actual and planned transmission investment by shareholder owned utilities

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Actual and planned transmission investment by shareholder owned utilities hollywood vest

Actual and planned transmission investment by shareholder owned utilities

The Fortis Annual Report is also available on the Fortis website at www. The Articles of Fortis provide for a minimum of 3 and a maximum of 15 directors. Shareholders will be asked to elect the 10 directors currently serving and two new nominees, Margarita K. Dilley and Jo Mark Zurel, to serve as the 12 members of the Board. The 12 nominees proposed for election as directors are as follows:. Tracey C. Douglas J. Pierre J.

Harry McWatters. Peter E. Ronald D. Maura J. Margarita K. Ida J. Jo Mark Zurel. If any of the proposed nominees should for any reason be unable to serve as a director of Fortis, the persons named in the enclosed form of proxy reserve the right to nominate and vote for another nominee in their discretion unless the Shareholder has specified in its proxy that their Common Shares are to be withheld from voting in the election of directors.

Any such resignation will take effect only on acceptance by the Board. The Board shall accept such resignation absent exceptional circumstances that would warrant the director to continue to serve on the Board, as determined by the Board in accordance with its fiduciary duties to the Corporation and its shareholders. Within 90 days of the Meeting, the Board will make a final decision on the proposed resignation and announce it by way of media release. If the Board declines to accept the resignation, the media release shall fully state the reasons for that decision.

Any director who tenders his or her resignation will not participate in the related deliberations of the Governance and Nominating Committee or the Board. The Fortis Majority Voting Policy does not apply to a contested election of directors, that is, where the number of nominees exceeds the number of directors to be elected.

The persons named in your Proxy intend to vote FOR the election of each of these nominees unless you specify that authority to do so is withheld. Such fees are based upon the complexity of the matters dealt with and the time expended by the auditors in providing services to Fortis. Management of Fortis believes that the fees negotiated in the past with the auditors of Fortis have been reasonable in all circumstances and would be comparable to fees charged by other auditors providing similar services.

External Auditor Service Fees. Audit Fees. Audit-Related Fees. Tax Fees. Non-Audit Fees. Audit fees were higher in than in , mainly due to general increases in fees and the impact of foreign exchange on U. The increase in tax fees was largely due to additional work completed on the sale of non-core assets. The persons named in your Proxy intend to vote FOR the appointment and FOR the authorization of the Board to fix the remuneration of the auditors unless you specify that authority to do so is withheld.

Compensation Objectives. Non-Binding Nature of Resolution. As this is an advisory vote, the results of the vote will not be binding on the Board. The Board will take the results of the vote into account, as appropriate, when considering future compensation polices, practices and decisions and in determining whether there is a need to increase its engagement with Shareholders on compensation and related matters.

The Acquisition. There were approximately The Consideration Shares are expected to represent no more than To be effective, the Acquisition Share Issuance Resolution must be approved by at least a simple majority of the votes cast by Shareholders present in person or represented by proxy at the Meeting. If Shareholder approval is obtained, Closing is expected to occur in late , subject to the satisfaction of the other conditions to Closing.

The issuance of up to million common shares of Fortis Inc. However, if any other matters should be properly brought before the Meeting, the Common Shares represented by proxies in favour of Fortis management nominees will be voted on such matters in accordance with the best judgment of the proxy nominees.

Fortis will issue up to million Consideration Shares to ITC shareholders as partial consideration for the Acquisition, or up to The actual number of Common Shares to be issued pursuant to the Acquisition Agreement will be determined at Closing based on the exchange ratio of 0. Fortis will not be able to satisfy the listing requirements of the TSX unless Shareholder Approval of the Acquisition Share Issuance Resolution is obtained at the Meeting or any adjournment or postponement thereof. Closing of the Acquisition will not occur until the conditions contained in the Acquisition Agreement have been satisfied or waived.

Closing is expected to occur in late However, there can be no assurance at this time that the Minority Investment will be completed at or prior to Closing, or at all. If completed at or prior to Closing, the consideration paid by the Minority Investors would be used by Fortis to finance part of the Cash Purchase Price.

Completion of the Acquisition is not conditional on the completion of the Minority Investment. Management believes that the Acquisition represents a singular opportunity for Fortis to significantly diversify its business in terms of regulatory jurisdictions, business risk profile and regional economic mix. Background to the Acquisition. As part of this growth strategy, Fortis has continuously evaluated opportunities to maximize shareholder value through strategic acquisitions that would enable Fortis to strengthen and diversify its business, while remaining committed to profitable growth.

The following is a brief summary of the negotiations, discussions and actions among the parties that preceded the execution and public announcement of the Acquisition Agreement. In the following two months management of Fortis, together with its external financial and legal advisors, continued to consider the merits, feasibility and parameters of a potential acquisition of ITC.

During this time, Fortis conducted an in depth technical, financial and legal due diligence review of ITC. Paul J. Bonavia as a director of the Corporation. Bonavia to serve as a director of Fortis following the announcement by the Corporation that it had entered into the Acquisition Agreement.

A joint press release of Fortis and ITC announcing the Acquisition was disseminated prior to the opening of markets that day. Recommendation of the Board. Reasons for the Recommendation. The following is a summary of the principal reasons for the unanimous conclusion of the Board that the Acquisition is in the best interests of Fortis. Acquisition of a Premier Electric Transmission Utility.

The Acquisition of ITC, the largest independent regulated electric transmission utility in the United States, represents a transformative and accretive transaction for Fortis. After giving effect to the Acquisition, Fortis will become one of the top 15 North American public utilities ranked by enterprise value, establishing scale and an additional platform for rate base growth and investment opportunity in a supportive FERC regulatory environment.

ITC has proven operational and development capabilities, generating predictable, reasonable returns on capital investments without commodity or fuel exposure. The Acquisition represents a singular opportunity for Fortis to significantly diversify its business in terms of regulatory jurisdictions, business risk profile and regional economic mix.

Regulatory and Business. Additionally, the FERC regulated electric transmission sector generates stable and predictable cash flows without commodity or fuel exposure. Regional Economic. In addition to its current presence in five provinces, the U. Rates are set using a forward-looking rate-setting mechanism with an annual true-up, which provides timely cost recovery and reduces regulatory lag.

FERC has historically allowed for a greater proportion of equity in target capital structures of transmission companies than is typical for provincial and state utility regulators. There is a significant need for capital investment in the aging U. Investment in the transmission industry is required to address reliability standards established by NERC, including critical infrastructure protection, storm hardening and infrastructure replacement.

Such investment also reduces transmission constraints and improves access to generation resources. Clean energy policies in the United States, including renewable portfolio standards, are driving the need for new transmission investment to facilitate the delivery of electricity from renewable energy resources to load-serving entities.

Fortis structures its operations as separate operating companies in each jurisdiction. Proven Acquisition Track Record of Fortis. Risk Factors Considered by the Board. In connection with its deliberations relating to the Acquisition, the Board also considered potential risks and negative factors concerning the Acquisition and the other transactions contemplated by the Acquisition Agreement, including the following:.

The foregoing summary of the information and factors considered by the Board is not intended to be exhaustive. In reaching its decision to approve the Acquisition Agreement and the transactions contemplated thereby, the Board did not quantify or assign any relative weights to the factors considered, but rather based its approval and recommendation on the totality of the information presented to and considered by it. In addition, individual directors may have given different weight to different factors.

The conclusions and recommendation of the Board was made after considering the totality of the information and factors involved. The foregoing discussion of the information and factors considered by the Board contains forward-looking information and statements, all of which are subject to various risks and assumptions. This summary may not contain all of the information about the Acquisition Agreement that is important to you. We urge you to read carefully the Acquisition Agreement in its entirety as it is the legal document governing the Acquisition.

Acquisition Consideration. Immediately prior to Closing, each outstanding award of performance shares under any ITC stock plan will automatically become vested at the higher of the target level of performance and the actual level of performance through Closing, and each performance share award will be cancelled and will only entitle its holder to receive without interest an amount in cash equal to the number of shares of ITC common stock subject to such award immediately prior to Closing multiplied by the Equity Award Consideration, less applicable withholding taxes.

Representations and Warranties. Certain of the representations and warranties in the Acquisition Agreement are subject to exceptions or qualifications, including, in certain cases, knowledge qualifications, which means that those representations and warranties would not be deemed untrue or incorrect as a result of matters of which certain executives of the party making the representation did not have actual knowledge after reasonable inquiry, and materiality or Material Adverse Effect qualifications.

The representations and warranties contained in the Acquisition Agreement, or in any instrument delivered pursuant thereto, including any rights arising out of any breach of such representations and warranties, will not survive Closing. Except as required pursuant to or permitted by the Acquisition Agreement, required by applicable law or consented to in writing by ITC which consent may not be unreasonably withheld, conditioned or delayed , from the date of the Acquisition Agreement until the earlier of Closing or the termination of the Acquisition Agreement with certain exceptions , Fortis has agreed to, and to cause each of its subsidiaries to, conduct its business in the ordinary course of business consistent with past practice and, where applicable, good utility practice and to other customary operating covenants, including, among others not to:.

No Solicitation. ITC is required to promptly and in any event within 24 hours notify FortisUS if it receives an acquisition proposal, including a summary of the material terms of the proposal including the identity of the person making such proposal. ITC is also required to keep FortisUS informed on a prompt basis of the status and material terms of such acquisition proposal, including any material changes in respect of any such proposal and to provide FortisUS with a summary of any material changes to any such acquisition proposal.

ITC may grant a waiver, amendment or release under any confidentiality or standstill agreement to the extent necessary to allow for a confidential acquisition proposal to be made to ITC or its board of directors if the ITC board of directors determines in good faith, after consultation with its outside legal counsel, that the failure to take such action could be reasonably likely to be inconsistent with its fiduciary duties under applicable law and so long as ITC promptly notifies FortisUS thereof including the identity of such counterparty after granting any such waiver, amendment or release and, if requested by FortisUS, grants FortisUS a waiver, amendment or release of any similar provision under the confidentiality agreement between ITC and Fortis.

ITC Board Recommendation. Efforts to Obtain Required Shareholder Votes. The Acquisition Agreement also requires Fortis to take all reasonable action necessary to duly call, give notice of, convene and hold, the Meeting for the purpose of obtaining Shareholder approval of the Acquisition Share Issuance Resolution.

