Contracts Between CEB and IPP: Agree to Make Public the Terms

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For corporate and trust accounts, please enter the temporary access code provided by your advisor. Actual price is available to 4 terragen options trading. The net asset value of an investment fund must be calculated using the fair value of the investment fund's assets and liabilities. The net asset value of each series of a fund is the value of all assets of that series less its liabilities. The net asset value of each series is calculated on each day that the Toronto Stock Exchange is open for trading a "valuation day".

A separate net asset value is calculated for each series of units of a fund. The terragen options trading asset value per unit of each series of a fund is calculated by dividing the net asset value of the series at the close of business on a valuation day by the total number of units of the series outstanding at that time. MER Show Tooltip Management expense ratio means the ratio, expressed as a percentage, of the expenses of an investment fund to its average net terragen options trading value, calculated in accordance with Part 15 of National Instrument In accordance with Part 15, an investment fund may disclose its management fee ratio only if the management terragen options trading ratio is calculated for the financial year or interim period of the investment fund, and it is calculated by dividing i the aggregate of A total expenses of the investment fund, excluding distributions if recognized as an expense, commissions terragen options trading other portfolio transaction costs, before income taxes, for the financial year or interim period, as shown on the statement of comprehensive income, and B any other fee, charge or expense of the investment fund that has the effect of reducing the investment fund's net asset value, by ii the average net asset value of the investment fund for the financial year or interim period.

Seven-day yield Show Tooltip This is an annualized yield based terragen options trading the seven-day period ended on April 30,and does not represent an actual one-year return. Net distribution yield Show Terragen options trading The net distribution yields is intended to show fund's distributions in percentage form relative to its NAV.

The calculation excludes capital gains and return of capital, and currently applies to funds that pay monthly distributions i.

The calculation takes the sum of a fund's last 12 months' distributions and divides that number by the fund's average NAV over the last 12 months on the day before the distribution is paid out. Duration Show Tooltip Duration is a measure of a security's price sensitivity to changes in interest rates. Duration differs from maturity in that it considers a security's interest payments in addition to the amount of time until the security reaches maturity, and also takes into account certain maturity-shortening features e.

Securities with longer durations generally tend to be more sensitive to interest rate changes than securities with shorter durations. A fund with a longer average duration generally can be expected to be more sensitive to interest rate changes than a fund with terragen options trading shorter average duration. Show Tooltip Terragen options trading values calculated and displayed in this return calculator may differ slightly from the published returns for identical periods due to the specificity of rounding in the underlying daily return data.

Published returns for are calculated based on daily return data expressed to sixteen significant digits. The return calculator uses daily returns expressed to two significant digits.

Why terragen options trading in this fund? A high-yield offering that aims to provide regular income by investing primarily terragen options trading floating rate debt. Floating rate coupons tend to move in tandem with short-term interest rates, helping to reduce the impact that rising interest rates may have on a portfolio.

Risk measures Show Tooltip Risk measures are based on 3-year net returns series B. All returns are calculated in Canadian currency. Show Tooltip Statistical measure of how much a return varies over an extended period of terragen options trading. The more variable the returns, the larger the standard terragen options trading. Investors may examine historical standard deviation in conjunction with historical returns to decide whether an investment's volatility would have been acceptable given the returns it would have produced.

A higher standard deviation indicates a wider dispersion of past returns and thus greater historical volatility. Standard deviation does not indicate how an investment actually performed, but it does indicate the volatility of its returns over time. Standard deviation is annualized. The returns used for this calculation are not load-adjusted. Standard deviation does not predict the future volatility of a fund.

Show Tooltip A measure of a portfolio's sensitivity to market movements as represented by a benchmark index. The benchmark index has a beta of 1. A beta of more less than 1. Show Tooltip A measurement of how closely terragen options trading portfolio's performance correlates with the performance of the fund's primary benchmark index or equivalent. Risk classification Show Tooltip The investment risk level indicated is required to be determined in accordance with the Canadian Securities Administrators standardized risk classification methodology, which is based on the historical volatility of terragen options trading fund, as measured by the ten-year annualized standard deviation of the returns of the fund.

