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Monday, December 1, 2014


Hydraulic fracturing has driven down the price of natural gas from a high of $13 per million British Thermal Units (mmBTU) in 2008, natural gas prices have plummeted to below $2.00 per mm BTU, nearing record-setting lows, a game changer for both coal and renewables. The impact of 10,000's or even 100,000's of fracked natural gas wells near where people live has not been fully vetted. Is cheap natural gas worth the risk?

Couldn't resist a Battlestar Reference

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1. Background

2. Acronyms/Definitions
3. Business Case
4. Benefits
5. Risks/Issues
6. Success Factors
7. Next Steps
8. Companies
9. Links

The geology of shale natural gas formations differs from formation to another. Best practices fracking technology from one region may not be safe in another part of the country.

Most of the growth in shale gas production has been from the Marcellus Formation in the Pennsylvania area


  • Natural gas is a cornerstone of the U.S. economy, providing a quarter of the country’s total energy. Owing to breakthroughs in technology, production from shale formations has gone from a negligible amount just a few years ago to being almost 30 percent of total U.S. natural gas production. This has brought lower prices, domestic jobs, and the prospect of enhanced national security due to the potential of substantial production growth. But the growth has also brought questions about whether both current and future production can be done in an environmentally sound fashion that meets the needs of public trust.

  • Fracking refers to the procedure of creating fractures in rocks and rock formations by injecting fluid into cracks to force them further open. The larger fissures allow more oil and gas to flow out of the formation and into the wellbore, from where it can be extracted.

  • Simplified Steps In Hydraulic Fracturing

    1. A well is drilled vertically to the desired depth, then turns ninety degrees and continues horizontally for several thousand feet into the shale believed to contain the trapped natural gas.

    2. A mix of water, sand, and various chemicals is pumped into the well at high pressure in order to create fissures in the shale through which the gas can escape.

    3. The liquid goes through perforated sections of the wellbore and into the surrounding formation, fracturing the rock and injecting sand or proppants into the cracks to hold them open.

    4. Natural gas escapes through the fissures and is drawn back up the well to the surface, where it is processed, refined, and shipped to market.

    5. This process may be repeated multiple times in “stages” to reach maximum areas of the wellbore. When this is done, the wellbore is temporarily plugged between each stage to maintain the highest water pressure possible and get maximum fracturing results in the rock.

    6. The fracturing plugs are drilled or removed from the wellbore and the well is tested for results.

    7. Wastewater (also called "flowback water" or "produced water") returns to the surface after the fracking process is completed for disposal or treatment and re-use, leaving the sand in place to prop open the cracks and allow gas and oil to flow. In Michigan, this water is contained in steel tanks until it can be stored long-term by deep injection in oil and gas waste wells.

  • The development of shale gas in the United States has been very rapid. Natural gas from all sources is one of America’s major fuels, providing about 25 percent of total U.S. energy. Shale gas increased from ess than two percent of total U.S. natural gas production in 2001. to almost 40% by 2014.  The USEIA expects the share to reach 50% by 2025.

  • This very rapid growth has contributed to a situation where there is not consensus on the environment impacts impact of fracking, nor is the science completely understood. In addition, state and federal regulatory frameworks have not kept pace with the rapid expansion of production rooted in change in applications of technology and field practice.

  • Parts of the country, such as regions of the Appalachian mountain states where the Marcellus Shale is located, which have not experienced significant oil and gas development for decades, are now undergoing significant development pressure.

    Pennsylvania, for example, which produced only one percent of total dry gas production in 2009, is one of the most active new areas of development. Even states with a history of oil and gas development, such as Wyoming and Colorado, have experienced significant development pressures in new areas of the state where unconventional gas is now technically and economically accessible due to changes in drilling and development technologies.

    Output from the Haynesville shale, mostly in Louisiana was negligible in 2008; today, the Haynesville shale alone produces eight percent of total U.S. natural gas output.

  • According to the U.S. Energy Information Agency (EIA), the rapid expansion of shale
    gas production is expected to continue in the future. The EIA projects shale gas to be 45 percent of domestic production by 2035. What will be the environmental impact?
    The 56% increase in total natural gas production from 2012 to 2040 in the AEO2014 Reference Case results from increased development of shale gas, tight gas and offshore natural gas resources.  

2. Acronyms/Definitions
  1. Bakken Formation - - Rock unit from the Late Devonian to Early Mississippian age occupying about 200,000 square miles of the subsurface of the Williston Basin, underlying parts of Montana, North Dakota, and Saskatchewan. The formation is entirely in the subsurface, and has no surface outcrop. It is named after Henry Bakken, a farmer in Williston, ND who owned the land where the formation was initially discovered. in 1953.

  2. Completion - The process of making a well ready for production (or injection). This principally involves preparing the bottom of the hole to the required specifications, running in the production tubing and its associated down hole tools as well as perforating and stimulating as required. Sometimes, the process of running in and cementing the casing is also included.

  3. CH4 - Methane - Primary component of natural gas

  4. Closed Loop System - Consists of using a small waste-water processing system on the well site. It removes pollutants from the frack water as well as additional water that may also be present in the formation itself--all of which flows back up a well.

    Waste water is pumped directly into steel storage containers and held for processing.

    Solids extracted from the water by this method are removed by truck to a waste treatment station for disposal. Treated water that remains after on-site processing may then be reused on a later frack job. Typically, up to 50 percent of the frac water can be recovered and reused. It can be reused up to a dozen times without treatment.

    Less waste water needs to be moved off site, and less water is required for additional drilling operations. This method generally lowers total drilling cost, as well as the amount of water used and its cost. It also contributes to higher drill rates which provides cost savings.

  5. Dissolved Hydrocarbons - Found in both flowback and produced water. Some are pumped down the well during hydro-fracturing. These consist of glycols used in descaling and some light petroleum distillates used to enhance viscosity of the fracturing fluid. These are generally around 0.1% of the fracturing fluid volume.

    Flowback water typically contains both free and dissolved hydrocarbons that come from the formations. These are dissolved in the frac water when it is pumped underground and held there under pressure during hydro-fracturing. Many of these are lighter than water and return to the surface with the flowback. Concentrations in the flowback water are usually low--below 100 parts per million. These can generally be removed by absorption using activated carbon during treatment. There are federal and state regulations preventing release of dissolved and free hydrocarbons into water steams, so they must be removed.

  6. GWP - Global Warming Potential - Commonly used to compare the radiative forcing of ifferent gases relative to CO2 and represents the ratio of the cumulative radiative forcing t years after emission of a GHG to the cumulative radiative forcing from emission of an equivalent quantity of CO2.

    Comparing the climate implications of CH4 and CO2 emissions is complicated because of the much shorter atmospheric lifetime of CH4 relative to CO2. On a molar basis, CH4 produces 37 times more radiative forcing than CO2. However, because CH4is oxidized to CO2 with an effective lifetime of 12 yr, the integrated, or cumulative, radiative forcings from equi-molar releases of CO2 and CH4 eventually converge toward the same value.

    Determining whether a unit emission of CH4is worse for the climate than a unit of CO2 depends on the time frame considered. Because accelerated rates of warming mean ecosystems and humans have less time to adapt, increased CH4emissions due to substitution of natural gas for coal and oil may produce undesirable climate outcomes in the near-term.

    The Intergovernmental Panel on Climate Change (IPCC) typically uses 100 yr for the calculation of GWP. Howarth et al. (1) emphasized the 20-year GWP, which accentuates the large forcing in early years from CH4 emissions, whereas Venkatesh et al. adopted a 100-yr GWP and Burnham et al. (4) utilized both 20-and 100-yr GWPs.

    GWPs were established to allow for comparisons among GHGs at one point in time after emission but only add confusion when evaluating environmental benefits or policy trade-offs over time. Policy tradeoffs like the ones examined here often involve two or more GHGs with distinct atmospheric lifetimes.

    A second limitation of GWP-based comparisons is that they only consider the radiative forcing of single emission pulses, which do not capture the climatic consequences of real-world investment and policy decisions that are better simulated as emission streams.

  7. Flowback Water - aka backflow water - The murky, salty water from fracking natural gas wells. It consists of frac fluid which returns to the surface (aka the frac load recovery) as well as produced water. This water contains clay, dirt, metals, chemicals and even diesel that may have been added.

    The frack load recovery can be anywhere from 15-40% percent of the volume of fluid that is injected, that is forced down a well, and it flows back over a period of 3-4 weeks after fracking--most of it within 7 to 10 days. More than half of the frack fluid remains in the formation. At a certain point there is a transition between primarily recovering frack fluid to that of produced water. Usually this point is difficult to distinguish, yet may be discerned from the different chemical signatures of the frack water versus the naturally occurring water produced by the formation. A typical flowback of frack fluids might run 40,000 bbl. After the initial 3-4 week post-fracking recovery of fluids, an additional 10,000 to 30,000 bbl of produced water may flow for up to two years.

    Flowback water may be characterized as having high salinity and total dissolved solids (TDS). It is laden with the same fracking chemicals that were pumped into the well, in addition to any unique contaminants that are present in the rock formation water deep below. In addition to natural salinity of water in the formation, any fresh water that is forced down a well, when it is fracked, will tend to dissolve salts in the formation thus giving the recovered water very high salinity.

    The retuning fluid is generally collected in metal tanks or else open pools, lagoons or pits lined with one or more layers of plastic. These are then pumped dry, and water is usually either recycled for fracking additional wells or else trucked off site to a waste water disposal facility. Containment pits, or open-air ponds that are lined with plastic, can become points of failure. Occasionally, liners get cracked or damaged. Contaminated fluids can then leach into ground water.

    Increasingly, drillers are shifting to closed loop systems as the preferred method of handling flowback water.

  8. Fracking Additives - While companies performing fracking have resisted disclosure of the exact contents of the fracking fluid by claiming that this information is proprietary, studies of fracking waste indicate that the fluid contains: formaldehyde, acetic acids, citric acids, and boric acids, among hundreds of other chemical contaminants.

    Between 24,000 pounds and 230,000 pounds of chemicals into each well. Some of the chemicals are relatively harmless, used in common household products. But others – such as 2-butoxyethanol – are known to cause cancer in animals.

    Product Purpose Downhole Result Other Common Uses
    Acid Helps dissolve minerals and initiate cracks in the rock Reacts with minerals present in the formation to create salts, water and carbon dioxide (neutralized).

