CLP Group 2013 Interim Results

12 August 2013

Disclaimer

This presentation contains some comments about future events including our expectations about the performance of CLP Group's business. The comments are not audited and are based on a number of factors that we cannot control. We cannot be certain that the comments will be accurate or complete and so they should not be relied on. As circumstances change we will update our website at www.clpgroup.com and, where relevant, notify the Hong Kong Stock Exchange. This presentation is not an offer of securities for sale in the United States. Securities may not be offered or sold in the United States absent registration or an exemption from registration. Any public offering of securities in the United States must be made by means of a prospectus that contains detailed information about the issuer and its management, as well as financial statements

1

HK$M 1H2013 1H2012 Change Hong Kong / Hong Kong related 3,766 3,566 5.6% Overseas 347 715 51.5% Others, net (217) (384) Operating earnings 3,896 3,897 Non-recurring items (129) (541) Total earnings 3,767 3,356 12.2%

Operating earnings per share (HK$)

1.54

1.62

4.9%

Total earnings per share (HK$) 1.49 1.39 7.2% Dividends per share (HK$)

First interim dividend 0.53 0.53 Second interim dividend 0.53 0.53

Total interim dividends 1.06 1.06

Financial Performance

2

Earnings Details 1H2012 1H2013 HK$M

715

3,566 3,766

347

Hong Kong SoC 3,417 3,240

Nuclear power business 294 268

PSDC and sales to Guangdong from HK 55 58

Australia (45) 268

China 541 393

India (212) (19)

Southeast Asia and Taiwan 63 73

Other earnings 24 (64)

Unallocated net finance costs (15) (39)

Unallocated Group expenses (226) (281)

Operating earnings 3,896 3,897

Non-recurring items for Australia (42) (541)

Non-recurring item for China (87) -

Total earnings 3,767 3,356 12.2%

Financial Performance

Good performance from Hong Kong and China but reduced earnings from Australia and India

Hong Kong: Higher earnings reflecting ongoing investment in electricity infrastructure

Australia: Significantly lower earnings in challenging market conditions

China: Growth in earnings primarily due to lower coal price

India: Operating earnings affected by coal supply situation in Jhajjar

3

Hong Kong

SoC earnings growth of 5.5% to HK$3,417m − Higher earnings due to increased average net fixed assets

Capex of HK$3,017m, in line with Development Plan − CLP Power: HK$2,272m − CAPCO: HK$745m (CLP’s share: HK$298m)

Local sales decreased by 1.5% to 14,806 GWh primarily due to weather − Sales to China decreased by 38.1% to 620 GWh constrained by lower

contractual demand − Overall electricity sales decreased by 3.8%

Construction of the Hong Kong Branch Line is complete and gas from the Second West-East Pipeline commenced flowing

4

Hong Kong – Going Forward

2014-2018 Development Plan submitted to HKSAR Government Ongoing investment to support new infrastructure and

development Continue to develop new natural gas sources contemplated in

2008 inter-government MOU − Additional pipeline gas from South China Sea and new LNG terminal in

Shenzhen to be developed to meet future needs

Constructive engagement with HKSAR Government on SoC Interim Review

Continuing interconnection of Hong Kong and South China energy infrastructure

5

Australia – Financials

6

Conditions in Australia remain challenging − Declining energy demand − Suppressed wholesale prices − Intense retail competition and churn − Regulatory uncertainty

Internally EnergyAustralia (EA) has also experienced operational challenges and financial pressures including − Issues with new C1 billing system resulting in higher

operating costs − Yallourn industrial action − Falling forward prices resulting in unfavorable fair

value movements − Higher D&A from customer acquisition costs and the

new C1 billing system − Higher net interest expense due to the close-out of

interest rate swaps (HK$138m) after completion of the Waterloo transaction

In May, EA completed majority selldown of Waterloo wind farm realising proceeds of A$228m

In July, EA agreed to purchase Mt Piper and Wallerawang power stations which underpinned the 2011 GenTrader agreements from the NSW Government for a net cash consideration of A$160m

Financials (HK$m) 1H2013 1H2012

Gross margin – Electricity 5,200 5,634

Gross margin – Gas 918 844

Operating expenses and others (3,757) (3,597)

Renewables 49 63

EBITDAF 2,410 2,944

Fair value movement (115) (606)

EBITDA 2,295 2,338

Depreciation & amortisation (1,393) (1,086)

Net interest expenses (874) (821)

Tax expense (73) (163)

Operating earnings before one-off items (45) 268

Yallourn mine remediation (42) (644)

Tax consolidation effect - 103

Net Profit After Tax (NPAT) (87) (273)

Note: Individual items and totals are rounded to the nearest appropriate number . Some totals may not add down the page due to rounding of individual components

Customer accounts increased despite high churn environment − Customer accounts (Mass Market (MM) & Commercial & Industrial (C&I)): 2.848 million up 56k over 6 months

Retail segment sales volumes 11% lower for electricity and 4% higher for gas − MM electricity volumes down 5% reflecting lower per customer usage compared to prior year − C&I electricity sales down 14% mainly due to weakening economic conditions and intense competition − Gas volumes up 4% with higher C&I volumes partially offset by lower MM sales

Higher operating expenses predominantly relating to the new C1 billing system, including − Higher bad debt provisioning (A$11m) − Higher employee and contractor costs (call centre, billing stabilisation) (A$27m) − Higher administrative, marketing and other costs (A$11m)