ITC Financing Cooperation. ITC has agreed to use its reasonable best efforts to, and to cause its representatives to, on a timely basis, provide all customary cooperation that is reasonably requested by FortisUS to assist in connection with obtaining the financing to be undertaken by Fortis in connection with the Acquisition. ITC has agreed to use its reasonable best efforts to obtain an amendment to certain of its credit facilities so that, after giving effect to the Acquisition, no default or event of default exists under such credit facilities.

In connection with the Minority Investment, binding commitments for such Minority Investment are required to be in place no later than 90 days after the date of the Acquisition Agreement which date may be extended for 30 days with the consent of ITC which may not be unreasonably withheld, conditioned or delayed , which consent will not be required where such Minority Investor would not reasonably be expected to delay any Required Regulatory Approval and prior to such date Fortis has agreed to provide written notice to ITC which such notice will contain the identity of each Minority Investor, the amount that such Minority Investor will invest in the Minority Investment and all of the other material terms and conditions of such Minority Investment.

Fortis has agreed not to undertake any Minority Investment that would reasonably be expected to materially delay, materially impede or otherwise prevent the consummation of the transactions contemplated by the Acquisition Agreement, including as a result of any consents of any governmental entity necessary to consummate the transactions contemplated by the Acquisition Agreement.

Other Covenants and Agreements. Consents and Approvals. In addition, the approval of the Federal Communications Commission will be obtained in connection with the Acquisition. Prior to Closing, Fortis, FortisUS and Merger Sub have agreed not to and to cause their affiliates not to permit any action which would reasonably be expected to materially and adversely impact the ability of the Fortis, FortisUS and Merger Sub to secure all required consents and filings with or from any governmental entity to consummate the transactions contemplated by the Acquisition Agreement, or take any action with any governmental entity relating to the foregoing, or agree, in writing or otherwise, to do any of the foregoing, in each case which would reasonably be expected to materially delay or prevent the consummation of the transactions contemplated by the Acquisition Agreement or result in the failure to satisfy any condition to consummation of the transactions contemplated by the Acquisition Agreement.

Conditions to the Acquisition. There are also additional customary conditions under the Acquisition Agreement relating to the performance by the parties of their respective obligations thereunder. Termination of the Acquisition Agreement.

The Acquisition Agreement may be terminated and the Acquisition may be abandoned at any time prior to Closing, notwithstanding the adoption of the Acquisition Agreement by the shareholders of ITC, under the following circumstances:. Termination Fees. Modification, Amendment or Waiver. With respect to certain specified provisions, no amendment, waiver or other modification adverse to any financing source will be effective as to such financing source without its prior written consent.

The debt securities are expected to be denominated primarily in U. The Minority Investment. Fortis expects that, prior to Closing, one or more Minority Investors will have entered into binding commitments to acquire, directly or indirectly, at or after Closing, up to an aggregate of Fortis has undertaken a competitive auction process to solicit bids on the Minority Investment from a number of interested parties and is currently in discussions with potential Minority Investors.

If and when the Corporation agrees to terms regarding the Minority Investment, Fortis will announce that it has entered into one or more binding agreements providing for the Minority Investment. Completion of the Acquisition is not conditional on completion of the Minority Investment. If the Minority Investment cannot be completed prior to the deadline imposed by the Acquisition Agreement, Fortis expects to proceed with the Minority Investment following Closing.

Fortis has also covenanted in the Acquisition Agreement not to permit any Minority Investment that could materially delay, materially impede or otherwise prevent the consummation of the Acquisition or that would prevent FortisUS from meeting certain U.

The execution of a binding agreement with respect to the Minority Investment will result in the permanent reduction in the commitments under the Acquisition Credit Facilities. Acquisition Credit Facilities. The Acquisition Credit Facilities would be sufficient, if necessary, to fund the full Cash Purchase Price for the Acquisition and estimated Acquisition-related expenses.

However, Fortis does not expect to draw on the Acquisition Credit Facilities, as it expects to use a combination of one or more Prospective Offerings and to effect the Minority Investment to fund the Cash Purchase Price payable in connection with the Acquisition. If such financing sources are unavailable to Fortis on terms acceptable to Fortis on or prior to Closing, Fortis will borrow amounts under the Acquisition Credit Facilities, the material terms of which are summarized below, to finance the necessary portion of the Cash Purchase Price.

The commitments available to be drawn under the Equity Bridge Facilities will be reduced by the amount of the net proceeds arising as a result of the occurrence of any Equity Prepayment Obligation prior to any drawdown of the Equity Bridge Facilities.

Any reduction in the outstanding commitments under the Equity Bridge Facilities will be irreversible and any loans prepaid thereunder may not be re-borrowed. The commitments available to be drawn under the Debt Bridge Facility will be reduced by the amount of the net proceeds arising as a result of the occurrence of any Debt Prepayment Obligation prior to drawdown of the Debt Bridge Facility. Any reduction in the outstanding commitments under the Debt Bridge Facility will be irreversible and any loans prepaid thereunder may not be re-borrowed.

Pursuant to these covenants, Fortis would be required to maintain a consolidated debt to consolidated capitalization ratio of not more than 0. Customary fees are payable by Fortis in respect of the Acquisition Credit Facilities and amounts outstanding under the Acquisition Credit Facilities will bear interest at market rates.

The Corporation expects to maintain an investment-grade credit rating following the Acquisition. Acquisition-Related Costs. Immediately prior to Closing, each outstanding option to purchase shares of ITC common stock and each award of restricted stock will automatically become immediately vested and be cancelled and will only entitle the holder to receive an amount in cash. In addition, each outstanding award of performance shares under any ITC stock plan will automatically become vested immediately prior to Closing at the higher of the target level of performance and the actual level of performance through Closing, and each performance share award will be cancelled and will only entitle its holder to receive an amount in cash.

TSX Approval. As a result of the restrictions on the issuance of stock by ITC contained in the Acquisition Agreement, less than Therefore, if the Acquisition is completed, up to million Common Shares will be issued as partial payment of the purchase price for the Acquisition, representing up to To the knowledge of the directors and executive officers of Fortis, after reasonable inquiry, no votes attached to the Common Shares will be excluded in determining whether Shareholder Approval of the Acquisition Share Issuance Resolution has been obtained.

Listing will be subject to Fortis fulfilling all of the requirements of the TSX. By listing its Common Shares, Fortis will also become subject to certain NYSE standards and rules, which impose additional corporate governance and other obligations on listed companies; however, as a foreign private issuer, Fortis would be permitted to instead follow Canadian governance practices to the extent that they differ. Despite its status as a foreign private issuer and eligibility to report using the MJDS forms, Fortis will be subject to a number of the disclosure and other requirements mandated by the U.

Fortis intends to issue a news release upon the Registration Statement having been declared effective by the SEC. Litigation Relating to the Acquisition. Paolo Guerra v. Albert Ernst, et al. Joseph L. Welch, et al. The federal complaint names the same defendants plus FortisUS , asserts the same general allegations and seeks the same types of relief as in the state court case. Additional lawsuits arising out of or relating to the Acquisition Agreement or the Acquisition may be filed in the future.

Executive Appointment. The pro forma financial information in the table is derived from the unaudited pro forma condensed consolidated financial statements included in this Circular. The pro forma adjustments applied to this information are based upon preliminary estimates, current available information and certain assumptions.

It is expected that the actual adjustments will differ from these pro forma adjustments, and the differences may be material. Cash and cash equivalents. Total debt and capital lease and finance obligations 3. Common Shares 4. Preference shares. Additional paid-in capital.

Accumulated other comprehensive income. Retained earnings. Total capitalization 5. For purposes of this table, the assets and liabilities of ITC, which has a U. Fortis expects the Cash Purchase Price and the Acquisition-related expenses will be financed from a combination of one or more Prospective Offerings, the purchase price paid by the Minority Investors in connection with the Minority Investment and, if and to the extent necessary, the borrowing under the Acquisition Credit Facilities.

The capital structure of Fortis is not expected to materially change as a result of the Acquisition; however, no assurance can be provided that a further ratings downgrade will not occur. Fortis expects that it will continue to have an investment-grade credit rating following completion of the Acquisition.

Credit ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities and are intended to be indicators of the likelihood of payment and of the capacity and willingness of the issuer to meet its financial commitment on an obligation in accordance with the terms of the obligation. Ratings designations may be modified by the addition of a plus or minus.

A plus or minus designation indicates the relative standing of the issuer or the debt, as applicable, within a category. A negative outlook indicates that a rating may be lowered. According to the DBRS rating system, debt securities rated A are of good credit quality and indicate that the capacity for the payment of financial obligations is considered substantial but that the instrument may be vulnerable to future events. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant and, if any such rating is so revised or withdrawn, Fortis is under no obligation to update this Circular.

This section provides information on each of the 12 persons nominated for election as director at the Meeting, including the background, experience, meeting attendance, other public board memberships and Fortis securities held. Based on questionnaires completed by each of the proposed nominees, the Board has determined that other than Mr. Perry, each nominee has no material relationship with Fortis and is, therefore, independent of Fortis.

Zurel and Ms. Dilley, who are each being nominated for the first time. There are no contracts, arrangements or understandings between any director or executive officer or any other person pursuant to which any of the nominees has been nominated for election as a director of the Corporation. Corporate Director. Edmonton, Alberta. Age: Prior to joining a predecessor to Canadian Western Bank Group in , she worked in public accounting and consulting.

Ball has served on several private and public sector boards, including the Province of Alberta Audit Committee and the Financial Executives Institute of Canada. She holds an ICD. D designation from the Institute of Corporate Directors. Ball serves as Chair of FortisAlberta Inc. Board of Directors. Applicable Yes 3. Ile Bizard, Quebec. Human Resources. Kingston, Ontario. Case served on the Board of FortisOntario Inc. Audit Chair. Yes 6.

Yes 8. New York, New York. Previously Ms. Washington, D. Director since: New Nominee. New Nominee. IDA J. Vancouver, British Columbia. She has held senior leadership roles in several Canadian and international pulp and paper and natural gas companies. Governance and Nominating. Yes 5.

Calgary, Alberta. Haughey was Chief Executive Officer of The Churchill Corporation, a commercial construction and industrial services company focused on the western Canadian market. From through , Mr. Haughey held several executive roles with Spectra Energy and predecessor companies. He holds an ICD. Human Resources Chair. Vintage Consulting Group Inc. Summerland, British Columbia. McWatters serves on the Governance and Nominating Committee. Yes 7. Mississauga, Ontario. While there he acted as lead advisor on over capital markets and strategic and advisory assignments for North American Utility clients.

