corresp

International Power plc
Senator House
85 Queen Victoria Street
London EC4V 4DP
United Kingdom

Mr William Choi, Accounting Branch Chief
United States Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549
United States of America

27 November 2006

International Power plc — Form 20-F for the Year Ended 31 December 2005
Filed 30 June 2006
File No. 1-13644

Dear Mr Choi

In response to your letter dated 28 September 2006, we have set out in the attached pages our responses to the matters you have raised, together with additional background and explanations to those responses where appropriate. To assist your review of our responses, we have included the text of the Staff’s comments prior to each of our responses and we have keyed our responses to the item numbers used in the comment letter we received. We have discussed the contents of both your letter and our responses with our legal advisers, Clifford Chance LLP, and our auditors, KPMG Audit Plc.

As questions 1 and 2 are related, we have combined our responses to both questions under the respective headings “Revenue” and “Profitability”. As our response to question 3 is related to the response to question 5 we present the answer to question 5 following our response to questions 1 and 2.

In responding to your comments, International Power plc acknowledges that:

	•		International Power plc is responsible for the adequacy and accuracy of the disclosure in its filings;

	•		Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

	•		International Power plc may not assert Staff comments as a defence in any proceedings initiated by the Commission or any person under the federal securities laws of the United States of America.


	Yours sincerely
	/s/ MD Williamson
	MD Williamson
	Chief Financial Officer

Attachment

1.		For each of your geographic segments, you describe the major components that caused the revenue variance but it is unclear to what extent each component affected such variance between years. Please provide a discussion that describes the extent to which each variance is attributable to changes in price and changes in volumes being sold. Quantification of the changes should be precise, including disclosure of the quantity of energy sold and the average sale price. Future disclosures should be expanded to include the impact of the weather. Please also quantify revenue from capacity contracts separately.

2.		We note that your discussion of changes in operating expenses addresses the major components of variances but you do not quantify the amount of each component. While we expect that the selling price of power generally tracks with changes in your fuel costs, we assume that your spark spreads vary between periods. Therefore, please discuss the nature and quantify the amount of spark spreads, if material, and the specific factors driving those changes in future filings.

Revenue

IFRS requires us to provide segmental revenue and segmental result for each reportable segment. As a consequence, in our Operating and Financial Review and Prospects (“OFR”) we provided a summary overview of the major causes of changes in revenue in each of our geographical segments in order to reflect the nature of the segmental disclosures in our financial statements.

We do not believe it would be necessary to provide a more detailed discussion and analysis on revenue in total or by segment because our management does not use revenue as a performance measure within the company’s internal reporting and budgeting processes. This is because management does not consider revenue as a planning or decision—making performance indicator within the business. As a consequence, revenue does not feature as one of the key performance indicators of our business which we have set out in the Business and Financial Review section of our UK annual report.

Various factors have an impact on revenue. These factors include instances where the price of oil and gas have a direct impact on the price of electricity; the efficiency of our plants, which determines their place in the merit order and the prices at which it is economic for them to bid into the market to sell electricity; the extent to which we have contracted in advance or sell at spot prices when price spikes occur; as well as factors such as the weather.

Some of these factors impact profitability while others do not. In our view, details of changes in revenue only become useful to the reader when they indicate changes in profitability in the business. Thus we consider factors that affect our profitability to be more useful to investors than factors that affect only our revenue.

For the reasons discussed above we believe that our annual report for the year ended 31 December 2005 was responsive to the requirements of Form 20-F as filed, however in future filings we will provide a brief summary of the major events that affect total revenue when they have a direct impact on profitability rather than to provide detailed explanations solely on revenue by segment. We discuss below the additional disclosures relating to Group and segment results, which our management consider more meaningful measures of performance.

Profitability

As requested, in future filings we will provide more quantification of the major components of profitability.

Our management reporting systems generate information which focuses on profit from operations on a regional basis in order for our Executive Management Team to monitor performance of our business and segments. This corresponds with the segmental results we disclose in our financial statements.

We will include in future filings our explanations of changes in profitability. Such explanations will focus on the absolute amounts of the variances between years rather than actual recorded results. The explanation and quantification of each variance within a geographical segment will sum to the total variance between years in each segment.

It should be noted that our management does not separately evaluate results derived from merchant markets and results derived from capacity contracts. However, where material we will quantify changes in profitability of capacity contracts where there are either significant changes arising from acquisitions in the region or changes in contractual terms have a significant impact on profitability. We will include discussion in the OFR analysis of changes in profitability in a qualitative manner which will assist the reader in understanding the profitability of each region.

