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SUBMISSION PUBLIC VERSION

Case No: ADC 416

Period of Investigation: 1

April 2016 – 31 March 2017

20 October 2017

The Director

Operations 1

Anti-Dumping Commission

EMAIL: [email protected]

Ref: Anti-Dumping Investigation No.416 of Imports of Steel Rod In Coils

from Indonesia, Republic of South Korea and Vietnam

Sub: Comments on the Applicant’s particular market situation claims and

Request for the Use of Rod In Coils Price in Vietnam to Determine the

Normal Value in the Instant Investigation.

Dear Mr. Director,

On behalf of Government of Vietnam (hereinafter referred to as “GOV”), we hereby

submit comments on the applicant’s particular market situation claims in the on-going anti-

dumping investigation against steel rod in coils imported from Vietnam. In summary of this

submission as analyzed below, the GOV requests the Australia Anti-dumping Commission

(hereinafter referred to as “the Commission”):

mailto:[email protected]

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To reject the applicant’s claims of the existence of a particular market

situation in Vietnam and thus, to apply the rod in coils price in Vietnam’s

market in determining the normal value for those products originating from

Vietnam. In this case, any claim on a particular market situation in Vietnam

under Section 269 (2) (a) (ii) TAC, Custom Act 1901 is not warranted because

of insufficient evidence of the case record showing that:

(i) the rod in coils prices in Vietnam are artificially low due to the

absence of the GOV’s influence in both prices and cost of steel rod in

coils in Vietnam and

(ii) other conditions exist in Vietnam market that render the rod in coils

sales in Vietnam not suitable for use in determining the normal value

within the instant investigation.

In case of an affirmative decision on the particular market situation in

Vietnam, to implement Australia’s obligation under Article 2 of the WTO

Antidumping Agreement by using Vietnamese producers’ production cost data

to construct the normal value, instead of using Indonesian or any foreign data

as suggested by the applicant.

In addition, the GOV also notes that it has fully cooperated at its best capacity and provided

the Commission with requested response and information to the Commission’s questionnaire

in a timely manner. They are official and factual evidence to demonstrate that the GOV’s law

and policy do not intend to have or result in any distorting effects with regard to the rod in

coil industry and market in Vietnam. As an interested party to this proceeding, the GOV

requests that this position as supported by factual evidence should be carefully taken into

account by the Commission in accordance with its obligation under Article 6 of the

Agreement on Implementation of Article VI of the General Agreement on Tariffs and Trade

1994 (hereinafter referred to as “the WTO Antidumping Agreement) to which Vietnam and

Australia are both members. The GOV reserves its rights to provide additional comments on

the applicant’s allegation as well as any findings of the Commission at the later stage of this

investigation.

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Yours sincerely,

Dinh Anh Tuyet

IDVN Lawyers

Legal Counsel for the Government of Vietnam

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INTRODUCTION

1. At the outset, the GOV would like to note that the instant case against rod in coils is

the forth antidumping case and the second case having particular market situation

(herein after referred to as “PMS”) allegations initiated by the Commission against

Vietnamese imports only within 12 months. The first PMS investigation also targeted

the steel sector of Vietnam where the Commission sought detailed information on the

GOV’s law and policy applicable to the steel industry in general and galvanized steel

sector in particular as well as upstream producers of iron ore, coking coal, coke and

scrap steels. In its response to the Commission’s questionnaire, the GOV provided a

detailed explanation of its law and policy with supported data and legal documents

which was then reasonably and thoroughly examined by the Commission in order to

arrive at the conclusion that:

“... Additionally, the Commission did not find any evidence to support a finding that

the Government of Vietnam influenced or distorted the prices or costs of the goods in

the market, or any other conditions in the market that would support a finding of a

particular market situation in Vietnam.”1

2. This finding demonstrates an accurate and thorough understanding of the Commission

on the GOV’s law and policy with regards to the steel industry of Vietnam and should

serve as an important precedent for the Commission when considering any subsequent

PMS allegation against Vietnam, including this case on steel rod in coils. Therefore,

while the GOV is surprised and concerned with the Commission’s decision to

investigate the PMS issue within the steel sector again, it would trust that the

Commission would take a cautious approach in examining all evidence submitted by

the GOV in its response and other submissions and again reach a similar negative

conclusion on the existence of a particular market situation in Vietnam in this rod in

coil case.

3. In this case, the applicant relied entirely on its own misleading interpretation of the

GOV’s export and import tariff on raw materials to produce steel billet – the direct

input of steel rod in coils production to claim that the GOV intervened and distorted

1 Page 109-110, Final Report No.370, Alleged dumping of zinc coated (galvanized) steel exported to Australia from the Republic of India, Malaysia and the Socialist Republic of Vietnam.

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the prices of rod in coils on Vietnam market.2 Such claim is completely unwarranted

because neither the applicant’s submission nor factual evidence of the case record

supports the existence of any GOV’s intervention that may distort the rod in coils

price in Vietnam market. In this submission, the GOV discusses and analyzes all

factual evidence in light of Australia’s regulations and international obligations on

antidumping investigation to sustain (i) non-existence of a particular market situation

with regards to the rod in coils industry and market in Vietnam and (ii) the necessity

and suitability of using data associated with Vietnamese producers of rod in coils to

ensure a suitable determination of normal value under Article 2 of the WTO

Antidumping Agreement, instead of using Indonesian or any foreign cost benchmark

as suggested by the applicant as a result of any possible affirmation of a particular

market situation in Vietnam.

I. Any claim on the existence of a particular market situation in Vietnam

with regards to rod in coils in this case as provided under Section 269

(2)(a)(ii)TAC of Australia’s Custom Act 1901 is not warranted.

4. The GOV submits that there is no particular market situation in Vietnam regarding

rod in coils because criteria of establishing the existence of such market under Section

269(2)(a)(ii)TAC of Australia’s Custom Act 1901 and the Commission’s Dumping

and Subsidy Manual are not satisfied.

5. Pursuant to Section 269(1)TAC of Australia’s Custom Tariff 1901, a general principle

to establish the normal value of any goods exported to Australia is using “the price

paid or payable for like goods sold for home consumption in the exporting country”.

However, Section 269(2)(a)(ii) TAC provides an instance where the normal value of

goods exported to Australia cannot be ascertained by using the price paid or payable

in the exporting country because of the situation in the market of the country of export

which render the sales in that market are not suitable for use in determining a price

under subsection 1. This situation as described in Section 269(2)(a)(ii)TAC as such is

often referred to as “a particular market situation”.

6. The legislation does not define what constitutes a particular market situation that

would render domestic sales as unsuitable. However, the Commission in its Dumping

2 Page 67, Application for the publication of dumping and/or countervailing duty notices – Steel Rod in coils – exported from Republic of Indonesia, the Socialist Republic of Vietnam and the Republic of Korean, May 2017.

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and Subsidy Manual determines that a particular market situation exists in an

exporting country when

“(i) the prices are artificially low; or

(ii) there are other conditions in the market which render sales in that market not

suitable for use in determining prices under Subsection 269 TAC(1)” .3

7. The GOV believes that none of these factors exist in this case.

1. Insufficient evidence showing that the price of rod in coils sold in Vietnam are

artificially low

8. In the Commission’s Dumping and Subsidy Manual, in order to find “artificially low

pricing” of the subject merchandise, there must be sufficient evidence of the record

showing significant influence by the government of an exporting country that distorts

the prices or cost of that merchandise.

“…in investigating whether a market situation exists due to government influence, the

Commission will seek to determine whether the impact of the government’s

involvement in the domestic market has materially distorted competitive conditions. A

finding that competitive conditions have been materially distorted may give rise to a

finding that domestic prices are artificially low or not substantially the same as they

would be if they were determined in a competitive market. One example of

government influence distorting competitive conditions and leading to artificially low

prices may be the presence of government owned enterprises in the domestic market.

The presence of government owned enterprises, of itself, may not lead to the

conclusion that sales are unsuitable. Rather, market conditions will no longer be said

to prevail when the number of government owned enterprises, together with any

unprofitable sales by those same enterprises, has caused a significant distortion to the

prices received by private enterprises.”4

9. In the instant investigation, the GOV does not have any influence in a manner that

materially distorts competitive conditions of rod in coils on Vietnam market.

10. First, as indicated in its response to the Commission’s questionnaire, the GOV does

not have any direct ownership or representation in any rod in coil producers and

3 Page 36 Dumping and Subsidy Manual, April 2017 by the Anti-dumping Commission of Australia. 4 Page 36-37, Id.

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traders in Vietnam. The rod in coils industry is subject to the same set of laws and

regulations with other sectors of production and business in Vietnam. There is no

restriction or control by the GOV over the number of producers and traders or over

the private or foreign ownership in this sector or over the quantity of production and

sale in Vietnam and export markets. They are free to decide how much to produce and

at which price to sell their products in Vietnam and abroad. Being a steel rod in coil

maker or trader has never been a criterion to receive any benefit or favor under the

Vietnam’s law.

11. Second, to the extent that the Commission is concerned with the ownership of

Vietnam Steel Corporation – a state-owned company – in 05 rod in coils

producers,[INFORMATION OF ENTERPRISES] the GOV emphasizes two relevant

important factors to demonstrate that competitive market conditions still prevail in

Vietnam in this sector. Firstly, Vietnam Steel Corporation [INFORMATION OF

ENTERPRISES] did not produce and sell rod in coils during the POI but rather

operated as a holding company having equity interests and acting as shareholder in

those 05 producers,[INFORMATION OF ENTERPRISES]. Secondly, the local

private sector and foreign-invested enterprise prevail the whole rod in coils industry

when accounting for more than 75% of the total industry’s production quantity while

these 05 producers only accounted less than 25% and never exported the subject

merchandise to Australia.5 ,[INFORMATION OF ENTERPRISES] Thirdly, the only

exporter of rod in coils to Australia is a 100% private company in which both the

GOV and Vietnam Steel Corporation ,[INFORMATION OF ENTERPRISES]do not

have any ownership or equity interest.

12. Third, as responded to the Commission, steel rod in coils is not subject to any price

control measure taken by the GOV. Pursuant to Article 11 of the Law on Prices of

Vietnam6, enterprises have the right to self-determine the prices of goods or services

which they manufacture or deliver except for certain products subject to price

determination by the GOV. A list of these products is provided in Article 19 of this

Law. Rod in coils as well as all of the upstream raw materials including iron ore,

coking coal, coke, scrap steel and square billets are completely absent from such list.

5 Exhibit 1 to the GOV’s questionnaire response 6 This law is provided at Exhibit 10 to the GOV’s questionnaire response.

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Therefore, sale and purchase of rod in coils follow market supply and demand without

any intervention by the GOV.

13. In fact, as showed in Chart 1 below, rod in coils are sold in Vietnam are sold at a

similar level and even higher as opposed to those prices in other countries. This fact

demonstrates that rod in coils prices in Vietnam fluctuate according to the world

market without any influence by the GOV.

Chart 1: Comparison of sale price of rod in coils in Vietnam and in other

markets

Source: Consolidated from Exhibit 1 to this Submission

14. In the Dumping and Subsidy Manual, the Commission also attributes the existence of

“artificially low” price to the export country’s government influence and distortion of

the cost of inputs to produce the subject merchandise:

“Prices may also be artificially low or lower than they would otherwise be in a

competitive market due to government influence and distortion of the costs of inputs.

The mere existence of any government influence on the costs of inputs would not be

enough to make sales unsuitable. The Commission looks at the effect of this influence

on market conditions and the extent to which domestic prices can no longer be said to

prevail in a normal competitive market. It should be noted that government influence

on costs can only disqualify the sales if those costs can be shown to be affecting the

domestic prices. Thus, a range of conditions concerning the sales themselves may

0.0

100.0

200.0

300.0

400.0

500.0

600.0

700.0

2013 2014 2015 2016 2017

Compare price of rod in coils price in Vietnam and in other markets

Vietnam Shanghai Steel Wire Rod Furture Wire Rod (CFR Dubai)

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have the effect of rendering those sales prices as being unsuitable for use in

determining prices under subsection 269TAC(1). When relevant and reasonably

reliable evidence supporting the proposition that domestic selling prices are

unsuitable for normal values is set out in the application, and an investigation is

initiated, the Commission will adopt the following procedures in order to ensure

interested parties have an opportunity to consider the claims and present evidence:

Notify the government of the country and the exporters of the claims and of the

evidence provided. Additional questions will be inserted into the exporter

questionnaire titled “Market Situation”. A ‘Market Situation’ questionnaire will

also be prepared for government.

Both questionnaires will be based upon the evidence provided by the Australian

industry that supported the decision to investigate. That is, the information

supporting the claim that the domestic prices are materially influenced by the

government of that country and are not substantially the same as they would be if

they were determined in a competitive market. Any other relevant information in

the possession of the Commission may also be taken into account when preparing

the questionnaire. The government and the exporter will be asked to respond as

specifically as possible to the questions. Accompanying letters will draw attention

to these questions.

If the government of the country or exporters fail to respond after being given a

reasonable opportunity to do so, or do not provide probative evidence in

response, all available evidence is weighed up, including the prima facie evidence

of the application. One possible outcome is that the Commission will determine

that a situation in the market has rendered domestic selling prices unsuitable for

establishing normal values.”7

15. In the Questionnaire, specific questions were raised to the GOV regarding its law and

policy regarding iron ore, coking coal, coke, scrap steels, and steel billet – raw

materials that constitute a part of production cost of the subject merchandise. The

GOV fully cooperated with the Commission by providing requested information and

data at its best capacity, which demonstrates that the GOV has not implemented any

policy to place a downward effect on the price of raw material inputs into the

7 Page 37, the Dumping and Subsidy Manual, April 2017 by the Anti-dumping Commission of Australia.

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production of rod in coils including iron ore, coking coal, coke and scrap steel as

further analyzed below:

1.1 Coking coal and coke

16. Contrary to the applicant’s claims in its Application, the GOV’s import and export

tariff policies on these materials did not distort the market conditions in Vietnam

during the period of investigation

17. First, in terms of export, during 2012-2016, tariffs imposed on coking coal and coke

were gradually reduced from 20% to 10% as indicated in Table 1 below. This is a

normal tariff level and does not show any sign of export restriction, which is totally

contrary to the applicant’s allegation.

Table 1: Vietnam’s export tariff applicable to coke and coking coal

2012 2013 2014 2015 2016

Export tariff of coke 20% 20% 13% 13% 10%

Export tariff of coking

coal 20% 10% 10% 10% 10%

Sourced: Consolidated from Exhibit 9 to the Initial Questionnaire Response

18. Further, export of coke and coking coal are not subject to any value-added tax or any

quantity restrictions. Combined with the export tariff, this demonstrates that the GOV

has not been trying to increase the supply of coke and coking coal in the domestic

market by reducing their availability to the international market. Hence, the situation

in this case is completely different from the Dumping and Countervailing

Investigation No.198 as cited by the applicant where the Commission found that the

Government of China’s increase in export tariff in order to restrict the export and

increase the supply of materials in the domestic market.8

19. Moreover, the GOV notes that unlike China, Australia, Russia, India or the U.S,

Vietnam is not a big player in terms of coal supply and consumption in the world.

Therefore, Vietnam’s market for coal is quite sensitive to developments on the world

market including any changes in terms of supply and demand of coking coal and coke

8 In this case, the Government of China increased the export tariff applicable to coke and coking coal from 25% to 40% and from 5% to 10% during 2008-2012, which was found by the Commission as an attempt to restrict the export of coking coal.

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taking place in giant players rather than to the GOV’s import or export tariff on these

materials.

Table 2: Vietnam and other countries’ coal production and consumption

Coal: Production Unit: Million tonnes oil equivalent

Year 2012 2013 2014 2015 2016 Share (%)

US 517.79 500.87 507.70 449.34 364.82 10.0%

Russian Federation 168.29 173.12 176.59 186.38 192.77 5.3%

South Africa 146.57 145.26 148.23 142.89 142.44 3.9%

Australia 265.86 285.78 305.70 305.81 299.29 8.2%

China 1873.54 1894.59 1864.21 1825.56 1685.71 46.1%

India 255.05 255.73 269.45 280.90 288.53 7.9%

Indonesia 227.39 279.66 269.94 271.98 255.74 7.0%

Vietnam 23.57 23.00 23.01 23.23 22.04 0.6%

Coal: Consumption Unit: Million tonnes oil equivalent

Year 2012 2013 2014 2015 2016 Share (%)

US 437.92 454.57 453.53 391.82 358.43 10%

Total Europe &

Eurasia 528.06 508.05 487.26 471.34 451.56 12%

China 1927.79 1969.07 1954.48 1913.62 1887.55 51%

India 329.99 352.78 387.54 396.55 411.95 11%

Indonesia 53.02 57.01 45.12 51.16 62.70 2%

Japan 115.82 121.15 119.15 119.89 119.94 3%

Vietnam 15.04 15.83 18.94 22.25 21.33 1%

Source: Consolidated from World Energy Statistics 2017 provided at Exhibit 3 to this

Submission.

20. As can be seen from Table 2, Vietnam’s shares of the world’s coal production and

consumption account less than 1%. Indeed, Vietnam’s export of coking coal during

2012-2016 is totally inelastic to the GOV’s change in the export tariff on this

material:

Chart 2: Vietnam’s coking coal export quantity during 2012-2016

21. As can be seen, the export quantity of coking coal reached the highest level in 2012

when the export tariff was set at the highest level. When the tariff was reduced to 10%

in 2013 and maintained that level until 2016, the quantity of export did not increase

but followed a downward trend. Thus, there is no causation between the GOV’s

export tariff and the supply of coking coal to international markets.

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22. Similar observations can be made with regards to coke export as described in Table 3

below:

Table 3: Coke export by Vietnam and Applicable Export Tariff

23. The overall trend for both export tariff and the quantity of coke export by Vietnam is

decreasing during 2012-2016.

24. Second, in terms of import, the GOV notes that tariff levels levied on imported coking

coal and coke are not decided merely by the GOV’s discretion. Rather, they are

subject to Vietnam’s obligation under multilateral agreement (i.e. WTO) or free trade

agreements. Thus, applicable tariffs during 2012-2016 on imported coking coal and

coke from major country suppliers should be anticipated a long time before the POI

and should not be considered as an attempt of the GOV to encourage the importation

for the domestic market. For example, the fact that a decrease in the tariff of coking

coal of HS code 2704.0020 and 27.04.00.30 imported from Australia to 0% in 2016 as

cited by the applicant in the petition was in fact decided since 2009 as a Vietnam’s

obligation under the ASEAN-Australia/New Zealand Free Trade Area. Exhibit 2

provides detailed information of the import tariff on coking coal and coke into

Vietnam from 05 largest suppliers corresponding to Vietnam’s commitments under

relevant free trade agreements.

25. Import tariff rates applicable to coking coal and coke during 2012-2016 result from

the negotiation and agreement between the GOV and its counterparts in the process of

establishing free trade areas. It is the implementation of such obligations that led to

the reduction in the import tariff rates in 2016. This fact obviously contradicts the

applicant’s allegation that the GOV changed its import policy to encourage the

importation of these materials into Vietnam in order to create a favor to the

downstream value added industries such as steel billet and rod in coils.

26. In addition, the quantity of coking coal imported into Vietnam is more dependent on

prices fluctuations in the world market. For instance, as indicated in Chart 3 below,

the import volume of coking coal into Vietnam in 2016 from Australia – the largest

supplier – was completely elastic to the price market.

Chart 3: Price elasticity of Coal import into Vietnam from Australia in 2016

1.2 Iron ore and scrap steel

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27. First, the GOV submits that no export restriction measures in form of quota or tariff

against iron ore and scrap steel were introduced during the POI in order to reserve the

market for these products for domestic downstream users as claimed by the applicant.

It is an obvious fact that the export tariff levied by the GOV on iron core remained

unchanged during 2012-2016 while the quantity of export has increased dramatically

as shown in Table 4 below:

Table 4: Iron ore export by Vietnam and Applicable Export Tariff

28. A similar trend is observable with regards to the export of scrap steel.

Table 5: Scrap steel export by Vietnam and Applicable Export Tariff

29. Thus, there is no correlation between the GOV’s export tariff in this regard and the

so-called “export restriction” policy as claimed by the applicant.

30. Meanwhile, import tariff on iron ore of 0% applicable during 2012-2016 was actually

the ceiling rate under Vietnam’s WTO commitments since 2007. Obviously contrary

to the applicant’s claim, it is not the GOV’s policy to maintain a difference of 40%

between the export and import tariff rates on iron ore in order to favor the

downstream producers such as steel billet or rod in coils.

31. In addition, the increase in iron ore import volume during 2015-2016 is attributed to

the steel billet production expansion by a number of BOF projects invested with

private and foreign capital by Hoa Phat Group and Formosa Ha Tinh Steel

[INFORMATION OF ENTERPRISES]. Chart 4 shows that Vietnam’s domestic

production of iron ore hardly satisfied the demand during this period.

Chart 4: Iron ore production and consumption for steel billet production in

Vietnam

32. Similarly, the increase in scrap steel imports results from the investment in steel billet

by private sectors such as Vinakyoei Vietnam and POSCO SS Vina.

[INFORMATION OF ENTERPRISES]

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33. Therefore, the fact that import of iron ore and scrap steel increased significantly into

Vietnam during 2015-2016 has nothing to do with the GOV’s import tariff. Rather it

results from the capacity expansion of the billet sector by investment from the private

and foreign sectors.

1.3 Electricity

34. In its submission dated September 6, 2017, the applicant claimed that the rod in coil

prices in Vietnam is artificially low due to government influence and distortion of the

cost of electricity9 and requested the Commission to substitute the steel billet

production cost of Indonesia for that of Vietnam in order to calculate the cost of

production of rod in coils. This claim is clearly unfounded

35. First, the GOV’s influence in the electricity price – an input of steel billet production

– is not sufficient to allow a conclusion that a market situation exists in the

Vietnamese’s rod in coils market that renders the sale of rod in coils in Vietnam

unsuitable for determining normal value under Section 269TAC(1). The

Commission’s Dumping and Subsidy Manual correctly points out that:

“…The mere existence of any government influence on the costs of inputs would not

be enough to make sales unsuitable. The Commission looks at the effect of this

influence on market conditions and the extent to which domestic prices can no longer

be said to prevail in a normal competitive market. It should be noted that government

influence on costs can only disqualify the sales if those costs can be shown to be

affecting the domestic prices.”10

36. First, the GOV would note that its regulation of electricity tariff is a normal practice

that is also adopted by a number of other countries including Indonesia and Australia.

Exhibit 6 provides the applicable tariff decided by the GOV during 2012-2015 in

comparison with that of Indonesia and Australia (Queensland) where caps on

electricity tariff are also applied. Nowhere in Australia’s regulations on antidumping

and the Commission’s practice of previous cases that support an affirmative finding of

a particular market situation resulting from the government control on electricity

tariff. Further, given the fact that electricity tariffs in Vietnam and Indonesia are both

regulated by the government, it would be even more unreasonable if the Commission

9 Page 1, OneSteel Manufacturing Pty Ltd’s Submission dated 6 September 2017. 10 Page 36, the Dumping and Subsidy Manual, April 2017 by the Anti-dumping Commission of Australia

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accepts the applicant’s request to replace the Vietnamese steel billet cost data by

Indonesia’s value.

37. Second, the GOV’s influence on electricity cost cannot disqualify domestic sales of

rod in coils because it does not affect those sale prices. This position is fully in

accordance with the Commission’s view in the Deep Drawn Stainless Steel Sinks-

China (hereinafter referred to as Sink-China).

38. In the Sink-China case, the Commission concluded that the cost of 304 SS CRC steel

– an input to produce the sink did not impact the domestic price of the latter in a

manner that rendered domestic sales of sink unsuitable for determining normal values

because (i) the proportion of this material on average of 45-55% of the total cost of

the sinks are “considerably lower” than the proportion of distorted raw materials of

finished merchandise whose domestic sales are unsuitable in previous cases and (ii)

the difference between reasonably competitive market cost and the Chinese’s 304 SS

CRS steel is only 10% as follows:

“…Although satisfied that government influence has distorted the cost of 304 SS CRC

steel incurred by Chinese exporters of the goods, the Commissioner is not satisfied

that this has impacted the domestic selling prices of deep drawn stainless steel sinks

to such an extent that those prices are no longer suitable for determining section 269

TAC(1) normal values.

In making this assessment, the Commissioner notes the following.

the distorted input (304 SS CRC) represented on average 45% to 55% of the

total cost to manufacture incurred by Chinese deep drawn stainless steel sink

manufacturers. Although this is considered to reflect a significant proportion

of the cost to manufacture the goods, it is considerably lower than the

proportion of the cost to manufacture represented by distorted raw materials

in the production of HSS, hot rolled plate steel, galvanised steel and

aluminium zinc coated steel, all of which were found to be subject to have

particular market situations in China during the Commission’s investigations

into each product. In these cases, the percentage of total costs represented by

distorted raw materials was significantly higher, and hence more likely to

have a ‘flow on’ effect of rendering selling prices of the manufactured product

unsuitable for determining normal values.