Standard deviation is used to quantify the historical dispersion of returns around the average returns over a recent ten-year period. See definition of terragen options trading deviation. Top ten holdings Show Tooltip The information provided in this listing and top ten holdings or top five issuers may differ from a fund's holdings in its annual report and as follows, where applicable: For the annual report, a fund's investments include trades executed through the end of the last business day of the period.

This listing and the ten holdings or five issuers include trades executed through the end of the previous business day. The list terragen options trading any investment in derivative instruments, and excludes the value of any cash collateral held for securities on loan and a fund's net other assets.

The top ten holdings or top five issuers for fixed-income and money market funds are presented to illustrate examples of the securities that the fund terragen options trading bought and the diversity of the areas in which the fund may invest, may not be the representative of the terragen options trading current or future investments, and may change at any time. Depositary receipts, credit default swaps and equity total return swaps are normally combined with the underlying security.

The listing of portfolio holdings provides information on a fund's investments as at the date indicated. The information provided in this listing may differ from a fund's holdings in its annual report. Eric Mollenhauer Portfolio manager. Kevin Nielsen Portfolio manager.

Fidelity fixed income brochure. Fidelity's made-in-Canada investment solutions. Please complete security terragen options trading and answer:. Security Answer case senstive. You now have access to exclusive Fidelity sales support and marketing materials. What is the middle name of your youngest child? Annualized standard deviation Show Tooltip Statistical measure of how much a return varies over an extended period of time. Beta Show Tooltip A measure of a portfolio's sensitivity to market movements as represented by a benchmark index.

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Peevey is the assigned Commissioner in this proceeding, and Charlotte F. The state Energy Action Plan lays out a "loading order" for investment in electricity resources in California that puts energy efficiency as the top priority, with renewable resources second, and clean fossil-fired generation to the extent other options are not available.

Energy efficiency building codes and appliance efficiency standards promulgated by the Energy Commission provide a base for energy and GHG emissions reductions. Consistent with AB , the Energy Commission has recommended statewide energy efficiency goals at the level of all cost-effective investment in energy efficiency, to be met through a combination of utility and non-utility programs, including building codes and appliance standards.

In addition, during the Public Utilities Commission will adopt IOU energy efficiency goals for the years to It is reasonable for the State of California to apply minimum requirements in the areas of cost-effective energy efficiency and renewables to all retail providers of electricity. It is reasonable that existing California policies regarding energy efficiency building codes and appliance efficiency standards, retail provider energy efficiency programs, the renewables portfolio standard program, solar photovoltaic and solar water heating programs, and the emissions performance standard be maintained and strengthened as recommended in this decision.

For the electricity sector, a cap-and-trade system, in conjunction with the continuation and strengthening of existing policies regarding energy efficiency building codes and appliance efficiency standards, retail provider energy efficiency programs, the renewables portfolio standard program, solar photovoltaic, and the emissions performance standard as recommended in this decision, is likely to be a less expensive means of complying with AB 32 GHG emission reduction requirements than sole reliance on existing and increased mandatory programmatic requirements.

For the electricity sector, GHG emissions trading would maximize flexibility in achieving emissions targets by allowing obligated entities to rely on least-cost options across the entire economy. For the electricity sector, a GHG emissions cap-and-trade program would encourage investment in research and innovation in technologies that lower GHG emissions. For the electricity sector, a GHG emissions cap-and-trade program would allow market participants to manage risk associated with compliance obligations.

For the electricity sector, a GHG emissions cap-and-trade program would internalize GHG externalities and should distribute the cost of GHG reductions most efficiently across all capped entities. Implementing a GHG emissions cap-and-trade system in for the electricity sector would allow entities to gain experience with finding real least-cost GHG emission reduction opportunities. It is reasonable for ARB to proceed to design a multi-sector GHG emissions cap-and-trade system for California that includes the electricity sector, for implementation in , as described in this decision provided that ARB finds that the tests outlined in Part 4 and Part 5 of AB 32 are met.

For the electricity sector, placing the compliance obligation in a GHG emissions cap-and-trade system on the entities that deliver power to the electricity grid in California, which we call "deliverers," is reasonable because this point of regulation best meets, on balance, the most important criteria, as described in this decision.