    Swimming pool chemicals and cleaners
    Anti-bacterial Agent Eliminates bacteria in the water that produces corrosive byproducts Reacts with micro-organisms that may be present in the treatment fluid and formation; these micro-organisms break down the product with a small amount of the product returning in the produced water
    Disinfectant; sterilizer for medical and dental equipment
    Breaker Allows a delayed breakdown of the gel Reacts with the cross-linker and gel once in the formation, making it easier for the fluid to flow to the borehole; this reaction produces ammonia and sulfate salts, which are returned to the surface in produced water

    Hair colorings, as a disinfectant, and in the manufacture of common household plastics
    Clay stabilizer Prevents formation clays from swelling Reacts with clays in the formation through a sodium-potassium ion exchange; this reaction results in sodium chloride (table salt), which is returned to the surface in produced water

    Low-sodium table salt substitutes, medicines and IV fluids
    Corrosion inhibitor Prevents corrosion of the pipe Bonds to metal surfaces, such as pipe, downhole; any remaining product that is not bonded is broken down by micro-organisms and consumed or returned to the surface in the produced water

    Pharmaceuticals, acrylic fibers and plastics
    Crosslinker Maintains fluid viscosity as temperature increases Combines with the breaker in the formation to create salts that are returned to the surface with the produced water

    Laundry detergents, hand soaps and cosmetics
    Friction reducer “Slicks” the water to minimize friction Remains in the formation where temperature and exposure to the breaker allows it to be broken down and consumed by naturally occurring micro-organisms; a small amount returns to the surface with the produced water

    Cosmetics including hair, make-up, nail and skin products
    Gelling agent Thickens the water to suspend the sand Combines with the breaker in the formation, making it easier for the fluid to flow to the borehole and return to the surface in the produced water

    Cosmetics, baked goods, ice cream, toothpastes, sauces and salad dressings
    Iron control Prevents precipitation of metal in the pipe Reacts with minerals in the formation to create simple salts, carbon dioxide and water, all of which are returned to the surface in the produced water

    Food additives; food and beverages; lemon juice
    pH Adjusting Agent Maintains the effectiveness of other components, such as cross-linkers Reacts with acidic agents in the treatment fluid to maintain a neutral (non-acidic, non-alkaline) pH; this reaction results in mineral salts, water and carbon dioxide — a portion of each is returned to the surface in the produced water

    Laundry detergents, soap, water softeners and dishwasher detergents
    Scale inhibitor Prevents scale deposits downhole and in surface equipment Attaches to the formation downhole with the majority of the product returning to the surface with the produced water, while the remaining amount reacts with micro-organisms that break down and consume it

    Household cleansers, de-icers, paints and caulks
    Surfactant Increases the viscosity of the fracture fluid Returns to the surface in the produced water, but in some formations it may enter the natural gas stream and return in the produced natural gas

    Glass cleaners, multi-surface cleansers, antiperspirants, deodorants and hair colors

  9. Fracturing fluid - The fluid used during a hydraulic fracture treatment of oil, gas, or water wells. The fracturing fluid has three major functions:
    1. Open and extend the fracture.
    2. Transport the proppant along the fracture length.
    3. Transport radioactive tracers through the fractures to determine the injection profile and track the locations of fractures

  10. Fracture gradient - The pressure to fracture the formation at a particular depth divided by the depth. A fracture gradient of 18 kPa/m (0.8 psi/foot) implies that at a depth of 3 km (10,000 feet) a pressure of 54 MPa (8,000 psi) will extend a hydraulic fracture.

  11. Fracture Monitoring - Injection of radioactive tracers along with the other substances in hydraulic fracturing fluid is used to determine the injection profile and location of fractures created by hydraulic fracturing, Gamma-emitting tracer isotopes that can be used as radioactive tracer material, include Antimony-121, Antimony-122, Antimony-123, Antimony-124,Antimony-125, Antimony-126, Antimony-127, Chromium-51, Cobalt-57, Cobalt-58, Cobalt-60, Gold-198, Iodine-127, Iodine-128, Iodine-129, Iodine-130, Iodine-131, Iridium-192, Iron-59, Krypton-85, Potassium-39 (activated to Potassium-40), Potassium-41 (activated to Potassium-42), Potassium-43, Rubidium-86,Scandium-45 (activated to Scandium-46), Scandium-47, Scandium-48, Silver-110, Strontium-85, Xenon-133, Zinc-65, and Zirconium-95. ;Iodine-131 was listed more often than other isotopes.

    In April 2011, the EPA found elevated iodine-131 levels in Philadelphia's drinking water and milk from Little Rock, Arkansas.  The National Cancer Institute has reported that children exposed to iodine-131, especially those drinking a great deal of milk, may have an increased risk of thyroid cancer. Both Philadelphia and Little Rock are located downstream from shale formations in which hydraulic fracturing is occurring. Iodine-131 was also found in the drinking water of other cities near other hydrofracturing sites.

    There are other sources for Iodine-131 such as nuclear energy production and the March 2011 Japanese nuclear incident.

  12. ISIP — Initial shut in pressure - Pressure measured immediately after injection stops. The ISIP provides a measure of the pressure in the fracture at the wellbore by removing contributions from fluid friction.

  13. Leakoff - Loss of fracturing fluid from the fracture channel into the surrounding permeable rock

  14. Marcellus Formation - A unit of marine sedimentary rock found in eastern North America. Named for a distinctive outcrop near the village of Marcellus, New York, it extends throughout much of the Appalachian Basin. The shale contains largely untapped natural gas reserves, and its proximity to the high-demand markets along the East Coast of the United States makes it an attractive target forenergy development.

    Maximum thickness of the Marcellus ranges from 270 m in New Jersey, to 12 m in Canada In West Virginia, the Marcellus Formation is as much as 60 m thick In extreme eastern Pennsylvania, it is 240 m thick thinning to the west, becoming only 15 m thick along the Ohio River, and only a few feet in Licking County, Ohio

  15. NGL - Natural Gas Liquids - Hydrocarbons such as propane, ethane, butane, and pentanes that are mingled with methane in wet gas areas such as ;the Marcellus shale such as southwestern Pennsylvania and northern West Virginia. These must be separated from the methane before it can be transported by gas pipelines. Wet gas, or condensate, develops in lower pressure areas of the Marcellus play. "Dry gas" occurs in higher pressure areas that tend to be more mountainous. NGLs can be separated from methane in a cryogenic processing plant.

  16. NORM - Naturally Occurring Radioactive Material - Radon gas in the natural gas streams concentrate as NORM in gas processing activities. Radon decays to Lead 210, then to Bismuth 210, Polonium 210 and stabilizes with Lead 206. Radon decay elements occur as a shiny film on the inner surface of inlet lines, treating units, pumps and valves associated with propylene, ethane and propane processing systems.

    NORM characteristics vary depending on the nature of the waste. NORM may be created in a crystalline form, which is brittle and thin, and can cause flaking to occur in turbulars. NORM formed in carbonate matrix can have a density of 3.5 grams/cubic centimeters and must be noted when packing for transportation. NORM scales may be white or a brown solid, or thick sludge to solid, dry flaky substances.Cutting and reaming oilfield pipe, removing solids from tanks and pits, and refurbishing gas processing equipment may expose employees to particles containing increased levels of alpha emitting radionuclides that could pose health risks if inhaled or ingested.

    NORM is not federally regulated in the United States. The Nuclear Regulatory Commission (NRC) has jurisdiction over a relatively narrow spectrum of radiation, and the Environmental Protection Agency (EPA) has jurisdiction over NORM and has never developed NORM regulations. Therefore, this responsibility befalls the states. Since no government entity has implemented regulations, then states may choose the stringency or lax of the regulations.

  17. Play - Oil and gas jargon used to refer to geographically similar prospects having similar source, reservoir, and trap controls of natural gas migration, accumulation and storage

  18. Produced Water - Produced water is naturally occurring water found in the sedimentary shale beds traversed by the wellbore. It is generally very saline in nature and presents an environmental challenge for drillers. Produced water requires proper treatment before disposal. It should not be confused with recovered fracturing fluid pumped down a well when it is hydro-fractured.

    There is a point where the water that flows up a well shifts from being primarily recovered fracturing fluid to that of produced water. The dividing line can be difficult to discern, yet can be distinguished by comparing the different chemical signatures of the recovered frack fluid to that of the naturally-occurring shale formation water.

    Produced water has very high salinity and total dissolved solids (TDS).It picks up various minerals from the shale formation including barium, calcium, iron, magnesium and sulpher. There are also dissolved hydrocarbons present in produced water.

    Produced water may also include low levels of naturally occurring radioactive substances (NORM) such as radium.

  19. Proppant - Suspended particles in the fracturing fluid that are used to hold fractures open after a hydraulic fracturing treatment, thus producing a conductive pathway that fluids can easily flow along. Naturally occurring sand grains or artificial ceramic material are common proppants used.

  20. Natural Gas Sources

  21. SB 4 - California Law regulating fracking - After intense debate and heavy lobbying from all sides, the state Senate and Assembly approved a fracking bill on Sep 11, 2013 that gained momentum from Gov. Jerry Brown’s public endorsement. The bill is particularly timely because of the potential for a drilling boom in California’s Monterey Shale.

    SB4 will erect a permitting system for fracking, and regulates acidizing. The measure also mandates groundwater monitoring and requires fracking firms to notify neighbors of planned wells. Companies also would have to release more information about the chemicals they shoot underground. It has been opposed by both industry and environmental groups.

    This bill establishes a comprehensive regulatory program for oil and gas well stimulation treatments (e.g., hydraulic fracturing, acid well stimulation), which includes, among other things, a study, the development of regulations, a permitting process, and public notification and disclosure
    1. Requires the Secretary of the Natural Resources Agency, on or before January 1, 2015, to cause to be conducted, and completed, an independent scientific study on well stimulation treatments, including acid well stimulation and hydraulic fracturing treatments.
    2. Requires an owner or operator of a well to record and include all data on acid treatments and well stimulation treatments, as specified.
    3. Requires the division, in consultation with the Department of Toxic Substances Control, the State Air Resources Board, the State Water Resources Control Board, the Department of Resources Recycling and Recovery, and any local air districts and regional water quality control boards in areas where well stimulation treatments may occur, on or before January 1, 2015, to adopt rules and regulations specific to well stimulation, including governing the construction of wells and well casings and full disclosure of the composition and disposition of well stimulation fluids, and would authorize the division to allow well stimulation treatments if specific conditions are met.
    4. Requires an operator to apply for a permit, as specified, with the supervisor or district deputy, prior to performing a well stimulation treatment of a well and prohibits the operator from either conducting a new well stimulation treatment or repeating a well stimulation treatment without a valid, approved permit. 
    5. Require the division, within 5 business days of issuing a permit to commence a well stimulation treatment, to provide a copy to specific boards and entities and to post the permit on a publicly accessible portion of its Internet Web site. 
    6. Provides that the well stimulation treatment permit expires one year from the date that a permit is issued. 
    7. Requires the division to perform random periodic spot check inspections during well stimulation treatments, as specified.
    8. Requires the Secretary of the Natural Resources Agency to notify various legislative committees on the progress of the independent scientific study on well stimulation and related activities, as specified, until the study is completed and peer reviewed by independent scientific experts. 
    9. Requires the operator to provide a copy of the approved well stimulation treatment permit to specified tenants and property owners at least 30 days prior to commencing a well stimulation treatment. 
    10. Requires the operator to provide notice to the division at least 72 hours prior to the actual start of a well stimulation treatment in order for the division to witness the treatment. 
    11. Requires the supplier, as defined, of the well stimulation treatment to provide to the operator, within 30 days following the conclusion of the treatment, certain information regarding the well stimulation fluid. T
    12. Requires the operator, within 60 days of the cessation of a well stimulation treatment, to post or cause to have posted on an Internet Web site accessible to the public specified information on the well stimulation fluid, as specified. 
    13. Requires the division to commence a process to develop an Internet Web site for operators to report specific information related to well stimulation treatments and would require the Internet Web site to be operational no later than January 1, 2016. 
    14. Requires a supplier claiming trade secret protection for the chemical composition of additives used in a well stimulation treatment to disclose the composition to the division, in conjunction with a well stimulation treatment permit application, as specified, but would, with certain exceptions, prohibit those with access to the trade secret from disclosing it. 
    15. Because this bill creates a new crime, it would impose a state-mandated local program.

  22. TDS - Total Dissolved Solids - The gritty substance that is a mixture of salt and other dissolved minerals that come from deep underground in the Marcellus shale. Drilling waste water has enough TDS to make it up to five times as salty as seawater.

    Large quantites of TDS can produce a salty sediment. If it is used in industrial processes, this polluted water can corrode and clog any machinery that is being employed.

    When waste water contaminated with TDS is left untreated and finds its way into the drinking water supply, it can affect the color, tastes and odor of the water. Should it come in contact with freshwater streams it can also be very harmful to fish and other creatures who make it their habitat.