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The difference between the reasonably competitive market cost determined by

the Commission for 304-SS CRC87 (see Non-Confidential Appendix 4 and

Non-Confidential Appendix 8 for discussion) and the costs actually incurred

by Chinese exporters of the goods is on average 10% (i.e. Chinese-incurred

costs are 10% lower than the reasonably competitive market cost for 304 SS

CRC). This uplift, while significant, is substantially lower than uplifts to steel

raw material costs observed by the Commission in its investigations into other

Chinese steel products.

When combined with the consideration that this is a 10% uplift to a cost that is

approximately 45 – 55% of total manufacturing costs, the Commission

considers this does not provide strong evidence that the impact of distorted

stainless steel costs has had the impact of creating a market situation in the

deep drawn stainless steel sinks market (i.e. it is likely that this distorted input

has not impacted the price of deep drawn stainless steel sinks to such an extent

that domestic prices of those goods are no longer suitable for use in

determining normal value)..”11

39. In this case, a thorough examination of Vietnam’s electricity tariff and its proportion

in the cost of billet and rod in coils production also shows a similar uplift level as in

the Deep Drawn Stainless Steel Sinks- China case.

40. First, electricity represents on average 3% to 10% of the total cost to manufacture

steel billet for BOF and EAF technologies.12 Adding to rolling stage (i.e. rolling billet

into rod in coils), total cost of electricity to manufacture long steel accounts for

around 35% and can even be more efficient.13This proportion is even much lower than

the proportion of the distorted cost of raw material in the China-Sink case.

41. Second, Vietnam’s electricity tariff during 2016 is almost at the same level with other

countries. Exhibit 6 provides the applicable tariff to electricity consumption for

production and business purpose in Vietnam and other countries including Indonesia,

11 Page 131-132, REP 238 Deep Drawn Stainless Steel Sinks- China

12 Cost of electricity to produce steel using BOF and EAF technologies can be found via

http://www.steelonthenet.com/cost-eaf.html and http://www.steelonthenet.com/cost-bof.html

13 Id.

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http://www.steelonthenet.com/cost-eaf.html

http://www.steelonthenet.com/cost-bof.html

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Thailand, Malaysia and Australia in 2016. Accordingly, Vietnam’s tariff is around

14% lower than the average of these countries and 9% lower than Indonesia.

42. As such, an uplift of 8%-14% to a cost that is approximately 35% of the total

manufacturing cost of rod in coils should not be considered strong evidence that

influence cost of electricity in Vietnam has had the impact of creating a market

situation in the rod in coil market.

43. In fact, electricity cost does not have any significant impact on the price of steel billet

and rod in coils in Vietnam. As indicated in Chart 5 below, fluctuations in electricity

tariffs had no correlation with the prices of steel billet in Vietnam’s market.

Chart 5: Electricity price changes and steel billet price developments in Vietnam

during 2012-2016

44. As can be seen, billet price reached its highest peak in 2012 when the electricity price

was lowest. Meanwhile, the former reduced almost by 50% when the latter reached

almost the highest level in 2015.

45. For all of reasons above, the GOV strongly requests the Commission to reject the

applicant’s position in its submission dated September 6, 2017 regarding the existence

of a particular market situation in Vietnam’s rod in coils market due to the GOV’s

influence on electricity and thus, render the applicant’s request for using Indonesia’s

billet cost of production groundless.

1.4 Steel billet

46. Regarding steel billet, as indicated in Exhibit 6 and 9 to the GOV’s Initial

Questionnaire Response, export tariff of steel billet was maintained at 0% for 2012-

2016 while import tariff for main foreign suppliers such as Japan and China were set

at various levels between 0% - 7%. In addition, steel billet is not subject to any import

or export restrictions. These are strong evidence that the GOV does not encourage the

importation and restrict the exportation of inputs to manufacture rod in coils as

alleged by the applicant.

47. In addition, as reported in the GOV’s Initial Questionnaire Response, effectively from

March 22, 2016, the GOV levied a safeguard tax of 23% on imported billet with a

17

Public Record

regular liberalization of 2% each year in order to rescue the domestic billet industry.

This, needless to say, results in increasing the price of steel billets in Vietnam.

Chart 7: Steel billet price in Vietnam after safeguard duty in 2016 in comparison

with price of Black sea areas

48. As a result, Vietnamese producers of rod in coils incurred a higher cost of production

of rod in coils given the fact that domestic production of billet did not satisfy the

consumption demand.14

49. Further, the GOV would note that all of its policy including import and export tariff

on iron ore, scrap steel, coking coal and coke were already reported to the

Commission in the Zinc Coated (Galvanized) Steel-Vietnam No 370 (hereinafter

referred to as Galvanized Steel-Vietnam), where the Commission concluded that there

is no evidence “to support a finding that the Government of Vietnam influenced or

distorted the prices or costs of the goods in the market, or any other conditions in the

market that would support a finding of a particular market situation in Vietnam.”15

Accordingly, the GOV requests the Commission to adopt the same findings as there

are no changes in terms of the GOV’s policies as reported in the Gavalnized Steel-

Vietnam case and this instant investigation.

50. As with galvanize steel producers, Vietnamese rod in coils manufacturers are totally

free from the GOV control to decide on their own production and sale price. Thus, the

GOV strongly opposes the applicant’s claim on the existence of the so-called

“artificially low” price of rod in coils sale in Vietnam market and requests the

Commission to conclude that there is no particular market situation in Vietnam that

may arise out of such claim.

2. There are no other conditions in the market rendering sales in Vietnam not

suitable for use in determining the normal value

14 As indicated in Exhibit 4 to the GOV’s Initial Questionnaire Response, total domestic supply of billet was 7.8 million tons in 2016 while the consumption quantity is more than 8.6 million tons. 15 Page 109-110, Final Report No.370, Alleged dumping of zinc coated (galvanized) steel exported to Australia from the Republic of India, Malaysia and the Socialist Republic of Vietnam.

18

Public Record

51. According the Antidumping and Subsidy Manual, other conditions in the market

which may render sales in that market not suitable for use in determining prices under

subsection 269TAC(1) may include:

differing patterns of demand in the exporter’s domestic market and the

sales to Australia (including domestic sales significantly different in

character or design features to the types exported; domestic sales

through a single sales channel (including via a related party

distributor); and unusual patterns of sales in the domestic market for

the good). Implicit in such findings is the assumption that it is not

possible to make reasonable adjustments to ensure comparability of

the domestic sales prices;

where only a single sale to one customer constitutes 5 per cent of the

sales to Australia;

significant barter trade; or

Non-commercial processing arrangements.”16

52. None of those conditions exist in this case. First, long steel products including rod in

coils are of high demand in Vietnam market due to the significant development of

infrastructure and housing construction all over the country. As estimated by the

Vietnam Steel Association, the domestic market in 2016 was in need of more than 3

million tons of rod in coils. The total production of the whole country was estimated

at around 1.3 million tons and 75%17 was served the domestic market. Thus, sales in

domestic market play a dominant proportion and are comparable to export sales for

purpose of dumping calculations.

53. In addition, the whole sector is majority owned by the private sector which are free to

decide what and how many to produce and who to sell. Therefore, rod in coils market

in Vietnam is an absolutely commercial market where producers are free to set up

different channels of sale including distribution and agents. Exhibit 9 provides a list of

distribution and agents of some rod in coils producers. Their sale prices in the

domestic markets show no relevance with any non-commercial arrangement or

significant barter trade or any other conditions that are sufficient to remove the

“commercial nature” out of the Vietnam market.

54. Therefore, the GOV is not aware of any other conditions in Vietnam’s rod in coils

market that may render domestic sales unsuitable for normal value determination.

16 Page 36, Dumping and Subsidy Manual 17 Total export of rod in coils by Vietnam in 2016 was 306,159 tons.

19

Public Record

II. In the event of an affirmative decision of a particular market situation in

Vietnam, the Commission is obliged to use Vietnam producers’ data of

production cost to construct the normal value.

55. Even if the Commission affirmatively determines that a particular market situation in

Vietnam exists in a manner that renders domestic sales of rod in coils in Vietnam

unsuitable for normal value calculation, it is obliged under Article 2.2 of the WTO

Antidumping Agreement to construct the normal value based on Vietnamese

producers’ data on cost of production or export sale to third countries.

56. Article 2.2 provides as below:

“ When there are no sales of the like product in the ordinary course of trade in the

domestic market of the exporting country or when, because of the particular market

situation or the low volume of the sales in the domestic market of the exporting

country(2), such sales do not permit a proper comparison, the margin of dumping

shall be determined by comparison with a comparable price of the like product when

exported to an appropriate third country, provided that this price is representative, or

with the cost of production in the country of origin plus a reasonable amount for

administrative, selling and general costs and for profits.”

57. As such, the existence of a particular market situation authorizes the Commission

only to disregard domestic sales of rod in coils in Vietnam for normal value

calculation. Either the cost of production incurred by Vietnamese producers or

representative sale prices of rod in coils to third countries must be applied to

determine normal value. Nothing in this Article further authorizes the Commission to

rely on a foreign benchmark of production cost to calculate the normal value as

requested by the applicant in this case. This interpretation is fully supported and

clarified by Article 2.2.1.1 as follows:

“For purpose of paragraph 2, costs “shall” normally be calculated on the basis of

records kept the exporter or producer under investigation, provided that such records

are in accordance with the generally accepted accounting principles of the exporting

country and reasonably reflect the costs associated with the production and sale of

the product under consideration.”

58. As long as the Vietnamese producer’s cost records comply with requirements under

Article 2.2.1.1, the Commission is obliged to calculate the cost of production based on

20

Public Record

the former’s records and data as a general principle. This Article does not require an

investigated producer’s cost to be on competitive basis in order for such cost records

to be used to construct normal value. Thus, the Commission is not authorized to use a

foreign cost benchmark to replace Vietnamese producers’ cost records merely because

the latter is not competitively based due to the existence of a particular market

situation in Vietnam.

59. The GOV’s position in this regard is supported by the WTO jurisprudence with

regards to the interpretation of Article 2.2 of the WTO Anti-dumping Agreement.

60. In EC-Tube or Pipe Fitting, the Appellate Body clearly indicated that Article 2.2.1.1

identified the records kept by the exporter or producer under investigation “to be the

preferred source for cost of production data.”18 Therefore, the Commission as the

investigation authority in this case is directed to base its calculation of costs on such

records when two conditions under this Article are met.

61. Moreover, in EU-Biodiesel – a dispute that addresses a similar situation where

Argentina challenged the EU’s departure from the Argentinian respondents’ recorded

costs of raw materials because of Argentina’s imposition of an export tax on soya-a

biodiesel input, the Appellate Body found that the EU’s departure acted inconsistently

with Article 2.2.1.1 and Article 2.2 of the WTO Anti-dumping Agreement. Therefore,

the GOV opines that the applicant’s request for substituting Indonesia’s steel billet

cost data for that of Vietnamese producers’ in this case would obviously amount to a

violation engaged by the EU in the Biodiesel case and thus, such request should be

dismissed by the Commission.

62. First, Article 2.2.1.1 of the WTO Antidumping Agreement requires the cost records to

“reasonably reflect” the cost actually incurred by the producers instead of insisting on

the reasonableness of the cost itself. In other words, this Article “requires a

comparison between the costs in the producer's or exporter's records and the costs

incurred by such producer or exporter. The object of the comparison is to establish

whether the records reasonably reflect the costs actually incurred, and not whether

they reasonably reflect some hypothetical costs that might have been incurred under a

different set of conditions or circumstances and which the investigating authority

considers more 'reasonable' than the costs actually incurred.”19 Therefore, in EU-

Biodiesel case, the mere affirmation by EU that the Argentina’s domestic prices of the

soya bean – main raw material used by biodiesel producers – were found to be

18 EC-Tube or Pipe Fittings, (DS219) AB report, para 99. 19 EU-Biodiesel, (DS473), AB report, para 6.41.

21

Public Record

artificially lower than international prices due to the distortion by Argentina

government’s export tax system “cannot serve as a sufficient basis under Article

2.2.1.1 for concluding that the producers' records do not reasonably reflect the costs

associated with the production and sale of biodiesel.20” Applying the same

interpretation in this rod in coils case, the applicant’s request for replacing

Vietnamese producers’ billet cost data with those of Indonesian by merely relying on

its alleged existence of “artificially low” prices of inputs to produce rod in coils in

Vietnam would present a violation of Article 2.2.1.1 in an exact manner with the EU

in the cited case. The GOV strongly believes that the Commission would carefully

take into account this issue in order to avoid this mistake.

63. Second, according to the Appellate Body, while Article 2.2 does not prohibit the

authority from relying on information other than that contained in the records kept by

the exporter or producer, including in-country and out-of-country evidence, this does

not mean that an investigating authority may simply substitute the costs from outside

the country of origin for the "cost of production in the country of origin" as suggested

by the applicant.21 According to the Appellate Body, Article 2.2 of the Anti-Dumping

Agreement and Article VI:1(b)(ii) of the GATT 1994 “make clear that the

determination is of the "cost of production […] in the country of origin". Thus,

whatever the information that it uses, an investigating authority has to ensure that

such information is used to arrive at the "cost of production in the country of origin.

Compliance with this obligation may require the investigating authority to adapt the

information that it collects22”. Thus, by replacing the actual cost of raw materials in

the Argentine producers’ records with the surrogate price of soybeans, the EU was

found not to adapt the information it used to arrive at the cost of production in

Argentina and thus, the arising cost was found not to represent the cost of production

in Argentina for purpose of constructing normal value as required by Article 2.2

64. In the rod in coils case, the applicant is repeating exactly the EU’s mistake when

requesting the Commission to just substitute the Vietnamese producer’s billet cost of

production data with those of Indonesia without any adapting attempt to ensure the

surrogate value may result in an arrival at the cost of production in Vietnam as

required by Article 2.2. Therefore, the GOV requests the Commission to reject the

applicant’s request for surrogate value.

20 Id, para 6.55. 21 Id, para6.73 22 Id.

22

Public Record

CONCLUSION

For the above analysis, the GOV once again urges the Commission to reject (i) the

applicant's claim on the existence of a particular market situation in Vietnam with regards to

rod in coils and (ii) its requests to replace Vietnamese producers's cost of production data

with those of Indonesia for purpose of constructing the normal value. In addition, in case

where the Commission decides to construct the normal value of rod in coils in this case, the

GOV requests the Commission to implement Australia's obligation under Article 2 of the

WTO Antidumping Agreement to ensure that the arising constructed normal value reflects

the the cost of production of rods in coils in Vietnam. The GOV also reverses its rights to

submit to the Commission additional comments in this matter within the schedule of the

authority in this investigation./

Respectfully .

IDVN Lawyers

Counsel for the Government of Vietnam

23

23

Column 1 Column 2 Column 3 Column 4 Column 5

Tariff Item Number

Description of Goods Base Rate

Category Note

2702.20.00.00.00 - Agglomerated lignite

5% B10

27.03 Peat (including peat litter), whether or not agglomerated.

2703.00.10.00.00 - Peat, whether or not compressed into bales, but not agglomerated

5% B10

2703.00.20.00.00 - Agglomerated peat

5% B10

27.04 Coke and semi-coke of coal, of lignite or of peat, whether or not agglomerated; retort carbon.

2704.00.10.00.00 - Coke and semi-coke of coal A 2704.00.20.00.00 - Coke and semi-coke of lignite or of

peat 5% B10

2704.00.30.00.00 - Retort carbon

5% B10

2705.00.00.00.00 Coal gas, water gas, producer gas and similar gases, other than petroleum gases and other gaseous hydrocarbons.

A

2706.00.00.00.00 Tar distilled from coal, from lignite or from peat, and other mineral tars, whether or not dehydrated or partially distilled, including reconstituted tars.

A

27.07 Oils and other products of the distillation of high temperature coal tar; similar products in which the weight of the aromatic constituents exceeds that of the non-aromatic constituents.

2707.10.00.00.00 - Benzol (benzene) 1% B10 2707.20.00.00.00 - Toluol (toluene) 1% B10 2707.30.00.00.00 - Xylol (xylenes) 1% B10 2707.40.00.00.00 - Naphthalene 1% B10 2707.50.00.00.00 - Other aromatic hydrocarbon mixtures of

which 65% or more by volume (including losses) distils at 250°C by the ASTM D 86 method

1% B10

- Other: 2707.91.00.00.00 - - Creosote oils 1% B10 2707.99 - - Other: 2707.99.20.00.00 - - - Carbon black feedstock 1% B10 2707.99.90.00.00 - - - Other

1% B10

27.08 Pitch and pitch coke, obtained from coal tar or from other mineral tars.

2708.10.00.00.00 - Pitch A 2708.20.00.00.00 - Pitch coke

A

27.09 Petroleum oils and oils obtained from bituminous minerals, crude.

2709.00.10.00.00 - Crude petroleum oil 15% B10 2709.00.20.00.00 - Condensates X 2709.00.90.00.00 - Other

X

Public Record Exhibit 2

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User

Typewriter

VJEPA TARIFF SCHEDULE

HS Code Description

Base

rate

(MFN

2005)

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

2022 and

subsequent

years

Viet Nam

Schedule of Tariff Commitments

Annex 1

2621.10.00.00 - Ash and residues from the incineration of

municipal waste

10% 10% 10% 10% 7% 5% 5% 5% 0% 0% 0% 0% 0% 0% 0%

2621.90.00.00 - Other 10% 10% 10% 10% 7% 5% 5% 5% 0% 0% 0% 0% 0% 0% 0%

27 Chapter 27-Mineral fuels, mineral oils and

products of their distillation; bituminous

substances; mineral waxes

27.01 Coal; briquettes, ovoids and similar solid

fuels manufactured from coal.

- Coal, whether or not pulverised, but not

agglomerated:

2701.11.00.00 - - Anthracite 5% 5% 5% 5% 5% 5% 5% 5% 0% 0% 0% 0% 0% 0% 0%

2701.12 - - Bituminous coal:

2701.12.10.00 - - - Coking coal 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2701.12.90.00 - - - Other 5% 5% 5% 5% 5% 5% 5% 5% 0% 0% 0% 0% 0% 0% 0%

2701.19.00.00 - - Other coal 5% 5% 5% 5% 5% 5% 5% 5% 0% 0% 0% 0% 0% 0% 0%

2701.20.00.00 - Briquettes, ovoids and similar solid fuels

manufactured from coal

5% 5% 5% 5% 5% 5% 5% 5% 0% 0% 0% 0% 0% 0% 0%

27.02 Lignite, whether or not agglomerated,

excluding jet.

2702.10.00.00 - Lignite, whether or not pulverised, but not

agglomerated

5% 5% 5% 5% 5% 5% 5% 5% 0% 0% 0% 0% 0% 0% 0%

2702.20.00.00 - Agglomerated lignite 5% 5% 5% 5% 5% 5% 5% 5% 0% 0% 0% 0% 0% 0% 0%

27.03 Peat (including peat litter), whether or not

agglomerated.

2703.00.10.00 - Peat, whether or not compressed into

bales, but not agglomerated

5% 5% 5% 5% 5% 5% 5% 5% 0% 0% 0% 0% 0% 0% 0%

2703.00.20.00 - Agglomerated peat 5% 5% 5% 5% 5% 5% 5% 5% 0% 0% 0% 0% 0% 0% 0%

27.04 Coke and semi-coke of coal, of lignite or

of peat, whether or not agglomerated;

retort carbon.

2704.00.10.00 - Coke and semi-coke of coal 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2704.00.20.00 - Coke and semi-coke of lignite or of peat 5% 5% 5% 5% 5% 5% 5% 5% 0% 0% 0% 0% 0% 0% 0%

2704.00.30.00 - Retort carbon 5% 5% 5% 5% 5% 5% 5% 5% 0% 0% 0% 0% 0% 0% 0%

2705.00.00.00 Coal gas, water gas, producer gas and

similar gases, other than petroleum gases

and other gaseous hydrocarbons.

0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

AANZFTA - Annex 1 (Viet Nam)

91 / 632


25

HS Code Description

Base

rate

(MFN

2005)

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

2022 and

subsequent

years

Viet Nam

Schedule of Tariff Commitments

Annex 1

2706.00.00.00 Tar distilled from coal, from lignite or from

peat, and other mineral tars, whether or not

dehydrated or partially distilled, including

reconstituted tars.

0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

27.07Oils and other products of the distillation

of high temperature coal tar; similar

products in which the weight of the

aromatic constituents exceeds that of the

non-aromatic constituents.

2707.10.00.00 - Benzol (benzene) 1% 1% 1% 1% 1% 1% 1% 1% 0% 0% 0% 0% 0% 0% 0%

2707.20.00.00 - Toluol (toluene) 1% 1% 1% 1% 1% 1% 1% 1% 0% 0% 0% 0% 0% 0% 0%

2707.30.00.00 - Xylol (xylenes) 1% 1% 1% 1% 1% 1% 1% 1% 0% 0% 0% 0% 0% 0% 0%

2707.40.00.00 - Naphthalene 1% 1% 1% 1% 1% 1% 1% 1% 0% 0% 0% 0% 0% 0% 0%

2707.50.00.00 - Other aromatic hydrocarbon mixtures of

which 65% or more by volume (including

losses) distils at 250°C by the ASTM D 86

method

1% 1% 1% 1% 1% 1% 1% 1% 0% 0% 0% 0% 0% 0% 0%

- Other:

2707.91.00.00 - - Creosote oils 1% 1% 1% 1% 1% 1% 1% 1% 0% 0% 0% 0% 0% 0% 0%

2707.99 - - Other:

2707.99.20.00 - - - Carbon black feedstock 1% 1% 1% 1% 1% 1% 1% 1% 0% 0% 0% 0% 0% 0% 0%

2707.99.90.00 - - - Other 1% 1% 1% 1% 1% 1% 1% 1% 0% 0% 0% 0% 0% 0% 0%

27.08 Pitch and pitch coke, obtained from coal

tar or from other mineral tars.

2708.10.00.00 - Pitch 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2708.20.00.00 - Pitch coke 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

27.09 Petroleum oils and oils obtained from

bituminous minerals, crude.

2709.00.10.00 - Crude petroleum oils 15% 15% 15% 10% 10% 7% 7% 5% 0% 0% 0% 0% 0% 0% 0%

2709.00.20.00 - Condensates 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5%

2709.00.90.00 - Other 15% 15% 15% 15% 15% 15% 15% 15% 15% 15% 15% 15% 15% 15% 15%

AANZFTA - Annex 1 (Viet Nam)

92 / 632


26

2015 2016 2017 2018No CC AHTN 2012 Description Schedule

ATIGA Tariff (%)


1719 VN 2701.12.10 - - - Coking coal Sch-A 0 0 0 0

1720 VN 2701.12.90 - - - Other Sch-A 0 0 0 0

1721 VN 2701.19.00 - - Other coal Sch-A 0 0 0 0

1722 VN 2701.20.00 - Briquettes, ovoids and similar solid fuels manufactured from coal Sch-A 0 0 0 0

27.02 Lignite, whether or not agglomerated, excluding jet.

1723 VN 2702.10.00 - Lignite, whether or not pulverised, but not agglomerated Sch-A 0 0 0 0

1724 VN 2702.20.00 - Agglomerated lignite Sch-A 0 0 0 0


1725 VN 2703.00.10 - Peat, whether or not compressed into bales, but not agglomerated Sch-A 0 0 0 0

1726 VN 2703.00.20 - Agglomerated peat Sch-A 0 0 0 0

2704.00Coke and semi-coke of coal, of lignite or of peat, whether or not

agglomerated; retort carbon.

1727 VN 2704.00.10 - Coke and semi-coke of coal Sch-A 0 0 0 0

1728 VN 2704.00.20 - Coke and semi-coke of lignite or of peat Sch-A 0 0 0 0

1729 VN 2704.00.30 - Retort carbon Sch-A 0 0 0 0

1730 VN 2705.00.00Coal gas, water gas, producer gas and similar gases, other than petroleum

gases and other gaseous hydrocarbons.Sch-A 0 0 0 0

1731 VN 2706.00.00Tar distilled from coal, from lignite or from peat, and other mineral tars,

whether or not dehydrated or partially distilled, including reconstituted tars.Sch-A 0 0 0 0

27.07

Oils and other products of the distillation of high temperature coal tar; similar

products in which the weight of the aromatic constituents exceeds that of the

non-aromatic constituents.