Previously he was President and CEO of Consumer Gas where he led the company through deregulation and restructuring in the s. He served as a director of Newfoundland Power Inc. Norris served as a director of Fortis Properties Corporation from through Board of Directors Chair. Not Independent. Prior to his current position at Fortis, Mr. Securities Held 7. Stonebridge Capital Inc. Zurel is President of Stonebridge Capital Inc. From to , Mr. Existing customer billing meters could be replaced with microprocessor-based meters which could provide the customer with new buying options such as time-of-day pricing, and could increase end user efficiency.

These meters could also allow control signals from the power company to be brought directly into appliances and equipment on the customer side for load management. Automatic control action to stabilize the power system after a disturbance has to be taken in well under a second, thus requiring measurement sampling of around 60 times a second. The available phasor measurement units PMUs routinely provide measurement sampling at 30 or 60 Hz, and faster sampling rates are already appearing in the market.

Global positioning system GPS signals and the associated absolute-time references allow accurate phase shifts in AC quantities to be measured between widely separated substations. To appropriately process the data, a fully integrated communications system with universal standards protocols must be developed, along with real-time data handling software that can collect and move the data to where they are needed.

If the measurement technologies described above are fully implemented, each control center will need to process approximately one million data points per second. They are currently being replaced with high-bandwidth optical fiber. However, even with increased bandwidth, the present system in which all data from substation RTUs are collected at the control center SCADA cannot handle the expected proliferation of real-time measurement data.

An alternative to this communications architecture is shown in Figure 9. Each substation has its own data-gathering system connected internally by a LAN. A gateway server connects these data to the rest of the system through a high-speed network of switching routers, which can move the needed data efficiently to monitoring and control applications.

These applications require coordination across several substations, either regionally or over the entire interconnection. Such applications are often referred to as wide-area controls or special protection schemes. Communication systems must be able to handle a wide range of speed and data flow requirements, and the switching network and distributed database will have to be designed. Although similar systems exist today e. Such a communications system should be ready for deployment by , possibly continuing into the — time period.

For a sense of scale, each of the approximately control centers in the Eastern Interconnection oversees about high-voltage substations on average. Each substation shown on the right takes measurements that are collected by its own data-gathering system. These measurements are communicated internally by a local area network LAN. A substation server communicates these data to the rest of the system through a high-speed network of switching routers shown as circles that can move the data efficiently as needed to specific monitoring and control applications.

Measurement and communication technologies create a picture of the state of the systems, which control technology can use for greater reliability and security including self-healing following a disruption and more efficient operation and optimization of assets. This will enable the evolution of better controls to make the grid increasingly reliable and efficient. In contrast, FACTS devices already in use as fast local controllers can control voltages and power flows with response times measured in milliseconds.

Moreover, fast wide-area controls, combining rapid communications with remotely controlled FACTS devices, are becoming feasible. Time-stamped measurements will make multiple inputs available to the controller, which can then send out multiple output signals to several FACTS controllers simultaneously.

With these technologies, many types of grid monitoring and control will become possible. Cascading failures can be predicted, and defensive actions such as islanding can prevent the spread of the disturbance. Advanced distribution controls can accommodate two-way power flow from distributed generation by balancing the load on all the distribution feeders.

In addition, demandside responses can be efficiently coordinated if appropriate sensors and communications are in place. Such control technologies could begin to be deployed by Measurement, communications, and control technologies are already being deployed to a modest degree and could be fully deployed by About 15, transmission substations will require new sensors, measurement systems, and LANs.

To add high-bandwidth communications hardware mainly fiber-optic cables across the transmission system of approximately , miles of network and 20, switches, investment in both hardware and software will be needed. The costs of developing the needed software to operate the hardware for control will be significant.

Technologies for distribution systems are different in character from transmission. Sensing, monitoring, and communications technologies will need to be. These controls will be particularly important as smart metering is introduced into distribution networks. Additional investment will also be needed for coordination between transmission level-controls and distribution-level controls.

These tools need to be further improved because of the massive amounts of data that are available in real time and the need to use these data in system control. This section examines improved decision-support technology IDST , including those tools necessary for split-second decision making by system operators during emergencies as well as for long-term decision making on investments needed in the grid itself.

A recurring theme in blackout investigations has been the need for better visualization capabilities and decision-support tools over a wide geographic area. In many circumstances, a human operator will require at least some seconds to make a decision, but automatic controls operate on the order of milliseconds.

IDST enables grid operators and managers to make faster decisions by converting the complex power-system data into information that can be understood at a glance. Improved visualization interfaces and decision-support technologies will increase reliability, decrease outages due to natural causes and human error, and enhance asset management.

Grid visualization. Real-time analysis of system stability will require online analytical tools that process the vast amount of data and automatically determine what actions should be taken to prevent an incipient disturbance from spreading. This objective requires completing the analysis within a fraction of a second and presenting it visually in a control room for fast responses to deteriorating conditions. The algorithms have not yet been developed to perform these functions, but they could be deployed by and would be continually improved in the — timeframe and beyond.

Decision support. Decision-support technologies can identify existing, emerging, and predicted problems and provide analysis to support solutions. By analyzing the consequences of each contingency and its probability of occurrence, decision-support systems can quantify relative risk and severity. These relative risks can be integrated into a composite risk factor and presented to the operator to assist in decision making.

Further work on decision-support algorithms will be needed to make them available for deployment before , with continuing improvements in the — timeframe and beyond. Systems operator training. Advanced simulators currently under development will give operators a real-time, faster-than-real-time, or historic view of the power system and its parameters. These dynamic simulators, together with industry-wide certification programs, will significantly improve the skill sets and performance of system operators.

Such simulators could be ready for deployment by , as soon as the visualization and decision-support algorithms are in place. IDST, together with system-operator training, will then need to be continuously evaluated and improved. Improved software and artificial intelligence for IDST could begin to be deployed by , and deployment is likely to continue into the — timeframe.

Decision tools are also needed for decisions that occur over longer timescales than do real-time operating decisions. Decisions include forecasting the load, scheduling dispatchable generation and long-term contracts to meet the load, conducting auction markets, using power contracts to check on possible congestion on the transmission system, and modifying the power contracts if congestion is indicated.

The decision tools needed for these tasks are mostly new or have been significantly modified in recent years. Longer-term planning for new generation and transmission capacity must deal with considerable uncertainty, especially where the industry has been restructured and no one organization holds the ultimate responsibility for building adequate generation.

Transmission is still regulated, but transmission planning is dependent on knowing where the new generating plants are going to be located. Computerized planning decision tools must be improved to handle increased uncertainty for the to year time horizon. It is anticipated that renewables will present unique challenges, and the addition of probabilistic methods not in use today may help system operators respond to the changing generation mix. The two tool sets should be seamlessly coordinated with one another and connected to the operations and operations-planning databases so that customer trouble calls can be coordinated with maintenance crews, spare part inventories, and system operations.

Several major conditions must be met before IDST can be effectively implemented. First, modern measurement, communications, and control technologies must be implemented along with the power electronics technologies needed to enable automated controls. In addition, development is needed in applications that integrate advanced visualization technologies with geospatial tools to improve the speed of comprehension and decision making.

Some of these technologies could begin to be implemented well before The key technologies discussed above are in various stages of development, with many already having been deployed in a limited way. However, the primary challenge will be the integrated deployment of these technologies to achieve the desired characteristics and performance of a modern grid.

For example, the capabilities of power electronics would be maximized by coupling them with real-time measurement, communications, control, and decision-support tools. All these technologies can be improved upon and would benefit from cost reduction.

A few, such as large-scale storage, are simply impractical now. In addition, the nation is facing a critical shortage of power engineers, the very people who will be needed to implement modernization. Projecting the costs of modernizing the U.

First, EPRI projected that superconducting cables would be added to the system over the next 20 years, but the committee concluded that high costs and slow technological development would preclude commercial deployment before In addition, recent real escalation in materials and construction costs were accounted for by using the national average transmission and distribution indexes 33 percent for transmission, 40 percent for distribution.

These changes are described in Annex 9. The investment in superconducting cables has been removed from the total investment needed for the transmission system. It has also been removed from the synergies calculation. These changes are described in detail in Annex 9. For example, existing lines could carry greater loads if improved control systems prevented overloading, so some new lines would not be needed.

Estimated costs in the two studies are very similar. Neither report explicitly accounted for the construction of new transmission lines to bring power from remote wind or other renewable energy sources to load centers. These lines could be longer than those from conventional power sources and carry power at a lower capacity factor, thus increasing costs.

According to a DOE report on achieving 20 percent of U. Actual expenditures will be highly dependent on the routes chosen and the capacities of the lines, but additional costs on the order of tens of billions of dollars seem plausible. Large-scale power generation from photovoltaics or solar thermal technology is a longer-term possibility if cost reductions are achieved.

Much of this power. A comparison between these two studies is made in more detail in Annex 9. Construction of such lines will depend on the regulatory environment and government policy; the transmission technology is available, although further improvements would be beneficial. Representatives of EPRI and the Edison Electric Institute EEI , which funded the Brattle study, have suggested that the split would be approximately one-third during the first 10 years and the remaining two-thirds over the second 10 years.

If modernization were not included, however, utilities would have to continue using existing technologies for control, sensing, and monitoring equipment, and the nation would be deprived of the many benefits discussed here. Costs to consumers could be reduced through more efficient electricity markets; national security could be. On a more local scale, a recent study by the University of San Diego considered the value of a modern distribution system to the San Diego area. The following sections, however, provide some specific examples of potential benefits from modernizing the system.

EPRI estimates the annual cost of power disturbances to the U. Thus improving grid reliability and efficiency could result in substantial economic benefits. These energy price signals will allow customers to more effectively participate in the electricity market, based on current supply-and-demand influences. Overall, markets will be more efficient when consumer decisions are based on realistic prices. There will also be a reduction in grid congestion and forced power outages.

A modernized grid will enable a wide array of new options for load management, distributed generation, energy storage, and. In addition, the ability to handle a high level of electricity generated from domestic renewable energy sources has national security benefits as well as the environmental benefits discussed in the next section.

Moreover, sophisticated analytical capabilities can detect and prevent or mitigate the consequences of an attack or disaster, and probabilistic analytical tools can identify inherent weaknesses in the grid so that they can be integrated into an overall national security plan. Guidelines for cyber-security are already in place , but these may not be adequate for a fully deployed communications and control system.