    Waste water containing TDS is typically treated in sewage treatment plants, although it can also be recycled by the drillers before its final disposal. The substance is not considered to be a major health risk.

    TDS are not unique to natural gas drilling. They are also produced as a by-product of other extraction industries--the most notable in the Appalachian area is coal mining.

  23. Tight Gas - Natural gas which is difficult to access because of the nature of the rock and sand surrounding the deposit. The Natural gas reservoirs have low porosity and low permeability. It can be compared to drilling a hole into a concrete driveway–the rock layers that hold the natural gas are very dense, therefore the gas doesn’t flow easily. Because this gas is so much more difficult to extract than natural gas from other sources, companies require a large financial incentive to go after it.

    Wood Mackenzie defines Tight Gas as gas held in reservoirs with a permeability of below 0.1 milli Darcies including gas held in shales. A medium with a permeability of 1 darcy permits a flow of 1 cm³/s of a fluid with viscosity 1 cP (1 mPa·s) under a pressure gradient of 1 atm/cm acting across an area of 1 cm². A millidarcy (md) is equal to 0.001 darcy and a microdarcy (µd) equals 0.000001 darcy.

    Typical values of permeability range as high as 100,000 darcys for gravel, to less than 0.01 microdarcy for granite. Sand has a permeability of approximately 1 darcy.

  24. Well-to-Wheels - Complete Natural Gas Lifecycle

3. Business Case
  • After sorting through the evidence, my opinion is fracking is a mining operation. Mining is inherently dirty and not an activity I'd want close to my home, but  I would't like to life right next to any industrial process.  Fracking is not evil and the risks can be mitigated, but accidents and negligence are real dangers and should be regulated.

  •  Fracking can be done correctly, without pollution. Frack fluids definitely contain toxic chemicals, but so do about 100,000 other industrial processes. For example, those employed in making paper are much worse and we're not debating whether or not to have a paper industry.

    The environmental impacts of shale development are challenging but manageable. Research and regulation, both state and Federal, are needed to minimize the environmental consequences.

  • The environmental issues with fracking should be compared to the overall climate impact of coal. In the U.S. electricity supply sector, the cost benchmark for reducing carbon dioxide emissions lies with substitution of natural gas for coal, especially older, less efficient units. Substitution through increased utilization of existing combined cycle natural gas power plants provides a relatively low-cost, short-term opportunity to reduce U.S. power sector CO2
    emissions by up to 20%, while also reducing emissions of criteria pollutants and mercury.

    Furthermore, additional gas-fired capacity will be needed as backup if variable and intermittent renewables, especially wind, are introduced on a large scale.

4. Benefits
  • Power Generation - The fracking binge has already altered the outlook for the U.S. power and manufacturing sectors. More than the rise of renewables, cheap natural gas has paved the way for the retirement of more than 100 coal-fired powered plants, too aged to meet federal clean air rules.

    Efforts to build new coal plants are constrained too. Because natural gas power plants are cheaper to build and fuel, the natural gas boom has radically lowered the count of new coal-fired plants being proposed. According to data tracked by the National Energy Technology Lab and Sierra Club, plans for more than 160 coal plants have been shelved in recent years, partly due to natural gas’ cost advantage, as well as soft growth of demand for power.
    “Natural gas has done more than other legislative initiative to push coal out of the equation,” said panelist Michael Levi, a senior fellow for energy and the environment at the center for foreign aaffairs, and by my reckoning, one the smartest observers out there on this issue.

  • Manufacturing Jobs - Less than a decade ago, natural-gas-reliant manufacturers were decamping from the U.S., transplanting operations to the Arabian Gulf, Latin America and other gas-rich regions. Now many are returning. Makers of chemicals, fertilizer and pharmaceuticals, all of which use natural gas as both an energy source and a raw material are returning stateside, lured by natural gas for under $2.50 per thousand cubic feet, less than fifth of the price in Europe or East Asia.

    As Jim Motavalli reports in The New York Times, Nucor, which uses natural gas to make steel, is building a $750-million facility in Louisiana, just eight years after shutting down a similar plant in the same state and shipping it to Trinidad, to tap the island’s recently-developed natural gas supplies.

    The cost advantage provided by cheap natural gas is even sharper for companies that use methane as a raw material -- to make plastics, for example. Kevin Swift, chief economist at the American Chemistry Council, tells the Times that because European chemicals companies use oil-based raw materials derived to make plastics, the U.S. has a 50-to-1 advantage. “‘Shale gas’ is really driving this,” he says. “A million [British thermal units] of natural gas that might cost $11 in Europe and $14 in South Korea is $2.25 in the U.S. Partly because of that, chemical producers have plans to expand ethylene capacity in the U.S. by more than 25 percent between now and 2017.”

    Add up the impact of investments like these and high rates of shale gas recovery could result in a million new manufacturing jobs by 2025, according to a 2011 PricewaterhouseCoopers study cited by Motavalli.

  • Transportation - Compared to current petroleum prices, natural gas costs $1.50 per gallon equivalent, nearly two-thirds less than current pump prices for gasoline or diesel. Large fleets of heavy-duty vehicles -- from buses to garbage trucks to delivery vehicles -- have been among the earliest converts. One-quarter to a half of Navistar’s new vehicle sales in these markets opt for natural gas.

    Long-distance highway trucking may be the next to switch. Speaking with the Times, Navistar chief executive Dan Ustian, predicts that natural gas could capture up to a fifth of sales of highway tractor-trailers within a year.

    The need for on-road refueling infrastructure remains a constraint. There simply aren’t many publicly accessible natural gas refueling sites. The count is under 1,000, less than 1 percent the number of gas stations.

  • Fewer Pollutants than other fossil fuels - Natural gas produces far lower amounts of sulfur dioxide and nitrous oxides than any other hydrocarbon fuel

5. Risks/Issues
Schematic of Fracking Risks
  • Accidents & Negligence - Proponents have reported that groundwater contamination doesn't come directly from the "fracking" part of the process (the injection of hydraulic fracturing chemicals into Shale rock formations) but from other parts of the hydraulic fracturing process.

    • Poorly constructed or damaged wellbores and pipelines can allow the fluid to flow into aquifers. A 2011 MIT report found there is no evidence that these fractures can also penetrate shallow freshwater zones and contaminate them with fracturing fluid, but there is evidence of natural gas migration into freshwater zones in some areas, most likely as a result of substandard well completion practices by a few operators.
    • Volatile chemicals held in waste water evaporation ponds can to evaporate into the atmosphere, or overflow. In one of the cases described by a 2012 Cornell University study impounded wastewater was released into a field and pond, killing at least 70 animals. In another case, workers slit the lining of a wastewater impoundment (evaporation ponds) so that it would drain and be able to accept more waste.
    • Groundwater may become contaminated by trucks carrying fracking chemicals and wastewater if they are involved in accidents on the way to fracking sites or disposal destinations.
    • Release of unprocessed or under-processed waste water into rivers can contaminate water supplies.

  • Surface Water Pollution - The flowback waste that is pumped out after a well is fracked is a salty brine, mildly radioactive, and laced not just with toxic chemicals but with natural hydrocarbons and heavy metals like barium and benzene, which are known carcinogens even in minute quantities. In fracking operations out West, the flowback is generally injected into underground sites that meet EPA standards. But in the Marcellus, there are virtually no injection sites. In the early days, gas producers did pretty much whatever they wanted with the billions of gallons of toxic water their operations produce. "Since there were no laws covering the disposal of this stuff at first, they just dumped it into rivers or hauled it off to sewage plants to be 'treated,' which they knew didn't work," says Deborah Goldberg, a lawyer at Earth­justice. "They just wanted to get rid of the stuff as quickly and as cheaply as possible."

    New laws in Pennsylvania now prohibit companies from discharging flowback into rivers and streams. Instead, operators like Chesapeake either "recycle" their water by running it through a filtration system, or haul it off to Ohio and inject it underground – a process which, some seismologists now suspect, is the reason Ohio was hit by an un

  • Methane Contamination of Drinking Water - In 2011, scientists at Duke University, published the first rigorous, peer-reviewed study of pollution at drilling and fracking operations. Examining 60 sites in New York and Pennsylvania, they found "systematic evidence for methane contamination" in household drinking water: Water wells half a mile from drilling operations were contaminated by methane at 17 times the rate of those farther from gas developments. Although methane in water has not been studied closely as a health hazard, it can seep into houses and build up to explosive levels.

    The study caused a big stir, in part because it was the first clear evidence that fracking was contaminating drinking water, contrary to the industry's denials. Just weeks after the study was released, the Pennsylvania Department of Environmental Protection fined Chesapeake $1.1 million – the largest fine against an oil and gas operator in the agency's his­tory – for contaminating 17 wells in Bradford County, including some that had been part of the Duke study.

    It is important to note that not every instance of groundwater methane contamination is a result of hydraulic fracturing. Often, local water wells drill through many shale and coal layers that can naturally seep methane into the producing groundwater. This methane is often biogenic (created by organic material decomposition) in origin as opposed to thermogenic (created through "thermal decomposition of buried organic material.") Thermogenic methane is the methane most often sought after by oil & gas companies deep in the earth, whereas biogenic methane is found in shallower formations (where water wells are typically drilled). Through isotope analysis and other detection methods, it is often fairly easy to determine whether the methane is biogenic or thermogenic, and thus determine from where it is produced. The presence of thermogenic methane does not confirm the source of gas. The gas composition and isotopic finger print must compared by experts with other known sources of gas to confirm a match.

  • NORM - Naturally Occurring Radioactive Material- Radon gas in the natural gas streams concentrate as NORM in gas processing activities. Radon decays to Lead 210, then to Bismuth 210, Polonium 210 and stabilizes with Lead 206. Radon decay elements occur as a shiny film on the inner surface of inlet lines, treating units, pumps and valves associated with propylene, ethane and propane processing systems.

    NORM characteristics vary depending on the nature of the waste. NORM may be created in a crystalline form, which is brittle and thin, and can cause flaking to occur in turbulars. NORM formed in carbonate matrix can have a density of 3.5 grams/cubic centimeters and must be noted when packing for transportation. NORM scales may be white or a brown solid, or thick sludge to solid, dry flaky substances.

    Cutting and reaming oilfield pipe, removing solids from tanks and pits, and refurbishing gas processing equipment may expose employees to particles containing increased levels of alpha emitting radionuclides that could pose health risks if inhaled or ingested.

    The hazardous elements found in NORM are Radium 226, 228 and Radon 222 and also daughter products from these radionuclides. The elements are referred to as "bone seekers" which when inside the body migrate to the bone tissue and concentrate. This exposure can cause bone cancers and other bone abnormalities. The concentration of Radium and other daughter products build over time, with several years of excessive exposures.

    Radium radionuclides emit alpha and beta particles as well as gamma rays. The radiation emitted from a Radium 226 atom is 96% alpha particles and 4% gamma rays. The alpha particle is the most dangerous particle associated with NORM. Alpha particles are helium nuclei. Alpha particles travel short distances in air, of only 2-3 centimeters and cannot penetrate through a dead layer of skin on the human body. However, alpha particles are "bone seekers" due to Radium possessing a high affinity for Chloride ions. In the case that Radium atoms are not expelled from the body, they concentrate in areas where Chloride ions are prevalent, such as bone tissue. The half-life for Radium 226 is approximately 1620 years, and will remain in the body for the lifetime of the human; a significant length of time to cause damage.