Whilst in general terms weather does have an impact on the results of our business, we believe the impact of weather cannot be separately quantified, and therefore if provided in our OFR it would not be reliable. For example, although demand in the US often rises in summer due to increased domestic and commercial air conditioning usage, profitability is related to overall supply during the period. Quantifying the impact of weather would involve estimating the impacts on spark spreads, and such estimates would not be reliable. On this basis we will add qualitative information in relation to the weather when our management believe the weather has had an impact on profitability between periods but it will not be possible for us to quantify this impact.

In summary, in future filings we propose to focus on the profitability of our regions and the factors causing changes in profitability between periods. We will discuss and quantify where there are specific factors driving those changes, including spark spreads and load factors. We will explain the major causes of changes in revenue but our explanations of changes in revenue will be limited to those items which have a direct impact on profitability in the region.

We attach in the appendix an example of our proposed revised disclosures for the North American region as this region has a mix of merchant and contracted assets.

Please tell us the basis under IFRS for your presentation of the “excluding exceptional items” column in your consolidated income statement. All of the items in this column appear to be non-GAAP measures which, unless required or expressly permitted under IFRS, would be prohibited by Item 10(e) of Regulation S-K.

We consider that the items to which you refer are GAAP measures presented in accordance with IFRS and thus are not prohibited by Item 10(e) of Regulation S-K.

IFRS sets no maximum as to the information that may be presented on the face of the income statement, though certain minimum line items are required (IAS 1.81). IAS 1 states principles for the classification and presentation of amounts in the income statement, requiring preparers to apply judgement in the application of those requirements. In particular, expenses must be analysed by nature or function either on the face of the income statement or in the notes (IAS 1.88).

IFRS requires the nature and amount of items of income and expense that are material either to be presented on the face of the income statement or disclosed in the notes (IAS 1.86). In addition, IFRS requires additional line items, headings and subtotals to be presented on the face of the income statement when such presentation is relevant to an understanding of the entity’s financial performance (IAS 1.83). IFRS states (IAS 1.84) that because the effects of an entity’s various activities, transactions and other events differ in frequency, potential for loss or gain and predictability, disclosing the components of financial performance assists in an understanding of the financial performance achieved and in making projections of future results.

In order to comply with the above IFRS requirements, we believe it is necessary to disaggregate each income statement line item (e.g. cost of sales) into the individually material amounts that need to be disclosed separately by virtue of their size or incidence in order for the reader to obtain a proper understanding of the financial information (as discussed in note 1(ab) to the financial statements) and the component of each line item that does not comprise such individually material amounts, whilst ensuring that the total amount by nature or function is also disclosed. In particular, we believe disclosure of the individual components of each line item is necessary in order to meet the requirements of IAS 1.83 and 1.84. There are several ways in which these requirements may be met. We have complied with these requirements of IFRS through the use of separate headings and subtotals as specifically mandated by IAS 1.83.

We further note that these measures would not be prohibited in accordance with guidance contained in Answer 28 of the Staff’s “Frequently Asked Questions Regarding the Use of Non-GAAP Financial Measures”, which states:

“Some non-US GAAP standard setters specify a minimum level of caption detail for financial statement presentation, but require or permit additional caption detail. In some cases, the standard setter does not specify the particular additional captions to be presented. The Staff believes that additional detail of the components of the financial statements determined in conformity with the GAAP used in the primary financial statements will generally be useful to US investors. The “expressly permitted” condition is not intended to prohibit the inclusion of those captions.”

Finally, we note that the three-column analysis of our income statement between exceptional items, excluding exceptional items and total amounts is consistent with our previous

presentation under UK GAAP. This presentation was not previously prohibited under Item 10(e) (see section 8 of the AICPA International Practices Task Force Highlights of 25 November 2003) and, based on the analysis above, we do not believe that it is prohibited in our current circumstances, notwithstanding our transition to IFRS. We would also note that we have continued to provide those disclosures indicated in the above Highlights that we consider to be helpful to readers, as follows:

•		a description of the nature of exceptional items and why management considers them to be exceptional (see pages 27, 36 and F-73 of our 2005 Form 20-F);