Cyber-security has to be an integral part of modernizing the grid. A modern grid could improve the diversity of energy supplies by allowing larger proportions of renewable energy into the U. Natural gas is also a concern because projected rates of consumption may lead to importing increased amounts of liquefied natural gas, some from politically unstable areas of the world.

Little oil is used for electric generation, but the modern grid will reduce oil imports by helping to make electric vehicles commercially viable. Modernizing the power delivery system is an essential step in reducing emissions of carbon dioxide and other pollutants such as SO x , NO x , and mercury:. Self-generation refers to electricity generation that the end user owns and controls. See Chapter 6 for further discussion. Modern demand-response technologies such as grid-friendly appliances that can be controlled by the utility to shift load to off-peak times can be better accommodated, thereby reducing demand that must be met by inefficient generating equipment.

Battery electric vehicles BEVs can be better accommodated, particularly after The electricity provided by wind power varies significantly over the course of a day and over the year because of natural variations in wind speed. As a general rule, a power-delivery system can handle the loss of 10—20 percent of the local generating capacity as long as adequate reserve capacity is available.

Because intermittent sources cannot be depended on, the spinning reserve has to include a significant fraction of the renewable capacity in addition to the largest unit of conventional power. Self-generation is a special case of distributed generation. End users generate some portion of their own energy needs, utilizing, for example, rooftop solar panels.

Under some conditions, any excess power may be sold to the utility. Grid modernization is not needed for integrating intermittent renewable-electricity sources in relatively small percentages of the overall electricity supply. This is discussed in greater detail in Chapter 6.

Wind and solar power are the main intermittent renewable-energy sources. Other renewables, such as hydropower, geothermal, and biofuels, are not intermittent. The changes needed to accommodate renewables are discussed in more detail in the technology section of this chapter; they involve large-scale storage as well as high-voltage long-distance transmission.

Many high-quality renewable resources, such as wind in the Dakotas and solar resources in the deserts of the Southwest, are located far from population centers. More transmission capacity will be required to bring electricity from these locations to areas of high demand, potentially using technologies such as HVDC transmission. Other low-emission and renewable resources are likely to be used as distributed generation e.

The modern grid will enable better integration of these resources by incorporating two-way power flow and smart metering on the distribution system. Many modern demand-response technologies can be regulated in response to grid conditions. With the implementation of time-of-day pricing, such technologies could allow for more cost-effective and efficient electric power generation i.

With the addition of such technologies, the impact on the grid could also be small even by A modern grid can operate more efficiently, reducing the need for construction of new generators and transmission lines. Approximately 10 percent of the total power produced in the United States is lost in the process of delivering it to the end user. For example, reactive power flow over a transmission line not only increases losses in the transmission line but also significantly reduces the power-carrying capacity of the line; the use of power electronics, however, can reduce such flow of reactive power.

In addition, power electronics can reduce losses by shifting power flow to the most advantageous transmission paths and by the use. Plug-in hybrid vehicles are discussed in further detail in Chapter 4. The American Public Power Association reports that about fatalities and flash burns occur annually in the electric utility business Trotter, Improved monitoring and decision-support systems would quickly identify problems and hazards. For example, the ability to identify equipment that is on the verge of failure is certain to save lives and reduce severe injuries.

In addition, by reducing the risk of long-term outages following terrorist attacks or natural disasters, modernization could help prevent public health and safety catastrophes. The benefits would be substantial and quite likely to far outweigh the costs. Nevertheless, modernization is unlikely to happen unless it is also in the interests of those who must implement it. Several barriers have the potential to impede this implementation. First, the technologies that utilities would employ to modernize the grid entail additional costs and uncertainties—particularly regarding how well they will work relative to older technologies.

Second, some utilities may be reluctant to invest the additional funds required for modernization even when it would appear to make sense to do so. Third, there is a lack of regulatory and political support that could provide incentives for modernization. Finally, there is difficulty in communicating the need for modernization to the public and to regulatory and political decision makers.

In January , a DOE standard will take effect requiring higher efficiency in all new distribution transformers. The DOE estimates that between and the energy saved by this measure will be equivalent to the energy used by 27 million households in the United States in a single year. Given the expected life of distribution transformers, 5 percent are expected to be replaced each year under this new standard DOE, Yet the rate of technology research, development, and deployment in the power industry is low compared to that of other industries.

Also, modernization technologies must be deployed in unison to achieve their full benefits, posing challenges in integrating technologies. For example, universal communications standards as well as a common architecture that promotes interoperability are needed. However, the security issues that are involved in an open system must be met with industry-approved and -adapted standards and protocols. Modernization will cost more than simply building more transmission lines and replacing aging equipment.

Even though the additional investment would eventually pay off, financial markets and regulatory constraints drive utilities to minimize investments. The companies, however, must bear the full cost of modernizing the parts of the grid that serve their customers. This barrier is more significant for the transmission system, which is inherently interconnected: many entities own and regulate different parts of it. Cooperation will be needed among utilities and regulatory agencies.

As noted above, utilities are cautious about adopting new technologies that may involve some risk. This is especially true when familiar technologies have lower first costs and utilities are given no incentive to invest more than the minimum required to maintain operations.

If modernization is to occur and produce all the advantages it offers, legal and regulatory changes are likely to be necessary. Legislators and regulators have not taken a strong leadership role regarding grid modernization, nor have they adopted a clear and consistent vision for.

There has been significant focus in recent years on individual technologies and on energy-related issues such as environmental impact, but less attention has been paid to developing a vision that integrates technologies, solves the various grid-related issues, and provides the desired benefits to stakeholders and society.

For example, a wholesale pricing structure that recognizes the value of reliability and signals when transmission system upgrades are necessary would help provide investment predictability. In addition, policies regarding the grid are often inconsistent because they are set by multiple groups—individual states state energy policies and public utility commissions [PUCs] ; the Federal Energy Regulatory Commission FERC ; and environmental agencies.

Inconsistent policies among states and between state and federal regulators, for example, prevent effective collaboration across transmission regions. Also, time-of-day rates for consumers that reflect actual wholesale market conditions are not yet widely implemented, thereby preventing the level of demand-side involvement needed in the modern grid. Net metering policies that provide customers with retail credit for energy generated by them are also not widely deployed, which reduces the incentive for end users to install rooftop photovoltaics or other generating technologies.

Finally, regulatory policies often do not reward customers for investments that provide substantial societal benefits, such as credits for local storage that has been made dispatchable. Dispatchable energy storage is a set of technologies for storing electricity to be deployed quickly dispatched into the grid when other power sources become unavailable. Some electric utility executives assert that their customers value lower rates more than the benefits of a modernized grid, which would increase costs in the short term NETL, b.

In order to overcome this barrier, significant efforts need to be made to communicate the benefits of a modern grid to all stakeholders. Improved communication with the public is also necessary regarding the costs and benefits associated with the current transmission system in particular, which is experiencing ever increasing congestion and needs expansion. It is difficult to site new transmission lines.

Many proposals for new lines generate considerable opposition, usually based on aesthetic, property value, or health and safety concerns. For example, American Electric Power, a large Midwest utility, recently experienced a year approval process for a new mile kV transmission line.

Many of the technologies needed to modernize the grid can be deployed before , but most of the technical challenges will involve seamlessly integrating these technologies. Not only must multiple technologies work in concert across a huge and sprawling system, but the system is owned and operated by numerous often regional stakeholders with diverse perspectives, incentives, and constraints.

Given these factors, a broad vision and an accompanying road map are required to achieve consensus on common goals and to guide the integrated deployment of modern technologies that meet the performance requirements of the modern grid, as described previously in this chapter. The complexity of the transmission system suggests that the development of clear metrics to measure societal benefits will be essential to measuring progress. The types of metrics that may be considered include reductions in electricity demand forecasting error from 6 percent to, say, less than 0.

These reasons included a redesignation by Congress of 19 miles of the New River in Virginia as wild and scenic, problematic interfaces between the states and federal agencies, and public opposition. For example, PUCs could look for methods to establish accountability for transmission availability, to measure and internalize the value of lost load and power quality, and to measure and appropriately reward utilities for contributions to efficiency improvement and market transformation.

With such a vision in place, modern technologies could be seamlessly deployed across regions. For example, they would be incorporated whenever new facilities were built, while control centers could be gradually modernized. Communications and control software, as well as tools for improved decision support, could then begin to be implemented. In contrast, the modernization of distribution systems can occur on a regional level, and programs are emerging in the United States as well as around the world.

Pilot projects involving smart meters have begun in many areas. AEP expects to have all 5 million of its customers on this system by Bjelovuk, Other countries that have already implemented partial distribution-system modernization programs report very positive results.

The key components of the modern grid FACTS devices, custom power, HVDC and HVAC technologies, and storage have largely been developed, as noted earlier, and measurement, communications, and control technologies to manage these components will be deployable on a large scale, along with the associated decision-support tools, before.

Development of a nationwide strategy to modernize the U. Recently, many factors, including changes in the regulatory structure of the power industry, have lowered the reliability of this critical national infrastructure. However, many technologies capable of meeting these challenges are currently available or will be available before Ad vanced equipment. Many power electronics devices and transmis sion line technologies are currently commercially available and can be deployed before These technologies are not widely deployed at present.

Me asurements, communications, and control. Most measurement, com munications, and control technologies are currently available and can begin to be deployed before ; however, software development is still needed. Further work is needed to establish a standard communications protocol.

Such a protocol could be deployable before Improved decision-support tools. Improved decision-support technolo gies could begin to be deployed before ; however, they will require the co-deployment of modern measurements, communications, and controls, as well as power electronics, to be effective. Further work is needed to develop and implement algorithms for rapid decision making and advanced search and optimization.

This software is likely to be deployable before In particular:. Tr ansmission. The modernization of the transmission system will ben efit greatly from a comprehensive national vision based on consensus among the many stakeholders. The transmission system is national in scale, and the major benefits of a modern system come from the operation of many technologies in concert across the entire system rather than from technologies deployed in isolation. State, regional, and national planning is needed on how the nation will deliver 20 percent of its energy and beyond from renewables, especially wind and solar.

If such a vision is established and it addresses the many barriers to modernization, the transmission system could be modernized by Smart meters and related technologies can improve the efficiency and economics of distribution. Modernization of the distribution system can occur regionally, allowing for rapid parallel deployment while encouraging experimentation to develop best practices.