Higher Depreciation & Amortisation due to amortisation of capitalised customer acquisition costs and initial depreciation of the new C1 billing system

EnergyAustralia – Retail Segment

7

Financials (A$m) 1H2013 1H2012 Variance

Gross margin 399 435 (36)

Operating expenses and others (260) (208) (52)

EBITDAF 139 227 (88)

Depreciation & Amortisation (64) (22) (42)

EBITF 76 206 (130)

Note: Individual items and totals are rounded to the nearest appropriate number . Some totals may not add down the page due to rounding of individual components

Results materially impacted by depressed wholesale price offset by carbon tax assistance − Lower wholesale electricity contract prices, lower sales volumes, higher costs associated with green instruments and

higher fuel costs placed pressure on margins − Carbon tax transitional assistance to partially compensate for the diminution of value at Yallourn and the carbon tax

impact on earnings provided a net benefit in 1H2013 largely offsetting the margin decline

− Contribution from gas sales increased due to higher margins on contracts and gas storage revenues

Generation volumes decreased by 6% − Yallourn output constrained due to ongoing industrial action − Remediation of Morwell River Diversion continued − Wallerawang constrained due to the collapse of a cooling tower − Partially offset by higher output from Mt Piper and other assets

EnergyAustralia – Wholesale Segment

8

Financials (A$m) 1H2013 1H2012 Variance

Gross margin 395 385 10

Operating expenses and others (172) (165) (7)

EBITDAF 222 219 3

Depreciation & Amortisation (106) (108) 2

EBITF 116 111 5

The outlook for the Australian energy sector is challenging Retail competition remains intense with high levels of churn Continuing cost pressures in 2013 from implementation issues with C1 and in 2014 from

the EnergyAustralia Integration Program Continuing soft demand combined with the RET requirement for new build renewable

generation has constrained wholesale prices. This may result in the closure or impairment of costly or inflexible power plants across the industry

In this environment removing the relatively costly and restrictive Gentrader arrangements and gaining full and flexible operational control of the Mt Piper and Wallerawang power stations will support the future profitability of these assets

The key projects for the 2H2013 to meet these challenges include − Stabilising the new customer management and billing system, and delivery of initiatives to

improve customer service levels and cost effectiveness − Finalising implementation of retail and corporate efficiency programmes, including up to 100

positions being made redundant across 2013 − Preparation for integration of the NSW customer base and removal of the TSA − Optimising and ensuring cost effectiveness across our generation operations − Integration of Mt Piper and Wallerawang Power Stations into EnergyAustralia operating portfolio

9

EnergyAustralia

Chinese Mainland – Financials Higher earnings from coal-fired projects

primarily due to lower coal price − Average decrease in coal price of about 14% − Partly offset by lower dispatch

Higher earnings from renewables projects − Wind: Lower earnings due to no accrual of

provincial subsidy for projects in Shandong (pending policy announcement), partially offset by higher generation due to better wind resources

− Jiangbian Hydro: Higher earnings due to the increase in water flow during the second quarter of 2013

− Other Hydro: Higher earnings from Huaiji Hydro due to higher tariff from tariff adjustment in July 2012 and higher generation in 1H2013

Reversal of HK$25m unrealised translation loss upon remittance of a USD-deposit back to Hong Kong

Recognition of HK$87m loss for Boxing Biomass project for the full impairment and divestment cost

10

HK$m 1H2013 1H2012

Coal-fired projects 431 368

Renewables projects 123 68 - Wind 74 97

- Jiangbian Hydro 20 (31)

- Other Hydro and Biomass 29 2

Operating expenditure (30) (31)

Earnings from operations 524 405

Development expenditure (14) (10) RMB appreciation gain / fair value of RMB forward contracts 6 (2)

Reversal of unrealised translation loss 25 -

Operating earnings 541 393

Loss for Boxing Biomass (87) -

Total earnings 454 393

Chinese Mainland – Coal-fired projects

Higher earnings from coal-fired projects due to lower fuel costs partially offset by lower dispatch

Lower earnings from Fangchenggang mainly due to lower dispatch resulting from soft demand and outages in 1H2013, partially offset by ~19% reduction in coal price

Earnings from Guohua affected by lower dispatch, partially offset by ~9% reduction in coal price

Higher earnings from Shandong due to ~15% decrease in coal price

11

HK$m 1H2013 1H2012 Fangchenggang 198 228

Guohua & Shenmu 112 114

Shandong 121 26

Total 431 368

Chinese Mainland – Nuclear

Daya Bay has maintained high safety record and has continued to implement additional safety measures in accordance to the regulatory schedule and as required in the National Comprehensive Nuclear Safety Review

Acquisition for the 17% shareholding of Yangjiang project to supply Guangdong awaiting regulatory approval from the PRC authorities

Continue to work with China General Nuclear Power Corporation (CGNPC) to explore feasibility of additional nuclear import to Hong Kong, subject to Hong Kong Government’s decision on future fuel mix for electricity generation

NDRC’s establishment of benchmark tariff setting mechanism will promote the development of the nuclear industry

12

Chinese Mainland – Going Forward

Development of the 1,320MW ultra-supercritical units of Phase II of Fangchenggang using imported coal − In-principle approval from NDRC obtained in July 2012 and final

approval expected in 2H2013

Complete acquisition for 17% stake investment in Yangjiang nuclear project to supply Guangdong

