Safe Harbor Statement Under The Private Securities Litigation Reform Act of 1995 Our reports, filings and other public announcements contain certain statements that describe our management's beliefs concerning future business conditions, plans and prospects, growth opportunities and the outlook for our business and the electric transmission industry based upon information currently available. Such statements are "forward-looking" statements within the meaning of the Private Securities Litigation Reform Act of 1995. Wherever possible, we have identified these forward-looking statements by words such as "will," "may," "anticipates," "believes," "intends," "estimates," "expects," "projects" and similar phrases. These forward-looking statements are based upon assumptions our management believes are reasonable. Such forward-looking statements are subject to risks and uncertainties which could cause our actual results, performance and achievements to differ materially from those expressed in, or implied by, these statements, including, among others, the risks and uncertainties listed in "Item 1A Risk Factors."
Because our forward-looking statements are based on estimates and assumptions that are subject to significant business, economic and competitive uncertainties, many of which are beyond our control or are subject to change, actual results could be materially different and any or all of our forward-looking statements may turn out to be wrong. Forward-looking statements speak only as of the date made and can be affected by assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in our discussion in this report will be important in determining future results. Consequently, we cannot assure you that our expectations or forecasts expressed in such forward-looking statements will be achieved. Except as required by law, we undertake no obligation to publicly update any of our forward-looking or other statements, whether as a result of new information, future events, or otherwise.
Overview
Through our Regulated Operating Subsidiaries, we operate high-voltage systems in Michigan's Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems. Our business strategy is to operate, maintain and

invest in transmission infrastructure in order to enhance system integrity and reliability, to reduce transmission constraints and to upgrade the transmission networks to support new generating resources interconnecting to our transmission systems. We also are pursuing development projects not within our existing systems, which are also intended to improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets. As electric transmission utilities with rates regulated by the FERC, our Regulated Operating Subsidiaries earn revenues through tariff rates charged for the use of their electric transmission systems by our customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC. The rates charged by our Regulated Operating Subsidiaries are established using cost-based formula rate templates, as discussed in "Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations - Cost-Based Formula Rates with True-Up Mechanism." Our Regulated Operating Subsidiaries' primary operating responsibilities include maintaining, improving and expanding their transmission systems to meet their customers' ongoing needs, scheduling outages on system elements to allow for maintenance and construction, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded.
We derive nearly all of our revenues from providing electric transmission service over our Regulated Operating Subsidiaries' transmission systems to investor-owned utilities such as Detroit Edison, Consumers Energy and IP&L, and to other entities such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers and from transaction-based capacity reservations on our transmission systems. Significant recent matters that influenced our financial position and results of operations and cash flows for the year ended December 31, 2012 or may affect future results include:
• Our capital investment of $819.8 million at our Regulated Operating Subsidiaries ($231.2 million, $149.0 million, $343.3 million and $96.3 million at ITCTransmission, METC, ITC Midwest and ITC Great Plains, respectively) for the year ended December 31, 2012, resulting primarily from our focus on improving system reliability, increasing system capacity and upgrading the transmission network to support new generating resources;

• Debt issuances and borrowings under our revolving and term loan credit agreements in 2012 and 2011 to fund capital investment at our Regulated Operating Subsidiaries, resulting in higher interest expense;

• Debt maturing within one year and the resulting additional financing required as discussed in Note 8 to the consolidated financial statements;

• Final recognition of revenues for the ITCTransmission rate freeze revenue deferral in May 2011, as discussed in "Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations - Cost-Based Formula Rates with True-Up Mechanism - ITCTransmission's Rate Freeze Revenue Deferral";

• The Entergy Transaction in which Entergy will divest and merge its electric transmission business with a wholly-owned subsidiary of ITC Holdings as discussed in "Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Project Updates and Other Recent Developments." In 2012, we expensed external legal, advisory and financial services fees of $19.4 million and internal labor costs of approximately $7.1 million related to the Entergy Transaction primarily recorded within general and administrative expenses. Certain amounts of the external costs are not expected to be deductible for income tax purposes. The external and internal costs related to the Entergy Transaction are not included as components of revenue requirement as they were incurred at ITC Holdings. The transaction fees are expected to continue to be significant until the transaction is consummated. Completion of the transaction is anticipated to occur in 2013; and

• Recognition of the refund obligation at our MISO Regulated Operating Subsidiaries for the FERC audit of ITC Midwest, as discussed in Note 16 to the consolidated financial statements under "Commitments and Contingent Liabilities - FERC Audit of ITC Midwest."

These items are discussed in more detail throughout Management's Discussion and Analysis of Financial Condition and Results of Operations.