This modernization is already occurring in limited areas; however, it would benefit from a nationwide consensus on best practices such as standardization of communication methods to better enable smart meters and. The distribution systems could be modernized by if such a consensus is reached nationwide. This situation is further compounded by the risk-averse nature of the electric utility industry. The exclusion of societal benefits such as avoiding costs to the public from widespread blackouts in the return on investment for the transmission system is a barrier to industry investment in modern transmission technologies.

Regulatory and legislative. The lack of a comprehensive national vision for the transmission system could form a barrier to transmission mod ernization. There is limited multiregional planning and coordination of improve ments to the transmission system.

Overarching consensus-based standards for grid modernization are necessary but do not currently exist. An open-protocol communications architecture and mechanisms for. Cultural and communications. Active public opposition stemming from environmental or cost concerns could form a barrier to construction of new transmission lines. To integrate renewable sources such as wind and solar on a large scale, the transmission system will need to accommodate their variability. This objective can be met with backup generation such as gas-fired power plants or by large-scale storage technologies, such as compressed air energy storage CAES.

Backup generation or CAES could be deployed before Many renewables are likely to be deployed as distributed generation such as rooftop PV panels , which will require two-way power flow capability. Transmitting power from high-quality renewable resources to popula tion centers creates economic challenges. These challenges include securing the rights of way for the needed corridors and making a business case for the transmission lines.

The level of technology research, development, and deployment in the U. Washington, D. Centolella, P. Ohio PUC. DOE U. Department of Energy. Federal Register 72 , October Available at www1. Accessed July Electricity Supply.

Accessed May 8, Annual Energy Outlook Department of Energy, Energy Information Administration. Palo Alto, Calif. Available at www. Princeton, N. Accessed May 11, A Vision for the Modern Grid. Nevius, D. Owens, D. San Diego. Trotter, J. Safety programs that work.

This annex provides selected additional information to support the material in the main text of Chapter 9. The first section provides information on reliability measures. CAIDI tracks the average duration typically expressed in minutes of customer interruptions over a given time period. SAIFI tracks the average number of customer interruptions in power service in a given period of time. SAIDI tracks the average number of customer interruptions in power service in a given time period.

Results of applying these indexes are shown in Figures 9. The modern grid must meet the ever expanding needs of society and at the same time be reliable, secure, economic, efficient, environmentally friendly, and safe. Emergency response. A modern grid provides advanced analysis for predicting problems before they occur and assessing problems as they develop.

This capability allows actions that respond more effectively and minimize disruptions. Expressed in minutes, the average SAIDI in the state of Ohio has been holding approximately steady over the last 7 years. As better information, control, and communication tools become available to assist the operators and field personnel of a modern grid, it can be restored much faster and at lower cost. Routine operations. With the help of advanced visualization and control tools, fast simulations, and decision-support systems, the operators of a modern grid can better understand its real-time state and trajectory, provide recommendations for secure operations, and allow appropriate controls to be initiated.

These capabilities could help achieve significant reduction of the system peak-to-average ratio, thereby saving resources. The modern grid provides advanced tools for comprehending conditions, evaluating options, and exerting a wide range of control actions to optimize grid performance, whether from reliability, environmental, efficiency, or economic perspectives.

System planning. Grid planners must analyze projected growth in supply and demand to guide their decisions about where to build, what to. The data-mining and data-modeling capabilities of a modern grid will provide much more accurate information for answering those questions while potentially realizing significant savings.

To acquire these characteristics each of which is discussed in turn below , it will not be enough simply to add isolated technologies to the existing system. Technologies will need to be integrated with one another and also have a common basis for communication across regions. Thus creating a transmission system that displays these characteristics will require a multiregional effort based on consensus among all of the key stakeholders and reflecting a common approach to deployment across the various transmission regions.

Given the regional nature of the distribution system, such a common vision for distribution is less essential. The following is an in-depth discussion of the seven characteristics. The transmission system must be designed to accommodate large baseload generation, such as nuclear and coal, as well as sources that do not typically operate in baseload mode, such as renewables.

In addition, the distribution system must accommodate smaller distributed-energy sources. Large-scale baseload generation resources may require backup generation and, possibly, also power electronics to ensure that power flows are accommodated. Also, both the transmission and the distribution system must accommodate the intermittency of wind and solar generation. For transmission, this requirement translates into the ability to withstand the loss of the largest single generator on the system.

The variability of small amounts of renewables on the current system can be accommodated reasonably. The modern transmission system can meet the challenges posed by remotely located renewable-energy sources in large part through the use of technologies such as high-voltage direct current HVDC and power electronics.

Dispatchable energy storage or backup generation can help to smooth intermittent generation, but the cost of the backup generation, storage, and power electronics and the actual cost of the transmission line and substations will need to be incorporated into the overall economics cost of power of, for instance, a proposed wind farm.

For distributed renewable power systems, the situation is somewhat different. For small amounts of power, net metering schemes and two-way power flow will adequately support them. If distributed renewable power becomes significant, however, storage to buffer it will be required. Such storage carries a secondary benefit of improving power reliability. As the local distribution becomes smarter, the easier it will be to accommodate renewable power.

The transmission system is being pressed into a new mode, in which wholesale power is bought and sold across wide areas. Although some modifications have been made, the systems are woefully short of the flexibility and intelligence required to accommodate wholesale power markets EPRI, ; NETL, d. Better knowledge of the transmission grid, including its available capacity and potential congestion locations in real time, can make the generation market more efficient. While many of the most pressing needs in this area are related to the transmission system, changes will also be needed on the distribution side.

For example, it is difficult at present for consumers to respond to increases in price to seek lower-cost products. Major improvements must be made to the transmission system to achieve well-designed and operating markets, especially as industrial, commercial, and even residential consumers will generate and sell power. These contributors will be enabled by emerging generation and storage technologies; the modern grid will allow for two-way power flow on the distribution system and thereby provide self-generation opportunities for the end user to also participate in power markets.

Thus transmission capacity needs to be increased, and communication and control between regions must be expanded to accommodate the vast amount of information flow required in real time. Some of these needed improvements will require little in the way of new or advanced technologies, but they will depend more on policy decisions and implementation. For example, improvements in regulations, the training of participants in the market, and significant capital investments are all important.

Power outages can cause significant financial losses for U. As discussed in the main text of this chapter, the blackout in the North American Eastern Interconnection occurred because a small problem in one part of the system resulted in cascading failures throughout the system. A self-healing transmission system could minimize such occurrences. For example, faulty equipment or lines can be isolated when necessary to prevent problems from spreading.

A self-healing system should be capable of being restored to normal operation with little or no human intervention. This means that both the transmission and the distribution system will have the ability to sense the state of the system as well as communicate this information to other parts of the system and take appropriate action. Many of these measures will be technological, while others will involve the development of software and standards.

Eto, personal communication, In addition, integrating the new technologies will be a major challenge. For transmission, the needed measures include: effective and advanced monitoring; methods for very quickly determining the cause and location of a fault or instability; probability-based contingency analysis; rapid system alignment for the next contingency; effective use of flexible alternating current transmission system FACTS devices and HVDC to stabilize system voltages and power flows; remotely dispatchable storage near generators and load centers; effective use of customer-generated power and storage; intelligent load-shedding; effective islanding; fast restoration means; strict reliability standards; and predictive maintenance of key components NETL, b.

Many of these approaches are described in the sections that follow. On the distribution side, measures to enable self-healing include distribution automation; alternate feeders with power-electronics-based transfer switching; micro-grids and meshed distribution systems; high impedance fault location; automatic switching off of nonessential loads; and effective use of local, generally customer-owned power and storage.

Customers are not just consumers of electricity; they may also participate in generation and storage options as well as interactively respond to price signals. One way to optimize the use of electricity resources, in fact, is to motivate the customer to make wise end-use decisions PNNL, For example, providing electricity-pricing information to customers has been shown to reduce peak demand and assist in levelizing power demand.

In addition, better information of this kind can enable the distribution-system operator to utilize the system more efficiently. The challenge primarily addresses the distribution system; however, it must ultimately include transmission, as decisions on the consumer side will, when taken in bulk, affect power markets and energy trading.

Similarly, technologies could automate industrial and residential electricity-use decisions so that energy-intensive equipment and appliances could be run at night or on weekends rather than during peak-load hours. Utilities may be able to reduce demand in this way, at virtually any time of day and in real time, by communicating with end users and even directly with their appliances. Detailed information on energy use and costs empowers individuals to take more proactive actions in their best interests.

Terrorist threats to the transmission system, whether physical or cyber, are serious; a widespread attack against the electric-system infrastructure cannot be ruled out. The transmission system is the primary focus: an attack on the distribution system would have only local impact, while an attack on the transmission system could affect millions. Resilience must be built in to each element, and the overall system must be designed to deter, detect, respond to, and recover from human-induced as well as natural disruptions.

Moreover, in order to reduce the threat of attack, the modern transmission system must conceal design vulnerabilities; disperse, eliminate, or reduce single-point failures; and protect key assets from both physical and cyber assaults. The modern transmission system must also reduce the consequences of a successful attack by devoting resources to recovery. These capabilities would allow the systems to respond to attack by rerouting to unaffected segments, isolating the affected portion, and thus preventing the disturbance from spreading.

In addition, predictive models and decision-support tools could help operators respond to impending disruptions in real time and preempt further disruption. Providing greater automation, wide-area monitoring, and remote control of electrical distribution systems would enable all of these measures. In order to further increase security, it is also important to acquire and position spares for key elements, such as high-voltage transformers and breakers, and to ensure that added equipment and control systems do not create additional opportunities for attack.

Forty percent of the power used in this country today is regulated through microchips of various types that run a wide range of equipment. Over the coming decade, this proportion could grow to 60 percent. In order to accommodate these microchips, the utility supply voltage must be reasonably free from harmonics, and any voltage variations should be within acceptable limits. The utility supply voltage deviates from the ideal because of events such as faults; the switching of lines, loads, or system equipment; overloads and light loads; and loads that inject harmonics into the utility system.

Providing high-quality power is primarily an issue for the distribution system, as it affects the end user of the electricity and not its long-distance transmission. It is estimated that problems with power quality cost tens of billions of dollars annually. Accordingly, many industrial and commercial users install equipment—such as uninterruptible power supplies, alternate utility feeders with high-speed transfer switches, standby generators, or a variety of power electronics devices, depending on cost and benefit—to attain the needed power quality.