Explore feasibility of additional nuclear import for Hong Kong, subject to Hong Kong Government’s decision on fuel mix

Continue to develop and build our renewable energy portfolio with focus on majority-owned wind and solar projects − 51% owned Jinchang solar project (100MW) commenced operation in July

2013

13

India – Financials

Paguthan continued to be constrained by lower dispatch due to high gas prices − Lower operating earnings mainly due to lower

recovery of income tax under PPA and higher dividend distribution tax provision due to higher tax rate effective 1 April 2013

Jhajjar operating loss resulted from low capacity charge revenue and disputed penalty provision under PPA due to low availability from coal shortage − Jhajjar net fair value movement and exchange

differences mainly included HK$120m translation loss on USD-loans as a result of devaluation of Indian Rupees and HK$35m translation loss on Euro and USD retention payables

Higher earnings from renewables primarily due to − Increase in operating projects (1H2013: 594MW vs.

1H2012: 482MW) − The HK$49m deferred tax related to reversal of

previously recognised net deferred tax liabilities

HK$m 1H2013 1H2012 Paguthan

Operating earnings 146 187

Unrealised exchange gain on translation of FX receivables under PPA 13 15

Dividend distribution tax provision (34) (27)

Total Paguthan earnings 125 175 Jhajjar

Operating loss (162) (120)

PPA disputed penalty provision (86) -

Net fair value movement on financial derivatives and exchange differences (160) (75)

Pre-operating loss - (27) Total Jhajjar earnings (408) (222) Renewables

Operating earnings (including development expense) 30 17

Deferred tax 49 14

Translation loss on unhedged USD loan (7) -

Pre-operating loss (1) (3)

Total Renewables earnings 71 28 Total earnings (212) (19)

14

Jhajjar − Operations continued to be impacted by coal shortages with plant availability

constrained at less than 40% in 1H2013 − Approval obtained from Haryana Chief Minister to procure 1.7 million tonnes

(equivalent to 35-40% of heat value required for full availability) of imported coal for the period from June 2013 to May 2014

− With the blending of imported coal, the plant operated at an availability of ~50% in June and ~85% in July

− Expect both units to generate consistently with a target availability at 75-80% for 2H2013

− Expect further improvement in the commercial performance over the next 6-18 months

Wind: Portfolio growth − Growth: Operational 594 MW (1H2012: 482 MW) and 457 MW under construction

Paguthan: Availability of adequate and reasonably priced gas supplies remains a major concern

Continue steady growth of wind projects in reforming states, with adequate grid infrastructure and creditworthy offtakers 15

India

Southeast Asia & Taiwan

16

Lower earnings from Ho-Ping mainly due to HK$62m provision for penalty imposed by the Taiwan Fair Trade Commission and lower generation due to planned overhaul in 1H2013, partially offset by lower coal costs

Higher earnings from Lopburi solar project with full six-month operation in 2013. Completed 8MW expansion in May 2013

Continue assessing development of Vietnam coal-fired projects

HK$m 1H2013 1H2012 Ho-Ping earnings 50 81 Lopburi Solar earnings 30 16

Operating expenditure (11) (17)

Development expenditure (6) (7) Total earnings 63 73

Outlook Steady performance from Hong Kong business

− Focus on operating efficiency, cost control and mitigation of tariff increases − Secure Government’s approval for the 2014-2018 Development Plan − Engage with the Government to complete the Interim Review of SoC Agreement

Australia – Focus on enhancing performance of existing business − Continue stabilisation activities associated with the new C1 billing system − Restructure across business functions to reduce operating costs − Optimise mix of generation sources and plans in response to low wholesale price conditions − Complete Mt Piper and Wallerawang acquisition

China – Continuation of niche strategy − Obtain final approval to commence construction of Fangchenggang II − Complete acquisition of 17% stake in Yangjiang nuclear project − Continue growth in renewables − Explore opportunities for further participation in nuclear including feasibility of additional import for

Hong Kong

India – Continue to stabilise fuel supply for existing thermal projects − Focus on implementation of imported coal arrangements for Jhajjar, and work with Coal India to

improve domestic coal quality and deliveries − Maintain measured growth of wind projects

17

Appendices

Financial Obligations at a Glance

Borrowings of CLPH and CLPP

HK$6,486m

HK$29,863m

CLP Group (consolidated with EnergyAustralia, India &

PRC subsidiaries) HK$66,198m

Borrowings of EnergyAustralia, India & PRC subsidiaries (non-recourse to CLPH)

Borrowings of CAPCO and PSDC assuming 100%

30 Jun 2013 31 Dec 2012

(a)

Net Debt*/Total Capital 24% 22% Interest Cover 11x 12x

Net Debt/Total Capital 39% 37% Interest Cover 4x 4x

Total Debt = (a)+(b)

(b)

HK$36,335m

HK$6,622m

HK$29,313m

HK$62,655m

HK$33,342m

Total Debt/Total Capital 42% 42%

A-1

Total Debt/Total Capital 28% 28%

* As of 30 June 2013, CLPH and CLPP had a cash balance of HK$5.3 billion (Dec 2012: HK$10 billion)

Credit Ratings

Long term Rating

Foreign Currency Outlook Local Currency Outlook

Short term Rating

Foreign Currency Local Currency

S&P Moody’s S&P Moody’s S&P

CLP Holdings CLP Power EnergyAustralia

A-2 A-2

P-1 P-1

A-1 A-1

- -

P-1 P-1

A– Stable

A–

Stable

A2 Stable

A2

Stable

A Stable

A

Stable

A-2

A1 Stable

A1

Stable

BBB Negative

BBB

Negative

S&P and Moody’s affirmed the credit ratings of CLP Holdings and CLP Power. S&P revised the outlook of