The "deliverer" is the entity that owns electricity as it is delivered to the grid in California. For electricity whose deliverer would otherwise be a federal entity not subject to California regulation, it is reasonable for the deliverer for AB 32 compliance purposes to be the first non-federal entity that owns the electricity thereafter on the physical path in California.

By choosing a deliverer point of regulation we are simply choosing a trigger that determines which entities have to comply, but what is being regulated is the amount of GHGs being produced in California or to supply electricity to customers located in California.

The deliverer point of regulation does not single out wholesale sales of electricity, but rather applies uniformly to electricity consumed in California and electricity generated in California.

An entity with compliance obligations under a deliverer form of regulation, if it does not already possess enough allowances, would have an opportunity after delivery of the energy to acquire allowances on the market or to show compliance using flexible compliance mechanisms such as offsets to the extent they are allowed. The GHG regulatory program we are proposing would not prevent even high-GHG sources from providing reliability services when needed. A deliverer point of regulation would treat all electricity delivered to the California grid the same, whether that electricity is generated in California or elsewhere.

In either case, the deliverer would later have to surrender GHG allowances or secure adequate offsets to the extent they are allowed based on the amount of GHG emissions associated with that electricity.

The potential adverse impacts of global warming include the exacerbation of air quality problems, a reduction in the quality and supply of water to the state from the Sierra snowpack, a rise in sea levels resulting in the displacement of thousands of coastal businesses and residences, damage to marine ecosystems and the natural environment, and an increase in the incidences of infectious diseases, asthma, and other human health-related problems. It will also increase the strain on electricity supplies necessary to meet the demand for summer air-conditioning in the hottest parts of the state.

Additional local benefits of the GHG program we are recommending include its encouragement of a wide range of clean energy sources, which protects the reliability of the grid, and the avoidance of unnecessary costs and inefficiencies that would result if California were to wait until the federal government begins regulating GHG emissions.

Any burdens on interstate commerce that may result from the implementation of AB 32 under the regulations that we recommend to ARB including a deliverer point of regulation would be purely incidental, while the local benefits to California of reducing GHG emissions, and therefore the impact of global warming, would be most significant. To the extent such actions are unable to sufficiently reduce GHG emissions associated with the use of electricity, these regulations are expected to result in investments outside of the electricity sector that will cost-effectively reduce GHG emissions from other activities.

The emissions associated with multi-jurisdictional utilities' deliveries of electricity to the California grid should be regulated using a deliverer point of regulation. Nevertheless, the methodology for tracking and accounting for the GHG attributes of the electricity these utilities deliver to California may not be identical to that of other entities not similarly situated.

The auctioning of some portion of the emission allowances available to the electricity sector would promote least-cost GHG emission reductions throughout the California economy, promote liquidity in the emission allowance market, improve incentives for investing in energy efficiency and low-GHG technologies and fuels, improve the accuracy of emission allowance prices as a reflection of marginal emission reduction costs, and allow new market entrants access to allowances on an equal basis with other parties.

It is reasonable to require that some portion of the GHG emissions allowances for the electricity sector be auctioned in a GHG emissions cap-and-trade system in which deliverers are the point of regulation for the electricity sector. As part of this approach, the majority of proceeds from the auctioning of allowances for the electricity sector would be used in ways that benefit electricity consumers in California.

The record in R. Key differences between the electricity and natural gas sectors make it reasonable to recommend that ARB proceed to design a multi-sector GHG emissions cap-and-trade system for California but not include the natural gas sector at this time.

Entities in the natural gas sector have fewer options to reduce GHG emissions than entities in the electricity sector. There are limited commercially available lower carbon alternative sources of natural gas. The only options in effect for reducing GHG emissions in the natural gas sector are energy efficiency programs. The Legislature has recently approved financial incentives for residential and commercial customers to install solar water heating equipment which will reduce GHG emissions when implemented.

The incremental benefits from including the natural gas sector in a multi-sector GHG emissions cap-and-trade system are likely to be less than those from including the electricity sector.

Reporting protocols for GHG emission arising from the storage, transportation and distribution of natural gas to end-users are under development and do not yet include provisions for reporting end-user combustion related GHG emissions.

Implementing a multi-sector GHG emissions cap-and-trade system that includes small end-users of natural gas now may expose those customers to greater price risk than small end-users in the electricity sector.