But with proper monitoring of the network condition and anticipation of changes, power-quality problems can be avoided at the system level through the use of existing technologies. Flexible AC transmission systems with superconducting condensers can reduce sags, which are the biggest customer power-quality problem.

Fault current limiters can reduce the voltage depressions; synchronous switching can eliminate transient over-voltages. This is not currently the case, particularly on the transmission side. Reducing these losses by just 10 percent would be equivalent to adding seven new MW power plants operating 80 percent of the time.

Average loads are much lower than peak loads, but the system must be sized to accommodate peak loads along with adequate safety margins to allow for failure contingences. Over the course of a year, the transmission system carries only about 50 percent of its full load capacity, and that fraction is dropping. This trend will necessarily drive the cost of electricity upward because the full cost of the system must be borne by the average transmission.

Further, the growth in intermittent renewable sources of energy may shift baseload generation capacity to standby power, resulting in more capacity that is not fully utilized. Reducing transmission losses is important not just for the cost of the losses but also for increasing available transmission capacity. Several options could be considered:. Reducing flow of reactive power over the lines. In principle, a deficit or surplus of reactive power should be corrected at or near where it occurs—namely, generators, transmission lines, and loads or load areas.

Power flow through parallel paths. Currents flow through all parallel paths and are distributed according to their impedances, which, if not carefully selected, may cause losses or reduce transmission capacity. In general, losses can be decreased by appropriate adjustment of impedances—for example, through series capacitor compensation of some lines or phase-shifting transformers.

Evaluation of transformer losses. Most utilities evaluate load and no-load losses as part of their evaluation of procurement price. Nevertheless, for cash flow or other reasons there is a temptation to procure transformers on a first-cost basis. Appropriate regulations could ensure that they are purchased with appropriate loss evaluation. Rather, it means that each asset will be coordinated with all other assets to maximize the overall function.

For example, load-sharing would routinely adjust the loads of transformers or lighten the loads of transmission-line sections, thereby allowing for more efficient operation of the transmission system. This information may be gathered as a direct reading.

Automated analysis, such as comparing the wear to the threshold value, would enable the signaling of an exceeded threshold to the asset manager, who would then perform maintenance. Today, operators know the condition of equipment only when they perform scheduled maintenance or when a failure occurs.

In the operation of a modern grid, optimization can extend to the identification of untapped capacity, thus avoiding the start-up of more costly generation resources. Dynamic real-time data reveal when and where such unused generating capacity is available. The use of excess capacity also applies to transformers, transmission lines, and distribution lines. For example, deploying a costly distributed energy resource could be avoided if the operator knew that the distribution system was capable of carrying a greater load from the substation.

Decision makers can decide more economically where, what, and how to invest in future grid improvements. Whether from optimizing assets or operating efficiently, the real-time information from the modern grid sensors, coupled with communicating it widely and processing it effectively, will significantly enhance the system.

The Flexible Alternating Current Transmission System FACTS is a collection of mostly power-electronics-based devices that are applied, depending on the need, to control one or more AC transmission parameters—such as current, voltage, active power, and reactive power—in order to enhance power-transfer capability and stability. They will improve power quality and increase efficiency by enabling high-speed control of power systems, power-flow control over lines, control of voltages, and reactive-power management.

They will also be of value in the prevention of system collapse and restoration. FACTS technology helps meet many of the challenges outlined previously: enabling the connection of remote and asynchronous sources of power such as wind, solar, fuel cells, and microturbines; supporting wholesale power markets through power-flow control; stabilizing power swings; making the system more secure and self-healing; and optimizing the use of available assets.

The second application is injection of current in shunt, which enables control of the line voltage. The ones most used are the following:. Static volt-amperes reactive compensators SVCs , which together with variable shunt capacitors or inductors help to control shunt current and reactive power, are used primarily for controlling the line voltage and stabilizing the power system.

Thyristor-controlled series capacitors TCSCs , which control the magnitude of current flow through the line, are used primarily for controlling the current and stabilizing the power system. Static shunt compensators STATCOMs , which are voltage-sourced converters connected in shunt with a line for controlled injection of lagging or leading reactive current and hence for controlling reactive power , are used primarily for controlling the voltage and stabilizing the power system.

Variable frequency transformers VFTs are used primarily to control active and reactive power flow through a line as well as to adjust frequency drift. Custom power is very much like FACTS, but it is designed for lower voltages and for use in the distribution system. Custom-power devices, inserted between the utility and the customer, can achieve significant improvement in power quality by.

These capabilities address the need for power quality in 21st-century applications. They would provide relief to many present users, such as banks, that have to employ expensive uninterruptible power supplies, along with standby generation, because any power interruption and voltage dip would be unacceptable. In other industries, annual losses because of power-quality issues amount to billions of dollars. Therefore many electricity consumers—in particular, companies with automated production—would appreciate low-cost solutions that provide substantial improvement in the number and duration of voltage dips and power outages.

Several custom-power devices are commercially available to control voltage or current. However, they are still too expensive for widespread use. DC lines have several advantages over AC lines that make them preferable under certain circumstances. While power on an AC line automatically follows the path of least resistance, DC current is controllable. Therefore, a DC line carrying power from a distant generating plant is considered to have the same reliability as a local plant, a significant advantage when an ISO is determining required reserve margins.

DC lines can be less expensive per mile than AC lines are, especially for underground transmission. DC lines require two cables, while AC requires three. A DC underground or submarine line can carry 2—3 times the power of a comparably sized AC line. Finally, heat dissipation in an underground DC cable is less of a problem because the lower voltage allows a solid insulator rather than one containing fluid, which raises concerns about possible leaks and damage to groundwater. Because the U.

Most HVDC projects to date have been based on current source converter technology, in which the DC current flows in the same direction and power reversal involves reversal of voltage. These converters, assembled with thyristors, 2 have been operated at.

A thyristor is a semiconductor power device that turns on with a gate pulse but has no gate turnoff. Recently, voltage source converter technology has become available in which the DC voltage has the same polarity and the power reversal involves reversal of current. This technology, which offers the advantages of low harmonic levels, a reactive power supply, and easier multiterminal HVDC in which more than two converters are connected to one line , is available at ratings of up to MW.

Storage would provide improved system stability and efficiency by enabling load-leveling, system regulation, instantaneous reserve power, and the dispatch of reactive power to the system. Pumped hydroelectric power, currently the only proven means of large-scale energy storage, is unlikely to be expanded greatly because few sites are both economically and environmentally acceptable. Other near-term candidates are compressed-air energy storage CAES and, for lower power levels, battery storage.

Longer-term candidates include ultracapacitor storage, flywheel storage, and superconducting energy storage.

Key Facts about the Electric Power Industry.

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Actual and planned transmission investment by shareholder owned utilities Deferred income tax expense. While FERC has primary jurisdiction over shareholder-owned electriccompanies, the agency has only very limited jurisdiction over federalandstate-owned utilities and electric cooperatives. Net cash used in provided by financing activities. None of the interest rate swaps contain credit-risk-related contingent features. The Fortis Majority Voting Policy does not apply to a contested election of directors, that is, where the number of nominees exceeds the number of directors to be elected.
Forex pairs volatility Worksource jacksonville florida/reinvestment assets. It should be noted that in order to achieve the full benefits of synergies on the transmission side, equipment throughout the system would need to be deployed in an integrated way. About 15, transmission substations will require new sensors, measurement systems, and LANs. Reasons for the Recommendation. Electric ity prices—unlike the prices for most o the r common consumergoods—did not keep pace with the rate of inflation for many years, despitean ever-increasing national appetite for electricity.
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FOREX INCOME TAXABLE

Significant demands will be placed on Fortis as a result of the Acquisition. As a result of the Acquisition, significant demands have been and will continue to be placed on the managerial, operational and financial personnel and systems of Fortis and ITC. Fortis and ITC cannot provide assurance that their systems, procedures and controls will be adequate to support the expansion of operations following and resulting from the Acquisition.

The future operating results of Fortis and the combined company will be affected by the ability of its officers and key employees to manage changing business conditions and to implement and improve its operational and financial controls and reporting systems. Fortis has limited experience in the independent transmission industry and may not be successful in retaining the services of executives and other employees that it needs to realize all of the anticipated benefits of the Acquisition.

While Fortis indirectly owns and operates transmission assets other than those of ITC, those assets are limited and do not constitute a material portion of the consolidated rate base of Fortis. However, Fortis will compete with other potential employers for employees and may not be successful in retaining the services of executives and other employees that it needs to realize all of the anticipated benefits of the Acquisition.

The unaudited pro forma condensed consolidated financial information is presented for illustrative purposes only and may not be indicative of the results of operations or financial condition of Fortis following the Acquisition. In addition, the pro forma combined financial information included in this Business Acquisition Report is based in part on certain assumptions regarding the Acquisition.

Initial decisions have been issued by the presiding administrative law judge in both base rate complaints. This initial decision is a non-binding recommendation to FERC on the second base rate complaint and is subject to review by FERC, which may adopt, modify, or reject the initial decision. In addition, parties to the base rate complaint proceedings may file requests for rehearing of a FERC order within 30 days of the date of the order and may file a petition for review of a FERC order with the applicable U.

Court of Appeals. As such, the ultimate outcome of the base rate complaints cannot be predicted at this time. If any such FERC challenges are initiated and are successful, the resulting lower rate base would negatively impact the revenues and net income of ITC. Fortis may not have discovered undisclosed liabilities of ITC. In the course of the due diligence review of ITC that Fortis conducted in connection with the Acquisition, Fortis may not have discovered, or may have been unable to quantify, undisclosed liabilities of ITC and its subsidiaries and Fortis will not be indemnified for any of these liabilities.

If ITC has undisclosed liabilities, Fortis as a successor owner may be responsible for such undisclosed liabilities. Fortis and ITC may be targets of additional securities class action and derivative lawsuits which could result in substantial costs. Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered into merger agreements.

Even if the lawsuits are without merit, defending against these claims can result in substantial costs and divert management time and resources. Following announcement of the agreement to complete the Acquisition, four putative class actions were filed by purported shareholders of ITC on behalf of a purported class of ITC shareholders in Oakland County Circuit Court, State of Michigan.

Paolo Guerra v. Albert Ernst, et al. Joseph L. Welch, et al. The amended complaint did not name FortisUS Inc. The amended complaint asserts the same general allegations and seeks the same types of relief as in the original complaint, but also purports to assert claims derivatively on behalf of ITC. The defendants intend to oppose any application for fees submitted by the plaintiffs. See attached. Mark One. Commission File Number: State or Other Jurisdiction of Incorporation or.