  • Fracking Additives are Secret - It is impossible to know what chemicals are flowing out of the wells, or how toxic they are, because companies are not required to disclose the compounds they use in fracking operations. Providers of fracking fluids, such as Halliburton, claim that the composition of such fluids can't be revealed without disclosing trade secrets. In 2005, the industry lobbied hard for what's known as "the Halliburton loophole," which exempts it from federal disclosure requirements. In recent months, Colorado, Texas and Pennsylvania have moved to tighten state regulations and require mandatory disclosure of what's in the fracking fluids, but loopholes still remain. "We don't know the chemicals that are involved," Vikas Kapil, chief medical officer at the National Center for Environmental Health, admitted at a recent conference. "We don't have a great handle on the toxicology of fracking chemicals."

    It is difficult to assess health impact because of the industry's strategic lobbying efforts that resulted in legislation allowing them to keep the proprietary chemicals in the fluid secret, protecting them from being held legally responsible for contamination. If you don't know what chemicals are, you can't conduct pre-drilling tests and establish a baseline to prove that chemicals found postdrilling are from hydraulic fracturing.

  • Methane Leakage - Natural Gas is twice as clean as coal at the burner tip, but methane is 25 times as potent a greenhouse gas as carbon dioxide,” so gas might be dirtier than coal. Industry and environmental groups estimates of methane leakage diverge radically.

    An Greater focus needed on methane leakage from natural gas infrastructure finds that a shift to compressed natural gas vehicles from gasoline or diesel vehicles leads to greater radiative forcing of the climate for 80 or 280 yr, respectively, before beginning to produce benefits. Compressed natural gas vehicles could produce climate benefits on all time frames if the well-to-wheels CH4 leakage were capped at a level 45–70% below current estimates. By contrast, using natural gas instead of coal for electric power plants can reduce radiative forcing immediately, and reducing CH4 losses from the production and transportation of natural gas would produce even greater benefits.

    Estimates of the net climate implications of fuel-switching strategies should be based on complete fuel cycles (e.g., “well to-wheels”) and account for changes in emissions of relevant radiative forcing agents. Unfortunately, such analyses are weakened by the paucity of empirical data addressing CH4 emissions through the natural gas supply network. The U.S. Environmental Protection Agency (EPA) recently doubled its previous estimate of CH4leakage from natural gas systems.

    Contrary to previous estimates of CH4 losses from the “upstream” portions of the natural gas fuel cycle (8, 9), a recent paper by Howarth et al. calculated upstream leakage rates for shale gas to be so large as to imply higher lifecycle GHG emissions from natural gas than from coal (1). Howarth et al. estimated CH4 emissions as a percentage of CH4 produced over the lifecycle of a well to be 3.6–7.9% for shale gas and 1.7–6.0% for conventional gas.

    An analysis of reported routine emissions for over 250 well sites with no compressor engines in Barnett Shale gas well sites in Fort Worth, Texas, in 2010 revealed a highly skewed distribution of emissions, with 10% of well sites accounting for nearly 70% of emissions . Natural gas leak rates calculated based on operator-reported, daily gas production data at these well sites ranged from 0% to 5%, with six sites out of 203 showing leak rates of 2.6% or greater due to routine emissions alone.

    The EPA’s latest estimate of the amount of CH4 released because of leaks and venting in the natural gas network between production wells and the local distribution network is about 570 billion cubic feet for 2009, which corresponds to 2.4% of gross U.S. natural gas production (1.9–3.1% at a 95% confidence level)

    The EDF notes EPA’s reported uncertainty appears small considering that its current value is double the prior estimate, which was itself twice as high as the previously accepted amount.

    Each of the three curves within the panels of Fig. 1 represents a distinct choice and its associated emission duration: for example, whether to rent a CNG or a gasoline car for a day (Pulse TWP); whether to purchase and operate a CNG or gasoline car for a 15-yr service life (Service-Life TWP); and whether a nation should adopt a policy to convert the gasoline fleet of cars to CNG (Fleet Conversion TWP). In each of these cases, a TWP greater than 1 means that the cumulative radiative forcing from choosing natural gas today is higher than a current fuel option after t yr. The results for pulse TWP at 20 and 100 yr are identical to fuel-cycle analyses using 20-year or 100-year GWPs for CH4.
    Given EPA’s current estimates of CH4 leakage from natural gas production and delivery infrastructure, in addition to a modest CH4 contribution from the vehicle itself (for which few empirical data are available), CNG-fueled vehicles are not a viable mitigation strategy for climate change. (See my blog article Natural Gas Shale Gale for more details about this study and the overall impact of cheaper natural gas)

  • Air Pollution - Natural gas is composed of methane, ethane, liquid condensate, and volatile organic compounds (VOCs). The VOCs that are especially impactful on health are benzene, toluene, ethyl benzene, and xylene (referred to as a group, called BTEX). Health effects of exposure to these chemicals include neurological problems, birth defects, and cancer.

    VOCs, including BTEX, mixed with nitrogen oxides from combustion and combined with sunlight can lead to ozone formation. Ozone has been shown to impact lung function, increase respiratory illness, and is particularly dangerous to lung development in children. In 2008, measured ambient concentrations in the rural Sublette County, Wyoming where ranching and natural gas are the main industries were frequently above the National Ambient Air Quality Standards (NAAQS) of 75ppb and have been recorded as high as 125 ppb.

    According to an article in 'Environmental Health Perspectives,' people living near shale gas drilling sites often "complain of headaches, diarrhea, nosebleeds, dizziness, blackouts, muscle spasms, and other problems." Cause-and-effect relationships have not been established.

    In March 2011, pollution from natural gas drilling in the Upper Green River Basin in western Wyoming triggered levels of ground-level ozone, the main ingredient in smog, worse than those recorded in Los Angeles, one of the smoggiest cities in the U.S.

    In Dish, Texas, a rural town northwest of Dallas, the state's environmental regulators detected levels of cancer-causing benzene, sometimes at levels dangerous to human health, likely coming from industry's 60 drilling wells, gas production pads and rigs, a treating facility and compressor station.

    At the same time, a state study in Pennsylvania of air quality near Marcellus Shale drilling sites in four counties found no emissions at levels that would threaten the health of nearby residents or workers.

  • Induced Seismicity (Earthquakes) - A U.S. Geological Survey (USGS) team has found that a sharp jump in earthquakes in America’s heartland appears to be linked to oil and natural gas drilling operations..

    So far, there is no evidence that injection of fluids underground can cause an earthquake that can cause damage. So far the biggest is magnitude 3.0

    As hydraulic fracturing has exploded onto the scene, it has increasingly been connected to earthquakes. Some quakes may be caused by the original fracking — that is, by injecting a fluid mixture into the earth to release natural gas (or oil). More appear to be caused by reinjecting the resulting brine deep underground.

    Earthquakes in Ohio weren’t caused by the original fracking — that is, by injecting a fluid mixture into the earth to release natural gas (or oil). It was caused by a Class II disposal well used to reinject the resulting brine deep underground. That reinjection is banned in some states. The Ohio Department of Natural Resources (ODNR) has issued a preliminary report “on the relationship between the Northstar 1 Class II disposal well and 12 Youngstown area earthquakes” (news release here). They spell out what happened and the steps they will take to make sure it doesn’t happen again.

    In 2011, a USGS report examined a cluster of earthquakes in Oklahoma and reported:
    • The analysis showed that shortly after hydraulic fracturing began small earthquakes started occurring, and more than 50 were identified, of which 43 were large enough to be located. Most of these earthquakes occurred within a 24 hour period after hydraulic fracturing operations had ceased.

      The earthquakes range in magnitude from 1.0 to 2.8.

  • Compliance An analysis of oil wells fracked and reported by industry since the beginning of the year shows dozens of those wells are not showing up on the State's website, as required by new state law SB 4. As many as 77 different oil wells that the gas and oil industry reported were fracked in January and February had yet to show up on the website run by California’s Division of Oil, Gas and Geothermal Resources (DOGGR) by May 20, 2014.
    As of 2014, oil and gas companies have 60 days to report hydraulic fracturing activity in to the California state government.    Information like the company's name, well ID numbers and exact locations should all be available on the website of DOGGR (the Division of Oil, Gas & Geothermal Resources). This map compares DOGGR's public reporting with information from the hydraulic fracturing industry's own disclosure resource,  Source: NBC Bay Area 

6. Success Factors
  1. In 2011, the Department of Energy set up a committee to examine the full range of environmental impacts of fracking. The committee released a report of environmental guidelines for the natural gas industry and recommended

    • Improve public information about shale gas operations: Create a portal for access to a wide range of public information on shale gas development, to include current data available from state and federal regulatory agencies. The portal should be open to the public for use to study and analyze shale gas operations and results.

    • Improve communication among state and federal regulators: Provide continuing annual support to STRONGER (the State Review of Oil and Natural Gas Environmental Regulation) and to the Ground Water Protection Council for expansion of the Risk Based Data Management System and similar projects that can be extended to all phases of shale gas development.

    • Improve air quality: Measures should be taken to reduce emissions of air pollutants, ozone precursors, and methane as quickly as practicable. The Subcommittee supports adoption of rigorous standards for new and existing sources of methane, air toxics, ozone precursors and other air pollutants from shale gas operations.

      (1) Enlisting a subset of producers in different basins to design and rapidly implement measurement systems to collect comprehensive methane and other air emissions data from shale gas operations and make these data publically available;

      (2) Immediately launching a federal interagency planning effort to acquire data and analyze the overall greenhouse gas footprint of shale gas operations through out the lifecycle of natural gas use in comparison to other fuels; and

      (3) Encouraging shale-gas production companies and regulators to expandimmediately efforts to reduce air emissions using proven technologies and practices.

    • Protection of water quality: The Subcommittee urges adoption of a systems approach to water management based on consistent measurement and public disclosure of the flow and composition of water at every stage of the shale gas production process. The Subcommittee recommends the following actions by shale gas companies and regulators – to the extent that such actions have not already been undertaken by particular companies and regulatory agencies:

      (1) Measure and publicly report the composition of water stocks and flow throughout the fracturing and clean-up process.

      (2) Manifest all transfers of water among different locations.

      (3) Adopt best practices in well development and construction, especially casing, cementing, and pressure management. Pressure testing of cementedcasing and state-of-the-art cement bond logs should be used to confirm formation isolation. Microseismic surveys should be carried out to assure that hydraulic fracture growth is limited to the gas producing formations. Regulations and inspections are needed to confirm that operators have taken prompt action to repair defective cementing jobs. The regulation of shale gas development should include inspections at safety-critical stages of well construction and hydraulic fracturing.

      (4) Additional field studies on possible methane leakage from shale gas wells to water reservoirs.

      (5) Adopt requirements for background water quality measurements (e.g., existing methane levels in nearby water wells prior to drilling for gas) and report in advance of shale gas production activity.

      (6) Agencies should review field experience and modernize rules and enforcement practices to ensure protection of drinking and surface waters.

    • Disclosure of fracturing fluid composition: The Subcommittee shares the prevailing view that the risk of fracturing fluid leakage into drinking water sources through fractures made in deep shale reservoirs is remote. Nevertheless the Subcommittee believes there is no economic or technical reason to prevent public disclosure of all chemicals in fracturing fluids, with an exception for genuinely proprietary information. While companies and regulators are moving in this direction, progress needs to be accelerated in light of public concern.

    • Reduction in the use of diesel fuel: The Subcommittee believes there is no technical or economic reason to use diesel in shale gas production and recommends reducing the use of diesel engines for surface power in favor of natural gas engines or electricity where available.

    • Managing short-term and cumulative impacts on communities, land use, wildlife, and ecologies. Each relevant jurisdiction should pay greater attention to the combination of impacts from multiple drilling, production and delivery activities(e.g., impacts on air quality, traffic on roads, noise, visual pollution), and make efforts to plan for shale development impacts on a regional scale. Possible mechanisms include:

      (1) Use of multi-well drilling pads to minimize transport traffic and need for new road construction.