EnergyAustralia’s BBB credit rating to negative from stable

Highlights of CLP Group’s Financing Activities

CLP Holdings arranged HK$500 million 3-year bank loan facility in January 2013

CLP Power arranged a total of HK$911 million debt in bank and bond markets − HK$750 million 3-year bank loan facilities arranged in March 2013 − A$20 million (HK$161 million) 10-year bond issued in May 2013. Australian dollar proceeds

were swapped back to Hong Kong dollars to mitigate foreign currency risk

EnergyAustralia extended the A$700 million (HK$5,026 million) working capital facility in July 2013 by one year to June 2016 with existing lenders at reduced margin

CLP India arranged a total of Rs.8.05 billion (HK$1,039 million) short term bank loans in the first half of 2013 to bridge finance the construction of various wind projects which will be replaced by long-term financing after construction completion

CLP China arranged a RMB750 million (HK$946 million) project level loan for Jinchang solar project (51% CLP owned) in May 2013

A-3

Hong Kong Electricity Business

Residential Commercial Infrastructure & Public Services Manufacturing Total Local Sales Export Sales Total Sales

4,052 6,133 3,947 903

15,035

1,002

16,037

1H2012 Change 1H2013 GWh

A-4

Electricity Sales

(6.0%) 0.3% 0.5%

(2.8%)

(1.5%)

(38.1%)

(3.8%)

3,809 6,153 3,966 878

14,806

620

15,426

Hong Kong Electricity Business – Capex

HK$M 1H2013 1H2012 Change

CLP Power HK 2,272 2,289 (0.7%)

CAPCO 745 1,368 (45.5%)

Total 3,017 3,657 (17.5%)

Capex incurred up to June 2013 of HK$37.1billion, vs. Development Plan from October 2008 to December 2013 of HK$41.6 billion*

A-5

4,9035,650

2,272

1,341 1,2791,149

1,188

298

2,010 1,919 1,724

1,783

447

4,5524,447

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

FY2009 FY2010 FY2011 FY2012 1H2013

CAPCO - EM’s share

CAPCO - CLP’s share

CLP Power

5,788 5,831 6,052

Total Capital Expenditure in line with Development Plan

6,838

* Included HK$1.7 billion capex approved in 2011 related to new gas receiving station and cost for the Black Point Power Station plant modifications

2,570

Significant emissions reductions achieved over the past 2 decades

Hong Kong – Environmental Improvement

NOx

SO2

RSP

60

240

Total Emissions Reduction

1990 – 2012 NOX 81% SO2 86% RSP 82%

Total 81% Electricity Demand

Electrostatic Precipitators

at CPPS

Low NOx burners at

CPPS

Nuclear at Daya Bay

Natural Gas at BPPS

Increasing use of Ultra Low Sulphur

Coal

Emissions Control Project

2012 Generation Mix by Fuel

A-6

Coal 48%

Nuclear 30%

Gas 18%

Oil 2%

Energy Transfer

2%

2012 Residential Tariff Comparison

Comparison based on annual domestic consumption of 3,300 kWh - Tariff and exchange rate at January 2013

Source: Web search

A-7

020406080

100120140160180200220240260280300320340

Kuala Lumpur

Taipei

Vancouver

Jakarta

Shanghai

Shenzhen

Seoul

CLP

Miam

i

San Francisco

Washington, D

.C.

Macau

Houston

Paris

Helsinki

Lisbon

Singapore

Luxembourg

Amsterdam

London

Manila

Brussels

Wellington

Tokyo

Madrid

New York

Sydney

Rome

Berlin

Residential Tariff HK cents/kWh (as of Jan 2013)

Electricity Tariff Rises in Major Metropolitan Cities

A-8

Comparison based on annual residential consumption of 3,300 kWh - From 2005 to January 2013

Source: Web search

TaipeiVancouv erKuala LumpurSeoul

LuxembourgCLP Power

BrusselsParis

Toky oLisbon

AmsterdamJakarta

WellingtonBerlin

SingaporeRome

New YorkMadrid

LondonSy dney

0% 20% 40% 60% 80% 100% 120% 140% 160%

0

10

20

0

30

60

90

120

150

Jan-96 Jan-98 Jan-00 Jan-02 Jan-04 Jan-06 Jan-08 Jan-10 Jan-12

Gas Price (US$/MMBtu) Oil Price (US$/Barrel)

Crude Oil price (JCC) Japan LNG import price Yacheng price (original gas) China LNG import price

Gas Price Trend (1996-2012)

Yacheng Gas

Market

Short term South China Sea Gas

CLP Power Gas Prices Yacheng ~US$6 ; Short term South China Sea ~US$14; Market US$18-US$21

A-9

$127

$547

$1,100

$171

$171

$99

$137

$102

$239

$667

$1,172

$-

$500

$1,000

$1,500

$2,000

$2,500

Total Bill 2007 / 08

Energy Carbon Other Green Retail Network Total Bill 2013 / 14

$2,266

Australia – Industry Conditions

• Electricity tariffs have increased significantly in Australia in recent years

• For example, while the most recent regulated tariff determination in NSW was a modest 3.1% from July 1 2013, NSW Electricity Tariffs have more than doubled since 2007/08 as indicated in the accompanying chart