1732 VN 2707.10.00 - Benzol (benzene) Sch-A 0 0 0 0

1733 VN 2707.20.00 - Toluol (toluene) Sch-A 0 0 0 0

1734 VN 2707.30.00 - Xylol (xylenes) Sch-A 0 0 0 0

1735 VN 2707.40.00 - Naphthalene Sch-A 0 0 0 0

1736 VN 2707.50.00- Other aromatic hydrocarbon mixtures of which 65% or more by volume (including

losses) distils at 250°C by the ASTM D 86 methodSch-A 0 0 0 0

- Other:

1737 VN 2707.91.00 - - Creosote oils Sch-A 0 0 0 0

2707.99 - - Other:

1738 VN 2707.99.10 - - - Carbon black feedstock Sch-A 0 0 0 0

Page 91 of 515


27

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ATIGA TARIFF SCHEDULE

HS Code Description Base rate EIF 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 20262027 and subsequent

years

Viet Nam Schedule of Tariff Commitments

- Coal, whether or not pulverised, but not agglomerated:

2701.11.00 - - Anthracite 0 0 0 0 0 0 0 0 0 0 0 0 0 0


2701.12.10 - - - Coking coal 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2701.12.90 - - - Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2701.19.00 - - Other coal 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2701.20.00- Briquettes, ovoids and similar solid fuels manufactured

from coal0 0 0 0 0 0 0 0 0 0 0 0 0 0

27.02 Lignite, whether or not agglomerated, excluding jet.

2702.10.00- Lignite, whether or not pulverised, but not

agglomerated0 0 0 0 0 0 0 0 0 0 0 0 0 0

2702.20.00 - Agglomerated lignite 0 0 0 0 0 0 0 0 0 0 0 0 0 0


2703.00.10- Peat, whether or not compressed into bales, but not

agglomerated0 0 0 0 0 0 0 0 0 0 0 0 0 0

2703.00.20 - Agglomerated peat 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2704.00Coke and semi-coke of coal, of lignite or of peat, whether

or not agglomerated; retort carbon.

2704.00.10 - Coke and semi-coke of coal 3 2.5 2.0 1.5 1.0 0.5 0 0 0 0 0 0 0 0

2704.00.20 - Coke and semi-coke of lignite or of peat 3 2.5 2.0 1.5 1.0 0.5 0 0 0 0 0 0 0 0

2704.00.30 - Retort carbon 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2705.00.00Coal gas, water gas, producer gas and similar gases, other

than petroleum gases and other gaseous hydrocarbons.U U U U U U U U U U U U U

2706.00.00

Tar distilled from coal, from lignite or from peat, and

other mineral tars, whether or not dehydrated or partially

distilled, including reconstituted tars.

0 0 0 0 0 0 0 0 0 0 0 0 0 0

27.07

Oils and other products of the distillation of high

temperature coal tar; similar products in which the weight

of the aromatic constituents exceeds that of the non-

aromatic constituents.

118


28

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VEAEU TARIFF SCHEDULE

HS Code Description Base rate EIF 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 20262027 and subsequent

years

Viet Nam Schedule of Tariff Commitments

2707.10.00 - Benzol (benzene) 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2707.20.00 - Toluol (toluene) 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2707.30.00 - Xylol (xylenes) 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2707.40.00 - Naphthalene 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2707.50.00

- Other aromatic hydrocarbon mixtures of which 65% or

more by volume (including losses) distils at 250°C by the

ASTM D 86 method

0 0 0 0 0 0 0 0 0 0 0 0 0 0

- Other:

2707.91.00 - - Creosote oils 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2707.99 - - Other:

2707.99.10 - - - Carbon black feedstock 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2707.99.90 - - - Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0

27.08Pitch and pitch coke, obtained from coal tar or from other

mineral tars.

2708.10.00 - Pitch 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2708.20.00 - Pitch coke 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2709.00Petroleum oils and oils obtained from bituminous

minerals, crude.

2709.00.10 - Crude petroleum oils 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2709.00.20 - Condensates 0 0 0 0 0 0 0 0 0 0 0 0 0 0

2709.00.90 - Other 0 0 0 0 0 0 0 0 0 0 0 0 0 0

27.10

Petroleum oils and oils obtained from bituminous

minerals, other than crude; preparations not elsewhere

specified or included, containing by weight 70% or more

of petroleum oils or of oils obtained from bituminous

minerals, these oils being the basic constituents of the

preparations; waste oils.

- Petroleum oils and oils obtained from bituminous

minerals (other than crude) and preparations not

elsewhere specified or included, containing by weight 70

% or more of petroleum oils or of oils obtained from

bituminous minerals, these oils being the basic

constituents of the preparations, other than those

containing biodiesel and other than waste oils :

2710.12 - - Light oils and preparations :

- - - Motor spirit :

119


29

14

ANNEX 1

MODALITY FOR TARIFF REDUCTION AND ELIMINATION FOR TARIFF LINES PLACED IN THE NORMAL TRACK

1. Tariff lines placed by each Party in the Normal Track on its own accord shall have their respective applied MFN tariff rates gradually reduced and eliminated according to the following Schedules:

(i) ASEAN 6 and China

ACFTA Preferential Tariff Rate

(Not later than 1 January) X = Applied MFN Tariff Rate

2005* 2007 2009 2010

X > 20% 20 12 5 0

15% < x < 20% 15 8 5 0

10% < x < 15% 10 8 5 0

5% < x < 10% 5 5 0 0

X < 5% Standstill 0 0

* The first date of implementation shall be 1 July 2005. (ii) Viet Nam


(Not later than 1 January) X = Applied MFN Tariff Rate

2005* 2006 2007 2008 2009 2011 2013 2015

X > 60% 60 50 40 30 25 15 10 0

45% < X < 60% 40 35 35 30 25 15 10 0

35% < X < 45% 35 30 30 25 20 15 5 0

30% < X < 35% 30 25 25 20 17 10 5 0

25% < X < 30% 25 20 20 15 15 10 5 0

20% < X < 25% 20 20 15 15 15 10 0-5 0

15% < X < 20% 15 15 10 10 10 5 0-5 0

10% < X < 15% 10 10 10 10 8 5 0-5 0

7% < X < 10% 7 7 7 7 5 5 0-5 0

5% < X < 7% 5 5 5 5 5 5 0-5 0

X < 5% Standstill 0

* The first date of implementation shall be 1 July 2005.


30

User

Typewriter

ACFTA TARIFF SCHEDULE

15

(iii) Cambodia, Lao PDR and Myanmar


(Not later than 1 January) X = Applied

MFN Tariff Rate 2005* 2006 2007 2008 2009 2011 2013 2015

X > 60% 60 50 40 30 25 15 10 0

45% < X < 60% 40 35 35 30 25 15 10 0

35% < X < 45% 35 35 30 30 20 15 5 0

30% < X < 35% 30 25 25 20 20 10 5 0

25% < X < 30% 25 25 25 20 20 10 5 0

20% < X < 25% 20 20 15 15 15 10 0-5 0

15% < X < 20% 15 15 15 15 15 5 0-5 0

10% < X < 15% 10 10 10 10 8 5 0-5 0

7% < X < 10% 7** 7** 7** 7** 7** 5 0-5 0

5% < X < 7% 5 5 5 5 5 5 0-5 0

X < 5% Standstill 0

* The first date of implementation shall be 1 July 2005. ** Myanmar shall be allowed to maintain ACFTA Rates at no more than 7.5% until 2010.

2. If a Party places a tariff line in the Normal Track, that Party shall enjoy the tariff concessions other Parties have made for that tariff line as specified in and applied pursuant to the relevant Schedules either in Annex 1 or Annex 2 together with the undertakings and conditions set out therein. This right shall be enjoyed for so long as that Party adheres to its own commitments for tariff reduction and elimination for that tariff line.

3. The tariff rates specified in the relevant Schedules in paragraph 1 only set out the level of the applicable ACFTA preferential tariff rates to be applied by each Party for the tariff lines concerned in the specified year of implementation and shall not prevent any Party from unilaterally accelerating its tariff reduction or elimination at any time if it so wishes. 4. Tariff lines in the Normal Track, which are subject to specific tariff rates, shall have such tariffs reduced to zero, in equal proportions in accordance with the timeframes provided in the Schedules set out in paragraph 1 of this Annex. 5. For all tariff lines placed in the Normal Track where the applied MFN tariff rates are at 0%, they shall remain at 0%. Where they have been reduced to 0%, they shall remain at 0%. No Party shall be permitted to increase the tariff rates for any tariff line, except as otherwise provided by the Agreement.


31

16

6. As an integral part of its commitments to reduce and/or eliminate the applied MFN tariff rates in accordance with the relevant Schedules in paragraph 1, each Party hereby commits to undertake further tariff reduction and/or elimination in accordance with the following thresholds:

(a) ASEAN 6 and China

(i) Each Party shall reduce to 0-5% not later than 1 July 2005 the tariff rates for at least 40% of its tariff lines placed in the Normal Track.

(ii) Each Party shall reduce to 0-5% not later than 1 January 2007 the tariff rates for at least 60% of its tariff lines placed in the Normal Track.

(iii) Each Party shall eliminate all its tariffs for tariff lines placed in the Normal Track not later than 1 January 2010, with flexibility to have tariffs on some tariff lines, not exceeding 150 tariff lines, eliminated not later than 1 January 2012.

(iv) Each Party shall eliminate all its tariffs for tariff lines placed in the Normal Track not later than 1 January 2012.

(b) Newer ASEAN Member States

(i) Each Party shall reduce to 0-5% not later than 1 January 2009 for Viet Nam; 1 January 2010 for Lao PDR and Myanmar; and 1 January 2012 for Cambodia the tariff rates for at least 50% of its tariff lines placed in the Normal Track.

(ii) Cambodia, Lao PDR and Myanmar shall eliminate their respective tariffs not later than 1 January 2013 on 40% of its tariff lines placed in the Normal Track.

(iii) For Viet Nam, the percentage of Normal Track tariff lines to have their tariffs eliminated not later than 1 January 2013 shall be determined not later than 31 December 2004.

(iv) Each Party shall eliminate all its tariffs for tariff lines placed in the Normal Track not later than 1 January 2015, with flexibility to have tariffs on some tariff lines, not exceeding 250 tariff lines, eliminated not later than 1 January 2018.

(v) Each Party shall eliminate all its tariffs for tariff lines placed in the Normal Track not later than 1 January 2018.

7. The tariff lines listed by the Parties in Appendix 1 shall have their respective ACFTA tariffs eliminated not later than 1 January 2012 for ASEAN 6 and China, and 1 January 2018 for CLMV.


32

BP Statistical Review of World Energy 2017

BP Statistical Review of World Energy June 2017

This workbook contains information presented in the 2017 BP Statistical Review of World Energy, which can be found on the internet at:

http://www.bp.com/statisticalreview

Please use the contents or the tabs at the bottom to navigate between the tables.

Primary Energy: Consumption - Mtoe (from 1965)

Primary Energy: Consumption by fuel type - Mtoe (2015-2016)

Oil: Proved reserves

Oil: Proved reserves - Barrels (from 1980)

Oil: Production – Barrels (from 1965)

Oil: Production – Tonnes (from 1965)

Oil: Consumption – Barrels (from 1965)

Oil: Consumption – Tonnes (from 1965)

Oil: Regional consumption – by product (from 1965)

Oil: Spot crude prices

Oil: Crude prices since 1861

Oil: Refinery throughput (from 1980)

Oil: Refinery capacities (from 1965)

Oil: Regional refining margins (from 1992)

Oil: Trade movements (from 1980)

Oil: Inter-area movements

Oil: Trade 2015-2016

Gas: Proved reserves

Gas: Proved reserves - Bcm (from 1980)

Gas: Production – Bcm (from 1970)

Gas: Production – Bcf (from 1970)

Gas: Production – Mtoe (from 1970)

Gas: Consumption – Bcm (from 1965)

Gas: Consumption – Bcf (from 1965)

Gas: Consumption – Mtoe (from 1965)

Gas: Trade movements pipeline

Gas: Trade movements LNG

Gas: Trade 2015-2016


33

http://www.bp.com/statisticalreview


Gas: Prices

Coal: Reserves

Coal: Prices

Coal: Production - Tonnes (from 1981)

Coal: Production - Mtoe (from 1981)

Coal: Consumption - Mtoe (from 1965)

Nuclear Energy – Consumption - TWh (from 1965)

Nuclear Energy – Consumption - Mtoe (from 1965)

Hydroelectricity – Consumption - TWh (from 1965)

Hydroelectricity – Consumption - Mtoe (from 1965)

Renewables - Other renewables consumption -Twh (from 1965)

Renewables - Other renewables consumption - Mtoe (from 1965)

Renewables - Solar consumption - TWh (from 1965)

Renewables - Solar consumption - Mtoe (from 1965)

Renewables - Wind consumption - TWh (from 1965)

Renewables - Wind consumption - Mtoe (from 1965)

Renewables - Geothermal, Biomass and Other - TWh (from 1965)

Renewables - Geothermal, Biomass and Other - Mtoe (from 1965)

Renewables - Biofuels production - Kboe/d (from 1990)

Renewables - Biofuels production - Ktoe (from 1990)

Electricity Generation - TWh (from 1985)

Carbon Dioxide Emissions (from 1965)

Renewable Energy - Geothermal (Installed capacity)

Renewable Energy - Solar (Installed capacity)

Renewable Energy - Wind (Installed capacity)

Approximate conversion factors

Definitions


34


Primary Energy: Consumption*Share

Million tonnes oil equivalent 2012 2013 2014 2015 2016 2016 2005-15 2016

US 2209.3 2270.6 2296.5 2275.9 2272.7 -0.4% -0.3% 17.1%

Canada 326.5 336.1 334.3 327.7 329.7 0.3% 0.2% 2.5%

Mexico 188.5 189.1 190.4 188.8 186.5 -1.5% 1.2% 1.4%

Total North America 2724.3 2795.9 2821.2 2792.4 2788.9 -0.4% -0.2% 21.0%

Argentina 83.4 86.5 86.7 88.7 88.9 -0.1% 2.5% 0.7%

Brazil 284.8 296.8 304.9 302.6 297.8 -1.8% 3.7% 2.2%

Chile 34.1 34.4 35.4 35.9 36.8 2.0% 2.4% 0.3%

Colombia 38.4 38.2 40.3 41.0 41.1 ♦ 4.2% 0.3%

Ecuador 14.3 14.7 15.5 15.5 15.3 -1.3% 4.7% 0.1%

Peru 21.2 21.7 22.4 23.7 25.3 6.3% 5.7% 0.2%

Trinidad & Tobago 22.0 22.4 21.9 21.6 19.4 -10.7% 2.8% 0.1%

Venezuela 84.1 83.3 78.1 78.8 74.6 -5.5% 1.1% 0.6%

Other S. & Cent. America 98.7 98.7 98.9 102.6 106.2 3.3% 1.2% 0.8%

Total S. & Cent. America 680.9 696.7 704.1 710.4 705.3 -1.0% 2.8% 5.3%

Austria 35.4 35.1 33.8 33.9 35.1 3.3% -0.6% 0.3%

Azerbaijan 12.3 12.6 13.2 14.5 14.5 -0.4% 0.5% 0.1%

Belarus 27.9 24.7 25.5 22.4 23.7 5.4% -1.0% 0.2%

Belgium 58.7 60.0 55.8 56.9 61.7 8.1% -1.3% 0.5%

Bulgaria 18.1 16.7 17.9 19.0 18.1 -5.2% -0.3% 0.1%

Czech Republic 41.9 41.8 40.2 40.2 39.9 -1.0% -0.9% 0.3%

Denmark 17.1 17.9 17.4 16.9 17.1 1.1% -1.5% 0.1%

Finland 28.1 27.7 26.7 26.7 27.1 1.4% -1.2% 0.2%

France 244.8 247.2 237.6 239.4 235.9 -1.7% -0.9% 1.8%

Germany 316.4 325.5 312.1 317.8 322.5 1.2% -0.4% 2.4%

Greece 29.3 27.9 26.3 26.4 25.9 -2.2% -2.2% 0.2%

Hungary 21.1 20.1 20.0 21.2 21.9 3.2% -2.0% 0.2%

Ireland 14.0 13.7 13.7 14.5 15.2 4.1% -0.9% 0.1%

Italy 162.2 155.7 146.9 149.9 151.3 0.7% -2.1% 1.1%

Kazakhstan 59.4 60.2 66.4 62.7 63.0 0.3% 3.5% 0.5%

Lithuania 5.8 5.4 5.2 5.4 5.5 0.9% -3.7% ♦

Netherlands 88.1 85.9 80.9 82.1 84.5 2.6% -1.6% 0.6%

Norway 47.8 45.0 46.4 47.2 48.6 2.7% 0.3% 0.4%

Poland 95.7 96.0 92.4 93.4 96.7 3.2% 0.3% 0.7%

Portugal 22.4 24.5 24.6 24.6 26.0 5.5% -0.3% 0.2%

Romania 34.0 31.5 32.5 32.6 33.1 1.2% -1.8% 0.2%

Russian Federation 695.2 686.8 689.2 681.7 673.9 -1.4% 0.5% 5.1%

Slovakia 16.2 16.8 15.5 15.7 15.9 1.4% -1.9% 0.1%

Spain 142.4 134.2 132.2 134.4 135.0 0.2% -1.2% 1.0%

Sweden 54.5 51.3 51.4 52.9 52.2 -1.7% -0.5% 0.4%

Switzerland 28.8 29.7 28.5 27.9 26.4 -5.5% 0.2% 0.2%

Turkey 120.1 118.5 122.6 131.9 137.9 4.2% 4.4% 1.0%

Turkmenistan 29.7 26.8 29.5 33.1 33.2 0.2% 5.4% 0.3%

Ukraine 122.6 114.7 101.2 83.9 87.0 3.4% -4.7% 0.7%

United Kingdom 202.1 200.9 188.6 190.9 188.1 -1.7% -1.8% 1.4%

USSR n/a n/a n/a n/a n/a n/a n/a n/a

Uzbekistan 49.2 48.7 50.5 51.7 52.7 1.5% 1.1% 0.4%

Other Europe & Eurasia 95.0 97.0 93.6 94.8 97.6 2.6% 0.6% 0.7%

Total Europe & Eurasia 2936.3 2900.6 2838.3 2846.6 2867.1 0.4% -0.4% 21.6%

Iran 235.2 246.0 261.9 262.8 270.7 2.7% 4.0% 2.0%

Israel 25.2 25.2 24.5 26.0 26.4 1.5% 1.9% 0.2%

Kuwait 41.0 39.5 37.6 41.5 41.7 0.3% 3.1% 0.3%

Qatar 29.3 43.4 42.5 50.2 49.2 -2.3% 9.5% 0.4%

Saudi Arabia 235.7 237.4 252.1 260.8 266.5 1.9% 5.1% 2.0%

United Arab Emirates 95.8 97.2 99.5 108.6 113.8 4.5% 5.6% 0.9%

Other Middle East 118.7 123.6 121.9 124.7 126.8 1.4% 2.9% 1.0%

Total Middle East 780.8 812.4 840.0 874.6 895.1 2.1% 4.5% 6.7%

Algeria 45.1 47.8 51.6 55.1 55.1 -0.3% 5.4% 0.4%

Egypt 86.5 85.7 85.4 86.7 91.0 4.7% 3.4% 0.7%

South Africa 121.9 123.6 125.2 120.1 122.3 1.5% 0.8% 0.9%

Growth rate per annum


35


Other Africa 149.3 158.3 165.6 171.7 171.8 -0.2% 3.5% 1.3%

Total Africa 402.9 415.4 427.9 433.5 440.1 1.2% 2.8% 3.3%

Australia 130.3 131.2 132.6 138.5 138.0 -0.6% 1.8% 1.0%

Bangladesh 26.5 27.0 28.2 31.3 32.4 3.2% 6.3% 0.2%

China 2797.4 2905.3 2970.6 3005.9 3053.0 1.3% 5.3% 23.0%

China Hong Kong SAR 27.0 27.8 27.1 27.9 28.6 2.3% 1.8% 0.2%

India 611.6 621.5 663.6 685.1 723.9 5.4% 5.7% 5.5%

Indonesia 170.5 174.2 162.9 164.8 175.0 5.9% 3.0% 1.3%

Japan 467.7 464.0 452.3 445.8 445.3 -0.4% -1.6% 3.4%

Malaysia 83.2 89.2 91.5 93.8 99.5 5.7% 3.3% 0.7%

New Zealand 19.7 19.9 20.9 21.0 21.4 1.8% 1.1% 0.2%

Pakistan 71.4 71.7 73.5 77.1 83.2 7.6% 2.3% 0.6%

Philippines 30.5 32.5 34.4 37.7 42.1 11.3% 3.6% 0.3%

Singapore 72.0 74.1 76.2 81.0 84.1 3.5% 5.5% 0.6%

South Korea 271.8 272.2 274.9 280.2 286.2 1.9% 2.4% 2.2%

Taiwan 108.4 109.9 112.1 111.1 112.1 0.6% 0.7% 0.8%

Thailand 113.7 115.7 119.1 121.8 123.8 1.4% 3.5% 0.9%

Vietnam 52.5 54.8 59.8 63.7 64.8 1.5% 7.5% 0.5%

Other Asia Pacific 54.3 54.1 57.5 60.7 66.3 8.9% 2.4% 0.5%

Total Asia Pacific 5108.6 5245.0 5357.2 5447.4 5579.7 2.1% 3.9% 42.0%

Total World 12633.8 12866.0 12988.8 13105.0 13276.3 1.0% 1.8% 100.0%

of which: OECD 5481.8 5540.4 5497.6 5505.5 5529.1 0.2% -0.3% 41.6%

Non-OECD 7152.0 7325.6 7491.3 7599.5 7747.2 1.7% 3.7% 58.4%

European Union # 1681.2 1669.3 1605.0 1626.7 1642.0 0.7% -1.1% 12.4%

CIS 1014.6 991.9 993.2 967.4 965.6 -0.5% 0.2% 7.3%

* Commercial solid fuels only, i.e. bituminous coal and anthracite (hard coal), and lignite and brown (sub-bituminous) coal, and other commercial solid fuels.

Excludes coal converted to liquid or gaseous fuels, but includes coal consumed in transformation processes.

^ Less than 0.05.

w Less than 0.05%.

n/a not available.

# Excludes Estonia, Latvia and Lithuania prior to 1985 and Slovenia prior to 1990.

Notes: Differences between these consumption figures and the world production statistics are accounted for by stock changes, and unadvoidable disparities in the definition, measurement or conversion of coal supply and demand data.

Annual changes and share of total are calculated using million tonnes oil equivalent figures.

Growth rates are adjusted for leap years.