Employer Identification No. Novi, MI Yes x No o. Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. Check one :. Large accelerated filer x. Accelerated filer o.

Non-accelerated filer o. Smaller reporting company o. Do not check if a smaller reporting. Yes o No x. Financial Information. Item 1. Financial Statements. Condensed Consolidated Statements of Operations Unaudited. Item 2. Item 3. Item 4. Controls and Procedures. Other Information. Legal Proceedings. Item 1A. Risk Factors. Item 5A. Item 6. Unless otherwise noted or the context requires, all references in this report to:.

Other definitions. ITEM 1. Current assets. Cash and cash equivalents. Accounts receivable. Regulatory assets. Prepaid and other current assets. Total current assets. Other assets. Total other assets. Current liabilities. Accounts payable. Accrued compensation. Accrued interest. Accrued taxes. Regulatory liabilities. Refundable deposits from generators for transmission network upgrades.

Debt maturing within one year. Total current liabilities. Accrued pension and postretirement liabilities. Deferred income taxes. Long-term debt. Commitments and contingent liabilities Notes 4 and Retained earnings. Accumulated other comprehensive loss income. See notes to condensed consolidated financial statements unaudited. Operation and maintenance. General and administrative. Depreciation and amortization.

Taxes other than income taxes. Total operating expenses. Allowance for equity funds used during construction. Other income. Other expense. Total other expenses income. Basic earnings per common share. Diluted earnings per common share.

Dividends declared per common share. Derivative instruments, net of tax Note 7. Available-for-sale securities, net of tax Note 7. Net income. Adjustments to reconcile net income to net cash provided by operating activities:.

Depreciation and amortization expense. Deferred income tax expense. Changes in assets and liabilities, exclusive of changes shown separately:. Other current liabilities. Estimated refund related to return on equity complaints. Other non-current assets and liabilities, net. Net cash provided by operating activities. Expenditures for property, plant and equipment. Net cash used in investing activities.

Issuance of long-term debt. Borrowings under revolving credit agreements. Net issuance of commercial paper, net of discount. Retirement of long-term debt. Repayments of revolving credit agreements. Repayment of term loan credit agreements. Issuance of common stock. Dividends on common and restricted stock. Repayment of refundable deposits from generators for transmission network upgrades. Repurchase and retirement of common stock. Forward contracts of accelerated share repurchase program.

Net cash used in provided by financing activities. Accordingly, they do not include all of the information and notes required by GAAP for complete financial statements. These accounting principles require us to use estimates and assumptions that impact the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities.

Actual results may differ from our estimates. The condensed consolidated financial statements are unaudited, but in our opinion include all adjustments consisting of normal recurring adjustments necessary for a fair statement of the results for the interim period. The interim financial results are not necessarily indicative of results that may be expected for any other interim period or the fiscal year. Supplementary Cash Flows Information. Supplementary cash flows information:.

Interest paid net of interest capitalized. Income taxes paid a. Supplementary non-cash investing and financing activities:. Additions to property, plant and equipment and other long-lived assets b. Fortis continues to have its shares listed on the Toronto Stock Exchange. Under the Merger Agreement, outstanding options to acquire common stock of ITC Holdings vested immediately prior to closing and were converted into the right to receive the difference between the Merger consideration and the exercise price of each option in cash, restricted stock vested immediately prior to closing and was converted into the right to receive the Merger consideration in cash and performance shares vested immediately prior to closing at the higher of target or actual performance through the effective time of the Merger and were converted into the right to receive the Merger consideration in cash.

The external and internal costs related to the Merger will not be included as components of revenue requirement at our Regulated Operating Subsidiaries as they were incurred by ITC Holdings. See Note 11 for legal matters associated with the Merger with Fortis. Recently Adopted Pronouncements. This new standard requires debt issuance costs to be shown as a direct deduction from the carrying amount of the related debt, consistent with debt discounts. Deferred financing fees net of accumulated amortization.

We have accounted for this adoption as a change in accounting principle that is required due to a change in the authoritative accounting guidance. In connection with implementing this guidance, we adopted an accounting policy to present unamortized debt issuance costs associated with revolving credit agreements, commercial paper and other similar arrangements as an asset that is amortized over the life of the particular arrangement.

In addition, we present debt issuance costs incurred prior to the associated debt funding as an asset for all other debt arrangements. This standard did not impact our consolidated statements of operations or cash flows. Recently Issued Pronouncements. We have considered all new accounting pronouncements issued by the FASB and concluded the following accounting guidance, which has not yet been adopted by us, may have a material impact on our consolidated financial statements. Revenue Recognition.

The guidance will supersede the current revenue recognition guidance and require entities to evaluate their revenue recognition arrangements using a five-step model to determine when a customer obtains control of a transferred good or service. We do not expect the guidance to have a material impact on our consolidated results of operations, cash flows or financial position.

However, we are still evaluating the disclosure requirements, the impacts of the recent clarifying amendments that have been issued by the FASB and the transition method we will elect to adopt the guidance. Classification and Measurement of Financial Instruments. The guidance requires entities to carry most investments in equity securities at fair value and recognize changes in fair value in net income, unless the investment results in consolidation or equity method accounting.

Additionally, the new guidance amends certain disclosure requirements associated with the fair value of financial instruments. Early adoption is permitted. The guidance is required to be adopted using a modified retrospective approach, with limited exceptions. We are currently assessing the impacts this guidance will have on our consolidated financial statements, including our disclosures.

Accounting for Leases. The new guidance creates a dual approach for lessee accounting, with lease classification determined in accordance with principles in existing lease guidance. Income statement presentation differs depending on the lease classification; however, both types of leases result in lessees recognizing a right-of-use asset and a lease liability, with limited exceptions. Under existing accounting guidance, operating leases are not recorded on the balance sheet of lessees.

The various amendments require different transition methods including modified retrospective approach through a cumulative effect. Assuming we adopt the guidance in the fourth quarter of , we expect to record an adjustment to beginning retained earnings for excess tax benefits generated in years prior to adoption that were previously unrecognized.

In addition, we expect to record an income tax benefit related to stock-based compensation that vested during The guidance should be applied retrospectively but may be applied prospectively if retrospective application would be impracticable. We are currently assessing the impacts this guidance will have on our classification of activity in our statement of cash flows. Regional Cost Allocation Refund. The timing for collection from our network customers of the amount refunded to the other RTOs has not yet been determined, but is expected to occur no later than ITC Interconnection.

The revenues earned by ITC Interconnection are based on its facilities reimbursement agreement with the merchant generating company. The financial results of ITC Interconnection are currently not material to our consolidated financial statements. In this order, the FERC suggested the MISO funding policy be revised to require mutual agreement between the interconnection customer and transmission owner to utilize the election to fund network upgrades.

We do not expect the resolution of this proceeding to have a material impact on our consolidated results of operations, cash flows or financial condition. The formula rate templates, prior to any proposed modifications, include certain deferred income taxes on contributions in aid of construction in rate base that resulted in the joint applicants recovering excess amounts from customers. Challenges Regarding Bonus Depreciation.

These condensed consolidated financial statements reflect the election of bonus depreciation for tax years and and the corresponding effects on revenue requirements for our Regulated Operating Subsidiaries. We are unable to predict the final outcome of this matter; however, the election of bonus depreciation will result in higher cash flows in the year of the election and reduce our rate base and therefore decrease our revenues and net income over the tax lives of the eligible assets.

Rate of Return on Equity Complaints. The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually, using formula rate templates, and remain in effect for a one-year period. By completing their formula rate templates on an annual basis, our Regulated Operating Subsidiaries are able to make adjustments to reflect changing operational data and financial performance, including the amount of network load on their transmission systems for our MISO Regulated Operating Subsidiaries , operating expenses and additions to property, plant and equipment when placed in service, among other items.

The formula rate templates do not require further action or FERC filings each year, although the template inputs remain subject to legal challenge at the FERC. Our Regulated Operating Subsidiaries will continue to use formula rate templates to calculate their respective annual revenue requirements unless the FERC determines any template to be unjust and unreasonable or another mechanism is determined by the FERC to be just and reasonable. Our formula rate templates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue requirements.

Revenue is recognized for services provided during each reporting period based on actual revenue requirements calculated using the formula rate templates. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The amount of accrued or deferred revenues is reflected in future revenue requirements and thus flows through to customer bills within two years under the provisions of the formula rate templates.

Net refund of revenue deferrals and accruals, including accrued interest. Non-current assets. Non-current liabilities. Intangible Assets. We have recorded intangible assets as a result of the METC acquisition in Derivative Instruments and Hedging Activities. We may use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates.

The use of these financial instruments mitigates exposure to these risks and the variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative financial instruments for trading or speculative purposes.

The interest rate swaps listed below manage interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the expected refinancing of the maturing ITC Holdings 6. The interest rate swaps have been determined to be highly effective at offsetting changes in the fair value of the forecasted interest cash flows associated with the expected debt issuance, resulting from changes in benchmark interest rates from the trade date of the interest rate swaps to the issuance date of the debt obligation.

This amount will be accumulated and amortized as a component of interest expense over the life of the forecasted debt. None of the interest rate swaps contain credit-risk-related contingent features. Refer to Note 10 for additional fair value information. A summary of the terminated interest rate swaps is provided below:. This amount is being amortized as a component of interest expense over the life of the related debt.

Some utilities were spending moneyon DSM as early as National data are not available for expenditures from Electric companies now are pursuing a variety of innovative business andregulatory approaches that will encourage the use of state-of- the -artefficiency technologies and services. They also are pursing actions to seizea wide range of opportunities to improve energy efficiency.

These areimproving the efficiency of buildings and appliances, accelerating the development of advanced metering infrastructure, supporting innovativerates and regulation, advancing more efficient distribution transformers,and encouraging the development of plug-in hybrid electric vehicles. Section Three:The Regulation Of Shareholder-Owned Electric CompaniesAlthough the electric power industry is a diverse onewith thousands of suppliers, not all of the m areregulated in the same way.

Some suppliers, such as shareholder-ownedelectric companies, are highly regulated at the federal and state levels; o the rs, such as electric cooperativesand government-owned utilities, are not subjectto the same regulatory requirements. The promotion of wholesale electric competition by the Federal Energy Regulatory Commission and the introductionof retail choice in some states, beginning in the lates, changed the regulatory landscape for utilities.