      (2) Evaluation of water use at the scale of affected watersheds.

      (3) Formal notification by regulated entities of anticipated environmental and community impacts.

      (4) Preservation of unique and/or sensitive areas as off-limits to drilling and support infrastructure as determined through an appropriate science-based process.

      (5) Undertaking science-based characterization of important landscapes, habitats and corridors to inform planning, prevention, mitigation and reclamation of surface impacts.

      (6) Establishment of effective field monitoring and enforcement to inform ongoing assessment of cumulative community and land use impacts.

    • Organizing for best practice: The Subcommittee believes the creation of a shale gas industry production organization dedicated to continuous improvement of best practice, defined as improvements in techniques and methods that rely on measurement and field experience, is needed to improve operational and environmental outcomes. The Subcommittee favors a national approach including regional mechanisms that recognize differences in geology, land use, water resources, and regulation. The Subcommittee is aware that several different models for such efforts are under discussion and the Subcommittee will monitor progress during its next ninety days. The Subcommittee has identified several activities that deserve priority attention for developing best practices:

      Air: (a) Reduction of pollutants and methane emissions from all shale gas production/ delivery activity. (b) Establishment of an emission measurement and reporting system at various points in the production chain.

      Water: (a) Well completion – casing and cementing including use of cement bond and other completion logging tools. (b) Minimizing water use and limiting vertical fracture growth.

    • Research and Development needs. The public should expect significant technical advances associated with shale gas production that will significantly improve the efficiency of shale gas production and that will reduce environmental impact. The move from single well to multiple-well pad drilling is one clear example. Given the economic incentive for technical advances, much of the R&D will be performed by the oil and gas industry. Nevertheless the federal government has a role especially in basic R&D, environment protection, and safety. The current level of federal support for unconventional gas R&D is small,and the Subcommittee recommends that the Administration and the Congress set an appropriate mission for R&D and level funding.

  2. Steps Ohio Department of Natural Resources (ODNR) is requiring to prevent reoccurrence of Fracking caused Earthquakes
    • A review of existing geologic data for known faulted areas within the state and avoid the locating of new Class II disposal wells within these areas;
    • A complete suite of geophysical logs (including, at a minimum, gamma ray, compensated density-neutron, and resistivity logs) to be run on newly drilled Class II disposal wells;
    • Operators to plug back with cement, prior to injection, any well drilled in Precambrian basement rock for testing purposes.
    • The submission, at time of permit application, of any information available concerning the existence of known geological faults within a specified distance of the proposed well location, and submission of a plan for monitoring any seismic activity that may occur;
    • A measurement or calculation of original downhole reservoir pressure prior to initial injection;
    • The installation of a continuous pressure monitoring system, with results being electronically available to ODNR for review; •
    • The installation of an automatic shut-off system set to operate if the fluid injection pressure exceeds a maximum pressure to be set by ODNR;
    • he installation of an electronic data recording system for purposes of tracking all fluids brought by a brine transporter for injection

  3. .
7. Next Steps
  • Air Pollution - On April 18, 2012, the Environmental Protection Agency (EPA) set the first-ever national standards to control air pollution from gas wells that are drilled using fracking, but not without making concessions to the oil and gas industry. Click here for EPA's final rule

    Top EPA officials said Wednesday that the new regulations would ensure pollution is controlled without slowing natural gas production. "By ensuring the capture of gases that were previously released to pollute our air and threaten our climate, these updated standards will protect our health, but also lead to more product for fuel suppliers to bring to market," said EPA Administrator Lisa Jackson in a statement.

    Much of the air pollution from fracked gas wells is vented when the well transitions from drilling to actual production, a three- to 10-day process which is referred to as "completion." An earlier version of the rule limiting air pollution from gas wells would have required companies to install pollution-reducing equipment immediately after the rule was finalized.

    Drillers now will be given more than two years to employ technology to reduce emissions of smog- and soot-forming pollutants during that stage. The EPA will require drillers to burn off gas in the meantime, an alternative that can release smog-forming nitrogen oxides, but will still slash overall emissions.

    Industry groups had pushed hard for the delay, saying the equipment to reduce pollution at the wellhead during completion was not readily available to service the about 25,000 wells a year are being fracked.

    Besides the new standards for oil and gas wells, the EPA also updated existing rules for natural gas processing plants, storage tanks and transmission lines that will reduce amounts of cancer-causing air pollution, such as benzene, and also reduce methane — the main ingredient in natural gas, but also one of the most potent global warming gases.

    There were other changes made since the EPA proposed the rule last July under a court order that stemmed from a lawsuit brought by environmental groups.

    Wells drilled in low-pressure areas, such as coalbed methane reserves, would be exempt because they release less pollution during completion. And companies that choose to re-fracture wells using the pollution-reducing equipment prior to the January 2015 deadline would not be covered by other parts of the regulation.

    The reaction from environmental groups was mixed on Wednesday, in large part to the two-year delay on requiring companies to perform so-called green completions.

8. Companies
  1. Halliburton - NYSE: HAL dual headquarters located in Houston and in Dubai, where Chairman and CEO David Lesar works and resides - ; The first frac job was performed in 1947 in limestone deposits by Halliburton

  2. Chesapeake Energy - Oklahoma City, OK - The second-largest producer of natural gas, a Top 15 producer of oil and natural gas liquids and the most active driller of new wells in the U.S. The company's operations are focused on discovering and developing unconventional natural gas and oil fields onshore in the U.S. Chesapeake owns leading positions in the Barnett, Haynesville, Bossier, Marcellus and Pearsall natural gas shale plays and in the Granite Wash, Cleveland, Tonkawa, Mississippi Lime, Bone Spring, Avalon, Wolfcamp, Wolfberry, Eagle Ford, Niobrara, Three Forks/Bakken and Utica unconventional liquids plays. The company has also vertically integrated its operations and owns substantial midstream, compression, drilling, trucking, pressure pumping and other oilfield service assets. For more information on Chesapeake environment initiatives, visit the environment section of,,,, or

    In April 2012 revelations that Aubrey McClendon, the company’s flamboyant co-founder, failed to disclose $1.1 billion of personal borrowing to co-invest in wells with the company have raised the specter of serious conflicts of interest and shaken investors. The company originally said its board was “fully” aware of the CEO’s financing transactions, but on April 26 said the directors were only “generally” aware and moved to end the co-investment program - which U.S. regulators are now scrutinizing.

    All the while, though, Chesapeake itself is becoming harder and harder to understand. The firm has been scrambling to raise about $10 billion in cash this year to help cope with a hefty debt load and sliding U.S. natural gas prices. Three transactions earlier this month raised $2.6 billion, but added to off-balance sheet debt and made the firm’s structure even more tangled.

    Chesapeake has negotiated seven joint ventures which give rival firms part-ownership of oil or gas fields in return for stumping up cash and a portion of drilling costs. No peer has a network of deals on anything close to this scale. Rival Devon Energy, which has a market value more than twice that of Chesapeake, has just one joint venture. And Chesapeake has concluded 10 volumetric production payment deals, under which it will hand over future output in return for cash paid upfront. The company has sold at least $4 billion-worth of its future gas production in this way, according to Argus Research.

    Investors wanting to wrap their heads around the firm must also contend with the fact it placed the cash flow from certain wells into a royalty trust - a type of vehicle in which the bulk of profit has to be distributed to its owners - and sold about half its interest for $440 million. The firm is also trying to sell a 20 percent stake through a public offering in its oilfield services firm, Chesapeake Oilfield Services, for $862.5 million.

    Visibility is further impeded by the firm’s over-active hedging business. Chesapeake reported realized gains on energy trading of $8.4 billion between 2006 and 2011. That’s more than four times its cumulative $1.8 billion of net income over the same period. “We don’t hedge just to say we’re hedged, we hedge to make money,” Chesapeake declared in a recent investor presentation. No gas rival trades energy on anything close to this scale, and it makes McClendon’s firm look at least as much like a hedge fund as a gas producer.

    Yet despite Chesapeake’s opacity and a 20 percent-plus fall in its market value since the end of March alone, investors still seem largely to give the company the benefit of the doubt. Its market capitalization is about $12 billion. That values the company at about 11 times estimated earnings for 2012 - in line with Devon Energy, but below the equivalent ratios for EOG Resources and Encana.

    But that isn’t, and shouldn’t be, the whole story. Chesapeake reported net debt of more than $10 billion at the end of its last quarter. That alone makes the firm’s debt load as a proportion of its market value almost twice as large as that of its major peers. But it also has plenty of what can be considered quasi-debt, including $4.3 billion of preferred stock and $1 billion of operating leases.

    Analysts think the firm should churn out about $4.3 billion of EBITDA this year. Include the quasi-debt and the market values the entire Chesapeake enterprise at just over six times EBITDA. Rivals like Devon, EOG and Encana are valued at roughly the same level. Yet Chesapeake deserves a discount for its complexity. EOG’s market capitalization is almost three times Chesapeake’s, but the smaller company’s 2011 annual report, as filed with the Securities and Exchange Commission, is more than three times as long. Add in other debt-like obligations, such as $14 billion in off-balance sheet commitments to partners in its various ventures, and investors’ apparent continuing faith in Chesapeake is even more of a head-scratcher.

    That’s even before considering the problem of Chesapeake’s cash flow - or lack of it. The firm has reported negative free cash flow every year for the past decade and doesn’t currently expect cash from operations to cover capital expenditures until 2014. Chesapeake can go on selling chunks of its businesses but that tends to mean the best bits get sold first. If the company insists on partial sales, that will add further complexity. And as the web of partnerships becomes denser, the company will get harder to sell as a whole.

    With no cash flow and its byzantine structure, Chesapeake is a trust-me story. The CEO’s personal transactions raise questions about the basis for such faith. All the more reason for investors to steer clear unless and until McClendon and his colleagues can explain exactly what’s in the corporate black box they have constructed.

  3. Marcellus Shale Coalition (MSC), formerly known as the Marcellus Shale Committee, is made up of over forty natural gas exploration and production companies with an interest in Marcellus shale development in Pennsylvania. It has even a larger number of assoicate and non-profit members. MSC is jointly sponsored by the Pennsylvania Oil and Gas Association and the Independent Oil and Gas Association of Pennsylvania.

  4. STRONGER - State Review of Oil and Natural Gas Environmental Regulations - Oklahoma City, OK - Formed in 1999 to reinvigorate and carry forward the state review process begun cooperatively in 1988 by the U.S. Environmental Protection Agency (EPA) and the Interstate Oil and Gas Compact Commission (IOGCC).

    STRONGER is a non-profit, multi-stakeholder organization whose purpose is to assist states in documenting the environmental regulations associated with the exploration, development and production of crude oil and natural gas.

  5. Companies Actively Drilling in the Marcellus Formation

9. Links
  1. Drilling Like There's No Tomorrow:Bankruptcy, Insurance, and Environmental Risk Judson Boomhower  Energy Institute at Haas School of Business November 2014 A a new Energy Institute at Haas working paper (available here), shows how making producers more accountable for environmental damages can help  policymakers encourage the continued development of these valuable resources while ensuring environmentally safe drilling and production.

    As the paper explains, there is a moral hazard problem that can lead oil and gas producers to take too many risks. Bankruptcy protection insulates small companies from worst-case outcomes by limiting their liability to their current assets. In addition, some types of environmental damage, like groundwater contamination, may take years to be detected. At that point, small producers may no longer exist or have the resources to finance cleanups or compensation.  The solution found in Texas was to require producers to buy a surety bond to cover the risk of environmental damage.