36


Primary Energy: Consumption by fuel*2015 2016

Million tonnes oil equivalent

Oil Natural

Gas

Coal Nuclear

Energy

Hydro

electric

Renew-

ables

Total Oil Natural

Gas

Coal Nuclear

Energy

Hydro

electric

Renew-

ables

Total

US 856.5 710.5 391.8 189.9 55.8 71.5 2275.9 863.1 716.3 358.4 191.8 59.2 83.8 2272.7

Canada 99.1 92.2 19.6 22.8 85.4 8.5 327.7 100.9 89.9 18.7 23.2 87.8 9.2 329.7

Mexico 84.4 78.4 12.7 2.6 7.0 3.7 188.8 82.8 80.6 9.8 2.4 6.8 4.1 186.5

Total North America 1040.0 881.2 424.2 215.3 148.2 83.6 2792.4 1046.9 886.8 386.9 217.4 153.9 97.1 2788.9

Argentina 32.2 43.4 1.4 1.6 9.6 0.6 88.7 31.9 44.6 1.1 1.9 8.7 0.7 88.9

Brazil 146.6 37.5 17.7 3.3 81.4 16.0 302.6 138.8 32.9 16.5 3.6 86.9 19.0 297.8

Chile 17.6 3.7 7.3 - 5.4 1.9 35.9 17.8 4.1 8.2 - 4.4 2.3 36.8

Colombia 15.6 9.6 5.3 - 10.1 0.4 41.0 15.9 9.5 4.6 - 10.6 0.5 41.1

Ecuador 11.8 0.6 - - 3.0 0.1 15.5 11.0 0.6 - - 3.5 0.1 15.3

Peru 10.7 6.4 0.8 - 5.4 0.4 23.7 11.4 7.1 0.8 - 5.4 0.6 25.3

Trinidad & Tobago 2.2 19.4 - - - ^ 21.6 2.2 17.2 - - - ^ 19.4

Venezuela 30.2 31.1 0.2 - 17.3 ^ 78.8 28.7 32.0 0.1 - 13.9 ^ 74.6

Other S. & Cent. America 67.5 6.6 3.2 - 20.8 4.5 102.6 68.5 6.7 3.4 - 22.5 5.1 106.2

Total S. & Cent. America 334.4 158.3 35.9 5.0 152.9 24.0 710.4 326.2 154.7 34.7 5.5 156.0 28.2 705.3

Austria 12.5 7.5 3.2 - 8.4 2.3 33.9 12.7 7.9 3.2 - 9.0 2.4 35.1

Azerbaijan 4.5 9.6 ^ - 0.4 ^ 14.5 4.6 9.4 ^ - 0.4 ^ 14.5

Belarus 7.7 14.0 0.7 - ^ ^ 22.4 7.5 15.3 0.8 - ^ 0.1 23.7

Belgium 31.0 13.6 3.2 5.9 0.1 3.2 56.9 31.8 13.9 3.0 9.8 0.1 3.2 61.7

Bulgaria 4.4 2.6 6.6 3.5 1.3 0.7 19.0 4.5 2.7 5.7 3.6 0.9 0.7 18.1

Czech Republic 8.9 6.5 16.6 6.1 0.4 1.7 40.2 8.4 7.0 16.9 5.5 0.5 1.7 39.9

Denmark 8.0 2.8 1.7 - ^ 4.3 16.9 8.0 2.9 2.1 - ^ 4.1 17.1

Finland 8.7 2.0 3.8 5.3 3.8 3.1 26.7 9.0 1.8 4.1 5.3 3.6 3.4 27.1

France 76.8 35.1 8.4 99.0 12.3 7.9 239.4 76.4 38.3 8.3 91.2 13.5 8.2 235.9

Germany 110.0 66.2 78.5 20.8 4.3 38.1 317.8 113.0 72.4 75.3 19.1 4.8 37.9 322.5

Greece 14.9 2.5 5.6 - 1.4 2.0 26.4 15.4 2.6 4.7 - 1.2 2.1 25.9

Hungary 7.0 7.5 2.4 3.6 0.1 0.7 21.2 7.1 8.0 2.3 3.6 0.1 0.8 21.9

Ireland 6.8 3.8 2.2 - 0.2 1.6 14.5 7.0 4.3 2.2 - 0.2 1.5 15.2

Italy 57.6 55.3 12.3 - 10.3 14.3 149.9 58.1 58.1 10.9 - 9.3 15.0 151.3

Kazakhstan 13.2 11.6 35.8 - 2.1 ^ 62.7 13.2 12.0 35.6 - 2.1 0.1 63.0

Lithuania 2.8 2.1 0.2 - 0.1 0.3 5.4 3.0 1.8 0.2 - 0.1 0.4 5.5

Netherlands 38.7 28.3 11.0 0.9 ^ 3.1 82.1 39.9 30.2 10.3 0.9 ^ 3.1 84.5

Norway 10.3 4.4 0.8 - 31.1 0.6 47.2 10.4 4.4 0.8 - 32.4 0.5 48.6

Poland 24.9 14.7 48.7 - 0.4 4.7 93.4 27.2 15.6 48.8 - 0.5 4.6 96.7

Portugal 11.5 4.3 3.3 - 2.0 3.6 24.6 11.2 4.6 2.9 - 3.6 3.7 26.0

Romania 9.2 9.0 5.9 2.6 3.8 2.2 32.6 9.5 9.5 5.4 2.6 4.1 2.0 33.1

Russian Federation 144.2 362.5 92.2 44.2 38.5 0.2 681.7 148.0 351.8 87.3 44.5 42.2 0.2 673.9


37


Slovakia 3.7 3.9 3.3 3.4 0.9 0.5 15.7 4.0 4.0 3.1 3.3 1.0 0.5 15.9

Spain 61.2 24.6 13.7 13.0 6.3 15.6 134.4 62.5 25.2 10.4 13.3 8.1 15.5 135.0

Sweden 14.1 0.8 2.1 12.8 17.0 6.1 52.9 14.7 0.8 2.2 14.2 14.1 6.1 52.2

Switzerland 10.7 2.6 0.1 5.3 8.5 0.7 27.9 10.2 2.7 0.1 4.8 7.8 0.8 26.4

Turkey 38.9 39.2 34.7 - 15.2 3.9 131.9 41.2 37.9 38.4 - 15.2 5.2 137.9

Turkmenistan 6.6 26.5 - - - ^ 33.1 6.7 26.6 - - - ^ 33.2

Ukraine 9.2 25.9 27.3 19.8 1.2 0.4 83.9 9.1 26.1 31.5 18.3 1.6 0.3 87.0

United Kingdom 71.8 61.3 23.0 15.9 1.4 17.5 190.9 73.1 69.0 11.0 16.2 1.2 17.5 188.1

USSR - - - - - - - - - - - - - -

Uzbekistan 2.7 45.2 1.1 - 2.7 ^ 51.7 2.8 46.2 1.0 - 2.7 ^ 52.7

Other Europe & Eurasia 33.3 13.6 23.0 1.9 20.7 2.3 94.8 34.5 13.9 23.0 1.8 21.7 2.5 97.6

Total Europe & Eurasia 865.9 909.2 471.3 263.9 194.7 141.6 2846.6 884.6 926.9 451.6 258.2 201.8 144.0 2867.1

Iran 84.5 171.7 1.6 0.8 4.1 0.1 262.8 83.8 180.7 1.7 1.4 2.9 0.1 270.7

Israel 11.4 7.6 6.7 - ^ 0.3 26.0 11.6 8.7 5.7 - ^ 0.4 26.4

Kuwait 22.3 19.2 - - - ^ 41.5 22.0 19.7 - - - ^ 41.7

Qatar 10.7 39.5 - - - ^ 50.2 11.7 37.5 - - - ^ 49.2

Saudi Arabia 166.6 94.0 0.1 - - ^ 260.8 167.9 98.4 0.1 - - ^ 266.5

United Arab Emirates 40.9 66.4 1.3 - - 0.1 108.6 43.5 69.0 1.3 - - 0.1 113.8

Other Middle East 76.5 45.9 0.5 - 1.8 0.1 124.7 77.3 47.1 0.5 - 1.8 0.2 126.8

Total Middle East 412.8 444.3 10.2 0.8 5.9 0.5 874.6 417.8 461.1 9.3 1.4 4.7 0.7 895.1

Algeria 19.5 35.5 0.1 - ^ ^ 55.1 18.9 36.0 0.1 - ^ 0.1 55.1

Egypt 39.6 43.0 0.4 - 3.2 0.4 86.7 40.6 46.1 0.4 - 3.2 0.6 91.0

South Africa 27.9 4.6 83.4 2.8 0.2 1.4 120.1 26.9 4.6 85.1 3.6 0.2 1.8 122.3

Other Africa 95.1 39.2 11.4 - 23.5 2.4 171.7 98.9 37.6 10.3 - 22.4 2.6 171.8

Total Africa 182.1 122.2 95.3 2.8 26.9 4.2 433.5 185.4 124.3 95.9 3.6 25.8 5.0 440.1

Australia 47.9 38.6 44.1 - 3.2 4.8 138.5 47.8 37.0 43.8 - 4.0 5.4 138.0

Bangladesh 6.2 24.2 0.7 - 0.2 ^ 31.3 6.6 24.8 0.8 - 0.2 ^ 32.4

China 561.8 175.3 1913.6 38.6 252.2 64.4 3005.9 578.7 189.3 1887.6 48.2 263.1 86.1 3053.0

China Hong Kong SAR 18.3 2.9 6.7 - - ^ 27.9 18.9 3.0 6.7 - - ^ 28.6

India 195.8 41.2 396.6 8.7 30.2 12.7 685.1 212.7 45.1 411.9 8.6 29.1 16.5 723.9

Indonesia 71.8 36.4 51.2 - 3.1 2.4 164.8 72.6 33.9 62.7 - 3.3 2.6 175.0

Japan 189.0 102.1 119.9 1.0 19.0 14.8 445.8 184.3 100.1 119.9 4.0 18.1 18.8 445.3

Malaysia 35.5 37.6 16.9 - 3.5 0.3 93.8 36.3 38.7 19.9 - 4.2 0.3 99.5

New Zealand 7.5 4.0 1.4 - 5.6 2.4 21.0 7.7 4.2 1.2 - 5.9 2.4 21.4

Pakistan 24.6 39.2 4.7 1.1 7.3 0.3 77.1 27.5 40.9 5.4 1.3 7.7 0.4 83.2

Philippines 18.3 3.0 11.6 - 2.0 2.8 37.7 19.9 3.4 13.5 - 2.1 3.1 42.1

Singapore 69.4 11.0 0.4 - - 0.2 81.0 72.2 11.3 0.4 - - 0.2 84.1

South Korea 113.8 39.3 85.5 37.3 0.5 3.9 280.2 122.1 40.9 81.6 36.7 0.6 4.3 286.2

Taiwan 46.5 16.5 37.8 8.3 1.0 1.0 111.1 46.7 17.2 38.6 7.2 1.5 1.0 112.1

Thailand 57.3 43.8 17.6 - 0.9 2.3 121.8 59.0 43.5 17.7 - 0.8 2.8 123.8

Vietnam 18.8 9.6 22.3 - 12.9 ^ 63.7 20.1 9.6 21.3 - 13.7 0.1 64.8


38


Other Asia Pacific 23.2 7.0 16.9 - 13.3 0.3 60.7 24.4 7.2 20.6 - 13.8 0.3 66.3

Total Asia Pacific 1505.8 631.6 2747.7 95.0 354.7 112.7 5447.4 1557.3 650.3 2753.6 105.9 368.1 144.5 5579.7

Total World 4341.0 3146.7 3784.7 582.7 883.2 366.7 13105.0 4418.2 3204.1 3732.0 592.1 910.3 419.6 13276.3

of which: OECD 2062.4 1464.9 972.7 446.7 309.9 248.9 5505.5 2086.8 1495.2 913.3 446.8 316.8 270.1 5529.1

Non-OECD 2278.5 1681.8 2812.0 136.0 573.4 117.8 7599.5 2331.4 1708.9 2818.7 145.2 593.4 149.5 7747.2

European Union 600.6 359.2 261.1 194.0 77.2 134.6 1626.7 613.3 385.9 238.4 190.0 78.7 135.6 1642.0

CIS 191.6 499.8 158.9 64.7 51.7 0.6 967.4 195.5 492.0 157.9 63.3 56.2 0.7 965.6

* In this review, primary energy comprises commercially traded fuels, including modern renewables used to generate electricity.

^ Less than 0.05.

Notes: Oil consumption is measured in million tonnes; other fuels in million tonnes of oil equivalent.


39


Oil: Total proved reserves at end 1996 at end 2006 at end 2015 at end 2016

Thousand Thousand Thousand Thousand Thousand

million million million million million Share R/P

barrels barrels barrels barrels tonnes of total ratio

US 29.8 29.4 48.0 48.0 5.8 2.8% 10.6

Canada 48.9 179.4 171.5 171.5 27.6 10.0% 105.1

Mexico 48.5 12.8 8.0 8.0 1.1 0.5% 8.9

Total North America 127.3 221.7 227.5 227.5 34.5 13.3% 32.3

Argentina 2.6 2.6 2.4 2.4 0.3 0.1% 10.6

Brazil 6.7 12.2 13.0 12.6 1.8 0.7% 13.3

Colombia 2.8 1.5 2.3 2.0 0.3 0.1% 5.9

Ecuador 3.5 4.5 8.0 8.0 1.2 0.5% 40.1

Peru 0.8 1.1 1.2 1.2 0.1 0.1% 24.0

Trinidad & Tobago 0.7 0.8 0.7 0.2 ^ ♦ 6.9

Venezuela 72.7 87.3 300.9 300.9 47.0 17.6% 341.1

Other S. & Cent. America 1.0 0.8 0.5 0.5 0.1 ♦ 10.3

Total S. & Cent. America 90.7 110.8 329.0 327.9 50.8 19.2% 119.9

Azerbaijan 1.2 7.0 7.0 7.0 1.0 0.4% 23.1

Denmark 0.9 1.2 0.5 0.4 0.1 ♦ 8.5

Italy 0.8 0.5 0.6 0.5 0.1 ♦ 18.8

Kazakhstan 5.3 9.0 30.0 30.0 3.9 1.8% 49.0

Norway 11.7 8.5 8.0 7.6 0.9 0.4% 10.4

Romania 1.0 0.5 0.6 0.6 0.1 ♦ 20.7

Russian Federation 113.6 104.0 102.4 109.5 15.0 6.4% 26.6

Turkmenistan 0.5 0.6 0.6 0.6 0.1 ♦ 6.3

United Kingdom 5.0 3.6 2.5 2.5 0.3 0.1% 6.9

Uzbekistan 0.6 0.6 0.6 0.6 0.1 ♦ 29.3

Other Europe & Eurasia 2.4 2.2 2.1 2.1 0.3 0.1% 15.6

Total Europe & Eurasia 142.8 137.6 154.9 161.5 21.8 9.5% 24.9

Iran 92.6 138.4 158.4 158.4 21.8 9.3% 94.1

Iraq 112.0 115.0 142.5 153.0 20.6 9.0% 93.6

Kuwait 96.5 101.5 101.5 101.5 14.0 5.9% 88.0

Oman 5.3 5.6 5.3 5.4 0.7 0.3% 14.6

Qatar 3.7 27.4 25.2 25.2 2.6 1.5% 36.3

Saudi Arabia 261.4 264.3 266.6 266.5 36.6 15.6% 59.0

Syria 2.5 3.0 2.5 2.5 0.3 0.1% 273.2

United Arab Emirates 97.8 97.8 97.8 97.8 13.0 5.7% 65.6

Yemen 2.0 2.8 3.0 3.0 0.4 0.2% *


40


Other Middle East 0.2 0.1 0.2 0.2 ^ ♦ 2.6

Total Middle East 674.0 755.9 803.0 813.5 110.1 47.7% 69.9

Algeria 10.8 12.3 12.2 12.2 1.5 0.7% 21.1

Angola 3.7 9.0 11.8 11.6 1.6 0.7% 17.5

Chad - 1.5 1.5 1.5 0.2 0.1% 56.1

Republic of Congo 1.6 1.6 1.6 1.6 0.2 0.1% 18.4

Egypt 3.8 3.7 3.5 3.5 0.5 0.2% 13.7

Equatorial Guinea 0.6 1.8 1.1 1.1 0.1 0.1% 10.7

Gabon 2.8 2.2 2.0 2.0 0.3 0.1% 24.1

Libya 29.5 41.5 48.4 48.4 6.3 2.8% 310.1

Nigeria 20.8 37.2 37.1 37.1 5.0 2.2% 49.3

South Sudan n/a n/a 3.5 3.5 0.5 0.2% 80.9

Sudan 0.3 5.0 1.5 1.5 0.2 0.1% 39.6

Tunisia 0.3 0.6 0.4 0.4 0.1 ♦ 18.4

Other Africa 0.7 0.7 3.7 3.7 0.5 0.2% 43.2

Total Africa 74.9 116.9 128.2 128.0 16.9 7.5% 44.3

Australia 3.8 3.5 4.0 4.0 0.4 0.2% 30.3

Brunei 1.1 1.2 1.1 1.1 0.1 0.1% 24.9

China 16.4 20.2 25.7 25.7 3.5 1.5% 17.5

India 5.5 5.7 4.8 4.7 0.6 0.3% 14.9

Indonesia 4.7 4.4 3.6 3.3 0.5 0.2% 10.3

Malaysia 5.0 5.4 3.6 3.6 0.5 0.2% 14.0

Thailand 0.2 0.5 0.4 0.4 ^ ♦ 2.3

Vietnam 0.9 3.3 4.4 4.4 0.6 0.3% 36.2

Other Asia Pacific 1.3 1.4 1.3 1.3 0.2 0.1% 12.5

Total Asia Pacific 39.0 45.5 48.8 48.4 6.4 2.8% 16.5

Total World 1148.8 1388.3 1691.5 1706.7 240.7 100.0% 50.6

of which: OECD 151.0 240.2 244.5 244.0 36.6 14.3% 28.8

Non-OECD 997.8 1148.1 1447.0 1462.7 204.1 85.7% 57.9

OPEC 805.0 936.1 1210.3 1220.5 171.2 71.5% 84.7

Non-OPEC 343.8 452.2 481.1 486.2 69.6 28.5% 25.2

European Union # 8.7 6.6 5.2 5.1 0.7 0.3% 9.3

CIS 121.9 121.9 141.1 148.2 20.1 8.7% 28.6

Canadian oil sands: Total 42.1 173.1 165.3 165.3 26.9

of which: Under active development 4.2 21.0 24.0 24.0 3.9

Venezuela: Orinoco Belt - 7.6 222.3 222.3 35.7

* More than 500 years.

^ Less than 0.05.

w Less than 0.05%.

# Excludes Estonia and Latvia in 2006.


41


Notes: Total proved reserves of oil - Generally taken to be those quantities that geological and engineering information indicates with reasonable certainty

can be recovered in the future from known reservoirs under existing economic and operating conditions. The data series for total proved oil does not necessarily

meet the definitions, guidelines and practices used for determining proved reserves at company level, for instance as published by the US Securities and Exchange Commission,

nor does it necessarily represent BP’s view of proved reserves by country.

Reserves-to-production (R/P) ratio - If the reserves remaining at the end of any year are divided by the production in that year, the result is the length of time

that those remaining reserves would last if production were to continue at that rate.

Gas Journal and independent estimates of Russian reserves based on official data and Chinese reserves based on information in the public domain.

Canadian oil sands 'under active development' are an official estimate. Venezuelan Orinoco Belt reserves are based on the OPEC Secretariat and government announcements.

Reserves include gas condensate and natural gas liquids (NGLs) as well as crude oil.

Shares of total and R/P ratios are calculated using thousand million barrels figures.

Source of data - The estimates in this table have been compiled using a combination of primary official sources, third-party data from the OPEC Secretariat, World Oil, Oil &


42


Oil: Proved reserves in thousand million barrelsShare

Thousand million barrels 2012 2013 2014 2015 2016 2016 2005-15 2016

US 44.2 48.5 55.0 48.0 48.0 - 4.8% 2.8%

Canada 173.7 173.0 172.2 171.5 171.5 - -0.5% 10.0%

Mexico 11.4 11.1 10.8 8.0 8.0 - -5.2% 0.5%

Total North America 229.3 232.6 237.9 227.5 227.5 - 0.2% 13.3%

Argentina 2.4 2.3 2.4 2.4 2.4 - 0.9% 0.1%

Brazil 15.3 15.6 16.2 13.0 12.6 -2.8% 1.0% 0.7%

Colombia 2.2 2.4 2.4 2.3 2.0 -13.3% 4.7% 0.1%

Ecuador 8.4 8.2 8.0 8.0 8.0 - 5.1% 0.5%

Peru 1.4 1.6 1.4 1.2 1.2 - 1.0% 0.1%

Trinidad & Tobago 0.8 0.8 0.8 0.7 0.2 -66.6% -1.0% ♦

Venezuela 297.7 298.3 300.0 300.9 300.9 - 14.2% 17.6%

Other S. & Cent. America 0.5 0.5 0.5 0.5 0.5 -3.0% -9.6% ♦


Azerbaijan 7.0 7.0 7.0 7.0 7.0 - - 0.4%

Denmark 0.7 0.7 0.6 0.5 0.4 -10.3% -9.1% ♦

Italy 0.6 0.6 0.6 0.6 0.5 -12.4% 3.0% ♦

Kazakhstan 30.0 30.0 30.0 30.0 30.0 - 12.8% 1.8%

Norway 7.5 7.0 6.5 8.0 7.6 -5.0% -1.9% 0.4%

Romania 0.6 0.6 0.6 0.6 0.6 - 2.7% ♦

Russian Federation 105.5 105.0 103.2 102.4 109.5 7.0% -0.2% 6.4%

Turkmenistan 0.6 0.6 0.6 0.6 0.6 - 0.9% ♦

United Kingdom 3.0 3.0 2.8 2.5 2.5 - -4.1% 0.1%


Uzbekistan 0.6 0.6 0.6 0.6 0.6 - - ♦

Other Europe & Eurasia 2.0 2.0 2.1 2.1 2.1 1.1% -0.6% 0.1%

Total Europe & Eurasia 158.2 157.2 154.6 154.9 161.5 4.3% 1.1% 9.5%

Iran 157.3 157.8 157.8 158.4 158.4 - 1.4% 9.3%

Iraq 140.3 144.2 143.1 142.5 153.0 7.4% 2.2% 9.0%

Kuwait 101.5 101.5 101.5 101.5 101.5 - - 5.9%

Oman 5.5 5.0 5.2 5.3 5.4 1.3% -0.5% 0.3%

Qatar 25.2 25.1 25.7 25.2 25.2 - -1.0% 1.5%

Saudi Arabia 265.9 265.9 267.0 266.6 266.5 ♦ 0.1% 15.6%

Syria 2.5 2.5 2.5 2.5 2.5 - -1.8% 0.1%

United Arab Emirates 97.8 97.8 97.8 97.8 97.8 - - 5.7%

Yemen 3.0 3.0 3.0 3.0 3.0 - 0.3% 0.2%

Other Middle East 0.3 0.3 0.2 0.2 0.2 -10.4% 5.5% ♦



43



Algeria 12.2 12.2 12.2 12.2 12.2 - -0.1% 0.7%

Angola 12.7 12.7 12.6 11.8 11.6 -1.8% 2.7% 0.7%

Chad 1.5 1.5 1.5 1.5 1.5 - - 0.1%

Republic of Congo 1.6 1.6 1.6 1.6 1.6 - 0.6% 0.1%

Egypt 4.2 3.9 3.7 3.5 3.5 - -0.7% 0.2%

Equatorial Guinea 1.7 1.7 1.1 1.1 1.1 - -4.8% 0.1%

Gabon 2.0 2.0 2.0 2.0 2.0 - -0.7% 0.1%

Libya 48.5 48.4 48.4 48.4 48.4 - 1.6% 2.8%

Nigeria 37.1 37.1 37.1 37.1 37.1 ♦ 0.2% 2.2%

South Sudan 3.5 3.5 3.5 3.5 3.5 - n/a 0.2%

Sudan 1.5 1.5 1.5 1.5 1.5 - 10.3% 0.1%

Tunisia 0.4 0.4 0.4 0.4 0.4 - -2.7% ♦

Other Africa 3.7 3.7 3.7 3.7 3.7 - 21.0% 0.2%

Total Africa 130.6 130.1 129.2 128.2 128.0 -0.2% 1.4% 7.5%

Australia 3.9 4.0 4.0 4.0 4.0 - 0.7% 0.2%

Brunei 1.1 1.1 1.1 1.1 1.1 - ♦ 0.1%

China 24.4 24.7 25.1 25.7 25.7 - 5.1% 1.5%

India 5.7 5.7 5.7 4.8 4.7 -2.3% -2.1% 0.3%

Indonesia 3.7 3.7 3.6 3.6 3.3 -8.2% -1.5% 0.2%

Malaysia 3.7 3.8 3.6 3.6 3.6 - -3.7% 0.2%

Thailand 0.4 0.5 0.4 0.4 0.4 - -1.3% ♦

Vietnam 4.4 4.4 4.4 4.4 4.4 - 3.5% 0.3%

Other Asia Pacific 1.1 1.3 1.3 1.3 1.3 -1.8% -0.9% 0.1%

Total Asia Pacific 48.5 49.1 49.3 48.8 48.4 -0.9% 1.8% 2.8%

Total World 1694.6 1701.8 1706.5 1691.5 1706.7 0.9% 2.1% 100.0%

of which: OECD 246.4 249.2 253.9 244.5 244.0 -0.2% ♦ 14.3%

Non-OECD 1448.2 1452.5 1452.7 1447.0 1462.7 1.1% 2.5% 85.7%

OPEC 1204.6 1209.1 1211.1 1210.3 1220.5 0.8% 2.7% 71.5%

Non-OPEC 490.0 492.7 495.5 481.1 486.2 1.1% 0.7% 28.5%

European Union # 6.0 5.8 5.6 5.2 5.1 -3.4% -2.9% 0.3%

CIS 144.2 143.7 141.9 141.1 148.2 5.1% 1.4% 8.7%

Canadian Oil Sands: Total 167.8 167.1 166.2 165.3 165.3 - -0.5% 9.7%

of which: Under active development 25.8 25.2 23.6 24.0 24.0 - 9.0% 1.4%

Venezuela: Orinoco Belt 220.0 220.5 221.7 222.3 222.3 - n/a 13.0%

^ Less than 0.05.

w Less than 0.05%.


'Remaining established reserves', less reserves 'under active development'.

Notes: Total proved reserves of oil - Generally taken to be those quantities that geological and engineering information indicates with reasonable certainty


44


can be recovered in the future from known reservoirs under existing economic and operating conditions. The data series for total proved oil does not necessarily



Reserves-to-production (R/P) ratio - If the reserves remaining at the end of any year are divided by the production in that year, the result is the length of time that those remaining reserves would last if

production were to continue at that rate.

Source of data - The estimates in this table have been compiled using a combination of primary official sources, third-party data from the OPEC Secretariat, World Oil, Oil &

Gas Journal and an independent estimates of Russian reserves based on official data and Chinese reserves based on information in the public domain.

Canadian oil sands 'under active development' are an official estimate. Venezuelan Orinoco Belt reserves are based on the OPEC Secretariat and government announcements.

Reserves include gas condensate and natural gas liquids (NGLs) as well as crude oil.

Annual changes and shares of total are calculated using thousand million barrels figures.