• This has been driven by increases in Network costs (up by around 130%), while green and carbon costs together are over 7 times higher than green costs were in 2007/08

• Demand has declined in response to a number of factors including these price rises and weakening economic conditions in Australia

• Other factors in declining usage and demand include

− Energy efficiency

− Solar PV and solar hot water penetration

− Decentralised generation

− Lower commercial & industrial load due to economic conditions

− Weather impacts

• These trends are now well established and are leading to significant reductions in forward energy projections

• This reduced demand, combined with continued build of generation to meet renewable energy targets, has seen reduction in forward wholesale energy prices (excluding the carbon impost) – putting pressure on generation earnings

A-10

Change in the average electricity bill for a typical residential customer in NSW on regulated tariffs from 2007/08 to 2013/14

Source: IPART and Company data

Source: AEMO 2013

170

180

190

200

210

220

230

240

250

Ann

ual e

nerg

y (T

Wh

sent

out

)

NEM Energy Forecasts

Actual AEMO 2010 (medium) AEMO 2011 (medium)AEMO 2012 (medium) AEMO 2013 (Medium)

2,944 104

646 (468)

(256)

(303)

(85) (212)

(88) 35 93 2,410

1H 2012 EBITDAF

Wholesale Gas Gross Margin

Net Carbon Impact

Electricity Volume &

Margin

Green, Fuel, Opex & Other

Retail Gross Margin &

Other Revenue

Higher Debt Provisioning

Employee & Consultancy

Costs

Admin, marketing opex and

other

Corporate Normalisation Adjustments

and Exchange Rate

Differential

1H 2013 EBITDAF

Australia – EBITDAF

HK

$m

Wholesale • Gas gross margin increased on higher margins from contracts and gas storage operations (+HK$104m) • Receipt of HK$1,005m transitional assistance relating to the diminution of value at Yallourn, partially compensating

for the HK$2,761m impairment (pre-tax) for Yallourn in 2011 and reduced earnings potential of the asset. The benefit was offset by a net unrecoverable cost of carbon of approximately HK$360m during the half

• Electricity gross margin was impacted by lower contract prices and lower sales volumes (-HK$468m) • Higher renewable compliance costs, fuel and other (-HK$256m)

Retail Gross Margin Retail gross margin decreased by 8% (-HK$303m) due to • Lower electricity sales due to lower MM per customer usage and weakening economic conditions and intense

competition • Gas volumes up 4% with higher C&I volume partially offset by lower MM sales

Retail Opex Retail opex increased primarily as a result of continuing issues with the new C1 billing system, including • higher debt provisioning associated with overdue accounts (-HK$85m) • higher employee and contractor costs (-HK$212m); and • higher adminstrative, marketing and other costs (-HK$88m)

Normalisation, FX and other

The HK$93m (pre-tax) half-on-half reduction in normalisation adjustments, FX and other includes items relating to business development activities, rebrand, information systems and projects and foreign exchange movements

Wholesale (+HK$26m)

Retail (-HK$688m)

A-11

1H 2013 1H 2012 1H 2013 1H 2012 1H 2013 1H 2012 1H 2013 1H 2012 1H 2013 1H 2012

Gross Margin 399 435 395 385 - - 794 820

Operating Expenses and Others (260) (208) (172) (165) (52) (57) (484) (430)

EBITDAF 139 227 223 220 (52) (57) 310 390

Depreciation & Amortisation (64) (22) (107) (108) (8) (6) (179) (136)

Operating EBITF 75 205 116 112 (60) (63) 131 254

Net Interest Expense (112) (102)

Income Tax Expense (12) (49)

Normalised NPATF 7 103 55 807

Fair Value Movement (post tax) (9) (53) (81) (424)

Normalisation Adjustments (post tax) (1) (13) (5) (109)

CLP Adjustments (post tax) - - (14) (6)

Operating earnings before One-Off Items (45) 268

Yallourn Mine Remediation (post tax) (6) (83) (42) (644)

Tax Consolidation Effect - 13 - 103

Net Profit After Tax (9) (33) (87) (273)

EnergyAustralia Holdings CLP Australia

Retail (A$m) Wholesale (A$m) Other (A$m) Total (A$m) Total (HK$m)

EnergyAustralia – Segment

A-12

Note • The segment information is based on a transfer price set to reflect the allocation of resources between Retail and Wholesale

businesses • Retail segment includes the sale of gas, electricity and energy-related products and services to all Mass Market customers

(residential, small and medium enterprises (SME)) and Commercial and Industrial (C&I) • Wholesale segment includes development, operations and constructions of power generation assets and management of risks

associated with the procurement and delivery of gas and electricity for Retail customers • The EnergyAustralia segment information contains normalisations to provide a consistent view of underlying performance • CLP Australia included the EnergyAustralia result as well as impacts from entities outside the EnergyAustralia Group

Remark: Individual items and totals are rounded to the nearest appropriate number . Some totals may not add down the page due to rounding of individual components

EnergyAustralia – Normalised NPATF

A-13

Reconciliation of NPAT to Normalised NPATF (HK$m) 1H 2013 1H 2012

NPAT (87) (273)

Yallourn Mine Remediation 42 644

Tax Consolidation Effect - (103)

Operating earnings before one-off items (45) 268

Fair value movement (post tax) 81 424

Normalisation Adjustments (post tax)