•		within the financial statements, the disclosures required by Item10(e)(1)(i)(C) and (D) of Regulation S-K as to why management believes the presentation of these measures provides useful information to investors (see pages F-4, F-18, F-73 and F-90 of our 2005 Form 20-F);

•		a reformatted condensed income statement that complies with Article 10 of Regulation S-X (see page F-90 of our 2005 Form 20-F);

•		within the Operating and Financial Review, the disclosures required by Item 10 (e)(1)(A)-(D), namely:

	•	a presentation with equal prominence of total and pre-exceptional amounts and a reconciliation between such amounts (see pages 29 to 31 of our 2005 Form 20-F);

	•	a description of the nature of exceptional items and why management considers them to be exceptional (see page 36 of our 2005 Form 20-F); and

	•	why management believes the presentation of these measures provides useful information to investors (see pages 27, 29 and 36 of our 2005 Form 20-F).

3.	We note that you have presented various non-GAAP measures which exclude “exceptional items” throughout your operating and financial review discussion. Please revise your disclosure to include a presentation, with equal or greater prominence, of the mostly directly comparable financial measure or measures calculated and presented in accordance with IFRS wherever your non-GAAP measures are presented. In this regard, we would expect reconciliation to the measures presented under “effective tax rate and interest coverage ratio (pre exceptional items)” and “net interest” on page 38 of your document. This comment similarly applies to your presentation of “free cash flow” and “net debt” presented in your discussion under Liquidity on page 39 of your document.

As referred to in Question 5, we do not believe the “excluding exceptional items” column in the consolidated income statement is a non-GAAP measure.

As outlined in our response to question 5, we do not believe the pre-exceptional measures of profit included in the reconciliation presented below “effective tax rate and interest coverage ratio”, and within the narrative on “net interest” are non-GAAP measures.

In the movement in Group net debt presented on page 39 of our Form 20-F, we reconciled from “profit for the year” to “free cash flow” rather than from “profit from operating activities” to “free cash flow”. A reconciliation from “cash flows from operating activities” to “free cash flow” can be deduced from the cash flow statement presented in the financial statements presented on page F-7.

However, in the OFR of future filings, we intend to show how “profit for the year” reconciles to “net cash flow from operating activities” (as shown on page F-7) within a revised format “movement in Group net debt”. We attach an example of our re-presented “movement in Group net debt” in the appendix.

We do not believe that net debt is a non-GAAP measure as it is an aggregation of GAAP measures (individual GAAP balance sheet values) as set out in note 34 to our financial statements (page F-56 of our annual report) and it is not presented as an alternative measure of financial position, performance or liquidity. IFRS (paragraph 50 of IAS 7) explicitly encourages us to disclose additional information relevant to users in understanding the financial position and liquidity of our business. The net debt grid on page F-56 is our additional disclosure in this respect, made in our IFRS financial statements, presented on a basis which continues a disclosure previously presented to users of the financial statements and which both our management and our investors find useful because it is information that aids in assessing our gearing and debt capitalisation.

An analysis of our net debt is presented on page 40 of our Form 20-F. This shows the aggregation of GAAP items included within net debt, and reconciles cash and cash equivalents to net debt.

We note that your certifying officers disclose their conclusions as to the effectiveness of your disclosure controls and procedures “within 90 days prior to the filing date of this report”. However, Item 307 of Regulation S-K requires that your certifying officers disclose their conclusions regarding the effectiveness of your disclosure controls and procedures “as of the end of the period covered by the report”. Please revise future filings accordingly.

We will revise future filings to disclose the conclusions as to the effectiveness of disclosure controls and procedures as of the end of the period covered by the annual report on Form 20-F.

Please further describe for us the circumstances leading up to your cancellation of the put option related to the 3.75% convertible notes due 2023. In this regard, please tell us what, if any, consideration was given up to the holders of the notes for the put cancellation. We note that under US GAAP, you continue to treat the conversion option as a derivative liability. Please cite the appropriate US GAAP literature that you relied upon for your classification prior to and after the cancellation of the option.

The cancellation was not of the holders’ put option, but of our option to cash settle any conversion option exercised by the bondholders, and no consideration was paid to or received from holders of the notes for this cancellation. The cancellation had no impact on the estimated fair value of the conversion option. We extinguished our cash settlement conversion option because it had the benefit of allowing us to treat the conversion feature as equity under IFRS, with no negative economic impact as a result. On page F-45 we outline that the impact of our waiver of our cash settlement option on 17 January 2005 enabled the transfer of the carrying value of the embedded derivative to equity. We believe that the note on page F-45 adequately explains the transaction in accordance with the requirements of IFRS.