45

Oil: Production*Share

Thousand barrels daily 2012 2013 2014 2015 2016 2016 2005-15 2016

US 8894 10073 11779 12757 12354 -3.2% 6.3% 13.4%

Canada 3740 4000 4271 4389 4460 1.6% 3.7% 4.8%

Mexico 2911 2875 2784 2587 2456 -5.1% -3.7% 2.7%

Total North America 15545 16948 18833 19733 19270 -2.3% 3.7% 20.9%

Argentina 664 655 641 641 619 -3.3% -2.7% 0.7%

Brazil 2145 2110 2341 2525 2605 3.2% 4.0% 2.8%

Colombia 944 1004 990 1006 924 -8.1% 6.7% 1.0%

Ecuador 505 527 557 543 545 0.4% 0.2% 0.6%

Peru 154 167 169 145 135 -6.6% 2.6% 0.1%

Trinidad & Tobago 117 115 114 109 96 -11.2% -4.4% 0.1%

Venezuela 2704 2680 2692 2644 2410 -8.9% -2.2% 2.6%

Other S. & Cent. America 143 148 154 149 138 -7.5% 0.3% 0.2%

Total S. & Cent. America 7376 7407 7659 7761 7474 -3.7% 0.6% 8.1%

Azerbaijan 872 877 849 840 826 -1.6% 6.6% 0.9%

Denmark 204 178 167 158 142 -10.2% -8.4% 0.2%

Italy 112 116 121 115 79 -31.3% -1.0% 0.1%

Kazakhstan 1664 1737 1710 1695 1672 -1.4% 2.7% 1.8%

Norway 1917 1838 1889 1948 1995 2.4% -4.1% 2.2%

Romania 83 86 84 83 79 -5.0% -3.1% 0.1%

Russian Federation 10642 10780 10838 10981 11227 2.2% 1.4% 12.2%

Turkmenistan 229 240 249 261 261 ♦ 3.1% 0.3%

United Kingdom 946 864 852 963 1013 5.1% -6.2% 1.1%


Uzbekistan 68 61 59 57 55 -3.1% -6.7% 0.1%

Other Europe & Eurasia 390 397 388 379 367 -3.0% -1.8% 0.4%

Total Europe & Eurasia 17127 17174 17206 17479 17716 1.4% ♦ 19.2%

Iran 3819 3615 3725 3897 4600 18.0% -0.8% 5.0%

Iraq 3116 3141 3285 4031 4465 10.8% 8.2% 4.8%

Kuwait 3169 3129 3101 3068 3151 2.7% 1.4% 3.4%

Oman 918 942 943 981 1004 2.4% 2.4% 1.1%

Qatar 1931 1906 1886 1890 1899 0.5% 5.1% 2.1%

Saudi Arabia 11635 11393 11505 11986 12349 3.0% 0.9% 13.4%

Syria 171 59 33 27 25 -7.4% -24.5% ♦

United Arab Emirates 3401 3627 3674 3928 4073 3.7% 3.0% 4.4%

Yemen 174 193 147 44 16 -62.7% -20.3% ♦

Other Middle East 184 209 214 213 205 -3.8% 1.4% 0.2%

Total Middle East 28518 28213 28515 30065 31789 5.7% 1.6% 34.5%

Algeria 1537 1485 1589 1558 1579 1.4% -2.4% 1.7%

Angola 1784 1799 1712 1826 1807 -1.1% 3.6% 2.0%

Chad 101 83 82 73 73 0.6% -8.3% 0.1%

Republic of Congo 281 250 266 257 238 -7.6% 0.4% 0.3%

Egypt 715 710 714 726 691 -4.8% 0.8% 0.8%

Equatorial Guinea 272 267 281 289 280 -3.1% -2.1% 0.3%

Gabon 253 232 232 230 227 -1.1% -1.6% 0.2%

Libya 1510 988 498 432 426 -1.4% -13.0% 0.5%

Nigeria 2370 2270 2347 2329 2053 -11.9% -0.8% 2.2%

South Sudan 31 100 155 148 118 -20.0% n/a 0.1%



46

Sudan 103 118 120 109 104 -5.0% -9.4% 0.1%

Tunisia 84 78 73 65 63 -3.3% -2.0% 0.1%

Other Africa 205 231 236 255 233 -8.7% 3.7% 0.3%

Total Africa 9247 8612 8307 8297 7892 -4.9% -1.7% 8.6%

Australia 479 407 436 393 359 -8.7% -3.6% 0.4%

Brunei 159 135 126 127 121 -4.6% -4.7% 0.1%

China 4155 4216 4246 4309 3999 -7.2% 1.7% 4.3%

India 906 906 887 876 856 -2.3% 1.7% 0.9%

Indonesia 918 882 852 841 881 4.8% -2.6% 1.0%

Malaysia 654 621 645 699 705 0.9% -0.8% 0.8%

Thailand 458 452 450 468 479 2.5% 4.5% 0.5%

Vietnam 357 361 373 362 333 -8.1% -0.7% 0.4%

Other Asia Pacific 287 272 291 295 278 -5.9% 0.4% 0.3%

Total Asia Pacific 8372 8252 8307 8369 8010 -4.3% 0.5% 8.7%

Total World 86183 86606 88826 91704 92150 0.5% 1.1% 100.0%

of which: OECD 19482 20635 22588 23596 23122 -2.0% 1.7% 25.1%

Non-OECD 66701 65971 66238 68108 69028 1.4% 0.9% 74.9%

OPEC 37480 36561 36573 38133 39358 3.2% 0.8% 42.7%

Non-OPEC 48703 50045 52254 53572 52792 -1.5% 1.4% 57.3%

European Union # 1526 1434 1412 1506 1488 -1.2% -5.7% 1.6%

CIS 13597 13810 13810 13932 14141 1.5% 1.7% 15.3%

* Includes crude oil, shale oil, oil sands and NGLs (natural gas liquids - the liquid content of natural gas where this is recovered separately).

Excludes liquid fuels from other sources such as biomass and derivatives of coal and natural gas.

^ Less than 0.05.

w Less than 0.05%.


Notes: Annual changes and shares of total are calculated using thousand barrels daily figures.


47

Oil: Production*Share

Million tonnes 2012 2013 2014 2015 2016 2016 2005-15 2016

US 393.2 446.9 522.7 565.1 543.0 -4.2% 6.2% 12.4%

Canada 182.6 195.1 209.4 215.6 218.2 0.9% 4.2% 5.0%

Mexico 143.9 141.8 137.1 127.5 121.4 -5.1% -3.7% 2.8%

Total North America 719.6 783.8 869.2 908.3 882.6 -3.1% 3.6% 20.1%

Argentina 31.1 30.5 29.9 29.8 28.8 -3.7% -2.8% 0.7%

Brazil 112.4 110.2 122.5 132.2 136.7 3.1% 4.0% 3.1%

Colombia 49.9 52.9 52.2 53.0 48.8 -8.1% 6.7% 1.1%

Ecuador 27.1 28.2 29.8 29.1 29.3 0.4% 0.2% 0.7%

Peru 6.7 7.1 7.3 6.2 5.6 -10.4% 1.6% 0.1%

Trinidad & Tobago 5.2 5.1 5.1 4.8 4.3 -10.5% -5.0% 0.1%

Venezuela 139.3 137.8 138.5 135.9 124.1 -9.0% -2.2% 2.8%

Other S. & Cent. America 7.3 7.5 7.7 7.5 7.0 -7.5% 0.2% 0.2%


Azerbaijan 43.4 43.5 42.1 41.6 41.0 -1.7% 6.5% 0.9%

Denmark 10.0 8.7 8.1 7.7 6.9 -10.2% -8.4% 0.2%

Italy 5.4 5.6 5.8 5.5 3.8 -31.4% -1.0% 0.1%

Kazakhstan 79.3 82.3 81.1 80.2 79.3 -1.4% 2.7% 1.8%

Norway 87.3 83.2 85.3 88.0 90.4 2.4% -4.4% 2.1%

Romania 4.0 4.1 4.1 4.0 3.8 -5.3% -3.0% 0.1%

Russian Federation 526.2 531.1 534.1 540.7 554.3 2.2% 1.3% 12.6%

Turkmenistan 11.2 11.7 12.1 12.7 12.7 -0.4% 3.0% 0.3%

United Kingdom 44.7 40.7 40.0 45.4 47.5 4.4% -6.1% 1.1%


Uzbekistan 3.2 2.9 2.8 2.7 2.6 -3.3% -6.9% 0.1%

Other Europe & Eurasia 19.2 19.6 19.2 18.8 18.2 -3.3% -1.6% 0.4%

Total Europe & Eurasia 833.6 833.3 834.7 847.3 860.6 1.3% ♦ 19.6%

Iran 180.7 169.8 174.2 181.6 216.4 18.9% -1.3% 4.9%

Iraq 152.5 153.2 160.3 197.0 218.9 10.8% 8.2% 5.0%

Kuwait 153.9 151.3 150.1 148.2 152.7 2.8% 1.3% 3.5%

Oman 45.0 46.1 46.2 48.0 49.3 2.4% 2.4% 1.1%

Qatar 82.2 80.3 79.4 79.1 79.4 0.1% 4.2% 1.8%

Saudi Arabia 549.8 538.4 543.4 567.8 585.7 2.9% 0.9% 13.4%

Syria 8.1 2.7 1.5 1.2 1.1 -8.3% -25.1% ♦


Yemen 8.0 8.9 6.7 2.0 0.8 -60.8% -20.5% ♦

Other Middle East 9.0 10.3 10.5 10.5 10.1 -3.9% 1.5% 0.2%


Algeria 67.2 64.8 68.8 67.2 68.5 1.6% -2.5% 1.6%

Angola 86.9 87.3 83.0 88.7 87.9 -1.2% 3.5% 2.0%

Chad 5.3 4.4 4.3 3.8 3.8 0.6% -8.3% 0.1%

Republic of Congo 14.3 12.6 13.4 12.9 11.9 -7.8% 0.3% 0.3%

Egypt 34.7 34.4 35.1 35.4 33.8 -4.8% 0.7% 0.8%

Equatorial Guinea 12.7 12.4 13.1 13.5 13.1 -3.3% -1.9% 0.3%

Gabon 12.7 11.6 11.6 11.5 11.4 -1.1% -1.6% 0.3%

Libya 71.2 46.5 23.4 20.3 20.0 -1.5% -13.0% 0.5%

Nigeria 114.4 109.2 112.8 112.0 98.8 -12.1% -1.0% 2.3%

South Sudan 1.5 4.9 7.7 7.3 5.8 -20.0% n/a 0.1%



48

Sudan 5.1 5.8 5.9 5.4 5.1 -5.0% -9.4% 0.1%

Tunisia 3.9 3.6 3.4 3.0 2.9 -3.8% -2.1% 0.1%

Other Africa 10.2 11.5 11.7 12.6 11.6 -8.6% 3.7% 0.3%

Total Africa 440.1 408.9 394.2 393.7 374.8 -5.1% -1.7% 8.6%

Australia 21.4 17.8 19.1 17.4 15.5 -11.1% -3.7% 0.4%

Brunei 7.8 6.6 6.2 6.2 5.9 -4.7% -4.8% 0.1%

China 207.5 210.0 211.4 214.6 199.7 -7.2% 1.7% 4.6%

India 42.5 42.5 41.6 41.2 40.2 -2.6% 1.7% 0.9%

Indonesia 44.6 42.7 41.2 40.7 43.0 5.2% -2.7% 1.0%

Malaysia 29.8 28.5 29.7 32.3 32.7 0.9% -0.7% 0.7%

Thailand 16.6 16.5 16.2 17.0 17.6 3.2% 4.0% 0.4%

Vietnam 17.3 17.4 18.1 17.4 16.0 -8.5% -0.8% 0.4%

Other Asia Pacific 12.6 12.0 13.0 13.2 12.4 -6.2% 0.7% 0.3%


Total World 4116.4 4125.3 4226.2 4359.5 4382.4 0.3% 1.0% 100.0%

of which: OECD 902.1 953.8 1041.9 1086.4 1060.0 -2.7% 1.6% 24.2%

Non-OECD 3214.4 3171.5 3184.3 3273.0 3322.4 1.2% 0.8% 75.8%

OPEC 1780.0 1732.0 1730.1 1803.2 1864.2 3.1% 0.6% 42.5%

Non-OPEC 2336.4 2393.3 2496.1 2556.2 2518.2 -1.8% 1.3% 57.5%

European Union # 73.0 68.5 67.3 71.9 70.8 -1.8% -5.5% 1.6%

CIS 668.8 676.8 677.1 682.5 694.5 1.5% 1.6% 15.8%

* Includes crude oil, shale oil, oil sands and NGLs (natural gas liquids - the liquid content of natural gas where this is recovered separately).

Excludes liquid fuels from other sources such as biomass and derivatives of coal and natural gas.

^ Less than 0.05.

w Less than 0.05%.


Notes: Annual changes and shares of total are calculated using million tonnes figures.



49

Oil: Consumption*Share


US 18490 18961 19106 19531 19631 0.5% -0.6% 20.3%

Canada 2340 2383 2372 2299 2343 1.9% 0.1% 2.4%

Mexico 2063 2020 1943 1923 1869 -2.8% -0.5% 1.9%

Total North America 22894 23364 23421 23753 23843 0.4% -0.6% 24.7%

Argentina 636 683 674 692 687 -0.7% 4.4% 0.7%

Brazil 2901 3110 3239 3170 3018 -4.8% 4.1% 3.1%

Chile 376 362 371 376 378 0.6% 3.5% 0.4%

Colombia 297 298 316 333 340 2.3% 3.5% 0.4%

Ecuador 233 247 260 254 239 -5.9% 4.2% 0.2%

Peru 213 227 225 240 256 6.9% 4.7% 0.3%

Trinidad & Tobago 40 45 42 45 44 -3.9% 2.8% ♦

Venezuela 792 782 719 648 611 -5.7% 0.7% 0.6%

Other S. & Cent. America 1339 1319 1324 1381 1402 1.5% 0.3% 1.5%


Austria 259 264 259 259 263 1.5% -1.0% 0.3%

Azerbaijan 92 101 99 99 99 -0.2% -0.7% 0.1%

Belarus 211 145 165 156 152 -2.2% 0.3% 0.2%

Belgium 622 636 635 666 675 1.4% -0.3% 0.7%

Bulgaria 82 76 82 92 96 4.0% -1.1% 0.1%

Czech Republic 192 184 195 189 178 -6.0% -1.0% 0.2%

Denmark 158 158 160 164 164 0.5% -1.3% 0.2%

Finland 193 191 183 184 189 2.6% -2.2% 0.2%

France 1676 1664 1616 1616 1602 -0.9% -1.8% 1.7%

Germany 2356 2408 2348 2340 2394 2.3% -1.0% 2.5%

Greece 312 295 294 306 313 2.5% -2.9% 0.3%

Hungary 129 129 144 153 154 0.9% -0.3% 0.2%

Ireland 135 137 136 142 147 2.9% -2.9% 0.2%

Italy 1346 1260 1184 1222 1232 0.9% -3.8% 1.3%

Kazakhstan 245 260 265 289 287 -0.6% 4.1% 0.3%

Lithuania 55 53 53 57 61 6.5% ♦ 0.1%

Netherlands 926 898 866 835 851 1.9% -2.2% 0.9%

Norway 235 243 232 238 242 1.7% 0.6% 0.3%

Poland 553 520 521 541 589 8.8% 1.1% 0.6%

Portugal 230 239 238 245 236 -3.5% -3.1% 0.2%

Romania 191 174 187 191 197 3.2% -1.3% 0.2%


Slovakia 74 75 71 77 83 8.5% -0.4% 0.1%

Spain 1291 1195 1191 1237 1268 2.5% -2.5% 1.3%

Sweden 309 306 308 300 313 4.3% -1.7% 0.3%

Switzerland 238 249 224 228 216 -5.2% -1.3% 0.2%

Turkey 680 718 741 839 886 5.7% 2.5% 0.9%

Turkmenistan 129 137 143 147 148 0.8% 3.0% 0.2%

Ukraine 267 257 222 198 195 -1.1% -3.9% 0.2%

United Kingdom 1533 1518 1511 1565 1597 2.1% -1.5% 1.7%


Uzbekistan 63 60 57 57 58 0.8% -5.7% 0.1%

Other Europe & Eurasia 692 683 660 683 705 3.2% -0.1% 0.7%

Total Europe & Eurasia 18594 18370 18287 18450 18793 1.9% -0.9% 19.5%



50

Iran 1854 2014 1961 1850 1848 -0.1% 0.9% 1.9%

Israel 295 247 231 247 251 1.9% -0.4% 0.3%

Kuwait 541 512 480 506 499 -1.3% 2.1% 0.5%

Qatar 257 287 293 316 339 7.5% 11.2% 0.4%

Saudi Arabia 3462 3470 3726 3868 3906 1.0% 5.8% 4.0%


Other Middle East 1586 1646 1631 1588 1600 0.7% 1.8% 1.7%


Algeria 370 387 390 425 412 -3.1% 5.5% 0.4%

Egypt 747 756 806 830 853 2.8% 3.0% 0.9%

South Africa 554 569 564 583 560 -3.9% 1.2% 0.6%

Other Africa 1900 2007 2012 2028 2111 4.1% 2.9% 2.2%

Total Africa 3571 3720 3771 3866 3937 1.8% 2.9% 4.1%

Australia 1036 1046 1045 1039 1036 -0.3% 1.8% 1.1%

Bangladesh 110 107 116 124 131 5.6% 4.5% 0.1%

China 10230 10734 11209 11986 12381 3.3% 5.7% 12.8%

China Hong Kong SAR 344 352 336 368 380 3.4% 2.5% 0.4%

India 3685 3727 3849 4164 4489 7.8% 4.8% 4.6%

Indonesia 1625 1639 1663 1592 1615 1.4% 2.0% 1.7%

Japan 4702 4516 4303 4139 4037 -2.5% -2.5% 4.2%

Malaysia 760 803 802 814 829 1.9% 2.5% 0.9%

New Zealand 148 151 154 160 164 2.3% 0.6% 0.2%

Pakistan 402 442 458 505 566 12.0% 5.0% 0.6%

Philippines 309 322 347 398 434 9.0% 2.4% 0.4%

Singapore 1202 1225 1268 1336 1382 3.4% 5.3% 1.4%

South Korea 2458 2455 2454 2577 2763 7.2% 1.1% 2.9%

Taiwan 983 1010 1032 1040 1046 0.6% -0.1% 1.1%

Thailand 1250 1298 1311 1355 1382 2.0% 2.9% 1.4%

Vietnam 369 371 389 407 431 6.0% 4.7% 0.4%

Other Asia Pacific 416 435 458 491 512 4.3% 4.6% 0.5%

Total Asia Pacific 30031 30636 31195 32494 33577 3.3% 2.8% 34.8%

Total World 90675 92114 93025 95003 96558 1.6% 1.2% 100.0%

of which: OECD 45512 45583 45184 45785 46217 0.9% -0.9% 47.9%

Non-OECD 45163 46531 47840 49218 50341 2.3% 3.6% 52.1%

European Union # 12955 12702 12500 12707 12942 1.8% -1.7% 13.4%

CIS 4205 4177 4326 4161 4223 1.5% 1.3% 4.4%

* Inland demand plus international aviation and marine bunkers and refinery fuel and loss. Consumption of biogasoline (such as ethanol), biodiesel and derivatives of coal and natural gas are also included.

w Less than 0.05%.

n/a not available.


Notes: Differences between these world consumption figures and world production statistics are accounted for by stock changes, consumption of non-petroleum additives

and substitute fuels, and unavoidable disparities in the definition, measurement or conversion of oil supply and demand data.

Annual changes and shares of total are calculated using thousand barrels daily figures.


51

Oil: Consumption*Share

Million tonnes 2012 2013 2014 2015 2016 2016 2005-15 2016

US 817.0 832.1 838.1 856.5 863.1 0.5% -0.9% 19.5%

Canada 102.3 103.5 103.1 99.1 100.9 1.5% ♦ 2.3%

Mexico 92.3 89.8 85.4 84.4 82.8 -2.1% -0.7% 1.9%

Total North America 1011.6 1025.4 1026.6 1040.0 1046.9 0.4% -0.8% 23.7%

Argentina 29.6 31.9 31.3 32.2 31.9 -1.1% 4.5% 0.7%

Brazil 134.3 144.2 150.6 146.6 138.8 -5.6% 4.0% 3.1%

Chile 17.5 16.8 17.4 17.6 17.8 0.4% 3.5% 0.4%

Colombia 13.9 13.9 14.8 15.6 15.9 2.0% 3.7% 0.4%

Ecuador 10.9 11.6 12.2 11.8 11.0 -6.6% 4.1% 0.2%

Peru 9.6 10.1 10.0 10.7 11.4 6.8% 4.1% 0.3%

Trinidad & Tobago 2.0 2.3 2.1 2.2 2.2 -4.3% 2.9% ♦

Venezuela 37.2 36.7 33.6 30.2 28.7 -5.3% 0.7% 0.6%



Austria 12.5 12.7 12.5 12.5 12.7 1.3% -1.2% 0.3%

Azerbaijan 4.2 4.5 4.4 4.5 4.6 1.5% -1.7% 0.1%

Belarus 10.4 7.1 8.1 7.7 7.5 -2.5% 0.2% 0.2%

Belgium 29.6 30.1 29.7 31.0 31.8 2.3% -0.8% 0.7%

Bulgaria 3.9 3.6 3.9 4.4 4.5 2.9% -1.0% 0.1%

Czech Republic 9.0 8.5 9.1 8.9 8.4 -6.2% -1.1% 0.2%

Denmark 7.8 7.7 7.8 8.0 8.0 0.3% -1.4% 0.2%

Finland 9.1 9.0 8.6 8.7 9.0 2.6% -2.4% 0.2%

France 80.3 79.3 76.9 76.8 76.4 -0.8% -1.9% 1.7%

Germany 111.4 113.4 110.4 110.0 113.0 2.4% -1.1% 2.6%

Greece 15.3 14.5 14.4 14.9 15.4 2.8% -3.0% 0.3%

Hungary 5.9 5.9 6.6 7.0 7.1 1.3% -0.5% 0.2%

Ireland 6.5 6.5 6.5 6.8 7.0 3.0% -3.1% 0.2%

Italy 64.2 59.4 55.8 57.6 58.1 0.5% -4.0% 1.3%

Kazakhstan 11.5 12.1 12.3 13.2 13.2 -0.2% 3.5% 0.3%

Lithuania 2.7 2.6 2.6 2.8 3.0 6.7% 0.1% 0.1%

Netherlands 43.7 41.4 39.6 38.7 39.9 2.8% -2.5% 0.9%

Norway 10.5 10.8 10.2 10.3 10.4 0.7% 0.2% 0.2%

Poland 25.7 23.8 23.9 24.9 27.2 8.8% 1.1% 0.6%

Portugal 11.0 11.3 11.1 11.5 11.2 -3.2% -3.5% 0.3%

Romania 9.2 8.4 9.0 9.2 9.5 3.4% -1.4% 0.2%


Slovakia 3.6 3.6 3.4 3.7 4.0 8.6% -0.4% 0.1%

Spain 64.7 59.3 59.0 61.2 62.5 1.8% -2.6% 1.4%

Sweden 14.6 14.4 14.5 14.1 14.7 3.7% -1.9% 0.3%

Switzerland 11.2 11.8 10.6 10.7 10.2 -5.4% -1.3% 0.2%

Turkey 31.6 33.5 34.3 38.9 41.2 5.6% 2.4% 0.9%

Turkmenistan 6.0 6.2 6.5 6.6 6.7 0.8% 2.9% 0.2%

Ukraine 12.5 11.9 10.3 9.2 9.1 -0.9% -3.9% 0.2%

United Kingdom 71.4 70.3 69.8 71.8 73.1 1.7% -1.5% 1.7%


Uzbekistan 3.0 2.9 2.7 2.7 2.8 0.7% -6.1% 0.1%





52

Iran 85.7 93.6 90.4 84.5 83.8 -1.1% 0.5% 1.9%

Israel 13.9 11.5 10.6 11.4 11.6 1.9% -0.7% 0.3%

Kuwait 24.4 22.7 21.0 22.3 22.0 -1.5% 1.3% 0.5%

Qatar 8.2 9.3 9.7 10.7 11.7 9.2% 11.6% 0.3%

Saudi Arabia 146.2 147.3 159.8 166.6 167.9 0.5% 5.9% 3.8%




Algeria 16.8 17.6 17.7 19.5 18.9 -3.2% 5.8% 0.4%

Egypt 35.3 35.8 38.3 39.6 40.6 2.3% 2.9% 0.9%

South Africa 26.5 27.3 27.0 27.9 26.9 -3.6% 1.2% 0.6%

Other Africa 90.0 94.8 94.5 95.1 98.9 3.7% 2.8% 2.2%

Total Africa 168.6 175.4 177.5 182.1 185.4 1.5% 2.8% 4.2%

Australia 47.9 48.2 48.1 47.9 47.8 -0.3% 1.9% 1.1%

Bangladesh 5.4 5.3 5.8 6.2 6.6 6.0% 4.8% 0.1%

China 487.1 508.1 528.0 561.8 578.7 2.7% 5.5% 13.1%


India 173.6 175.3 180.8 195.8 212.7 8.3% 4.9% 4.8%

Indonesia 74.4 74.5 75.3 71.8 72.6 0.8% 1.6% 1.6%

Japan 217.7 207.4 197.0 189.0 184.3 -2.8% -2.6% 4.2%

Malaysia 32.9 34.9 34.9 35.5 36.3 1.8% 2.4% 0.8%

New Zealand 7.0 7.1 7.2 7.5 7.7 1.8% 0.7% 0.2%

Pakistan 20.0 21.9 22.6 24.6 27.5 11.4% 4.9% 0.6%

Philippines 14.4 14.9 16.1 18.3 19.9 8.5% 2.1% 0.5%

Singapore 63.4 64.2 65.8 69.4 72.2 3.7% 5.3% 1.6%

South Korea 108.8 108.3 107.9 113.8 122.1 7.1% 0.8% 2.8%

Taiwan 44.6 45.1 46.1 46.5 46.7 0.1% -0.6% 1.1%

Thailand 52.3 54.5 55.0 57.3 59.0 2.6% 2.2% 1.3%

Vietnam 17.1 17.3 18.0 18.8 20.1 6.2% 4.4% 0.5%



Total World 4176.2 4220.9 4254.8 4341.0 4418.2 1.5% 1.0% 100.0%

of which: OECD 2071.7 2059.3 2036.7 2062.4 2086.8 0.9% -1.1% 47.2%

Non-OECD 2104.5 2161.6 2218.1 2278.5 2331.4 2.0% 3.4% 52.8%

European Union # 618.8 601.7 590.8 600.6 613.3 1.8% -1.9% 13.9% CIS 195.9 192.7 200.0 191.6 195.5 1.8% 1.0% 4.4%

♦ Less than 0.05%.

n/a not available.


and substitute fuels, and unavoidable disparities in the definition, measurement or conversion of oil supply and demand data.