  2. The Downside of a Boom  By DEBORAH SONTAG and ROBERT GEBELOFF New York Times, Nov.  22, 2014 -- North Dakota, a small state that believes in small government,  took on the oversight of a multibillion-dollar fracking industry with a slender regulatory system built on neighborly trust, verbal warnings and second chances.
  3. The SEAB Shale Gas Production Subcommittee Ninety-Day Report - August 2011

  4. Dangers of

  5. Greater focus needed on methane leakage from natural gas infrastructure Ramón A. AlvarNeural Energyez, Stephen W. Pacala, James J. Winebrake, William L. Chameides and Steven P. Hamburg Environmental Defense Fund, Austin, TX; Department of Ecology and Evolutionary Biology, Princeton University; College of Liberal Arts, Rochester Institute of Technology,
    School of the Environment, Duke University; Environmental Defense Fund, Boston. - Proceedings of the National Academy of Sciences Feb 2012

  6. Hydraulic Fracturing Facts - Chesapeake Energy

  7. "Environmental Impacts During Shale Gas Drilling: Causes, Impacts and Remedies," University of Buffalo May 2012 The report offers the first quantitative data review of Pennsylvania's regulation of hydraulic fracturing of natural gas.  The report finds that environmental events are declining and suggests that proposed regulations in New York could mitigate future problems

  8. Documentaries on Drilling -- Pro
    1. Modern Drilling Operations: Hydraulic Fracturing - Views of Devon drilling activities in a suburban area in Texas' Barnett shale.
    2. Shale Gas and Americas Future - Excellent introduction to Marcellus shale development from industry expert
    3. The Truth About Gasland - The Film "Gasland," whatever the intentions of the filmmaker, has contributed to a dialogue based more on fear than facts. While it is a dramatic movie, 'Gasland' is a deeply flawed documentary that gets several important facts wrong.

  9. Documentaries on Drilling -- Con
    1. Barnett Shale: An Aerial View - Video showing the transformation of Texas landscape by shale drilling.
    2. Barnett shale land farms is a video discussing the dumping of drilling waste on land farms in Texas.
    3. Gaslands by Josh Fox - Anti-drilling film (wiki)
    4. Rural Impact is a documentary that focuses on environmental impacts of gas drilling in Colorado.
    5. SkyTruth: Upper Green River Valley - A View From Above - 3-D visualization of natural gas development in Wyoming.
    6. Fracking Hell - The Untold Story - LinkTV

Monday, November 3, 2014

California Net Metering Debate

August 2014 - Added Def. Value of Solar
October 2014 - Added link to LBL Study Financial Impacts of Net-Metered PV on Utilities and Ratepayers: A Scoping Study of Two Prototypical U.S. Utilities

The solar industry and the state’s utilities disagree over just what impact net metering has on electricity rates, utility costs and grid operations.

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Back to Markets & Pricing Index
1. Background

2. Acronyms/Definitions
3. Business Case
4. Benefits
5. Risks/Issues
6. Success Criteria
7. Next Steps
8. Companies/Organizations
9. Links

  • AB-327the controversial California bill that tackles residential electricity rate reform and solar net metering policy in one fell swoop, was approved by the state Senate on Sep 9, 2013 and the Senate revisions passed the Assembly on Sep 12.   Gov. Jerry Brown has indicated his support.

  • Utilities have long argued that net metering doesn’t adequately compensate them for the costs they face in supplying solar-equipped customers with grid power while the sun isn’t shining. Too many net-metered customers could force utilities to raise rates on all non-solar customers, and eventually lead to a death spiral for utilities that end up paying out more than they’re taking in from their customer base. They argue that poor rate payers who cannot afford solar end up subsidizing rich home owners who have the capital to invest in roof top systems.

  • Solar advocates, by contrast, point to studies that show that net metering of distributed solar power is a net asset, rather than a liability, to the grid at large. Those benefits can stretch from lowering the average cost of electricity for all users, to helping meet the state’s aggressive goals to supply more and more of its power from renewable resources in the coming years.

  • Under current California low, Net Energy Metering (NEM) allows solar owners to roll their meters backward for every kilowatt-hour they send to the grid (up to the point where their bills zero out). The return they get on the electricity they generate is the same retail rate they pay for what they consume. Since the top electricity tiers are very expensive, solar can be very competitive.

  • NEM for California's IOU's is currently capped at 5%. Utilities and the CPUC have disagreed how the 5% should be calculated.

  • The California Solar Initiative was structured when it was launched in 2007 as a ten-step incentive program, and we are now at step ten. There is not another incentive program that will replace that.

2. Acronyms/Definitions

  1. ABx 1 - During the energy crisis, the Legislature passed ABx1 (Keeley, 2001) to protect California ratepayers from rampant price fluctuations due to a dysfunctional wholesale electricity market. ABx1 1 authorized the Department of Water Resources (DWR) to issue revenue bonds to purchase power at such prices the department deemed appropriate, on behalf of the cash-strapped investor-owned utilities (IOUs) which couldn't keep up with the volatile wholesale prices. Among other stabilizing efforts, ABx1 1 included a provision that prohibited the CPUC from increasing rates for usage under 130% of baseline(tiers 1 and 2) until DWR bond charges were paid off. Those charges continue.

    Because rates in the two lowest tiers were frozen, increased costs for generation, distribution, transmission and new programs created by the Legislature and the CPUC, have been disproportionately borne by those customers whose electricity usage falls in the upper tiers.

  2. SB 695 - In 2009 SB 695 (Kehoe) was signed into law as an urgency statute. Among its provisions, the bill removed the freeze on tier 1 and tier 2 rates and intended to allow for gradual rate increases through 2018 at which time the caps for those increases would sunset. Different formulas were created for Non-CARE customers and CARE enrollees.

    As a consequence, beginning Jan 1, 2010, the CPUC could grant increases in rates charged to non-CARE residential customers for tier 1 and 2 rates by the annual percentage change in the Consumer Price Index from the prior year plus one percent, but not less than three percent or more than five percent per year. Increases in tier 1 and 2 rates for the residential CARE program were statutorily tied to annual cost of living adjustments for CalWork's benefits not to exceed three percent per year. The IOUs were also permitted to add a third tier of rates for CARE enrollees. Prior to SB 695, CARE enrollees were subject to charges under only the first two rate tiers.

    The provisions of SB 695 resulted in three to five percent increases on tier 1 and 2 rates for non-CARE customers and resulted in a commensurate decrease in rates for tiers 3, 4, and 5. The rates for CARE enrollees in tiers 1 and 2 have not increased due to the suspension of COLAs for the CalWork's program, except for the addition of a third tier for CARE enrollees in the PG&E service territory. The rate adjustments, overall, were revenue neutral to the IOUs.

    In PG&E service territory the gap between tier 1 and tier 5 decreased by 17 cents, but tier 5 was still 2.65 times higher and 21.88 cents per KWh more.

  3. Rate History Since SB 695
    PG&ETier 1 Tier 2Tier 3Tier 4Tier 5CARE1CARE2CARE3
    SCETier 1 Tier 2Tier 3Tier 4Tier 5CARE1CARE2CARE3
    . In the SDG&E rates which took effect on Sep 1 2013, the rates for tiers 3 and 4 increased more than 20% going to more than $0.34 per kWh in tier 3 and $0.36 in tier 4. A recent notice to customers from SDG&E's president reported the expected impacts - if a bill is now $250, then it will increase to $325 in September. A $100 electric bill will rise to $115. .

    Tier 1 Tier 2Tier 3Tier 4CARE1CARE2CARE4CARE4
  4. SB 743 (Steinberg/Padilla) - modifies the index to which CARE enrollee rate increases are tied to strike CalWorks and add the Consumer Price Index.

    The rates for CARE customers in tiers 1 and 2 have not increased due to the suspension of COLAs for the CalWorks program. Consequently, assistance to CARE customers is far greater than intended.

    On Sep 12, the energy provisions were deleted and the bill was changed to streamline CEQA for a new downtown Sacramento sports arena.   Status: Passed Senate and Assemby Sep 12, 2013,

  5. AB 1755 (Perea, 2012) - authorized the CPUC to approve a fixed charge for residential customers beyond the statutory caps on rate increases for Tier 1 and Tier 2 customers. Status: Senate Floor Inactive File.

  6. CARE - California Alternate Rates for Energy - Program to discount rates for low-income gas and electric customers defined as those with incomes no greater than 200% of the federal poverty level and permits no more than three rate tiers.

    Currently, CARE customers are to receive a 20% discount off of their electric and gas bills. However, because of the cap on Tiers 1 and 2, the effective discount can be much higher if CARE customer is using more than 130% of the baseline allocation. In some instances, Pacific Gas and Electric (PG&E) has reported providing discounts in the range of 60% off of the otherwise applicable bill. (See IOU Charts below)

  7. Cross Subsidies - Recovering costs incurred by one group of customers from another group of customers. For example, California has an explicit policy to shift the cost of the CARE program discounts to all non-CARE customers

  8. Economic Efficiency - Obtaining maximum consumer satisfaction from available resources. In the rate design context, economic efficiency is achieved when pricing reflects the marginal cost of generating and delivering electricity, including externalities.

  9. Externality - A cost or benefit that is not included in the market price of a good because it's not included in the supply price or the demand price. Pollution is an example of an externality cost if producers aren't the ones who suffer from pollution damages. Externality is one type of market failure that causes inefficiency.

  10. Fixed Charges - In the spring of 2010 PG&E, as part of its triennial rate case, PG&E applied to the CPUC to establish a fixed customer charge of $3 for all non-CARE residential customers, and $2.40 for all CARE enrollees. Although the CPUC recognized a growing disparity in rates, they rejected the charge on legal and policy grounds and characterized it as "the most significant change in residential electric rate design in the last decade."

    Legally the CPUC opined that the statutory caps on rate increases for tier 1 and 2 residential customers included any new or increased fixed rate charges. They specifically found that the commission was "prohibited by law from approving PG&E's customer charge to the extent the total bill impacts exceed these statutory limitations on baseline rate increases.".

    Sacramento Municipal Utility District imposed, for the first time, a fixed charge of $10 per residential customer in 2012, which was increased to $12 this year, and there are plans increase the charge $2 per year for 3 to 4 years. Why the tool is critical now is not readily apparent; the costs of electric service now labeled as "fixed" are not new. The IOUs argue that the lack of a fixed charge has caused high usage customers to pay unfairly high bills and created an artificially attractive market for customer-owned generation because the highest tier rates are far in excess of cost. A fixed charge would bring down upper tier rates but the lack of a fixed charge didn't exacerbate the upper tier rates, the rate freeze on tier 1 and 2 customers is largely to blame.

  11. GRC - General Rate Case - Proceedings currently take place every three years before the CPUC. The GRC will set the base revenue requirements for electric/gas operations. These base revenues recover the utility's operation and maintenance expenses, depreciation, and taxes and provide a return on invested capital.

  12. Market Rate Net Metering - The user's energy use is priced dynamically according to some function of wholesale electric prices. The users' meters are programmed remotely to calculate the value and are read remotely. Net metering applies such variable pricing to excess power produced by a qualifying systems.

    Market rate metering systems were implemented in California starting in 2006, and under the terms of California's net metering rules will be applicable to qualifying photovoltaic and wind systems. Under California law the payback for surplus electricity sent to the grid must be equal to the (variable, in this case) price charged at that time.

  13. Marginal Cost - The cost of providing one additional unit of a good or service. In the electric utility context there are several types of marginal costs – energy, generation capacity, transmission capacity, and distribution capacity. The change in utility costs resulting from an additional customer or additional use of energy or capacity, or the change in costs related to a change in output. The CPUC uses marginal costs in allocating the utility’s revenue requirement to customer classes, and as reference points in rate design. In the California ratemaking context, short-run marginal costs would reflect current market conditions (e.g., over- or under- capacity situations), while long-run marginal costs would include the entire cost of new facilities.