Including all fuels in a multi-sector cap-and-trade system could maximize the benefits of a market-based system.

Taking a programmatic approach to the natural gas sector now does not preclude future inclusion of the natural gas sector in a multi-sector GHG emissions cap-and-trade system. It is reasonable for ARB to not include the natural gas sector when designing a multi-sector GHG emissions cap-and-trade system for California, for implementation in , as described in this decision. The statute requires POUs to establish year energy efficiency goals on a triennial basis.

SB directed the Public Utilities Commission and the Energy Commission to develop an emissions performance standard for non-renewable, generally fossil-fueled generation resources, for all retail providers of electricity. Because the FPA expressly leaves room for state regulations dealing with electricity and because there is nothing in the FPA that deals with the regulation of emissions either generally, or GHG emissions specifically the deliverer approach is not preempted by the FPA.

A GHG regulation that incorporates a deliverer point of regulation is an environmental regulation whose purpose is to decrease the impact of global warming on California insofar as that impact is caused by electricity used or generated in California. There is no field preemption here because, in enacting the FPA, Congress did not intend, either explicitly or implicitly, to occupy the field of environmental regulation of the power sector.

There is no FPA field preemption here because, under AB 32, California will not be regulating the same subject matter as the FPA, nor will its regulations be for the same intended purpose.

California will be regulating GHG emissions for the purpose of reducing them and lessening the impacts of global warming on California. While GHG regulation may have some impact on the wholesale prices paid for electricity, such regulation is no more preempted by the FPA than state regulations limiting the amount of other pollutants that may be emitted by electric power plants -- that may affect the cost of generating electricity and therefore indirectly affect the price of wholesale electricity.

The proposed structure for regulating GHG emissions would not prevent anyone from selling wholesale electricity into the California market, nor would it require a license to do so. The proposed deliverer point of regulation would not conflict with the FPA's electric reliability provisions. A deliverer point of regulation is not preempted by the FPA.

The regulations we are proposing are facially neutral, as between interstate and intrastate commerce, and do not have a discriminatory purpose or effect.

The use of a deliverer point of regulation would not violate the dormant Commerce Clause. The deliverer point of regulation would only regulate electricity that is generated in, or delivered for consumption in, California.

Thus, it would not regulate any commerce that occurs totally outside of California, and therefore would not regulate extraterritorially in violation of the Commerce Clause.

The fact that the Legislature required reporting by retail providers does not mean that retail providers must be the point of regulation for achieving the required reductions in GHG emissions. We recommend that the California Air Resources Board ARB set energy efficiency requirements in its scoping plan at the level of all cost-effective energy efficiency in the State.

This would be achieved through a combination of utility and non-utility programs coordinated at the State level, with consistent requirements across all types of retail providers. We recommend that the ARB adopt mandatory minimum levels of cost-effective energy efficiency savings for publicly owned utilities POUs , at levels recommended by the California Energy Commission Energy Commission.

We recommend that ARB adopt mandatory minimum levels of cost-effective energy efficiency for investor owned utilities, Community Choice Aggregators, and Electric Service Providers consistent with the programs and goals adopted by the California Public Utilities Commission Public Utilities Commission. We recommend that ARB work with the Public Utilities Commission and the Energy Commission to seek legislation that requires retail providers of electricity to deliver more than 20 percent of their power from renewable sources in the future, at levels and dates to be determined.

We recommend that, if ARB concludes that it does not have authority to adopt regulations consistent with Ordering Paragraphs 1, 2, 3, and 4, ARB seek such authority from the Legislature. This GHG emissions cap-and-trade system should include the electricity sector. We recommend that, for the electricity sector, ARB establish the compliance obligation in the GHG emissions cap-and-trade system on the entities that own electricity as it is delivered to the California electricity grid, as described in this decision.

We recommend that some portion of the GHG emission allowances available to the electricity sector be auctioned, with the majority of the proceeds from the auctioning of allowances for the electricity sector being used in ways that benefit electricity consumers in California.

We recommend that, for the natural gas sector, ARB rely on programmatic measures to achieve emission reductions and not include the natural gas sector in a multi-sector GHG emissions cap-and-trade system at this time.

We recommend consideration of the inclusion of the natural gas sector in a cap-and-trade program at a later date.