- Acquisition integration costs 12 20

- Development costs 4 89

- Majority sale of Waterloo wind farm (11) -

Other Adjustments (post tax) 14 6

Normalised NPATF 55 807

Notes • NPATF - Net Profit After Tax inclusive of normalisation adjustments and before Fair-value adjustments • Other Adjustments after tax include loss on the sale of securities in Silex and operating costs at the CLP Group level

EnergyAustralia – Operational Statistics

A-14

Operational Statistics 1H2013 1H2012 Change Generation Output (GWh) 12,036 12,809 (773)

Yallourn 4,031 4,615 (584) Mt Piper 4,422 4,134 288 Wallerawang 1,853 2,381 (528) Tallawarra 1,406 1,326 80 Ecogen 161 202 (41) Hallet 51 0 51 Waterloo 112 151 (39)

Electricity Sales (GWh) 14,045 15,699 (1,653) Natural Gas Sales (TJ) 35,580 34,350 1,230

Sales Volumes 1H2013 1H2012 Electricity (TWh) Gas (PJ) Electricity (TWh) Gas (PJ)

Mass Market New South Wales (ACT) 3.6 3.5 4.0 3.5 Victoria 1.8 12.6 1.7 14.1 South Australia 0.2 0.5 0.2 0.6 Queensland 0.4 0.0 0.4 0.0 Total Mass Market 6.0 16.6 6.3 18.3 Commercial & Industrial 8.1 19.0 9.4 16.1 Total 14.1 35.6 15.7 34.4

Customer Account Numbers (‘000) *

1H2013 1H2012 Electricity Gas Total Electricity Gas Total

Mass Market New South Wales (ACT) 1,073 267 1,339 1,100 257 1,357 Victoria 678 531 1,209 624 510 1,135 South Australia 104 61 164 93 59 152 Queensland 112 0 112 92 0 92 Total Mass Market 1,966 859 2,825 1,910 826 2,736 Commercial & Industrial 23 1 23 23 1 23 Total 1,988 859 2,848 1,932 827 2,759 Average Mass Market 1,943 852 2,795 1,938 833 2771 * End of period and billable account numbers

Remark: Individual items and totals are rounded to the nearest appropriate number . Some totals may not add down the page due to rounding of individual components

Australia – Forward Cap Prices

A-15

A negative mark-to-market movement of HK$115 million (HK$81 million after tax) was recorded in 1H2013

Mark-to-market movement represents the movement in the fair value of energy derivative products which, although used in managing energy portfolio risk, did not qualify for hedge accounting treatment and consequently have resulted in an adjustment to the P&L

The Mark-to-Market movement included in the P&L includes movements in the market price of caps, swaps and acquired contracts

The accompanying charts illustrate the general decline in the forward price for both swap and cap contracts in our key markets of Victoria and NSW

Yallourn Industrial Relations There are approximately 500 jobs at Yallourn, including 120 power station operations and maintenance employees under

an Enterprise Bargaining Agreement (EBA)

The existing EBA expired in mid 2012 and discussions commenced regarding the formulation of a new EBA

In March 2013, the CFMEU commenced industrial action which escalated to 3 days of strike action in April. Despite periods of negotiation and conciliation, the CFMEU escalated their industrial action to take control of the generation on 21 June 2013

EnergyAustralia then took the action of locking out the 75 power station shift operators and it is operating the generators with appropriately trained and qualified employees. Yallourn is, however, restricted to running only 2 of the 4 units at present

The power station shift operators remain locked out of the plant while the Conciliation process continues in an attempt to reach an agreement

In the meantime the business will continue to keep units running at the Station in an effort to minimise the impact of the business and maintain in employment the remaining 425 jobs, as well as local suppliers

Yallourn Mine Remediation On 6 June 2012, water from the Morwell River Diversion entered the Yallourn mine, following a structural failure of the

Morwell River Diversion

Remediation work includes the structural repair of the levee and reinforcement of the lining in the river diversion

Weather conditions through 2013 have delayed completion of the project and in mid June additional water was diverted into the mine following a significant rain event

Pumping of the original flood water out of the mines was completed in early February 2013, in line with EPA special water discharge limit license expiration. Pumping of the additional water from the June 2013 event is expected to complete in October 2013

An additional amount of A$8m has been raised to cover the cost of this latest incident, taking the total cost of remediation (including pumping) to A$163m

EA – Yallourn Industrial Relations and Mine Remediation

A-16

Australia – Impact of Carbon Australian Carbon Pricing Scheme On 1 July 2012, the Australian Government’s carbon pricing legislation came into effect. The package includes a default

target of 5% abatement on Year 2000 CO2 equivalent emissions by Year 2020 across the Australian economy, a fixed carbon price for the first three years beginning on 1 July 2012 and starting at A$23 per tonne for liable entities. The fixed carbon price will rise at a real 2.5% each year, and consequently increased to A$24.15 from 1 July 2013

To facilitate the transition to lower carbon emissions the Government established an Energy Security Fund. Under the Fund, a total of A$5.5 billion in the form of cash and free permits has been allocated to emission intensive coal-fired generation plant to be distributed as follows: − A one-off payment of A$1 billion to be divided between recipient generators in proportion to their historical emission

intensity and output and deliverable by 30 June 2012

− Four annual allocations of 41.705 million free carbon permits to be divided between recipient generators in proportion to their historical emission intensity and output, deliverable on the 1st of September 2013, 2014, 2015 and 2016