  14. NEM - Net Energy Metering - An electricity policy for consumers who own renewable energy facilities (such as wind power and solar power), and allows them to use generation whenever needed, instead of just when generated.

    The rules vary significantly from place to place: if net metering is available, if and how long you can keep your banked credits, and how much the credits are worth (retail/wholesale). Most net metering laws involve monthly roll over of kWh credits, a small monthly connection fee, require monthly payment of deficits (i.e. normal electric bill), and annual settlement of any residual credit. The treatment of annual excess generation ranges from lost, to compensation at avoided cost, to compensation at retail rate. In California, excess generation is rolled over indefinitely.

    There is considerable confusion between the terms "net metering" and "feed-in tariff". In general there are three types of compensation for local, distributed generation:

    1. Feed-in Tariff (FIT) which is generally above retail, and reduces to retail as the percentage of adopters increases.    See my post -  Feed-in Tariffs (FIT)

    2. Net Metering - which is always at retail, and which is not technically compensation, although it may become compensation if there is excess generation and payments are allowed by the utility. Net metering only requires one meter. A feed-in tariff requires two.

    3. Power Purchase Agreement (PPA) - compensation which is generally below retail, also known as a "Standard Offer Program", and can be above retail, particularly in the case of solar, which tends to be generated close to peak demand.

  15. Net Purchase and Sale - A different method of providing power to the electricity grid that does not offer the price symmetry of net metering, making this system a lot less profitable for home users of small renewable electricity systems.

    Under this arrangement, two uni-directional meters are installed—one records electricity drawn from the grid, and the other records excess electricity generated and fed back into the grid. The user pays retail rate for the electricity they use, and the power provider purchases their excess generation at its avoided cost (wholesale rate). There may be a significant difference between the retail rate the user pays and the power provider's avoided cost.

  16. Rate Cost Components: In California, rates are unbundled into generation, distribution, and transmission components based on key costdrivers for each component.
    • Generation Costs: Costs related to generating power to produce electricity. Typically defined in terms of capacity costs (e.g., $100/kW) and energy costs ($0.08/kWh).

    • Transmission Costs: Costs associated with the transmission system for moving power long-distances or at high voltage, regulated primarily by FERC.

    • Distribution Costs: Costs associated with distributing power to customers (e.g., poles and wires, meters). Typically defined in terms of capacity costs ($/kW) and customer costs ($ per customer)

    • PPC - Public Purpose Charges: Costs associated with a variety of programs, including energy efficiency, demand response, solar and distributed generation, low-income and medical needs

  17. Tier Rates - Residential electric rates in California's IOU territories are generally designed in a four or five-tiered structure based on the customer's quantity of electricity usage. Within prescribed usage tiers, the amount of electricity consumed is priced at increasing per-unit rates. Tier 1 is the customer's "baseline" - the level deemed necessary to supply a significant portion of the reasonable energy needs of the average residential customer; Tier 2 applies to usage between the baseline and 130% of that amount. Baseline levels vary depending on the climate of the region (e.g. hotter regions have a higher baseline).

    This multi-tiered conservation pricing structure grew out of the energy crisis. Prior to that time, a two-tier pricing structure was common.
    PG&E Tier Rate History  Source: TURN

  18. TOU - Time-of-Use Rates - (See my post Dynamic Pricing)  With time-based rates, utilities charge different prices based on the time of day electricity is used. The different charges should reflect the ups and downs of wholesale power prices due to supply and demand. In hot climates, power is typically most expensive late summer afternoons and early evening hours, when heavy air-conditioning use causes spikes in electricity use. With time-of-use or TOU rates, energy charges are higher during the hours of peak demand but lower at all other times.

    This creates financial incentives for consumers to shift energy use to the less expensive off-peak hours, which relieves the strain on energy supplies. However, customers in the hot climates cannot shift air conditioning use to another time of the day like they can their laundry.

    Peak demand dictates the size of generators, transmission lines, transformers and circuit breakers for utilities even if that amount lasts just a few hours a day. Power generation which is able to quickly ramp-up for peak demand often uses more expensive fuels, is less efficient and has higher marginal carbon emissions. Most natural gas plants in California's fleet are older and lack the fast-start technology, consequently they must idle until needed to meet peak demand and in that stand-by mode continue to produce emissions.

    TOU rates are advocated by many environmental groups who argue that the rates help rein in peak demand and avoid building new power plants. Some electric utilities similarly advocate for TOU because the rate reflects the principle of cost-causation and requires customers to make decisions about energy use when it has the highest cost and encourage customers to shift significant amounts of energy use away from the peak hours when power is most costly.

    TOU metering is a significant issue for solar power systems because they produce energy during the daytime peak-price period, and produce little or no power during the night period, when price is low. When this is the case, the effective output of a solar panel is increased, as more electricity can be consumed than is produced.

    • In Nov 2011, the CPUC approved a decision imposing mandatory time-variant pricing programs on small business customers of PG&E in two stages, beginning in November 2012.

    • In Dec 2012, the CPUC approved a decision imposing mandatory time-variant pricing programs on small business customers of SDG&E starting in November 2014, with an optional program commencing in November 2013.
  19. Value of Solar - The basic concept behind value of solar is that utilities should pay a transparent and market-based price for solar energy. The value of solar energy is based on:
    1. Avoiding the purchase of energy from other, polluting sources
    2. Avoiding the need to build additional power plant capacity to meet peak energy needs
    3. Providing energy for decades at a fixed price
    4. Reducing wear and tear on the electric grid, including power lines, substations, and power plants x
  20. Source: Institute for Local Self-Reliance

    Value of solar is not like net metering, where producing energy reduces your electricity bill just like turning off a light. As adopted, Minnesota’s value of solar formula includes all of the basic components of the theoretical policy, however, the overall adopted policy had some good elements that were lost in the legislative process.

    Source: Institute For Local Self-Reliance

3. Business Case
  • Utilities argue: "An electricity bill’s per-kilowatt-hour charge has three primary portions, the generation portion of the charge, the amount for that kilowatt-hour to actually be generated, the transmission portion of the charge, the part you pay for the use, construction, maintenance, etc., of the transmission line between the generation station and the local substation, and the distribution charge that is very similar to the transmission portion but is for the distribution system that actually allows the electricity to be delivered. NEM customers avoid paying non-generation components of rates for the portion of their electricity."

    Instead of NEM, SCE would like a “buy-all/sell-all (BA/SA) model” in which customers pay standard retail rates and get some payment for every kilowatt-hour they produce. BA/SA, however, would reimburse not the retail rate but only the generation portion of the retail rate.

  • Solar advocates argue: "Cost in our electric infrastructure in California is driven by peak demand. There is a huge benefit to reducing peak, and that is what the residential rooftop solar supported by NEM does. There are costs, but there are also benefits, and it works out that it is not really a subsidy.”

    A study on the cost-effectiveness of NEM in the Pacific Gas and Electric (PG&E) service territory by Crossborder Energy that concluded that, “on average over all customer classes, NEM does not impose costs on non-NEM customers,” adding, “on average, over all customer classes, NEM may now be cost-effective throughout the investor-owned utilities’ territories.”

  • SB 327 As Ammended
    1. Requires the California Public Utilities Commission (PUC), when it approves changes to electric service rates charged to residential customers, to determine that the changes are reasonable, including that the changes are necessary in order to ensure that the rates paid by residential customers are fair, equitable, and reflect the costs to serve those customers.

    2. Requires PUC to consider specified principles in approving any changes to electric service rates.

    3. Requires PUC to report to the Legislature its findings and recommendations relating to tiered residential electric service rates in a specified rulemaking by January 31, 2014.

    4. Recasts and revises limitations on electric and natural gas service rates of residential customers, including the rate increase limitations applicable to electric service provided to California Alternate Rates for Energy (CARE) customers.

    The Senate amendments, substantively revise this bill by adding new provisions
    1. Require the IOUs to provide annual distribution plans and for the PUC to approve those plans, if it finds them reasonable, in each IOU General Rate Case.

    2. Revise the current Net Energy Metering (NEM) statute to specify the maximum program capacity for customers in IOU service areas, require the PUC to develop a new NEM program by July 2015 and establish a transition to the new NEM program by 2017. The new NEM program is to be based on electrical system costs and benefits to nonparticipating ratepayers and remove both the total system capacity cap and the one megawatt project size limit. Existing NEM customers will be transitions no later than December 2020 to the new NEM.

      AB 327, as amended, calls for the CPUC to create a new study to serve as the basis for the state’s big three investor-owned utilities to develop brand-new net metering programs by the end of 2015, and instructs them to put those new programs in place in 2017.

      The bill states "There shall be no limitation on the number of new eligible customer-generators entitled to receive service pursuant to the standard contract or tariff after January 1, 2017" This means the current 5% cap for NEM of aggregate consumer demand will be eliminated.

      The three IOUs defined aggregate consumer demand as “coincident” peak demand. Renewables advocates argue that “non-coincident” peak demand should be used.

      Coincident peak demand is the designated period when all sectors (residential, commercial and industrial) reach their maximum electricity consumption and the state’s consumption peaks.

      Non-coincident peak demand is the sum of the individual peaking demands of all customers in the three sectors. Residential peak is typically late afternoon, commercial peak is early mid afternoon, and industrial peak can be at night. That sum of all peaks is greater than the total peak demand at any one time of the day.

      When the installed DG capacity eligible for NEM divided by the peak demand gets to five percent, the utilities are off the hook. So they want that bottom number to be smaller. Renewables advocates want just the opposite because the larger number keeps what one solar advocate called their “backbone” incentive in place.

      In April 2013, the CPUC concluded that the legislature “did not intend ‘aggregate customer peak demand’ to mean coincident peak demand

      Solar and ratepayer advocates were concerned that individual utilities might seek to alter the rates and tariffs that net-metering customers face in ways that could reduce their value. To counter that possibility, the new amendment to AB 327 requires that any such changes take place during a “rulemaking proceeding involving every large electrical corporation.”

      That means that the state’s three IOUS's, PG&E, SCE, and SDG&E, won’t be free to make changes on their own, but will have to collectively seek changes in a major CPUC process

    3. Provide the PUC with authority to require IOUs to procure renewable energy generation above that which is required in the 33% Renewable Portfolio Standard.

    4. Authorize the PUC to approved fixed monthly charges no greater than $10 for residential customers and $5 for low-income customers beginning in 2016. Specify discounts for low-income customers are not to exceed 30% to 35% of the average non-low-income customer.

      AB 327 doesn’t change rates itself. “Rate reform is going to be decided by the CPUC. All that AB 327 does is give the CPUC some more tools in that process.

    5. Establish that by 2018 the default rate schedule for residential customers shall be based on Time of Use and establishes provisions to protect senior or other vulnerable customers, in hot climate zones, from unreasonable hardship.

    6. Add technical amendments to the provisions related to residential electricity rate reform.

  • PUC Residential Rate Design Proceeding (R.12-06-013) is underway. On June 28, 2012, PUC initiated a proceeding to examine current residential electric rate design, including the tier structure in effect for residential customers, the state of time variant and dynamic pricing, potential pathways from tiers to time variant and dynamic pricing, and preferable residential rate design.

    This PUC proceeding is open to the public and allows interested parties opportunities to participate by making comments on PUC rulings, making rate design proposals, commenting on proposals made by others, commenting on proposals made by staff, and commenting on any decision made by PUC. According to the public schedule, final rounds of comments are due mid-summer 2013. This would be followed by a draft decision, which is also open to comments. (See 7. Next Steps and  9. Links below)

4. Benefits
  • Reducing Peak Demand - Solar advocates argue "Cost in our electric infrastructure in California is driven by peak demand. There is a huge benefit to reducing peak, and that is what the residential rooftop solar supported by NEM does. There are costs, but there are also benefits, and it works out that it is not really a subsidy.”