Under US GAAP, the removal of the cash settlement option did not remove the requirement of continuing to recognise an embedded derivative. We came to this conclusion under US GAAP

based on the guidance set out in Statement 133, Implementation Issue No. C8, which states that a forward contract that is indexed to both an entity’s own stock and currency exchange rates does not qualify for the exception in paragraph 11(a) of Statement 133.

We are aware that the topic has been considered by the EITF, but as there is currently no explicit authoritative guidance as to foreign currency convertible debt we have applied the principles outlined in Implementation Issue No. C8. We would reconsider our US GAAP treatment of the embedded derivative identified in the US GAAP numbers if and when any new US GAAP is promulgated.

In future filings please include a reconciliation of the numerators and denominators used in calculating basic and diluted earnings per share to the extent there is a difference between US GAAP and IFRS. In this regard, we note that the numerator used in the diluted per share computation for US GAAP appears to differ from the numerator of the diluted per share computation under IFRS.

We will include in future filings a reconciliation of the numerators and denominators used in calculating basic and diluted earnings per share to the extent that there is a difference between US GAAP and IFRS.

Please tell us your accounting treatment for payments on or receipts from interest rate swap agreements designated as cash flow hedges where interest expense attributable to the underlying debt has been capitalised. Please detail for us the capitalisation policy associated with the payments or receipts on such interest rate swaps and the period(s) in which such payments or receipts impact earnings. Refer to EITF 99-9.

The amounts presented in the net income reconciliation take into account the differences between US GAAP and IFRS relating to the treatment of the recycling of amounts accumulated in equity from equity to the income statement. Under IFRS, as outlined on page F-14, we make basis adjustments to the carrying value of the non-financial assets. Under US GAAP we do not make basis adjustments to the asset but we reclassify into earnings amounts accumulated in equity when the hedged transaction asset affects earnings in accordance with EITF 99-9 and FAS 133, paragraph 31. These amounts are therefore reclassified into earnings in proportion to the depreciation of the capitalised interest in the carrying value of the constructed asset.

This GAAP difference has no impact on net income for the periods presented and has an immaterial impact on equity attributable to equity holders of the parent between GAAPs. The effect of this GAAP adjustment is included within the total derivatives balance recorded in the equity reconciliation. Because the size of the income statement adjustment is nil for all periods and the post tax and minority interest share of the balance sheet adjustment was only £14 million, which is just over half a per cent of the US GAAP total equity attributable to equity holders of the parent, we considered the amount not significant enough to require separate discussion. On that basis we decided not to make specific reference to the adjustment in note (g) describing the significant differences between IFRS and US GAAP.

In future filings, if the amounts became material, we would add additional narrative explanation of the differences for cash settlement under swaps relating to non-financial assets.

APPENDIX

Question 2

North America

For the year ended 31 December 2005 profit from operations amounted to £49 million compared to a loss from operations of £21 million for the year ended 31 December 2004.

Our North American business region consists of plants in Texas, Massachusetts and Georgia in the USA and a plant in Puerto Rico. The majority of our North American plants namely Midlothian and Hays in Texas and Blackstone, Bellingham and a portion of the capacity at Milford in New England, sell their output in the wholesale market at prevailing rates, where we conduct energy trading activities. Trading activities are principally focused on selling the physical output of and purchasing fuel for our plants. However, we also perform limited proprietary trading that is subject to clear risk limits. All of these plants are subsidiaries and are consolidated in the Group financial statements.

The North American portfolio also includes plants that sell capacity and energy under long-term contracts. These contracted plants include Milford, where 56% of output is subject to a long-term contract, and our joint ventures Hartwell and Oyster Creek. In addition, output from our joint venture, EcoEléctrica, in Puerto Rico is contracted under a long-term PPA until 2021.

An improvement in market conditions in Texas and New England helped Midlothian, Hays, Blackstone and Bellingham generate an additional £40 million profit from operations in 2005 as compared with 2004.

Our Texas assets generated £47 million of this improvement, reflecting the contribution of Hays, following its de-mothballing in the Spring of 2005, which was offset by a reduction in profitability of £7 million from our New England assets.