Following the three year fixed price period the scheme changes to an emissions trading scheme or ETS. Originally this was restricted to Australia with a floor price of A$15 per tonne. However the scheme was changed in August 2012 to remove the floor price and instead link the Australian scheme to the European ETS. From 1 July 2015 up to 50% of an entity’s liability may be met through international permits (either EUAs or CERs etc) and a limit of 12.5% from CERs has now been imposed. Given that the average price of carbon in Europe over 2012 and early 2013 has been significantly lower than the previous price floor of A$15 per tonne, it is expected that the Australian carbon prices from July 2015 onwards will be lower than under the original scheme

While further changes to the scheme have been postulated by both major parties any change to the legislation must be approved by both houses of Parliament. No such amendments to legislation have formally been introduced to Parliament

EnergyAustralia participation in the Energy Security Fund On 22 June 2012 EnergyAustralia received a cash payment of A$257.5m (or 25.75% of the total) as part of the initial one-off

cash payment to eligible recipient generators

This cash payment was amortised in a straight line manner over the period to which it applied (1 July 2012 to 30 June 2013). The accounts for EnergyAustralia for the six months to 30 June 2013 therefore contain a benefit of A$128.75m in relation to this carbon compensation which is included within the calculation of Gross Margin

EnergyAustralia anticipates receiving a further 25.75% annual allocations of 41.705 million free carbon permits conditional on Yallourn passing a power system reliability test (administered by the Australian Energy Market Operator) and publishing a Clean Energy Investment Plan

A-17

Debt • Net Debt at 30 June 2013: A$2.2 billion

• Available liquidity A$856m across two facilities and a variety of maturity dates (plus A$515m in WCF)

• New debt financing in 2012: − US$400m private placement – tenor 5 to 15 years − A$750m bank facility – tenor of 4 and 5 years

• Repaid and cancelled: − A$650m Medium Term Note in Nov 2012 − A$350m bank facility due to mature Aug 2013

• Roll forward the WCF to maintain 3 year maturity

Credit Rating • On 30th April 2013(1) Standard and Poor’s affirmed the

BBB rating and stand-alone credit profile of BBB- for EnergyAustralia and revised the outlook for EnergyAustralia’s Credit Rating from Stable to Negative

• S&P referenced structural changes in the electricity market noting that the trend of declining energy demand and relatively soft electricity prices is placing pressure of EA's margins, and could weaken EA‘s financial profile

1. “Outlook On EnergyAustralia Holdings Ltd. Revised To Negative On Likely Weaker Financial Profile; 'BBB' Rating Affirmed” Standard and Poor’s Research update April 30 2013 2. Working Capital Facility rolled forward in July to mature in 2016

EnergyAustralia – Debt and Credit Rating

A-18

0

200

400

600

800

1000

1200

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

$M

Maturity

Debt Maturity Profile as at 31 July 2013 (2)

Syndicated Facility Headroom Syndicated Facility USPP MTN WCF Utilised WCF Headroom

WCF19%

Syndicated56%

MTN1%

USPP24%

Delta Western Acquisition – Transaction Overview

− EnergyAustralia acquired the exclusive long term rights to the output of the Mt Piper and Wallerawang power stations in early 2011 under Generation Trading Agreements, as part of a broader transaction which included 1.5 million NSW retail customers

− In July 2013, EnergyAustralia agreed to acquire the underlying Delta Western power station assets from the NSW Government for a net cash consideration of A$160 million (HK$1,154 million)(1)

− Acquiring the underlying assets releases the business from fixed contract commitments, improves the flexibility in our operations, provides the opportunity to reduce capital expenditure while accessing full plant capacity, and improves key metrics

− The acquisition will be funded from existing undrawn EA debt facilities

− The acquisition is expected to complete on 2 September 2013

Delta Western Overview Mt Piper Wallerawang

Commissioned 1992-3 1976-80

GTA Contract Capacity 1,340 MW 960 MW

Configuration 2 x 700 MW (1,400 MW)

2 x 500 MW (1,000 MW)

Capacity Factor (last 5 years) 81.5% 60.6%

CO2 Intensity (tonnes / MWh) 0.89 0.92

Note (1): The HK$ equivalent for the acquisition consideration (stated in A$) are translated for illustration purposes for this announcement at the exchange rates of A$1.00 = HK$7.2139 as of 25 July 2013, representing the exchange rates prevailing at transaction close.

Mt Piper Power Station Wallerawang Power Station

NEW SOUTH WALES

Sydney

Mt Piper

Canberra

Wallerawang

AUSTRALIA

WESTERNAUSTRALIA

NORTHERNTERRITORY

SOUTHAUSTRALIA

QUEENSLAND

NEW SOUTHWALES

VICTORIA

TASMANIA

Sydney

Melbourne

Perth

Darwin

Adelaide

Brisbane

Canberra

Hobart

Location

A-19

Taiwan Hong Kong

Australia

India

TAIWAN – total 264 MW

Operational Ho-Ping 1,320/264 MW (c)

China

AUSTRALIA – total 5,533 MW

Operational Yallourn 1,480/1,480 MW (c) Delta Western 2,400/2,400* MW (c) Hallett 203/203 MW (g) Ecogen 966/966* MW (g) Tallawarra 420/420 MW (g) Wilga Park 10/2 MW (g) Wind Projects 177/61 MW (w) Construction Wilga Park 6/1 MW (g)