  • Incentives for Conservation & Energy Efficiency - Large fixed charges can undermine customer incentives to reduce consumption and undertake energy efficiency improvements. For example, if you used 500 kilowatt-hours of electricity per month (about average for a California customer) and your rate was 15 cents for each of those kilowatt-hours, it might take two years to recover your investment in new energy efficient lighting.

    But if the utility charged you a $25 fixed charge per month, and reduced your rate to 10 cents per kilowatt hour to compensate, it would now take three years for that same energy efficiency investment to pay back because you cannot avoid that $25 charge and you would have to save 50 percent more kilowatt hours to recover your investment. Similar impacts would occur for consumers considering the installation of rooftop solar.

    (Note: AB327 permits fixed charges, but does not require them,

  • Reduced GHG - SB 327 makes it clear NEM will be additive to the state's 33% RPS goal for renewable energy.

5. Risks/Issues
  • Cost Calculation Methodology - Utilities' "all-in cost" is what energy experts call the "avoided cost." An avoided-cost analysis does not consider longer-term impacts. It is very hard for traditional utility people to see rooftop solar as a resource because they do not control it. As a result, they don’t consider it a resource; they think of it as opportunity energy, so they are not willing to consider cumulative impacts.

    In the absence of real data, utilities assume a simplistic binomial distribution of costs and benefits. The straw man is that solar either avoids transmission and distribution costs or it doesn’t, and the conclusion is that since it doesn’t, because PV has to be connected to the grid, therefore all the costs apply to solar and none are avoided.

    Will there will be worst-case days with both high peak demand and high cloud cover? I'd say "no" for a California summer heat wave, but I'm not responsible for maintaining the grid. Maybe a giant wildfire blots out the sun?

    In addition, economics change based on PV penetration. Enough solar on the grid will collapse peak hour demand. That has already happened in Germany. When high peak demand falls then the spread between the wholesale cost of midday power and late night power goes away. The most expensive power will be found just before solar kicks in and right after it goes away. In that potential future case, end-user solar would be sending relatively low value electricity to the grid and taking back more expensive.

  • Stranded Costs -   Utilities argue "An electricity bill’s per-kilowatt-hour charge has three primary portions, the generation portion of the charge, the amount for that kilowatt-hour to actually be generated, the transmission portion of the charge, the part you pay for the use, construction, maintenance, etc., of the transmission line between the generation station and the local substation, and the distribution charge that is very similar to the transmission portion but is for the distribution system that actually allows the electricity to be delivered. NEM customers avoid paying non-generation components of rates for the portion of their electricity."

  • Unfair Upper Tiers  - If a family can't buy or lease solar to shave the tier 3 and 4 electricity rates off of their bill, and if they don't qualify for enrollment in the CARE program, the cost of electricity, particularly in hot climates, can be a tremendous burden.

  • Legislative Rate Making - There is little disagreement between that the indices and freezes on tier 1 and 2 residential rates must be eliminated and that any modification for those rates must be gradual so as to prevent ratepayer shock. But should the Legislature provide a framework for rate design to reflect and protect its priorities? Some argue that restrictions in statute amount to "legislative ratemaking"

  • Equity - Utilities argue the beneficiaries of net metering are relatively rich home owners, while relatively poor rate payers who cannot afford to install solar or do not own their own homes have to support more fixed costs.

  • Time Lag in Net Metering Contracts - Under existing law, net metering would be suspended completely as of 2014, AB 327 removes that suspension. Utilities and the solar industry have been working under a deadline imposed by the CPUC, which would force net metering programs to cease as of the end of 2014. AB 327, as currently amended, would put that worry to rest.

    Under current law, there are no grandfathering protections at all for existing net metering customers. Everything under this is additive. These are all additional protections that nobody had before.

  • Impact on Current Net Metering Contracts - It was feared AB 327 would subject today’s existing net metering contracts to review and potential rewriting, as the CPUC comes up with a new net metering regime. That led some groups to decry the bill as an attempt to undercut their investment in solar.

    The Sep 2013 bill revisions address this concern by setting a deadline of Mar 31, 2014 for the CPUC to set a procedure for how it will deal with “grandfathering” existing net metering contracts into the new program that AB 327 requires it to create. It also states that “Any rules adopted by the commission shall consider a reasonable expected payback period based on the year the customer initially took service under the tariff or contract.”

    While that doesn’t change the fact that existing net metering contracts will be subject to change, it does address the concern that the previous version of the bill was “creating a lag time of uncertainty as the market waited for the new rules.

  • Net Metering Cap - Several years ago, the CPUC extended the cap for net metering from 2.5 percent to 5 percent of each IOU's nameplate capacity, but there’s been a longstanding dispute about how the  cap should be calculated.  Once the total number of customers signed up for net metering exceeded that cap, in terms of their kilowatt contribution to their utility’s total power mix, new customers would have been excluded.

    AB327 removes all legal uncertainty, and makes clear how the cap is calculated. As amended,, it sets clear figures for when each utility will reach that cap. That will either come as of Dec 31, 2016, or at the following capacities, whichever come first: 607 megawatts for SDG&E; 2,240 megawatts for SCE; and 2,409 megawatts for PG&E.

  • Consumer Backlash to TOU Rates - The impacts of TOU rates would be especially felt by inland climates where air conditioning use is the highest and drives peak demand in the state. if not managed well, the imposition of mandatory TOU rates on customers will result in a significant customer revolt. Even with effective notice and education of customers about how to manage TOU rates, the inland regions of California will be hit the hardest due to their reliance on air conditioning during the summer months.

    SMUD announced its TOU rate structure this year but customers will not be switched to TOU until 2018. To ensure that customers have adequate notice and education and to gain customer acceptance, delay default TOU and permit mandatory TOU with bill protection beginning in 2020.

  • Low Income Incentives - Because lower rates tend to encourage greater electricity consumption, should assistance for low-income households be offered as a fixed monthly credit, similar to food stamps, rather than as a rate discount?

6. Success Criteria In 2007 the CPUC adopted principles for rate design and expressed intent to use those as guidance in the Residential Rate Design Proceeding currently underway
  1. Rates should be based on marginal cost;
  2. Rates should be based on cost-causation principles;
  3. Rates should encourage conservation and reduce peak demand;
  4. Rates should provide stability, simplicity and customer choice; 
  5. Rates should encourage economically efficient decision-making.
7. Next Steps
  • The CPUC initiated a rulemaking on policy guidance for rate design in the summer of 2012 (R.12-06-013). They intend to consider how the state's energy policy goals for 2020 are affected by retail rate design and how rate design policies can and should be used to meet long-term climate and energy policy goals in an effort to align rates with policy objectives. More specifically, the proceeding will examine "whether the current tier structure continues to support the underlying statewide-energy goals facilitates the development of customer-friendly technologies, and whether the rates result in inequitable treatment across customers and customer classes."

8. Companies/Organizations
  1. CPUC - California Public Utilities Commission, San Franciso

  2. DRA - Division of Ratepayer Advocates San Francisco - A California state agency whose statutory mission is to obtain the lowest possible rate for service consistent with reliable and safe service levels. In fulfilling this goal, DRA also advocates for customer and environmental protections.

  3. PG&E - Pacific Gas and Electric, San Francisco

  4. SCE - Southern California Edison, Rosemead

  5. SDG&E - San Diego Gas and Electric, San Diego

  6. SMUD - Sacramento Municipal Utility District, Sacramento

  7. TURN - The Utility Reform Network, San Francisco

9. Links
  1. What’s so Great about Fixed Charges? by Severin Borenstein Energy Institute at Haas School of Business November 3, 2014

  2. Financial Impacts of Net-Metered PV on Utilities and Ratepayers: A Scoping Study of Two Prototypical U.S. Utilities - Satchwell, Andrew, Andrew D. Mills, Galen L. Barbose,  - Lawrence Berkeley National Lab (LBL) - September 2014  A scoping analysis to quantify the financial impacts of customer-sited PV on utility shareholders and ratepayers and to assess the potential efficacy of various options for mitigating those impacts.The analysis relied on a pro-forma utility financial model that LBL previously developed for the purpose of analyzing utility shareholder and ratepayer impacts of utility-sponsored energy efficiency programs.The findings from this scoping study point towards several high-level policy implications.

    1. First, even at 10% PV penetration levels, which are substantially higher than exist today, the impact of customer-sited PV on average retail rates may be relatively modest (at least from the perspective of all ratepayers, in aggregate. At a minimum, the magnitude of the rate impacts estimated within our analysis suggest that, in many cases, utilities and regulators may have sufficient time to address concerns about the rate impacts of PV in a measured and  deliberate manner.

    2. Second and by comparison, the impacts of customer-sited PV on utility shareholder profitability are potentially much more pronounced, though they are highly dependent upon the specifics of the utility operating and regulatory environment, and therefore warrant utility-specific analysis.

    3. Finally, LBL found that the shareholder (and, to a lesser extent,ratepayer) impacts of customer-sited PV may be mitigated through various “incremental” changes to utility business or regulatory models, though the potential efficacy of those measures varies considerably depending upon both their design and upon the specific utility circumstances. 
    4. Importantly, however, these mitigation strategies entail tradeoffs – either between ratepayers and shareholders or among competing policy objectives – which may ultimately necessitate resolution within the context of broader policy- and rate-making processes, rather than on a stand-alone basis.

    5. Areas for future research include 
      • examining: the relative impacts of customer-sited PV compared to other factors that may impact utility profitability and customer rates;
      •  the combined impacts of customer-sited PV, aggressive energy efficiency, and other demand-side measures;
      •  the rate impacts of customer-sited PV and various mitigation measures specifically on customers without PV and differences among customer classes; 
      • a broader range of mitigation options; 
      • potential strategies for maximizing the avoided costs of customer-sited PV;
      •  continued efforts to improve the methods and data required to develop reliable and actionable estimates of the avoided costs of customer-sited PV.

  3. Minnesota Value of Solar
  4. Free the Grid 2012 - policy guide that grades all 50 states on two key renewable energy programs: net metering and interconnection procedures.

  5. AB-327 Electricity: natural gas: rates: net energy metering: California Renewables Portfolio Standard Program.

  6. DSIRE - The Database of State Incentives for Renewable Energy

  7. DRA's Presentation on Rate Design Basics.

  8. CPUC -  Residential Rate Design Proceeding  (R.12-06-013)

    Aug. 27, 2012, 9:30 a.m. – 4 p.m.: Workshop to Discuss and Refine Preliminary Questions including transitioning to Time Varying and Dynamic Rates for Residential Rate Structure Rulemaking
  9. Dec. 5-6, 2012: Public Workshops on the CPUC's proceeding to Conduct a Comprehensive Examination of Investor Owned Electric Utilities’ Residential Rate Structures (R.12-06-013)
  10.  CPUC Workshop - December 6, 2012 - Retail Rate Reform Proceeding
    [Archive Video Part 1] [Send Eclip]
    [Archive Video Part 2] [Send Eclip]
     CPUC Workshop - December 5, 2012 - Retail Rate Reform Proceeding
    [Archive Video Part 1] [Send Eclip]
    [Archive Video Part 2] [Send Eclip]

    June 25, 2013Workshop on Time Varying and Dynamic Rates

     CPUC Workshop - June 25, 2013 - Time Varying and Dynamic Rates
    [Archive Video Part 1] [Send Eclip]
    [Archive Video Part 2] [Send Eclip]