Annual changes and shares of total are calculated using million tonnes figures.


* Inland demand plus international aviation and marine bunkers and refinery fuel and loss. Consumption of biogasoline (such as ethanol), biodiesel

and derivatives of coal and natural gas are also included.

Notes: Differences between these world consumption figures and world production statistics are accounted for by stock changes, consumption of non-


53

Oil: Regional consumption - by product groupShare


North America

Light distillates 10572 10778 10841 11088 11312 2.0% 0.1% 47.4%

of which: gasoline 10225 10388 10479 10741 10957 2.0% 0.2% 46.0%

Middle distillates 6409 6519 6801 6812 6750 -0.9% -0.6% 28.3%

of which: diesel/gasoil 4822 4888 5125 5046 4918 -2.6% -0.5% 20.6%

of which: jet/kerosene 1587 1631 1676 1766 1833 3.8% -0.9% 7.7%

Fuel oil 662 576 447 419 505 20.5% -11.3% 2.1%

Others 5251 5492 5332 5435 5276 -2.9% ♦ 22.1%

Total North America 22894 23364 23421 23753 23843 0.4% -0.6% 100.0%

of which: US

Light distillates 8932 9125 9164 9413 9556 1.5% -0.1% 48.7%

of which: gasoline 8682 8843 8921 9178 9327 1.6% ♦ 47.5%

Middle distillates 5278 5371 5632 5657 5594 -1.1% -0.9% 28.5%

of which: diesel/gasoil 3875 3931 4153 4102 3981 -3.0% -0.8% 20.3%


Fuel oil 367 317 256 258 356 37.8% -11.9% 1.8%

Others 3913 4147 4054 4203 4125 -1.8% 0.1% 21.0%

Total US 18490 18961 19106 19531 19631 0.5% -0.6% 100.0%

S. & Cent. America

Light distillates 2019 2118 2178 2231 2214 -0.7% 4.1% 31.7%

of which: gasoline 1831 1953 2018 2059 2032 -1.3% 4.7% 29.1%

Middle distillates 2635 2760 2774 2749 2696 -2.0% 3.7% 38.6%

of which: diesel/gasoil 2320 2440 2439 2411 2361 -2.1% 3.7% 33.8%

of which: jet/kerosene 315 320 335 338 334 -1.0% 3.3% 4.8%

Fuel oil 740 715 734 730 663 -9.2% -0.7% 9.5%

Others 1432 1481 1484 1429 1403 -1.8% 1.9% 20.1%


Europe & Eurasia

Light distillates 4325 4272 4208 4143 4144 ♦ -1.9% 22.1%

of which: gasoline 3198 3145 3134 3077 3071 -0.2% -1.7% 16.3%

Middle distillates 8839 8859 8787 9071 9269 2.2% 0.5% 49.3%

of which: diesel/gasoil 7299 7315 7194 7448 7609 2.2% 0.4% 40.5%

of which: jet/kerosene 1540 1544 1593 1623 1660 2.3% 0.6% 8.8%

Fuel oil 1499 1387 1369 1235 1306 5.7% -6.0% 7.0%

Others 3932 3852 3924 4000 4074 1.8% -0.6% 21.7%

Total Europe & Eurasia 18594 18370 18287 18450 18793 1.9% -0.9% 100.0%

of which: CIS

Light distillates 1300 1338 1329 1327 1314 -1.0% 2.3% 31.1%

of which: gasoline 1126 1141 1144 1118 1110 -0.7% 2.5% 26.3%


of which: diesel/gasoil 1074 1078 1026 991 1025 3.4% 1.9% 24.3%


Fuel oil 361 369 435 347 370 6.8% -3.6% 8.8%

Others 1149 1090 1219 1209 1236 2.3% 1.9% 29.3%

Total CIS 4205 4177 4326 4161 4223 1.5% 1.3% 100.0%

of which: USSR



54

Light distillates n/a n/a n/a n/a n/a n/a n/a n/a

of which: gasoline n/a n/a n/a n/a n/a n/a n/a n/a

Middle distillates n/a n/a n/a n/a n/a n/a n/a n/a

of which: diesel/gasoil n/a n/a n/a n/a n/a n/a n/a n/a

of which: jet/kerosene n/a n/a n/a n/a n/a n/a n/a n/a

Fuel oil n/a n/a n/a n/a n/a n/a n/a n/a

Others n/a n/a n/a n/a n/a n/a n/a n/a

Total USSR n/a n/a n/a n/a n/a n/a n/a n/a

of which: European Union


of which: gasoline 1904 1838 1828 1798 1798 ♦ -3.4% 13.9%

Middle distillates 6696 6674 6618 6875 7020 2.1% -0.1% 54.2%

of which: diesel/gasoil 5566 5540 5482 5705 5804 1.7% -0.2% 44.8%

of which: jet/kerosene 1130 1134 1136 1170 1216 4.0% ♦ 9.4%

Fuel oil 1028 909 839 797 848 6.4% -6.6% 6.5%

Others 2419 2400 2370 2432 2466 1.4% -1.8% 19.1%

Total European Union * 12955 12702 12500 12707 12942 1.8% -1.7% 100.0%

Middle East






Fuel oil 2042 2080 2211 2235 2192 -1.9% 3.9% 23.2%

Others 2223 2209 2276 2384 2525 5.9% 4.2% 26.8%


Africa






Fuel oil 440 438 437 431 421 -2.3% -0.5% 10.7%

Others 583 595 586 609 634 4.1% 1.9% 16.1%

Total Africa 3571 3720 3771 3866 3937 1.8% 2.9% 100.0%

Asia






Fuel oil 3216 2987 2828 2808 2898 3.2% -2.0% 8.6%Others 7083 7209 7523 7799 8310 6.5% 3.9% 24.7%


of which: China







55

Fuel oil 560 564 592 591 617 4.4% -4.1% 5.0%

Others 2932 2998 3179 3408 3683 8.1% 5.6% 29.7%

Total China 10230 10734 11209 11986 12381 3.3% 5.7% 100.0%

of which: Japan

Light distillates 1614 1631 1575 1610 1560 -3.1% -1.0% 38.6%

of which: gasoline 981 952 924 915 908 -0.8% -1.5% 22.5%


of which: diesel/gasoil 821 817 803 787 787 0.1% -3.7% 19.5%


Fuel oil 824 646 532 433 368 -14.9% -4.4% 9.1%

Others 903 895 876 816 817 0.2% -2.2% 20.3%

Total Japan 4702 4516 4303 4139 4037 -2.5% -2.5% 100.0%

World






Fuel oil 8598 8182 8027 7858 7986 1.6% -2.3% 8.3%

Others 20505 20837 21125 21656 22223 2.6% 1.7% 23.0%

Total World 90675 92114 93025 95003 96558 1.6% 1.2% 100.0%

OECD


of which: gasoline 13861 13941 13987 14226 14450 1.6% -0.4% 31.3%


of which: diesel/gasoil 12635 12719 12871 13111 13111 ♦ -0.2% 28.4%


Fuel oil 2822 2424 2071 1905 2005 5.2% -7.6% 4.3%

Others 9502 9696 9441 9548 9484 -0.7% -0.6% 20.5%

Total OECD 45512 45583 45184 45785 46217 0.9% -0.9% 100.0%

Non-OECD






Fuel oil 5776 5759 5957 5953 5981 0.5% 0.4% 11.9%

Others 11002 11142 11685 12108 12739 5.2% 4.1% 25.3%

Total Non-OECD 45163 46531 47840 49218 50341 2.3% 3.6% 100.0%

* Excludes Estonia, Latvia, Lithuania prior to 1992 and Slovenia prior to 1990.

w Less than 0.05%.

n/a not available.

Notes: ‘Light distillates’ consists of aviation and motor gasolines and light distillate feedstock (LDF).

‘Middle distillates’ consists of jet and heating kerosenes, and gas and diesel oils (including marine bunkers).

‘Fuel oil’ includes marine bunkers and crude oil used directly as fuel.

‘Others’ consists of refinery gas, liquefied petroleum gas (LPG), solvents, petroleum coke, lubricants, bitumen, wax, other refined products and refinery fuel and loss.




56

Oil: Spot crude prices

Dubai Brent Nigerian West Texas

Forcados Intermdiate

US dollars per barrel $/bbl * $/bbl † $/bbl $/bbl ‡

1972 1.90 - - -

1973 2.83 - - -

1974 10.41 - - -

1975 10.70 - - -

1976 11.63 12.80 12.87 12.23

1977 12.38 13.92 14.21 14.22

1978 13.03 14.02 13.65 14.55

1979 29.75 31.61 29.25 25.08

1980 35.69 36.83 36.98 37.96

1981 34.32 35.93 36.18 36.08

1982 31.80 32.97 33.29 33.65

1983 28.78 29.55 29.54 30.30

1984 28.06 28.78 28.14 29.39

1985 27.53 27.56 27.75 27.98

1986 13.10 14.43 14.46 15.10

1987 16.95 18.44 18.39 19.18

1988 13.27 14.92 15.00 15.97

1989 15.62 18.23 18.30 19.68

1990 20.45 23.73 23.85 24.50

1991 16.63 20.00 20.11 21.54

1992 17.17 19.32 19.61 20.57

1993 14.93 16.97 17.41 18.45

1994 14.74 15.82 16.25 17.21

1995 16.10 17.02 17.26 18.42

1996 18.52 20.67 21.16 22.16

1997 18.23 19.09 19.33 20.61

1998 12.21 12.72 12.62 14.39

1999 17.25 17.97 18.00 19.31

2000 26.20 28.50 28.42 30.37

2001 22.81 24.44 24.23 25.93

2002 23.74 25.02 25.04 26.16

2003 26.78 28.83 28.66 31.07

2004 33.64 38.27 38.13 41.49

2005 49.35 54.52 55.69 56.59

2006 61.50 65.14 67.07 66.02

2007 68.19 72.39 74.48 72.20

2008 94.34 97.26 101.43 100.06

2009 61.39 61.67 63.35 61.92

2010 78.06 79.50 81.05 79.45

2011 106.18 111.26 113.65 95.04

2012 109.08 111.67 114.21 94.13

2013 105.47 108.66 111.95 97.99

2014 97.07 98.95 101.35 93.28

2015 51.20 52.39 54.41 48.71

2016 41.19 43.73 44.54 43.34

* 1972 - 1985 Arabian Light, 1986 - 2016 Dubai dated.

† 1976 -1983 Forties, 1984 -2016 Brent dated.


57

‡ 1976 -1983 Posted WTI prices, 1984 -2016 Spot WTI (Cushing) prices.


58


59


60


61


62


63


64


65

Oil: Crude oil prices 1861 - 2016

US dollars per barrel

Year $ money of the day $ 2016

1861 0.49 13.04

1862 1.05 25.14

1863 3.15 61.15

1864 8.06 123.18

1865 6.59 102.91

1866 3.74 61.06

1867 2.41 41.22

1868 3.63 65.19

1869 3.64 65.37

1870 3.86 72.97

1871 4.34 86.60

1872 3.64 72.63

1873 1.83 36.51

1874 1.17 24.72

1875 1.35 29.39

1876 2.56 57.46

1877 2.42 54.32

1878 1.19 29.48

1879 0.86 22.06

1880 0.95 23.53

1881 0.86 21.30

1882 0.78 19.32

1883 1.00 25.65

1884 0.84 22.35

1885 0.88 23.41

1886 0.71 18.89

1887 0.67 17.82

1888 0.88 23.41

1889 0.94 25.01

1890 0.87 23.15

1891 0.67 17.82

1892 0.56 14.90

1893 0.64 17.03

1894 0.84 23.21

1895 1.36 39.08

1896 1.18 33.90

1897 0.79 22.70

1898 0.91 26.15

1899 1.29 37.06

1900 1.19 34.19

1901 0.96 27.58

1902 0.80 22.10

1903 0.94 25.01

1904 0.86 22.88

1905 0.62 16.49

1906 0.73 19.42

1907 0.72 18.47

1908 0.72 19.15

1909 0.70 18.62

1910 0.61 15.65


66

1911 0.61 15.65

1912 0.74 18.33

1913 0.95 22.98

1914 0.81 19.33

1915 0.64 15.12

1916 1.10 24.16

1917 1.56 29.18

1918 1.98 31.53

1919 2.01 27.88

1920 3.07 36.76

1921 1.73 23.19

1922 1.61 23.04

1923 1.34 18.84

1924 1.43 20.06

1925 1.68 22.99

1926 1.88 25.48

1927 1.30 17.96

1928 1.17 16.38

1929 1.27 17.78

1930 1.19 17.10

1931 0.65 10.24

1932 0.87 15.28

1933 0.67 12.40

1934 1.00 17.91

1935 0.97 16.95

1936 1.09 18.87

1937 1.18 19.71

1938 1.13 19.24

1939 1.02 17.61

1940 1.02 17.44

1941 1.14 18.57

1942 1.19 17.51

1943 1.20 16.64

1944 1.21 16.50

1945 1.05 13.99

1946 1.12 13.75

1947 1.90 20.40

1948 1.99 19.83

1949 1.78 17.91

1950 1.71 17.04

1951 1.71 15.78

1952 1.71 15.45

1953 1.93 17.30

1954 1.93 17.22

1955 1.93 17.29

1956 1.93 17.04

1957 1.90 16.18

1958 2.08 17.26

1959 2.08 17.11

1960 1.90 15.38

1961 1.80 14.43

1962 1.80 14.27

1963 1.80 14.11

1964 1.80 13.91

1965 1.80 13.68


67

1966 1.80 13.31

1967 1.80 12.93

1968 1.80 12.41

1969 1.80 11.78

1970 1.80 11.12

1971 2.24 13.26

1972 2.48 14.23

1973 3.29 17.77

1974 11.58 56.39

1975 11.53 51.44

1976 12.80 53.98

1977 13.92 55.09

1978 14.02 51.61

1979 31.61 104.50

1980 36.83 107.27

1981 35.93 94.87

1982 32.97 82.00

1983 29.55 71.21

1984 28.78 66.48

1985 27.56 61.47

1986 14.43 31.60

1987 18.44 38.95

1988 14.92 30.28

1989 18.23 35.28

1990 23.73 43.57

1991 20.00 35.25

1992 19.32 33.05

1993 16.97 28.19

1994 15.82 25.62

1995 17.02 26.80

1996 20.67 31.62

1997 19.09 28.55

1998 12.72 18.72

1999 17.97 25.89

2000 28.50 39.72

2001 24.44 33.13

2002 25.02 33.38

2003 28.83 37.61

2004 38.27 48.62

2005 54.52 67.00

2006 65.14 77.55

2007 72.39 83.79

2008 97.26 108.42

2009 61.67 68.99

2010 79.50 87.50

2011 111.26 118.71

2012 111.67 116.73

2013 108.66 111.95

2014 98.95 100.31

2015 52.39 53.05

2016 43.73 43.73

1861-1944 US Average.

1945-1983 Arabian Light posted at Ras Tanura.

1984-2016 Brent dated.


68

$2016 (deflated using the Consumer Price Index for the US)


69

Oil: Refinery throughputsShare

Thousand barrels daily* 2012 2013 2014 2015 2016 2016 2005-15 2016

US 14999 15312 15848 16188 16202 0.1% 0.6% 20.1%

Canada 1751 1719 1640 1635 1594 -2.5% -1.2% 2.0%

Mexico 1199 1224 1155 1064 933 -12.3% -1.9% 1.2%

Total North America 17949 18255 18643 18887 18729 -0.8% 0.3% 23.3%

Argentina 530 527 526 536 511 -4.7% ♦ 0.6%

Brazil 1889 2035 2085 1972 1831 -7.2% 1.5% 2.3%

Chile 164 174 174 165 163 -1.0% -2.3% 0.2%

Colombia 305 284 247 244 339 39.0% -2.0% 0.4%

Curacao 165 170 189 178 173 -2.6% -1.9% 0.2%

Ecuador 152 141 125 121 150 24.5% -2.2% 0.2%

Netherlands Antilles n/a n/a n/a n/a n/a n/a n/a n/a

Peru 189 183 185 182 185 1.6% 0.1% 0.2%

Trinidad & Tobago 107 132 105 125 148 18.2% -2.7% 0.2%

Venezuela 936 952 920 863 698 -19.2% -1.6% 0.9%

Other S. & Cent. America 335 301 295 316 291 -7.7% -10.9% 0.4%

Total S. & Cent. America 4771 4899 4851 4702 4490 -4.5% -1.5% 5.6%

Austria 170 174 173 179 164 -8.3% 0.1% 0.2%

Azerbaijan 124 132 135 130 117 -9.8% -1.3% 0.1%

Belarus 434 425 448 462 392 -15.1% 1.5% 0.5%

Belgium 634 555 645 644 640 -0.5% ♦ 0.8%

Bulgaria 118 113 104 121 125 3.4% -0.2% 0.2%

Czech Republic 145 134 151 145 109 -25.1% -0.7% 0.1%

Denmark 153 144 139 147 140 -4.9% -0.5% 0.2%

Finland 215 227 225 197 226 14.6% -0.2% 0.3%

France 1138 1117 1096 1152 1111 -3.5% -3.9% 1.4%

Germany 1901 1857 1833 1875 1887 0.6% -2.0% 2.3%

Greece 410 399 416 436 464 6.6% 1.5% 0.6%

Hungary 122 120 131 130 133 2.3% -0.8% 0.2%

Ireland 61 57 55 68 64 -4.9% 0.2% 0.1%

Italy 1475 1259 1198 1347 1300 -3.5% -3.3% 1.6%

Kazakhstan 331 341 361 342 339 -1.1% 4.6% 0.4%

Lithuania 181 192 160 170 185 8.4% -0.9% 0.2%

Netherlands 1144 1044 1067 1138 1147 0.8% -1.0% 1.4%

Norway 287 292 274 293 230 -21.6% 0.2% 0.3%

Poland 505 488 486 532 517 -2.9% 3.5% 0.6%

Portugal 221 239 217 278 273 -1.8% 0.5% 0.3%

Romania 182 189 194 208 228 9.9% -2.9% 0.3%

Russian Federation 5438 5636 5926 5773 5709 -1.1% 3.3% 7.1%

Slovakia 108 116 105 119 116 -2.9% 0.9% 0.1%

Spain 1186 1168 1185 1304 1303 ♦ 0.9% 1.6%

Sweden 417 332 380 401 395 -1.6% -0.3% 0.5%

Switzerland 68 97 98 56 59 4.3% -5.2% 0.1%

Turkey 398 421 406 526 532 1.3% 0.1% 0.7%

Turkmenistan 157 160 163 157 153 -2.8% 1.1% 0.2%

Ukraine 108 85 69 64 65 0.9% -16.1% 0.1%

United Kingdom 1348 1197 1125 1118 1069 -4.3% -3.6% 1.3%


Uzbekistan 62 58 62 63 70 11.5% -5.0% 0.1%



70

Other Europe & Eurasia 134 140 132 148 158 6.6% -3.2% 0.2%

Total Europe & Eurasia 19376 18908 19158 19724 19420 -1.5% -0.3% 24.1%

Iran 1932 1999 1932 1867 1891 1.3% 1.4% 2.3%

Iraq 579 598 487 409 440 7.6% -1.4% 0.5%

Israel 219 238 245 250 232 -7.4% 2.3% 0.3%

Kuwait 916 873 879 913 830 -9.2% 0.6% 1.0%

Qatar 292 270 261 253 280 10.8% 8.2% 0.3%

Saudi Arabia 1953 1876 2201 2479 2750 11.0% 2.2% 3.4%


Other Middle East 719 685 671 629 605 -3.8% -2.1% 0.8%


Algeria 478 492 615 591 584 -1.1% 5.2% 0.7%

Egypt 534 523 525 535 508 -5.0% -1.7% 0.6%

South Africa 401 411 461 441 477 8.1% -0.3% 0.6%

Other Africa 797 827 625 532 533 0.3% -6.6% 0.7%

Total Africa 2210 2254 2226 2099 2102 0.2% -1.7% 2.6%

Australia 600 588 538 427 433 1.5% -3.4% 0.5%

Bangladesh 24 27 24 25 23 -10.1% 1.1% ♦

China 9199 9599 10155 10684 11023 3.2% 6.2% 13.7%

India 4302 4462 4475 4561 4931 8.1% 5.9% 6.1%

Indonesia 820 822 848 836 885 5.8% -1.6% 1.1%

Japan 3400 3453 3289 3258 3280 0.7% -2.4% 4.1%

Malaysia 575 558 553 508 537 5.6% ♦ 0.7%

New Zealand 109 105 101 109 108 -1.4% 1.3% 0.1%

Pakistan 192 223 232 257 242 -5.7% 1.1% 0.3%

Philippines 170 158 168 212 216 1.7% 0.3% 0.3%

Singapore 1020 936 871 897 965 7.6% -2.7% 1.2%

South Korea 2582 2484 2516 2784 2928 5.2% 1.8% 3.6%

Taiwan 897 847 850 838 861 2.7% -2.2% 1.1%

Thailand 978 1078 1029 1132 1096 -3.2% 2.2% 1.4%

Vietnam 142 145 125 145 148 2.5% 32.0% 0.2%

Other Asia Pacific 89 97 96 92 107 16.8% -0.9% 0.1%


Total World 76653 77086 78083 79905 80550 0.8% 0.8% 100.0%

of which: OECD 37130 36733 36912 37965 37752 -0.6% -0.5% 46.9%

Non-OECD 39523 40353 41171 41940 42798 2.0% 2.1% 53.1%

European Union # 11895 11181 11132 11766 11660 -0.9% -1.5% 14.5%

CIS 6656 6840 7168 6996 6849 -2.1% 2.3% 8.5%

Source: Includes data from ICIS.

* Atmospheric distillation capacity on a calendar-day basis.

w Less than 0.05%.


Note: Annual changes and shares of total are calculated using thousand barrels daily figures.


