new transmission towers will rise from the current 56-80 feet to 165-190 feet tall.

The reason for the current path through the park service lands, according to the utilities, is that the companies already have the right away as the existing line was in place before the area was designated public land. Currently, the only additional right-of-way needed on any park service lands is an additional 50 feet of right-of-way that PPL has requested on a 0.8 mile segment in Pennsylvania.

Yet, environmental groups respond that renewable energy could replace the needed additional capacity. In contrast, the regional transmission organization (PJM) maintains that the project is essential to reliability in the future.

PPL and PSEG hope to have the line in service by 2015.