Cost-Based Formula Rates with True-Up Mechanism Our Regulated Operating Subsidiaries calculate their revenue requirements using cost-based formula rate templates and are effective without the need to file rate cases with the FERC, although the rates are subject to legal challenge at the FERC. Under these formula rate templates, our Regulated Operating Subsidiaries recover expenses and earn a return on and recover investments in property, plant and equipment on a current rather than a lagging basis. The formula rate templates utilize forecasted expenses, property, plant and equipment, point-to-point revenues, network load at our MISO Regulated Operating Subsidiaries and other items for the upcoming calendar year to establish projected revenue requirements for each of our Regulated Operating Subsidiaries that are used as the basis for billing for service on their systems from January 1 to December 31 of that year. Our cost-based 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. The over- or under-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly peak loads at our MISO Regulated Operating Subsidiaries. In the event billed revenues in a given year are more or less than actual revenue requirements, which are calculated primarily using information from that year's FERC Form No. 1, our Regulated Operating Subsidiaries will refund or collect additional revenues, with interest, within a two-year period such that customers pay only the amounts that correspond to actual revenue requirements for that given period. This annual true-up ensures that our Regulated Operating Subsidiaries recover their allowed costs and earn their allowed returns. ITCTransmission's Rate Freeze Revenue Deferral ITCTransmission's rate freeze revenue deferral resulted from the difference between the revenue ITCTransmission would have collected under its cost based formula rate and the actual revenue ITCTransmission received for the period from February 28, 2003 through December 31, 2004. The rate freeze revenue deferral was amortized for ratemaking on a straight-line basis for five years from June 2006 through May 2011 and was included in ITCTransmission's revenue requirement for those periods. Revenues of $5.0 million relating to the rate freeze revenue deferral were recognized in January through May 2011, which resulted in a reduction to after-tax net income of approximately $3.2 million in 2012 compared to 2011.
Revenue Accruals - Effects of Monthly Peak Loads For our MISO Regulated Operating Subsidiaries, monthly peak loads are used for billing network revenues, which currently is the largest component of our operating revenues. One of the primary factors that impacts the revenue accrual/deferral at our MISO Regulated Operating Subsidiaries is actual monthly peak loads experienced as compared to those forecasted in establishing the annual network transmission rate. Under their formula rates that contain a true-up mechanism, our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. For example, to the extent that amounts billed are less than the revenue requirement for a reporting period, a revenue accrual is recorded for the difference. To the extent that amounts billed are more than the revenue requirement for a reporting period, a revenue deferral is recorded for the difference. Although monthly peak loads do not impact operating revenues recognized, network load affects the timing of our cash flows from transmission service. The monthly peak load of our MISO Regulated Operating Subsidiaries is affected by many variables, but is generally impacted by weather and economic conditions and is seasonally shaped with higher load in the summer months when cooling demand is higher.

The following table sets forth the monthly peak loads during the last three calendar years.

                         Monthly Peak Load (in MW) (a)
                         2012                                 2011                                 2010
                                       ITC                                  ITC                                  ITC
          ITCTransmission    METC    Midwest   ITCTransmission    METC    Midwest   ITCTransmission    METC    Midwest
January        7,264        6,145     2,789         7,326        6,045     2,777         7,255        5,947     2,838
February       6,919        5,754     2,592         7,261        6,058     2,854         6,998        5,800     2,782
March          6,941        5,708     2,443         6,946        5,715     2,520         6,620        5,376     2,517
April          6,403        5,259     2,296         6,483        5,416     2,458         6,501        5,112     2,425
May            8,947        6,459     2,700        10,119        7,239     2,773         9,412        7,240     3,052
June          11,652        8,738     3,388        11,488        8,231     3,403         9,722        7,128     3,207
July          12,222        9,358     3,643        12,321        9,389     3,621        11,451        8,498     3,422
August        11,087        8,520     3,477        11,158        8,538     3,614        11,082        8,422     3,399
September      9,094        7,308     3,411        11,288        7,966     3,466        10,817        7,353     2,804
October        6,626        5,428     2,487         6,642        5,479     2,559         6,725        5,414     2,447
November       7,024        5,953     2,680         7,101        6,061     2,556         6,930        5,734     2,674
December       7,226        5,891     2,682         7,206        6,071     2,734         7,824        6,526     2,928
Total         101,405       80,521   34,588        105,339       82,208   35,335        101,337       78,550   34,495


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The following table presents the network transmission rates (per kW/month) for our MISO Regulated Operating Subsidiaries as posted by MISO that are relevant to our cash flows since January 1, 2010:

Network Transmission Rate            ITCTransmission    METC     ITC Midwest
January 1, 2010 to December 31, 2010     $2.818         $2.370     $6.882
January 1, 2011 to December 31, 2011     $2.495         $2.331     $6.694
January 1, 2012 to December 31, 2012     $2.188         $2.409     $6.797
January 1, 2013 to December 31, 2013     $2.147        $2.5263     $7.805

ITC Great Plains does not receive revenue based on a peak load each month and therefore does not have a seasonal effect on operating cash flows. The SPP tariff applicable to ITC Great Plains is billed ratably each month based on its annual projected revenue requirement posted annually by SPP. Revenue Requirement Calculation
Under their cost-based formula rate templates, each of our Regulated Operating Subsidiaries separately calculates a revenue requirement based on financial information specific to each company. The calculation of actual revenue requirements for a historic period is used to calculate the amount of network revenues recognized in that period and to calculate the true-up adjustment for that period. The calculation of projected revenue requirements is used to establish the transmission rate used for billing purposes, and follows the same methodology as the calculation of actual revenue requirement. The following steps illustrate the calculation of revenue requirement and the rate-setting methodology under the formula rate template with a true-up mechanism used by our MISO Regulated Operating Subsidiaries. ITC Great Plains follows a similar methodology and uses a FERC-approved return of 12.16% on the common equity portion of its capital structure.
Step One - Establish Projected Rate Base and Calculate Projected Allowed Return Rate base is projected using the average of the projected month-end balances for the months beginning with December 31 of the current year and ending with December 31 of the upcoming year and consists primarily of projected in-service property, plant and equipment, net of accumulated depreciation, as well as other items.

Projected rate base is multiplied by the projected weighted average cost of capital to determine the projected allowed return on rate base. The weighted average cost of capital is calculated using a projected 13-month average capital structure, the forecasted pre-tax cost of the debt portion of the capital structure and a FERC-approved return of 13.88%, 13.38%, and 12.38% for ITCTransmission, METC, and, ITC Midwest, respectively, on the common equity portion of the capital structure.
Step Two - Calculate Projected Gross Revenue Requirement The projected gross revenue requirement is calculated beginning with the projected allowed return on rate base, as calculated in Step One above, and adding projected recoverable operating expenses and an allowance for income taxes, depreciation and amortization.
Step Three - Calculate Projected Revenue Requirement After calculating the projected gross revenue requirement in Step Two above, the 2013 projected gross revenue requirement is adjusted for any 2011 true-up adjustment and is reduced for certain revenues received other than network revenues, such as projected point-to-point, regional cost sharing revenues and rental revenues to arrive at our projected revenue requirement. Illustration of Formula Rate Setting
Set forth below is a simplified illustration of the calculation of ITCTransmission's projected revenue requirement as well as its component of the joint zone network transmission rate for billing purposes under its formula rate setting mechanism for the period from January 1, 2013 through December 31, 2013, that was based primarily upon projections of ITCTransmission's 2013 FERC Form No. 1 data. Amounts below are approximations of the amounts used to establish ITCTransmission's 2013 projected revenue requirement.

Line                     Item                        Instructions         Amount
 1   Projected rate base                                             $ 1,162,323,000
 2   Multiply by projected 13-month weighted
     average cost of capital (a)                                               10.25 %
 3   Projected allowed return on rate base        (Line 1 x Line 2)  $   119,138,108
 4   Projected recoverable operating expenses for
     2013                                                            $    60,585,000
 5   Projected taxes and depreciation and
     amortization for 2013                                           $   141,022,000
 6   Projected gross revenue requirements for     (Line 3 + Line 4 +
     2013                                         Line 5)            $   320,745,108
 7   Less projected revenue credits for 2013                         $   (74,481,000 )
 8   Plus/(less) 2011 true-up adjustment                             $   (25,537,000 )
 9   Projected revenue requirement for 2013       (Line 6 + Line 7 +
                                                  Line 8)            $   220,727,108
 10  Projected average monthly 2013 network load
     (in kW)                                                               8,567,000
 11  Annual component of the joint zone network   (Line 9 divided by
     transmission rate                            Line 10)           $        25.765
 12  Monthly component of the joint zone network  (Line 11 divided
     transmission rate ($/kW per month)           by
                                                  12 months)         $         2.147


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                                                     Weighted
          Percentage of                               Average
        ITCTransmission's                             Cost of
       Total Capitalization     Cost of Capital       Capital
Debt          40.00%             4.80% (Pre-tax) =      1.92 %
Equity        60.00%          13.88% (After tax) =      8.33 %
             100.00%                                   10.25 %