71

Oil: Refinery CapacitiesShare

Thousand barrels daily* 2012 2013 2014 2015 2016 2016 2005-15 2016

US 17824 17925 17889 18315 18621 1.7% 0.5% 19.1%

Canada 2050 1965 1965 1966 1967 ♦ 0.4% 2.0%

Mexico 1606 1606 1522 1522 1522 - 0.4% 1.6%

Total North America 21479 21495 21375 21803 22110 1.4% 0.5% 22.7%

Argentina 657 657 657 657 657 - 0.7% 0.7%

Brazil 2001 2093 2235 2278 2289 0.5% 1.6% 2.3%

Chile 254 254 258 258 258 - 0.8% 0.3%

Colombia 336 336 336 421 421 - 3.1% 0.4%

Curacao 320 320 320 320 320 - - 0.3%

Ecuador 175 175 175 175 210 19.7% -0.1% 0.2%

Netherlands Antilles n/a n/a n/a n/a n/a n/a n/a n/a

Peru 252 253 253 253 253 - 1.3% 0.3%

Trinidad & Tobago 165 165 165 165 165 - - 0.2%

Venezuela 1303 1303 1303 1303 1303 - 0.1% 1.3%

Other S. & Cent. America 356 361 376 384 384 - -10.3% 0.4%

Total S. & Cent. America 5819 5917 6078 6214 6259 0.7% -0.3% 6.4%

Austria 193 193 193 193 193 - -0.4% 0.2%

Azerbaijan 205 205 205 205 205 - - 0.2%

Belarus 460 460 460 460 460 - - 0.5%

Belgium 753 776 776 776 776 - 0.3% 0.8%

Bulgaria 195 195 195 195 195 - -0.5% 0.2%

Czech Republic 178 178 178 178 178 - -0.8% 0.2%

Denmark 181 181 180 180 180 - -0.5% 0.2%

Finland 261 261 261 261 261 - - 0.3%

France 1513 1375 1375 1375 1224 -11.0% -3.6% 1.3%

Germany 2097 2061 2077 2049 2024 -1.2% -1.2% 2.1%

Greece 498 498 498 498 498 - 1.8% 0.5%

Hungary 165 165 165 165 165 - - 0.2%

Ireland 75 75 75 75 75 - - 0.1%

Italy 2113 1876 1915 1915 1915 - -2.7% 2.0%

Kazakhstan 330 350 350 350 350 - 0.6% 0.4%

Lithuania 241 241 241 241 241 - - 0.2%

Netherlands 1274 1274 1274 1293 1293 - 0.1% 1.3%

Norway 316 316 316 316 316 - - 0.3%

Poland 582 582 582 581 581 - 1.4% 0.6%

Portugal 306 306 306 306 306 - - 0.3%

Romania 214 235 228 239 256 7.1% -4.8% 0.3%


Slovakia 122 122 122 122 122 - - 0.1%

Spain 1546 1546 1546 1562 1562 - 1.3% 1.6%

Sweden 436 436 436 436 436 - - 0.4%

Switzerland 106 140 140 68 68 - -7.0% 0.1%

Turkey 613 613 613 613 613 - - 0.6%

Turkmenistan 251 251 251 271 271 - 0.8% 0.3%

Ukraine 248 262 248 248 248 - -7.2% 0.3%

United Kingdom 1526 1498 1337 1337 1227 -8.3% -3.0% 1.3%


Uzbekistan 232 232 232 232 232 - - 0.2%



72

Other Europe & Eurasia 436 387 404 413 413 - -0.4% 0.4%

Total Europe & Eurasia 23492 23536 23528 23563 23304 -1.1% -0.5% 23.9%

Iran 1952 1985 1985 1985 1985 - 1.6% 2.0%

Iraq 971 823 931 903 919 1.8% 2.2% 0.9%

Israel 292 294 301 301 301 - 1.1% 0.3%

Kuwait 936 936 936 936 936 - - 1.0%

Qatar 283 283 283 283 429 51.6% 7.5% 0.4%

Saudi Arabia 2107 2507 2899 2899 2899 - 3.2% 3.0%

United Arab Emirates 710 710 1143 1143 1143 - 6.3% 1.2%

Other Middle East 978 864 864 864 864 - 0.3% 0.9%


Algeria 652 647 651 651 651 - 3.9% 0.7%

Egypt 810 810 810 810 810 - - 0.8%

South Africa 520 520 520 520 520 - - 0.5%

Other Africa 1453 1473 1476 1476 1476 - 0.6% 1.5%

Total Africa 3435 3449 3457 3457 3457 - 0.9% 3.5%

Australia 663 662 536 443 452 2.0% -4.7% 0.5%

Bangladesh 40 43 43 43 43 - 1.8% ♦

China 12962 13594 14534 14306 14177 -0.9% 6.3% 14.6%

India 4279 4319 4319 4307 4620 7.3% 5.3% 4.7%

Indonesia 1141 1152 1155 1155 1155 - 0.9% 1.2%

Japan 4254 4123 3749 3721 3600 -3.2% -2.0% 3.7%

Malaysia 606 612 612 612 612 - 1.6% 0.6%

New Zealand 136 136 136 136 136 - 2.9% 0.1%

Pakistan 275 390 390 392 392 - 3.9% 0.4%

Philippines 261 270 271 271 271 - -0.3% 0.3%

Singapore 1422 1414 1514 1514 1514 - 0.6% 1.6%

South Korea 2878 2878 3110 3110 3234 4.0% 1.8% 3.3%

Taiwan 1197 1197 1197 988 988 - -1.6% 1.0%

Thailand 1230 1237 1252 1252 1235 -1.4% 1.5% 1.3%

Vietnam 159 159 159 159 163 2.5% 30.6% 0.2%

Other Asia Pacific 220 226 233 233 233 - 1.0% 0.2%


Total World 94176 95210 96990 96992 97430 0.5% 1.1% 100.0%

of which: OECD 44810 44314 43832 44073 44105 0.1% -0.2% 45.3%

Non-OECD 49367 50896 53158 52920 53325 0.8% 2.5% 54.7%

European Union # 14641 14247 14134 14151 13882 -1.9% -1.2% 14.2%

CIS 7562 8016 8121 8211 8221 0.1% 1.0% 8.4%

Source: Includes data from ICIS.

* Atmospheric distillation capacity at year end on a calendar-day basis.

w Less than 0.05%.

n/a not available.


Note: Annual changes and shares of total are calculated using thousand barrels daily figures.


73

Oil: Regional refining margins

US dollars per barrel

USGC Medium Sour Coking NWE Light Sweet Cracking Singapore Medium Sour Hydrocracking

1Q00 2.70 2.07 2.42

2Q00 5.22 4.26 0.63

3Q00 3.87 3.44 3.19

4Q00 3.78 3.63 2.19

1Q01 6.69 2.35 0.7

2Q01 7.71 3.35 0.96

3Q01 3.24 1.74 0.75

4Q01 1.79 1.53 1.2

1Q02 2.04 0.09 0.2

2Q02 2.62 0.59 0.18

3Q02 1.82 1.28 0.47

4Q02 2.98 2.19 1.41

1Q03 6.14 3.7 2.98

2Q03 3.59 2.14 0.66

3Q03 5.61 2.47 1.27

4Q03 3.52 2.21 2.2

1Q04 6.92 2.73 3.42

2Q04 9.18 5.29 2.8

3Q04 6.99 4.37 5.48

4Q04 5.52 4.72 8.02

1Q05 7.3 2.84 4.98

2Q05 9.37 5.68 6.3

3Q05 17.12 7.78 6.52

4Q05 11.64 5.51 4.42

1Q06 10.86 2.88 3.54

2Q06 17.74 5.78 6.83

3Q06 11.47 4.54 3.58

4Q06 7.92 2.49 2.95

1Q07 10.14 4.16 4.84

2Q07 24.46 7.12 6.01

3Q07 12.58 3.82 4.52

4Q07 6.82 4.84 5.8

1Q08 6.21 4.79 4.76

2Q08 8.59 7.46 9.41

3Q08 9.87 7.13 5.9

4Q08 2.49 7.48 5.16

1Q09 6.69 4.67 2.51

2Q09 6.00 3.1 -0.11

3Q09 4.16 2.6 -0.02

4Q09 1.75 2.69 -1.47

1Q10 3.5 4.29 0.97

2Q10 6.59 3.84 0.85

3Q10 4.72 2.59 2.34

4Q10 5.03 4.5 2.32

1Q11 2.59 3.19 4.23

2Q11 8.59 1.92 4.18

3Q11 4.73 2.98 4.41

4Q11 -1.14 4.67 3.32

1Q12 4.44 4.84 2.35


74

2Q12 11.07 7.08 2.23

3Q12 13.72 9.26 5.22

4Q12 3.5 6.76 2.93

1Q13 5.88 5.82 4.76

2Q13 10.61 4.54 2.74

3Q13 8.34 3.12 1.80

4Q13 7.59 2.89 1.30

1Q14 7.13 2.6 2.63

2Q14 13.67 2.86 1.33

3Q14 10.72 4.72 1.11

4Q14 3.41 5.52 3.96

1Q15 10.63 7.38 6.44

2Q15 14.70 7.94 4.07

3Q15 16.56 8.83 2.36

4Q15 8.59 4.74 5.03

1Q16 7.07 4.10 4.55

2Q16 8.99 4.56 2.51

3Q16 9.54 3.35 3.30

4Q16 8.33 5.60 4.09

Note: The refining margins presented are benchmark margins for three major global refining centres. US Gulf Coast (USGC), North West Europe (NWE - Rotterdam) and Singapore

In each case they are based on a single crude oil appropriate for that region and have optimized product yields based on a generic refinery configuration (cracking, hydrocracking or coking), again appropriate for that region.

The margins are on a semi-variable basis, ie the margin after all variable costs and fixed energy costs.


75

Oil: Trade movements

Share


Imports

US 10587 9859 9241 9450 10056 6.4% -3.5% 15.4%

Europe 12569 12815 12855 13959 14188 1.6% 0.4% 21.7%

China 6675 6978 7398 8333 9216 10.6% 9.3% 14.1%

India 4168 4370 4155 4357 4877 11.9% 6.9% 7.5%

Japan 4743 4637 4383 4332 4179 -3.5% -1.9% 6.4%

Rest of World 17862 20085 21261 22543 22939 1.8% 3.9% 35.0%

Total World 56604 58744 59293 62974 65454 3.9% 1.7% 100.0%

Exports

US 2682 3563 4033 4521 4723 4.5% 14.9% 7.2%

Canada 3056 3296 3536 3841 3906 1.7% 5.7% 6.0%

Mexico 1366 1347 1293 1326 1400 5.6% -4.3% 2.1%

S. & Cent. America 3830 3790 3939 4117 4170 1.3% 1.6% 6.4%

Europe1

2193 2578 2512 2990 3110 4.0% 3.0% 4.8%

Russia 7457 7948 7792 8455 8634 2.1% 2.1% 13.2%

Other CIS 1848 2102 2012 2024 1817 -10.2% 6.1% 2.8%

USSR & Central Europe n/a n/a n/a n/a n/a n/a n/a n/a

Saudi Arabia 8468 8365 7911 8017 8526 6.3% -0.7% 13.0%

Middle East (ex Saudi Arabia)2

11742 12242 12699 13446 14992 11.5% 1.2% 22.9%

North Africa3

2602 2127 1743 1717 1683 -2.0% -5.7% 2.6%

West Africa3

4724 4590 4849 4906 4486 -8.6% 1.1% 6.9%

Asia Pacific (ex Japan)4

6299 6307 6450 7068 7514 6.3% 4.8% 11.5%

Rest of World 338 491 524 546 493 -9.6% -9.9% 0.8%

Total World 56604 58744 59293 62974 65454 3.9% 1.7% 100.0%

Notes: Unless otherwise stated, this table shows inter-regional trade based on the regional classification in the table `Oil trade in 2015 and 2016’.1 Prior to 1993, Europe excludes Central Europe (Albania, Bulgaria, Czech Republic, Former Republic of Yugoslavia, Hungary, Poland, Romania, Slovakia).

2 Excludes intra-Middle East trade before 1993.

3 North and West African exports excludes intra-Africa trade prior to 1993.

4 Excludes Japan. Excludes trade between other Asia Pacific countries and Singapore prior to 1993.

n/a not available.


Bunkers are not included as exports.



76

Oil: Inter-area movements 2016

To

Crude (million tonnes) US Canada Mexico S. & Cent.

America

Europe Russia Other CIS Middle East Africa Australasia China India Japan

From

US - 15.0 - 3.3 4.0 - † 0.3 0.1 † 0.5 - 0.4

Canada 162.6 - - 0.1 1.6 - - † † † 0.2 - -

Mexico 29.1 0.7 - 1.7 13.5 - - 0.1 - - 1.0 6.2 4.6

S. & Cent. America 79.8 0.3 † - 12.7 † - - 0.6 - 51.0 27.7 1.7

Europe 3.2 2.1 - 1.2 - † † 0.5 0.7 † 5.8 1.2 -

Russia 1.9 - - 2.9 177.4 - 18.2 0.4 † 0.4 52.5 0.3 10.0

Other CIS 0.5 1.1 - - 61.6 0.8 - 5.3 0.7 - 4.2 1.3 0.4

Iraq 20.9 - - 0.4 49.7 † - 3.7 1.2 - 36.2 38.0 4.0

Kuwait 10.4 † - - 9.6 - - † 2.6 - 16.3 10.1 11.5

Saudi Arabia 54.8 3.1 - 3.3 43.0 - - 13.4 8.0 1.0 51.0 40.3 59.0

UAE 0.6 † - † 0.7 † - † 0.7 4.7 12.2 17.4 39.6

Other Middle East 1.5 † - † 22.2 - † 0.1 0.8 1.0 68.4 30.2 30.3

North Africa 3.6 3.4 - 1.5 38.5 - † 1.1 † 0.1 1.7 3.6 0.1

West Africa 22.2 3.5 - 10.1 64.6 † † † 10.7 1.6 59.5 28.9 0.3

East & S. Africa - - - - 0.1 - † † † - 6.7 † †

Australasia 0.2 - - 0.2 † - - † † - 3.2 † 0.4

China - - - † † - - † 0.2 † - - 1.2

India - - - † † - - - † † - - -

Japan - † - † - - - - - † - - -

Singapore - - - - - - - - - † † † -

Other Asia Pacific 2.1 † † † † † - 0.1 † 11.6 12.3 7.1 4.4

Total imports 393.3 29.2 † 24.6 499.4 0.8 18.3 25.1 26.3 20.4 382.6 212.3 168.0

Product (million tonnes)

From

US - 27.0 34.6 66.6 33.6 † † 2.3 5.6 0.5 7.2 6.7 7.7

Canada 26.0 - 0.1 0.3 2.1 † † † 0.2 † 0.2 0.1 0.4

Mexico 4.2 † - 1.5 0.2 † † † 0.1 † 0.2 † -

S. & Cent. America 9.6 0.1 1.1 - 4.8 † † 0.2 1.8 0.1 3.2 † 0.2

Europe 21.4 4.0 1.7 7.0 - 0.5 2.8 15.4 45.8 0.1 4.8 0.6 0.6

Russia 18.9 † - 2.2 89.3 - 9.1 4.2 2.7 - 2.3 0.5 1.6

Other CIS 0.7 † † 0.1 5.7 0.7 - † 0.1 † 0.3 † †

Iraq 0.2 - - - 0.1 - † 0.2 † - † 0.1 †

Kuwait † - - 0.6 2.3 - † 1.1 3.0 † 1.4 0.9 2.9

Saudi Arabia 0.3 † - 0.5 12.6 - † 1.3 6.4 † 2.2 7.7 2.3


77

UAE 0.1 † † 0.7 6.8 † † 2.2 7.1 0.1 8.2 5.1 5.3

Other Middle East 0.7 † † 0.3 6.3 † 0.2 9.4 3.6 0.1 3.2 4.0 5.9

North Africa 6.6 † 0.1 3.7 10.7 † † 0.6 0.3 † 0.9 0.2 0.5

West Africa 2.2 † † 0.5 2.4 † † † 0.2 0.3 0.6 † 0.1

East & S. Africa † † † 0.1 0.2 † † 0.8 0.6 † † † †

Australasia † † † † 1.2 † † † † - 0.4 † 0.9

China 1.0 0.4 0.1 3.8 2.4 0.3 † 1.8 1.6 1.8 - 0.9 0.4

India 4.3 † † 0.5 13.9 † † 13.9 7.1 2.5 0.4 - 1.9

Japan 1.1 † 0.1 0.6 0.2 † † 0.1 † 4.2 2.8 † -

Singapore 0.9 † 0.2 0.4 2.0 † † 0.7 2.4 7.0 7.0 1.4 1.2

Other Asia Pacific 6.2 † 0.2 1.2 4.0 0.1 † 1.0 3.7 10.9 29.1 1.6 7.0

Total imports 104.5 31.6 38.2 90.5 200.8 1.7 12.2 55.0 92.4 27.6 74.5 30.0 39.1

† Less than 0.05.

Notes: Bunkers are not included as exports. Intra-area movements (for example, between countries in Europe) are excluded.

Crude imports and exports include condensates.


78

Singapore Other Asia

Pacific

Total

† 0.7 24.4

- - 164.4

- 3.8 60.8

0.3 3.4 177.4

† 2.9 17.6

0.7 9.2 274.0

- 5.9 81.7

1.4 21.9 177.5

6.4 36.2 103.3

14.4 84.1 375.3

12.6 34.7 123.2

7.4 41.3 203.2

0.6 3.8 58.2

0.1 15.0 216.5

† † 6.9

0.5 4.9 9.4

† 1.6 2.9

- † †

† † †

- 0.1 0.1

3.5 - 41.0

48.1 269.5 2117.8

4.3 7.0 203.1

† 0.1 29.4

2.5 0.2 8.8

7.9 0.6 29.6

21.7 5.6 132.2

10.4 9.7 151.0

0.2 0.8 8.7

0.5 0.3 1.5

2.0 10.7 25.0

5.1 9.9 48.4


79

5.5 19.8 60.8

3.1 11.8 48.6

† 1.2 24.8

† 0.9 7.3

0.2 0.2 2.3

0.5 0.7 3.9

8.6 22.8 46.0

7.5 9.9 61.9

2.7 2.9 14.7

- 70.6 93.7

38.7 - 103.5

121.4 185.8 1105.2


80

Oil trade in 2015 and 2016

2015 2016

Crude Product Crude Product Crude Product Crude Product

Million tonnes Imports Imports Exports Exports Imports Imports Exports Exports

US 366.7 99.8 25.3 191.9 393.3 104.5 24.4 203.1

Canada 32.3 29.4 159.3 30.7 29.2 31.6 164.4 29.4

Mexico † 35.2 57.6 8.1 † 38.2 60.8 8.8

S. & Cent. America 27.0 88.9 173.4 30.4 24.6 90.5 177.4 29.6

Europe 499.9 187.6 11.8 131.7 499.4 200.8 17.6 132.2

Russia 2.9 2.0 261.9 152.9 0.8 1.7 274.0 151.0

Other CIS 23.1 12.8 88.5 11.8 18.3 12.2 81.7 8.7

Iraq - 1.7 161.2 0.8 † 1.2 177.5 1.5

Kuwait 0.1 0.7 96.6 26.4 † 0.8 103.3 25.0

Saudi Arabia † 7.3 359.2 38.4 † 7.3 375.3 48.4

United Arab Emirates 0.4 16.4 125.4 54.2 1.2 24.4 123.2 60.8

Other Middle East 26.2 19.3 157.5 42.4 23.9 21.4 203.2 48.6

North Africa 8.4 35.2 60.6 23.9 4.4 34.4 58.2 24.8

West Africa 0.8 31.3 236.7 7.3 0.7 32.9 216.5 7.3

East & S. Africa 20.0 31.3 8.8 2.7 21.2 25.1 6.9 2.3

Australasia 24.8 24.4 10.5 3.9 20.4 27.6 9.4 3.9

China 336.2 75.7 1.8 36.2 382.6 74.5 2.9 46.0

India 193.3 22.8 0.2 56.6 212.3 30.0 † 61.9

Japan 168.9 44.9 0.3 14.7 168.0 39.1 † 14.7

Singapore 45.9 125.8 0.1 87.7 48.1 121.4 0.1 93.7

Other Asia Pacific 259.1 164.2 39.1 104.0 269.5 185.8 41.0 103.5

Total World 2035.9 1056.7 2035.9 1056.7 2117.8 1105.2 2117.8 1105.2

Thousand barrels daily

US 7365 2086 509 4012 7877 2179 489 4234

Canada 649 614 3200 641 586 659 3293 613

Mexico ‡ 735 1157 169 ‡ 796 1217 184

S. & Cent. America 542 1858 3482 636 493 1887 3554 617

Europe 10039 3921 237 2753 10001 4187 353 2756

Russia 58 42 5259 3195 15 35 5487 3147

Other CIS 464 268 1777 247 366 254 1636 180

Iraq - 35 3238 17 ‡ 24 3554 30

Kuwait 2 15 1939 551 ‡ 17 2069 521

Saudi Arabia ‡ 153 7214 803 ‡ 152 7517 1009

United Arab Emirates 8 343 2518 1133 23 509 2468 1268

Other Middle East 526 404 3163 887 480 446 4069 1013

North Africa 168 737 1218 499 88 717 1165 518

West Africa 17 655 4753 153 14 686 4335 151

East & S. Africa 401 653 177 56 425 524 138 49

Australasia 497 509 211 81 408 575 189 81

China 6751 1582 36 757 7663 1553 58 959


81

India 3881 476 3 1184 4252 625 ‡ 1291

Japan 3392 939 6 306 3364 815 ‡ 307

Singapore 921 2630 2 1834 963 2531 2 1954

Other Asia Pacific 5204 3433 786 2174 5397 3872 822 2159

Total World 40885 22089 40885 22089 42413 23041 42413 23041

† Less than 0.05. ‡ Less than 0.5.

Notes: Bunkers are not included as exports. Intra-area movements (for example, between countries in Europe) are excluded.

Crude imports and exports include condensates.


82

Natural gas Total proved reserves at end 1996 at end 2006 at end 2015 at end 2016

Trillion Trillion Trillion Trillion Trillion

cubic cubic cubic cubic cubic Share R/P

metres metres metres metres feet of total ratio

US 4.7 6.0 8.7 8.7 307.7 4.7% 11.6

Canada 1.9 1.6 2.2 2.2 76.7 1.2% 14.3

Mexico 1.8 0.4 0.2 0.2 8.6 0.1% 5.2

Total North America 8.5 8.0 11.1 11.1 393.0 6.0% 11.7

Argentina 0.6 0.4 0.4 0.4 12.4 0.2% 9.2

Bolivia 0.1 0.7 0.3 0.3 9.9 0.2% 14.2

Brazil 0.2 0.3 0.4 0.4 13.1 0.2% 15.8

Colombia 0.2 0.1 0.1 0.1 4.4 0.1% 11.9

Peru 0.2 0.3 0.4 0.4 14.1 0.2% 28.5

Trinidad & Tobago 0.5 0.5 0.3 0.3 10.6 0.2% 8.7

Venezuela 4.1 4.7 5.7 5.7 201.3 3.1% 166.3

Other S. & Cent. America 0.1 0.1 0.1 0.1 2.2 ♦ 26.7

Total S. & Cent. America 6.0 7.2 7.7 7.6 268.0 4.1% 42.9

Azerbaijan n/a 0.9 1.1 1.1 40.6 0.6% 65.8

Denmark 0.1 0.1 ^ ^ 0.5 ♦ 2.9

Germany 0.2 0.1 ^ ^ 1.2 ♦ 5.3

Italy 0.3 0.1 ^ ^ 1.2 ♦ 6.6

Kazakhstan n/a 1.3 1.0 1.0 34.0 0.5% 48.3

Netherlands 1.6 1.2 0.7 0.7 24.6 0.4% 17.4

Norway 1.5 2.3 1.9 1.8 62.3 0.9% 15.1

Poland 0.1 0.1 0.1 0.1 3.2 ♦ 23.0

Romania 0.4 0.6 0.1 0.1 3.9 0.1% 12.0

Russian Federation 30.9 31.2 32.3 32.3 1139.6 17.3% 55.7

Turkmenistan n/a 2.3 17.5 17.5 617.3 9.4% 261.7

Ukraine n/a 0.7 0.6 0.6 20.9 0.3% 33.2

United Kingdom 0.8 0.4 0.2 0.2 7.3 0.1% 5.0

Uzbekistan n/a 1.2 1.1 1.1 38.3 0.6% 17.3

Other Europe & Eurasia 0.2 0.2 0.2 0.2 7.2 0.1% 23.2

Total Europe & Eurasia 39.8 42.8 56.8 56.7 2002.0 30.4% 56.7

Bahrain 0.1 0.1 0.2 0.2 5.8 0.1% 10.5

Iran 23.0 26.9 33.5 33.5 1183.0 18.0% 165.5

Iraq 3.4 3.2 3.7 3.7 130.5 2.0% *

Israel ^ ^ 0.2 0.2 5.5 0.1% 16.8

Kuwait 1.5 1.8 1.8 1.8 63.0 1.0% 104.2

Oman 0.6 1.0 0.7 0.7 24.9 0.4% 19.9

Qatar 8.5 25.5 24.3 24.3 858.1 13.0% 134.1

Saudi Arabia 5.7 7.1 8.4 8.4 297.6 4.5% 77.0

Syria 0.2 0.3 0.3 0.3 10.1 0.2% 79.1

United Arab Emirates 5.8 6.4 6.1 6.1 215.1 3.3% 98.5

Yemen 0.3 0.3 0.3 0.3 9.4 0.1% 365.8

Other Middle East ^ ^ ^ ^ 0.2 ♦ 52.6

Total Middle East 49.2 72.6 79.4 79.4 2803.2 42.5% 124.5

Algeria 3.7 4.5 4.5 4.5 159.1 2.4% 49.3

Egypt 0.8 2.0 1.8 1.8 65.2 1.0% 44.1


83

Libya 1.3 1.4 1.5 1.5 53.1 0.8% 149.2

Nigeria 3.5 5.2 5.3 5.3 186.6 2.8% 117.7

Other Africa 0.8 1.2 1.1 1.1 39.3 0.6% 54.9

Total Africa 10.2 14.4 14.2 14.3 503.3 7.6% 68.4

Australia 1.3 2.3 3.5 3.5 122.6 1.9% 38.1

Bangladesh 0.3 0.4 0.2 0.2 7.3 0.1% 7.5

Brunei 0.4 0.3 0.3 0.3 9.7 0.1% 24.6

China 1.2 1.7 4.8 5.4 189.5 2.9% 38.8

India 0.6 1.1 1.3 1.2 43.3 0.7% 44.4

Indonesia 2.0 2.6 2.8 2.9 101.2 1.5% 41.1

Malaysia 2.4 2.5 1.2 1.2 41.3 0.6% 15.8

Myanmar 0.3 0.5 0.5 1.2 42.0 0.6% 63.0

Pakistan 0.6 0.8 0.5 0.5 16.0 0.2% 10.9

Papua New Guinea ^ ^ 0.1 0.2 7.4 0.1% 20.1

Thailand 0.2 0.3 0.2 0.2 7.3 0.1% 5.4

Vietnam 0.2 0.2 0.6 0.6 21.8 0.3% 57.6

Other Asia Pacific 0.4 0.4 0.3 0.3 9.8 0.1% 13.7

Total Asia Pacific 9.9 13.2 16.2 17.5 619.3 9.4% 30.2

Total World 123.5 158.2 185.4 186.6 6588.8 100.0% 52.5

of which: OECD 14.7 14.9 17.9 17.8 629.1 9.5% 13.9

Non-OECD 108.9 143.3 167.5 168.8 5959.7 90.5% 74.3

European Union 3.6 2.8 1.3 1.3 45.3 0.7% 10.8

CIS 30.9 37.6 53.6 53.6 1891.8 28.7% 70.1


^ Less than 0.05.

w Less than 0.05%.

n/a. not available.