Pricing levels in the Texas power market recovered during 2005 from the low levels in 2003 and 2004. Market prices improved driven by the demand for peak power (up 3% to 60,300 MW), a warmer summer and a reduction in surplus generation following the retirements and mothballing of inefficient plant in 2004 and 2005. The current reserve margin in Texas is 24%. In Texas, gas fired generation typically sets the marginal price for power which means that the relatively high efficiency of our gas fired plants provides an economic advantage when gas prices are high.

In 2005, Midlothian and Hays in Texas, sold 10,228 GWh of electricity (2004: 3,611 GWh only at Midlothian) at an average gross margin of $12/MWh (2004: $6/MWh only at Midlothian). However, the average gross margin per MWh in 2004 did not take into account of the unplanned summer outages at Midlothian and this implied an average spark spread for Midlothian in 2004 of $8/MWh, increasing to $12/MWh in 2005.

In New England, the underlying reserve margin is now estimated at 20%. In this market, oil fired generation has a greater role in determining the market price of power, especially where domestic demand for gas in winter drives up the price relative to fuel oil. The relatively high efficiency of our gas fired plants therefore does not enjoy the same benefits of a high gas price environment as in Texas. Overall, spark spreads achieved during 2005 showed a slower rate of recovery relative to Texas.

We manage Blackstone and Bellingham in New England on a portfolio basis. In 2005, these plants sold in total 3,323 GWh of electricity (2004: 2,304 GWh) at an average gross margin of $6/MWh (2004: $12/MWh). The decline in average spark spread for Blackstone and Bellingham in the New England market (a decline from $12/MWh in 2004 to $6/MWh in 2005) resulted in a reduction of £7 million profit from operations between years. The first quarter of 2004 benefited from some very high, short duration, price spikes which lifted the full year spreads that year to $12/MWh. Excluding this, the underlying spreads for 2005 were ahead of 2004.

In January 2006 the New England system operator reported progress on the establishment of a capacity payment mechanism (a Forward Procurement Market instead of the previously proposed LICAP system). The details of the proposed capacity market are expected to be disclosed in Q4 2006. This is a positive development for the New England market and is designed to ensure improved security of supply and encourage the provision of reliable generation, particularly at times of peak demand.

Our contracted assets, EcoEléctrica, Hartwell and Oyster Creek, all of which are joint ventures, added £20 million to profit from operations in 2005 principally because EcoEléctrica provided its first full year of contribution, following its acquisition in December 2004 as part of the EME international portfolio.

The contribution received from our partly contracted asset, Milford, was £1 million less in 2005 as compared with 2004 due to higher fuel prices.

Net operating costs consist of operating income and operating costs, such as depreciation, payroll and property taxes. This income and costs have contributed an improvement of £11 million in profit from operations in 2005 compared to 2004, principally due to one time severance payments incurred in 2004, and in 2005 gains arising from the disposal of unused NOx credits and finalisation of insurance claims relating to a forced outage.

Question 3

Re-presented movement in Group net debt


	Year ended			Year ended
	31 December			31 December
	2005			2004
	£m			£m
Profit for the year		330			104
Adjustment for non-cash items		180			91
Dividend received from joint ventures and associates		92			69
Capital expenditure — maintenance		(72	)		(59	)
Other cash movements		3			—
Movements in working capital		(21	)		3
Tax and interest paid		(227	)		(104	)

Free cash flow		285			104
Exceptional finance costs		(5	)		(26	)
Refinancing costs capitalised on acquisition debt		(7	)		(22	)
Exceptional receipt from TXU administrators		58			—

Net cash inflow from operating activities		331			56
Capital expenditure for growth projects		(188	)		(158	)
Returns from investments/capital expenditure — other financial investments		48			(61	)
Acquisitions		(571	)		(1,195	)
Disposals		211			17
Dividends paid		(37	)		—
Proceeds from share/rights issue		2			286
Funding from minorities		80			165
Foreign exchange and other		(181	)		62

Increase in net debt		(305	)		(828	)
Opening net debt		(2,745	)		(692	)
Transitional adjustment on first-time adoption of IAS 39		44			—
Net cash/(debt) on acquisition of subsidiaries		27			(1,225	)

Closing net debt		(2,979	)		(2,745	)


Net cash inflow from operating activities		331			56
Net cash used in investing activities		(473	)		(1,242	)
Net cash from financing activities		179			1,065

Net increase/(decrease) in cash and cash equivalents		37			(121	)