Theenactment of the Energy Policy Act of EPAct in August , meanwhile, mandated important regulatorychanges to enhance reliability, promote investmentand fuel diversity, modernize outdated federal electricitylaws, and enhance consumer protections. The FPA regulates interstate wholesale power transactionsand the transmission of electric power. The Federal Energy Regulatory Commission FERC Today, FERC regulates interstate transmission and wholesale powertransactions, which involve shareholder-owned electric companies buyingor selling electricity from one ano the r or from o the r power suppliersfor resale to the ultimate customer.

FERC has the authority to regulate the prices, terms, and conditions of the se wholesale power sales and transmissionservices. While FERC has primary jurisdiction over shareholder-owned electriccompanies, the agency has only very limited jurisdiction over federalandstate-owned utilities and electric cooperatives. In , FERC issued Order , opening the electric transmission linesowned by shareholder-owned companies to all suppliers.

Virtuallythousands of suppliers are now competing for use of the se lines in the wholesale electricity market. EPAct allows FERC to extend a similarversion of the se requirements to the largest electric cooperatives andgovernment-owned utilities. After FERC opened access to transmission lines in the wholesale market,electric companies began joining toge the r to form Regional TransmissionOrganizations RTOs , which provide independently operated transmissionservice under consistent terms and conditions.

While all electric companies use similar methods to generate electricity,each operates differently to meet the unique needs of its service area. Asdiscussed, where you live determines how your rates are set. Regardlessof whe the r your state has adopted electric choice or not, electricity costsnationwide are affected by variables such as fuel prices and availability,usage patterns, infrastructure investment costs, and regulatory policy.

The cost of fuel used to generate electricity has a direct bearing on the price an electric company charges for service. That cost not onlydepends on the type of fuel used, but also on the distance between the source of fuel and the power plant, and related transportation costs.

Environmental considerations in many locations require the burningof fossil fuels of low sulfur content to meet strict air quality restrictionsregarding power plant emissions. Such fuels tend to be more expensivethan those with higher sulfur content. Federal or state public policies mayeven preclude the use of certain fuel sources altoge the r. State tax rates are ano the r major variable that affects retail electricityrates.

For example, some states impose a power generation tax. This taxis based on kilowatt-hours sold and is passed through to customers in the form of higher rates. The revenue from the se taxes is used to addresslocal needs. Differences in customer electricity usage patterns have an effect on the price per kilowatt-hour. Most electricity is used during daytime hourswhen businesses are operating and residential customers are active.

During the night, when businesses are closed and residential customersare asleep, the rate of consumption is much lower. Electric companiesschedule the operation of the ir generating units to meet the se changingpatterns of use, with more expensive units operating only at times ofhigh demand.

Electric companies typically cannot recover the ircosts when the y are incurred; instead, the y are requiredby regulatory authorities to spread out the ir costs to customersover the physical life of the investment—sometimesas long as 30 years—under the assumption that the re will be a stable customer base.

Today, electric companies are facing steadily increasingcosts to generate and deliver electricity to Americanhomes, businesses, and industries. While electric companiesmake continuous efficiency improvements and areworking closely with regulators to contain costs andto keep electricity prices as low as possible, risingelectricity costs are becoming inevitable throughout the United States. And yet, electricity remains one of the truebargains among crucial U. Electric ity prices—unlike the prices for most o the r common consumergoods—did not keep pace with the rate of inflation for many years, despitean ever-increasing national appetite for electricity.

In fact, from to , electricity prices rose, on average, by 1. Theprice of one kilowatt-hour of electricity in nominal dollars has increasedby just 27 percent since , while the prices of most o the r consumer goodshave risen at much higher levels. This evidence points to an industry that hasbecome more efficient itself—both in management and in technology.

Demand For Electric ity Is Growing. While efficiency improvements have had a major impact in meetingnational electricity needs relative to new supply, the demand for electricitycontinues to increase. According to the U. Overall, electricity consumption is expected to increase by at least40 percent by Americanhomes use 21 percent more electricity today than the y did in Goingforward, electricity use will continue to grow as house sizes increase andconsumers use more electric appliances and devices.

As shown on page 36, averageannual expenditures on electricity fell from 2. To meet the increasing demand for electricity and to ensure fuel diversityand reliability, electric companies must invest in new baseload powerplants. Electric companies work with the ir customers on ways that consumerscan reduce the ir electricity use and control the ir bills with energyefficiencyprograms.

Between and , electric company demandsidemanagement DSM programs saved almost billion kWh ofelectricity. That is enough to power almost 74 million average U. Section Four Infrastructure Investment Costs Are Growing. More investment is needed to ensure that we have arobust infrastructure network to maintain reliability.

In order to build the system to better meet current and future demand, toalleviate congestion, and to reinforce system reliability, electric companieshave earmarked billions of additional dollars for investment in the comingdecade. While the transmission system delivers high-voltage electricity fromgenerators to substations, the distribution system reduces the voltageand the n delivers the electricity to retail customers.

In addition to substations, the distribution system includes wires, poles, metering, billing, andrelated support systems involved in the retail side of electricity delivery. Data represent bothvertically integrated andstand-alone transmissioncompanies.

The need to expand our distribution infrastructure and install new distributionequipment to meet population and demand growth will requirecontinued investment. In addition, companies face ongoing non-recoverablecosts associated with supporting o the r facilities attached to utilitydistribution infrastructure, such as telephone and cable wires. Over the next decade, distribution investment islikely to exceed capital spending on generation capacity as well. All electric companies are subject to hundreds of environmental rules,including dozens of federal and state air and water quality requirementscreated with the Clean Air Act and Clean Water Act.

In fact, electric companiesspend billions of dollars each year to help ensure protection of the air, land, and water. As a result, air quality in the United States has improved dramatically inrecent years. In fact, since , electric companies have reduced emissionsof nitrogen oxides and sulfur dioxide by 44 percent and 40 percent,respectively, while electricity demand grew by 77 percent.

The costs associated with continuous environmental improvements aresignificant. For example, according to the U. As discussed in Section Three, a major shift in the electric utility landscapebegan in the mids, as a number of states, especially those in the Nor the ast, Mid-Atlantic region, and the Midwest, along with California,moved to restructure portions of the retail electricity industry. Section Five:The Financial Side OfThe Electric Power Industry From a financial perspective, the shareholder-ownedsector of the electric power industry is vastly differentfrom o the r sectors.

It relies more heavily on the privatesector for investment capital needed to finance itsoperations than o the r sectors, such as electric cooperativesand government-owned utilities. Traditionally,millions of Americans have relied on the modest, steadygrowth of utility stocks to supplement the ir retirementincome.

Millions of Americans own utility shares ei the r directly or indirectlythrough mutual funds, life insurance policies, pension funds, andemployer K programs. Many individual shareholders fall in the middle-incomebrackets and often rely, at least in part, on the dividends the yreceive to meet the ir living expenses.

The typical utility shareholder ismore than 65 years old and has owned utility stocks for more than 10years. The electric power industry continues to pay out a higher percentage ofearnings than any o the r U. Investors in electric companies greatly benefited from the Jobs andGrowth Tax Reconciliation Act of , which temporarily reduced to15 percent the top individual tax rate on dividends.

As a result, morecompanies are offering dividends—and dividends are larger. Millions ofAmericans—including millions of senior citizens—are receiving moredividend income. In the electric utility sector, for example, a significantlyhigher percentage of companies increased the ir dividends each year from to By , 41 companies—or 64 percent of the industry—raised the ir dividend payments, the highest percent since , when 65percent of the industry increased the ir dividend payments.

These investments will help ensure a reliablesupply of electricity to consumers and continued environmental improvementsin the future. The 15 percent tax rate is currently extended through; however, efforts are underway to fur the r extend—or make permanent— the reduced tax rate.

Governments have traditionally relied on shareholder-owned electriccompanies as a source of tax revenue. These electric companies pay federaland state income taxes and o the r local taxes, such as property taxes. Most electric cooperatives are exempt from federal and state incometaxes, but do pay o the r types of state and local taxes. Local governmentownedutilities also are not subject to most federal, state, and local taxesbut some make payments in lieu of taxes.

Federally owned utilitiesgenerally are exempt from federal, state, and local taxes. Section Five Since customer revenues are insufficient to finance all plants, facilities,and equipment needed to provide electric service from current cash flow,electric companies raise additional money by issuing stock and sellingdebt securities. This financing, called capitalization, takes three forms:long-term debt, common stock, and a very small amount of preferredstock less than one percent.

Electric companies attempt to implement anappropriate balance of debt bonds and equity stock that matches the risk profile of the ir investors. Although long-term debt remains an important source of financing,companies have reduced the ir reliance on this type of financing in recentyears. More debt can mean more risk, as companies must repay the debtobligations on a specific schedule called debt servicing.

The debt-to-capitalization debt-to-cap ratio is a common measure used byelectric companies, credit rating agencies, and o the r financial entities thatrepresents the percentage of overall capitalization being derived from longtermdebt.

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These forexticket convertisseur monnaie google will help facilitate the continued transition from coal utilities and unregulated energy operations. Favorable regulatory frameworks and a credibility by faring the least badly during market downturns, but of being approved. Similarly, New Mexico regulators recently valuations if customer rate changes. The regulatory framework insulates earnings kV lines to reinforce the driven strong earnings growth and earnings and cash flow volatility. In ERCOT, there are roughly GW of proposed renewable energy 1 percentage point below its wind, 76 GW of solar, growth in the years following Falling Interest Rates a Double-Edge as of April, highlighting the continued appetite for renewable energy in the state. Furthermore, much of the current these investments, given the heightened. In a separate decision, regulators Southern Reliability Link project in Connect causes us to discount the program for our projections. It has derisked its portfolio, has been on new system sales volume, resulting in less the initial stages of its. However, recent elections provide hope framework to continue. About two-thirds of the investment be lumpy as regulatory delays, earnings, but those are more rates at reasonable valuations compared state progresses on its decarbonization.

Actual expenditures from EEI's Annual Property & Plant Capital Investment Survey the transmission investment plans of investor-owned utilities comprised of. Investment of investor-owned electric companies and stand-alone transmission companies. Actual. Investment figures were obtained from the EEI. Property. Actual and Planned Transmission Investment by Investor-Owned Utilities · The These transmission investments help to save customers money over the long term by and Planning for the Energy Grid of the Future With Electric Transmission.