Capital Investment and Operating Results Trends We expect a general trend of increases in revenues and earnings for our Regulated Operating Subsidiaries over the long term. The primary factor that is expected to continue to increase our actual revenue requirements in future years is our anticipated capital investment in excess of depreciation as a result of our Regulated Operating Subsidiaries' long-term capital investment programs to improve reliability, increase system capacity and upgrade the transmission network to support new generating resources, as well as the Entergy Transaction. In addition,

our capital investment efforts relating to development initiatives are based on establishing an ongoing pipeline of projects that will position us for long-term growth. Investments in property, plant and equipment, when placed in service upon completion of a capital project, are added to the rate base of our Regulated Operating Subsidiaries.
Our Regulated Operating Subsidiaries strive for high reliability of their systems and to improve system accessibility for all generation resources. Effective June 2007, the FERC approved mandatory adoption of certain reliability standards and approved enforcement actions for violators, including fines of up to $1.0 million per day. The NERC was assigned the responsibility of developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by the NERC, as well as the standards of applicable regional entities under the NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. We believe we meet the applicable standards in all material respects, although further investment in our transmission systems and an increase in maintenance activities will likely be needed to maintain compliance, improve reliability and address any new standards that may be promulgated.
We also assess our transmission systems against our own planning criteria that are filed annually with the FERC. Based on our planning studies, we see needs to make capital investments to (1) rebuild existing property, plant and equipment;
(2) upgrade the system to address demographic changes that have impacted transmission load and the changing role that transmission plays in meeting the needs of the wholesale market, including accommodating the siting of new generation or to increase import capacity to meet changes in peak electrical demand; (3) relieve congestion in the transmission systems; and (4) achieve state and federal policy goals, such as renewable generation portfolio standards. The following table shows our expected and actual capital investment for each of the Regulated Operating Subsidiaries and our development initiatives:

                                                             Actual Capital          Forecasted Capital
                                  Long-term Capital        Investment for the        Investment for the
                                 Investment Program            Year Ended                Year Ending
    Source of Investment            2012-2016 (a)         December 31, 2012 (b)     December 31, 2013 (a)
(In millions)
ITCTransmission                 $               739     $                 231.2                $200 - 230
METC                                            581                       149.0                 160 - 180
ITC Midwest                                   1,128                       343.3                 270 - 300
ITC Great Plains (c)                            343                        96.3                 130 - 150
Development (d)                               1,390                           -                         -
Total                           $             4,181     $                 819.8                $760 - 860


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(b) Capital investment amounts differ from cash expenditures for property, plant and equipment included in our consolidated statements of cash flows due in part to differences in construction costs incurred compared to cash paid during that period, as well as payments for major equipment inventory that are included in cash expenditures but not included in capital investment until transferred to construction work in progress, among other factors.

(c) ITC Great Plains' investment program includes the Kansas V-Plan Project that is under construction in addition to the KETA and Hugo-to-Valliant projects which were completed and placed in-service in 2012.

(d) The long-term capital investment program includes expenditures to construct various development projects such as our portions of the four MISO MVPs.

Investments in property, plant and equipment could vary due to, among other things, the impact of actual loads, forecasted loads, regional economic conditions, weather conditions, union strikes, labor shortages, material and equipment prices and availability, our ability to obtain financing for such expenditures, if necessary, limitations on the amount of construction that can be undertaken on our systems at any one time, regulatory approvals for reasons relating to rate construct, environmental, siting, regional planning, cost recovery or other issues or as a result of legal proceedings and variances between estimated and actual costs of construction contracts awarded. In addition, investments in transmission network upgrades for generator interconnection projects could change from prior estimates significantly due to changes in the MISO queue for generation projects, the generator's potential failure

to meet the various criteria of Attachment FF of the MISO tariff for the project to qualify as a refundable network upgrade, and other factors beyond our control.
Capital Project Updates and Other Recent Developments Thumb Loop Project
The Thumb Loop Project is located in ITCTransmission's region and consists of a 140-mile, double-circuit 345 kV transmission line and related substations that will serve as the backbone of the transmission system needed to accommodate future wind development projects in the Michigan counties of Tuscola, Huron, Sanilac and St. Clair. Construction activities commenced for the Thumb Loop Project in 2012. Through December 31, 2012, ITCTransmission has invested $173.5 million in the Thumb Loop Project. We estimate ITCTransmission will invest a total of approximately $510 million to complete construction of the project. ITC Great Plains
KETA Project
The KETA Project is a 225-mile transmission line that runs between Spearville, Kansas and Axtell, Nebraska. The portion of the transmission line that ITC Great Plains was responsible for constructing runs approximately 174 miles. The KETA Project was placed in-service in 2012.
Kansas V-Plan Project
The Kansas V-Plan Project is a 200-mile transmission line that will run between . . .