HONG KONG – total 6,908 MW*

Operational Castle Peak 4,108/1,643 MW (c) Black Point 2,500/1,000 MW (g) Penny’s Bay 300/120 MW (d)

CLP Group Generation Portfolio – June 2013

Thailand

• Station Name Gross MW / CLP Equity MW * Including capacity purchase

Fuel Source: (c) – coal-fired (g) – gas-fired (w) – wind (h) – hydro (n) – nuclear (b) – biomass (d) – diesel (s) – solar

INDIA – total 3,026 MW

Operational Paguthan 655/655 MW (g) Wind Projects 594/594 MW (w) Jhajjar 1,320/1,320 MW (c) Construction Wind Projects 457/457 MW (w)

CHINA – total 6,626 MW Operational Daya Bay 1,968/1,380* MW (n) Pumped Storage 1,200/600* MW (h) Fangchenggang 1,260/882 MW (c) SZPC 3,060/900 MW (c) CSEC Guohua 7,870/1,440 MW (c) & Shenmu Boxing Biomass 15/12 MW (b) Hydro Projects 505/486 MW (h) Wind Projects 1,084/550 MW (w) CGN Wind 1,794/251 MW (w) Construction Wind Projects 74/74 MW (w) Jinchang Solar# 100/51 MW (s)

THAILAND – total 21 MW Operational NED Solar 63/21 MW (s)

13,379 Equity MW and 8,999 MW capacity purchase (total: 22,378 MW)

# Jinchang solar project commenced operation on 2 July 2013

A-20

Renewables Portfolio – June 2013

Australia

India

China

Thailand

AUSTRALIA – total 61 MW Operational Waterloo 111/28 MW (w) Cathedral Rocks 66/33 MW (w)

• Station Name Gross MW / CLP Equity MW

Solar project (s)

Hydro projects (h)

Biomass projects (b)

Wind projects (w)

INDIA – total 1,051 MW Operational Khandke 50/50 MW (w) Samana I 50/50 MW (w) Samana II 50/50 MW (w) Saundatti 72/72 MW (w) Theni I 50/50 MW (w) Theni II 50/50 MW (w) Harapanahalli 40/40 MW (w) Andhra Lake 106/106 MW (w) Sipla 50/50 MW (w) Bhakrani 76/76 MW (w) Construction

Bhakrani 27/27 MW (w) Tejuva 101/101 MW (w) Yermala 149/149 MW (w) Mahidad 50/50 MW (w) Jath 130/130 MW (w)

Changdao 27/12 MW (w) Weihai I & II 69/31 MW (w) Nanao II & III 60/15 MW (w) Shuangliao I & II 99/48 MW (w) Rongcheng I, II & III 148/73 MW (w) Datong 50/24 MW (w) Laizhou 41/18 MW (w) Changling II 50/22 MW (w) Guohua Wind 248/122 MW (w) Qujiagou 49/12 MW (w) Mazongshan 49/12 MW (w) Qian’an I & II 99/99 MW (w) CGN Wind 1,794/251 MW (w) Penglai I 48/48 MW (w) Chongming I 48/14 MW (w) Jiangbian 330/330 MW (h) Huaiji 125/106 MW (h) Dali Yang_er 50/50 MW (h) Boxing Biomass 15/12 MW (b) Guohua Wind 50/24 MW (w) Laiwu I 50/50 MW (w) Jinchang Solar# 100/51 MW (s)

Operational (1,299 MW) Majority-owned - Wind 147 MW - Hydro 486 MW - Biomass 12 MW Minority-owned - Wind 403 MW CGN Wind 251 MW

Construction (125 MW) Minority-owned - Wind 24 MW Majority-owned - Wind 50 MW - Solar 51 MW

CHINA – total 1,424 MW

THAILAND – total 21MW Operational NED Solar 63/21 MW (s)

2,557 Equity MW (over 19% of total generation capacity)

A-21 # Jinchang solar project commenced operation on 2 July 2013

A-22

Wind (1,987MW)

26 wind farms in China (624 MW)

Strategic investor in CGN Wind in China (251 MW)

2 wind farms in Australia (61 MW)

14 wind farms in India (1,051 MW)

Hydro (486 MW)

3 hydropower projects in China (486 MW)

Solar (72 MW)

1 solar project in Thailand (21 MW through NED)

1 solar project in China (51 MW)

Biomass (12 MW)

1 plant in China (12 MW)

2,557 Equity MW – Geographical and fuel diversity

Renewables Portfolio by Fuel Mix – June 2013

Capacity by Energy Type

Total Equity

MW (a) + (b)

% No. of projects

Equity MW in

operation (a)

%

MW under construction/

financially committed

(b)

%

Coal 7,929 59% 18 7,929 59% - -

Gas 2,281 17% 5 2,280 17% 1 <1%

Nuclear * 492 4% 1 492 4% - -

Diesel 120 1% 1 120 1% - -

Wind 1,987 15% 64 1,457 11% 530 4%

Hydro 486 4% 3 486 4% - -

Solar 72 <1% 3 21 <1% 51 <1%

Biomass 12 <1% 1 12 <1% - -

Total 13,379 100% 96 12,797 96% 582 4%

13,379 Equity MW Attributable to CLP Group

A-23

Equity MW by Fuel Mix – June 2013

* CLP owns 25% of GNPJVC which owns Daya Bay units 1 and 2