Notes: Total proved reserves of natural gas - Generally taken to be those quantities that geological and engineering information indicates with reasonable certainty

can be recovered in the future from known reservoirs under existing economic and operating conditions. The data series for total proved natural gas does not necessarily





Source of data - The estimates in this table have been compiled using a combination of primary official sources and third-party data from Cedigaz and the OPEC Secretariat.


84

Natural Gas: Proved reservesShare

Trillion cubic metres 2012 2013 2014 2015 2016 2016 2005-15 2016

US 8.7 9.6 10.4 8.7 8.7 - 4.2% 4.7%

Canada 2.0 2.0 2.0 2.2 2.2 - 2.9% 1.2%

Mexico 0.4 0.3 0.3 0.2 0.2 - -5.0% 0.1%

Total North America 11.1 12.0 12.8 11.1 11.1 - 3.6% 6.0%

Argentina 0.3 0.3 0.3 0.4 0.4 - -2.2% 0.2%

Bolivia 0.3 0.3 0.3 0.3 0.3 - -9.4% 0.2%

Brazil 0.5 0.5 0.5 0.4 0.4 -12.2% 3.4% 0.2%

Colombia 0.2 0.2 0.1 0.1 0.1 - 0.9% 0.1%

Peru 0.4 0.4 0.4 0.4 0.4 - 1.8% 0.2%

Trinidad & Tobago 0.4 0.3 0.3 0.3 0.3 -7.9% -4.8% 0.2%

Venezuela 5.6 5.6 5.6 5.7 5.7 - 2.8% 3.1%

Other S. & Cent. America 0.1 0.1 0.1 0.1 0.1 -0.1% -0.5% ♦


Azerbaijan 0.9 0.9 1.2 1.1 1.1 - 2.9% 0.6%

Denmark ^ ^ ^ ^ ^ -23.5% -17.9% ♦

Germany 0.1 0.1 ^ ^ ^ -9.3% -13.0% ♦

Italy 0.1 0.1 ^ ^ ^ -22.4% -8.3% ♦

Kazakhstan 0.8 0.9 0.9 1.0 1.0 - -2.8% 0.5%

Netherlands 0.8 0.8 0.7 0.7 0.7 - -5.9% 0.4%

Norway 2.1 2.0 1.9 1.9 1.8 -5.0% -2.4% 0.9%

Poland 0.1 0.1 0.1 0.1 0.1 - -0.6% ♦

Romania 0.1 0.1 0.1 0.1 0.1 - -16.0% 0.1%

Russian Federation 32.0 32.3 32.4 32.3 32.3 - 0.3% 17.3%

Turkmenistan 17.5 17.5 17.5 17.5 17.5 - 22.3% 9.4%

Ukraine 0.6 0.6 0.6 0.6 0.6 -2.1% -1.4% 0.3%

United Kingdom 0.2 0.2 0.2 0.2 0.2 - -8.1% 0.1%


Uzbekistan 1.1 1.1 1.1 1.1 1.1 - -0.8% 0.6%


Total Europe & Eurasia 56.6 56.9 57.0 56.8 56.7 -0.2% 2.8% 30.4%

Bahrain 0.2 0.2 0.2 0.2 0.2 -5.2% 6.7% 0.1%

Iran 33.8 34.0 34.0 33.5 33.5 - 2.0% 18.0%

Iraq 3.6 3.6 3.7 3.7 3.7 - 1.5% 2.0%

Israel 0.2 0.2 0.2 0.2 0.2 -13.9% 14.9% 0.1%

Kuwait 1.8 1.8 1.8 1.8 1.8 - 1.3% 1.0%

Oman 0.5 0.7 0.7 0.7 0.7 - -3.4% 0.4%

Qatar 24.9 24.7 24.5 24.3 24.3 - -0.5% 13.0%

Saudi Arabia 8.1 8.2 8.3 8.4 8.4 - 2.1% 4.5%

Syria 0.3 0.3 0.3 0.3 0.3 - -0.2% 0.2%

United Arab Emirates 6.1 6.1 6.1 6.1 6.1 - ♦ 3.3%

Yemen 0.3 0.3 0.3 0.3 0.3 - -1.9% 0.1%

Other Middle East ^ ^ ^ ^ ^ - 0.1% ♦

Total Middle East 79.7 80.0 80.1 79.4 79.4 ♦ 0.9% 42.5%

Algeria 4.5 4.5 4.5 4.5 4.5 - ♦ 2.4%

Egypt 2.0 1.8 1.8 1.8 1.8 - -0.3% 1.0%

Libya 1.5 1.5 1.5 1.5 1.5 ♦ 1.4% 0.8%



85

Nigeria 5.1 5.1 5.3 5.3 5.3 - 0.3% 2.8%

Other Africa 1.2 1.2 1.2 1.1 1.1 1.3% -0.8% 0.6%

Total Africa 14.4 14.2 14.3 14.2 14.3 0.1% 0.1% 7.6%

Australia 3.5 3.5 3.5 3.5 3.5 - 4.5% 1.9%

Bangladesh 0.3 0.3 0.2 0.2 0.2 - -6.6% 0.1%

Brunei 0.3 0.3 0.3 0.3 0.3 - -2.1% 0.1%

China 3.2 3.5 3.7 4.8 5.4 11.9% 11.7% 2.9%

India 1.3 1.4 1.4 1.3 1.2 -2.0% 1.3% 0.7%

Indonesia 2.9 2.9 2.8 2.8 2.9 3.3% 1.1% 1.5%

Malaysia 1.1 1.1 1.2 1.2 1.2 - -7.2% 0.6%

Myanmar 0.3 0.5 0.5 0.5 1.2 125.0% -0.2% 0.6%

Pakistan 0.6 0.6 0.5 0.5 0.5 - -6.1% 0.2%

Papua New Guinea 0.2 0.2 0.2 0.1 0.2 48.9% 50.2% 0.1%

Thailand 0.3 0.2 0.2 0.2 0.2 - -3.8% 0.1%

Vietnam 0.6 0.6 0.6 0.6 0.6 - 10.9% 0.3%

Other Asia Pacific 0.3 0.3 0.3 0.3 0.3 -0.1% -3.9% 0.1%


Total World 184.3 185.8 187.2 185.4 186.6 0.6% 1.7% 100.0%

of which: OECD 18.3 19.1 19.6 17.9 17.8 -0.7% 1.8% 9.5%

Non-OECD 166.0 166.7 167.5 167.5 168.8 0.8% 1.6% 90.5%

European Union 1.5 1.4 1.3 1.3 1.3 -1.5% -8.0% 0.7%

CIS 53.0 53.3 53.7 53.6 53.6 ♦ 3.6% 28.7%

^ Less than 0.05.

w Less than 0.05%. 1.2

n/a not available.

Notes: Total proved reserves of natural gas - Generally taken to be those quantities that geological and engineering information indicates with reasonable certainty

can be recovered in the future from known reservoirs under existing economic and operating conditions. The data series for natural gas does not necessarily





Source of data - The estimates in this table have been compiled using a combination of primary official sources and third-party data from Cedigaz and the OPEC Secretariat.

Annual changes and share of total are calculated using trillion cubic metres.


86

Natural Gas: Production*Share

Billion cubic metres 2012 2013 2014 2015 2016 2016 2005-15 2016

US 680.5 685.4 733.1 766.2 749.2 -2.5% 4.1% 21.1%

Canada 141.1 141.4 147.2 149.1 152.0 1.7% -1.3% 4.3%

Mexico 57.2 58.2 57.1 54.1 47.2 -13.0% 0.3% 1.3%


Argentina 37.7 35.5 35.5 36.5 38.3 4.6% -2.2% 1.1%

Bolivia 17.8 20.3 21.0 20.3 19.7 -3.0% 5.3% 0.6%

Brazil 19.3 21.3 22.7 23.1 23.5 1.2% 7.8% 0.7%

Colombia 12.0 12.6 11.8 11.1 10.4 -6.6% 5.2% 0.3%

Peru 11.9 12.2 12.9 12.5 14.0 11.7% 23.5% 0.4%

Trinidad & Tobago 42.7 42.8 42.1 39.6 34.5 -13.2% 1.8% 1.0%

Venezuela 29.5 28.4 28.6 32.4 34.3 5.5% 1.7% 1.0%

Other S. & Cent. America 2.7 2.4 2.3 2.5 2.4 -4.6% -2.7% 0.1%


Azerbaijan 15.6 16.2 17.6 17.9 17.5 -3.0% 13.2% 0.5%

Denmark 5.7 4.8 4.6 4.6 4.5 -2.2% -7.9% 0.1%

Germany 9.0 8.2 7.7 7.2 6.6 -8.2% -7.6% 0.2%

Italy 7.8 7.0 6.5 6.2 5.3 -14.8% -5.7% 0.1%

Kazakhstan 17.2 18.4 18.7 19.0 19.9 4.5% 4.0% 0.6%

Netherlands 63.8 68.6 57.9 43.3 40.2 -7.6% -3.6% 1.1%

Norway 114.7 108.7 108.8 117.2 116.6 -0.7% 3.2% 3.3%

Poland 4.3 4.2 4.1 4.1 3.9 -3.8% -0.5% 0.1%

Romania 10.0 9.6 9.7 9.8 9.2 -6.5% -1.0% 0.3%


Turkmenistan 62.3 62.3 67.1 69.6 66.8 -4.3% 2.0% 1.9%

Ukraine 18.6 19.3 18.2 17.9 17.8 -1.1% -0.3% 0.5%

United Kingdom 38.9 36.5 36.8 39.6 41.0 3.3% -7.7% 1.2%


Uzbekistan 56.9 56.9 57.3 57.7 62.8 8.4% 0.7% 1.8%



Bahrain 13.7 14.7 15.5 15.5 15.5 -0.8% 3.8% 0.4%

Iran 166.2 166.8 185.8 189.4 202.4 6.6% 6.4% 5.7%

Iraq 0.6 1.2 0.9 1.0 1.1 12.6% -3.6% ♦

Kuwait 15.5 16.3 15.0 16.9 17.1 1.0% 3.2% 0.5%

Oman 32.2 34.8 33.3 34.7 35.4 1.7% 4.6% 1.0%

Qatar 157.0 177.6 174.1 178.5 181.2 1.3% 14.6% 5.1%

Saudi Arabia 99.3 100.0 102.4 104.5 109.4 4.4% 3.9% 3.1%

Syria 5.8 4.8 4.4 4.1 3.6 -11.6% -3.0% 0.1%


Yemen 7.3 9.9 9.3 2.7 0.7 -73.4% - ♦



Algeria 81.5 82.4 83.3 84.6 91.3 7.6% -0.4% 2.6%

Egypt 60.9 56.1 48.8 44.3 41.8 -5.7% 0.4% 1.2%

Libya 11.1 11.6 11.3 11.8 10.1 -14.7% 0.4% 0.3%

Nigeria 43.3 36.2 45.0 50.1 44.9 -10.6% 7.2% 1.3%



87

Other Africa 17.6 20.0 18.6 19.3 20.2 4.5% 6.9% 0.6%

Total Africa 214.4 206.3 207.1 210.0 208.3 -1.1% 1.7% 5.9%

Australia 56.9 59.0 63.6 72.6 91.2 25.2% 7.0% 2.6%

Bangladesh 22.2 22.8 23.9 26.9 27.5 2.2% 6.9% 0.8%

Brunei 12.6 12.2 11.9 11.6 11.2 -3.8% -0.3% 0.3%

China 111.8 122.2 131.6 136.1 138.4 1.4% 10.3% 3.9%

India 38.9 32.1 30.5 29.3 27.6 -6.0% -0.1% 0.8%

Indonesia 77.1 76.5 75.3 75.0 69.7 -7.4% ♦ 2.0%

Malaysia 61.5 67.3 68.4 71.2 73.8 3.4% 1.1% 2.1%

Myanmar 12.7 13.1 16.8 19.6 18.9 -3.9% 4.8% 0.5%

Pakistan 43.8 42.6 41.9 42.0 41.5 -1.3% 0.7% 1.2%

Thailand 41.0 41.3 41.6 39.3 38.6 -2.2% 5.3% 1.1%

Vietnam 9.4 9.8 10.2 10.7 10.7 0.2% 5.2% 0.3%



Total World 3352.3 3403.9 3465.9 3530.6 3551.6 0.3% 2.4% 100.0%

of which: OECD 1197.2 1202.0 1247.6 1284.5 1281.6 -0.5% 1.9% 36.1%

Non-OECD 2155.1 2201.9 2218.3 2246.1 2270.0 0.8% 2.8% 63.9%

European Union # 146.6 144.8 132.5 119.8 118.2 -1.6% -5.5% 3.3%

CIS 763.0 778.1 760.9 757.6 764.3 0.6% 0.4% 21.5%

Source: Includes data from Cedigaz.

* Excludes gas flared or recycled. Includes natural gas produced for Gas-to-Liquids transformation.

w Less than 0.05%.

Notes: As far as possible, the data above represent standard cubic metres (measured at 15oC and 1013 mbar); as they are derived directly from tonnes

of oil equivalent using an average conversion factor, they do not necessarily equate with gas volumes expressed in specific national terms.

Annual changes and shares of total are calculated using billion cubic metres figures.



88

Natural Gas: Production*Share

Billion cubic feet per day 2012 2013 2014 2015 2016 2016 2005-15 2016

US 65.7 66.3 70.9 74.1 72.3 -2.5% 4.1% 21.1%

Canada 13.6 13.7 14.2 14.4 14.7 1.7% -1.3% 4.3%

Mexico 5.5 5.6 5.5 5.2 4.6 -13.0% 0.3% 1.3%


Argentina 3.6 3.4 3.4 3.5 3.7 4.6% -2.2% 1.1%

Bolivia 1.7 2.0 2.0 2.0 1.9 -3.0% 5.3% 0.6%

Brazil 1.9 2.1 2.2 2.2 2.3 1.2% 7.8% 0.7%

Colombia 1.2 1.2 1.1 1.1 1.0 -6.6% 5.2% 0.3%

Peru 1.1 1.2 1.3 1.2 1.4 11.7% 23.5% 0.4%

Trinidad & Tobago 4.1 4.1 4.1 3.8 3.3 -13.2% 1.8% 1.0%

Venezuela 2.8 2.8 2.8 3.1 3.3 5.5% 1.7% 1.0%



Azerbaijan 1.5 1.6 1.7 1.7 1.7 -3.0% 13.2% 0.5%

Denmark 0.6 0.5 0.4 0.4 0.4 -2.2% -7.9% 0.1%

Germany 0.9 0.8 0.7 0.7 0.6 -8.2% -7.6% 0.2%

Italy 0.8 0.7 0.6 0.6 0.5 -14.8% -5.7% 0.1%

Kazakhstan 1.7 1.8 1.8 1.8 1.9 4.5% 4.0% 0.6%

Netherlands 6.2 6.6 5.6 4.2 3.9 -7.6% -3.6% 1.1%

Norway 11.1 10.5 10.5 11.3 11.3 -0.7% 3.2% 3.3%

Poland 0.4 0.4 0.4 0.4 0.4 -3.8% -0.5% 0.1%

Romania 1.0 0.9 0.9 0.9 0.9 -6.5% -1.0% 0.3%


Turkmenistan 6.0 6.0 6.5 6.7 6.4 -4.3% 2.0% 1.9%

Ukraine 1.8 1.9 1.8 1.7 1.7 -1.1% -0.3% 0.5%

United Kingdom 3.8 3.5 3.6 3.8 4.0 3.3% -7.7% 1.2%


Uzbekistan 5.5 5.5 5.5 5.6 6.1 8.4% 0.7% 1.8%



Bahrain 1.3 1.4 1.5 1.5 1.5 -0.8% 3.8% 0.4%

Iran 16.0 16.1 18.0 18.3 19.5 6.6% 6.4% 5.7%

Iraq 0.1 0.1 0.1 0.1 0.1 12.6% -3.6% ♦

Kuwait 1.5 1.6 1.5 1.6 1.7 1.0% 3.2% 0.5%

Oman 3.1 3.4 3.2 3.4 3.4 1.7% 4.6% 1.0%

Qatar 15.2 17.2 16.8 17.3 17.5 1.3% 14.6% 5.1%

Saudi Arabia 9.6 9.7 9.9 10.1 10.6 4.4% 3.9% 3.1%

Syria 0.6 0.5 0.4 0.4 0.3 -11.6% -3.0% 0.1%


Yemen 0.7 1.0 0.9 0.3 0.1 -73.4% - ♦



Algeria 7.9 8.0 8.1 8.2 8.8 7.6% -0.4% 2.6%

Egypt 5.9 5.4 4.7 4.3 4.0 -5.7% 0.4% 1.2%

Libya 1.1 1.1 1.1 1.1 1.0 -14.7% 0.4% 0.3%

Nigeria 4.2 3.5 4.4 4.8 4.3 -10.6% 7.2% 1.3%

Other Africa 1.7 1.9 1.8 1.9 2.0 4.5% 6.9% 0.6%



89

Total Africa 20.7 20.0 20.0 20.3 20.1 -1.1% 1.7% 5.9%

Australia 5.5 5.7 6.2 7.0 8.8 25.2% 7.0% 2.6%

Bangladesh 2.1 2.2 2.3 2.6 2.7 2.2% 6.9% 0.8%

Brunei 1.2 1.2 1.1 1.1 1.1 -3.8% -0.3% 0.3%

China 10.8 11.8 12.7 13.2 13.4 1.4% 10.3% 3.9%

India 3.8 3.1 3.0 2.8 2.7 -6.0% -0.1% 0.8%

Indonesia 7.4 7.4 7.3 7.3 6.7 -7.4% ♦ 2.0%

Malaysia 5.9 6.5 6.6 6.9 7.1 3.4% 1.1% 2.1%

Myanmar 1.2 1.3 1.6 1.9 1.8 -3.9% 4.8% 0.5%

Pakistan 4.2 4.1 4.1 4.1 4.0 -1.3% 0.7% 1.2%

Thailand 4.0 4.0 4.0 3.8 3.7 -2.2% 5.3% 1.1%

Vietnam 0.9 0.9 1.0 1.0 1.0 0.2% 5.2% 0.3%



Total World 323.5 329.3 335.3 341.6 342.7 0.3% 2.4% 100.0%

of which: OECD 115.5 116.3 120.7 124.3 123.7 -0.5% 1.9% 36.1%

Non-OECD 207.9 213.0 214.6 217.3 219.0 0.8% 2.8% 63.9%

European Union # 14.1 14.0 12.8 11.6 11.4 -1.6% -5.5% 3.3%

CIS 73.6 75.3 73.6 73.3 73.7 0.6% 0.4% 21.5%



^ Less than 0.05.

w Less than 0.05%

n/a not available.


Notes: As the data above are derived from tonnes oil equivalent using average conversion factors, they do not necessarily equate with gas volumes expressed in specific national terms.

Annual changes and shares of total are calculated using billion cubic feet per day figures.


90

Natural Gas: Production* Share


US 620.2 626.4 673.3 707.1 690.8 -2.6% 4.2% 21.5%

Canada 127.0 127.3 132.4 134.2 136.8 1.7% -1.3% 4.3%

Mexico 51.5 52.4 51.4 48.7 42.5 -13.0% 0.3% 1.3%


Argentina 34.0 32.0 31.9 32.8 34.4 4.6% -2.2% 1.1%

Bolivia 16.0 18.3 18.9 18.2 17.8 -3.0% 5.3% 0.6%

Brazil 17.3 19.2 20.4 20.8 21.1 1.2% 7.8% 0.7%

Colombia 10.8 11.4 10.6 10.0 9.4 -6.6% 5.2% 0.3%

Peru 10.7 11.0 11.6 11.2 12.6 11.7% 23.5% 0.4%

Trinidad & Tobago 38.4 38.6 37.9 35.7 31.0 -13.2% 1.8% 1.0%

Venezuela 26.5 25.6 25.8 29.2 30.9 5.5% 1.7% 1.0%



Azerbaijan 14.0 14.6 15.8 16.2 15.7 -3.0% 13.2% 0.5%

Denmark 5.2 4.3 4.1 4.1 4.0 -2.2% -7.9% 0.1%

Germany 8.1 7.4 7.0 6.5 6.0 -8.2% -7.6% 0.2%

Italy 7.0 6.3 5.9 5.5 4.7 -14.8% -5.7% 0.1%

Kazakhstan 15.5 16.6 16.9 17.1 17.9 4.5% 4.0% 0.6%

Netherlands 57.4 61.8 52.1 39.0 36.1 -7.6% -3.6% 1.1%

Norway 103.3 97.9 97.9 105.4 105.0 -0.7% 3.2% 3.3%

Poland 3.9 3.8 3.7 3.7 3.6 -3.8% -0.5% 0.1%

Romania 9.0 8.6 8.8 8.8 8.2 -6.5% -1.0% 0.3%


Turkmenistan 56.1 56.1 60.4 62.6 60.1 -4.3% 2.0% 1.9%

Ukraine 16.7 17.3 16.4 16.1 16.0 -1.1% -0.3% 0.5%

United Kingdom 35.0 32.8 33.1 35.6 36.9 3.3% -7.7% 1.1%


Uzbekistan 51.2 51.2 51.6 52.0 56.5 8.4% 0.7% 1.8%



Bahrain 12.4 13.2 13.9 14.0 13.9 -0.8% 3.8% 0.4%

Iran 149.5 150.1 167.3 170.4 182.2 6.6% 6.4% 5.7%

Iraq 0.6 1.1 0.8 0.9 1.0 12.6% -3.6% ♦

Kuwait 14.0 14.7 13.5 15.2 15.4 1.0% 3.2% 0.5%

Oman 29.0 31.3 30.0 31.3 31.9 1.7% 4.6% 1.0%

Qatar 141.3 159.8 156.7 160.6 163.1 1.3% 14.6% 5.1%

Saudi Arabia 89.4 90.0 92.1 94.0 98.4 4.4% 3.9% 3.1%

Syria 5.2 4.3 4.0 3.7 3.2 -11.6% -3.0% 0.1%


Yemen 6.5 8.9 8.4 2.5 0.7 -73.4% - ♦



Algeria 73.4 74.2 75.0 76.1 82.2 7.6% -0.4% 2.6%

Egypt 54.8 50.5 43.9 39.8 37.6 -5.7% 0.4% 1.2%

Libya 10.0 10.5 10.2 10.6 9.1 -14.7% 0.4% 0.3%

Nigeria 39.0 32.6 40.5 45.1 40.4 -10.6% 7.2% 1.3%



91

Other Africa 15.9 18.0 16.8 17.4 18.2 4.5% 6.9% 0.6%

Total Africa 192.9 185.7 186.3 189.0 187.5 -1.1% 1.7% 5.8%

Australia 51.2 53.1 57.3 65.4 82.0 25.2% 7.0% 2.6%

Bangladesh 20.0 20.5 21.5 24.2 24.8 2.2% 6.9% 0.8%

Brunei 11.3 11.0 10.7 10.5 10.1 -3.8% -0.3% 0.3%

China 100.7 110.0 118.4 122.5 124.6 1.4% 10.3% 3.9%

India 35.0 28.9 27.5 26.4 24.9 -6.0% -0.1% 0.8%

Indonesia 69.4 68.8 67.7 67.5 62.7 -7.4% ♦ 2.0%

Malaysia 55.4 60.5 61.5 64.1 66.5 3.4% 1.1% 2.1%

Myanmar 11.5 11.8 15.2 17.6 17.0 -3.9% 4.8% 0.5%

Pakistan 39.4 38.4 37.7 37.8 37.4 -1.3% 0.7% 1.2%

Thailand 36.9 37.2 37.5 35.4 34.7 -2.2% 5.3% 1.1%

Vietnam 8.4 8.8 9.2 9.6 9.6 0.2% 5.2% 0.3%



Total World 3024.7 3073.1 3132.8 3195.0 3212.9 0.3% 2.5% 100.0%

of which: OECD 1085.1 1091.3 1136.3 1173.5 1169.9 -0.6% 1.9% 36.4%

Non-OECD 1939.6 1981.8 1996.5 2021.5 2043.0 0.8% 2.8% 63.6%

European Union # 132.0 130.4 119.3 107.8 106.4 -1.6% -5.5% 3.3%

CIS 686.7 700.3 684.8 681.8 687.9 0.6% 0.4% 21.4%



^ Less than 0.05.

w Less than 0.05%.

n/a not available.


Notes: Annual changes and shares of total are calculated using million tonnes oil equivalent figures.



92

Natural Gas: Consumption in billion cubic metres*Share

Billion cubic metres 2012 2013 2014 2015 2016 2016 2005-15 2016

US 723.2 740.6 753.0 773.2 778.6 0.4% 2.2% 22.0%

Canada 100.2 103.9 104.2 102.5 99.9 -2.8% 0.5% 2.8%

Mexico 79.9 83.3 86.8 87.1 89.5 2.5% 3.6% 2.5%

Total North America 903.3 927.8 944.1 962.8 968.0 0.3% 2.1% 27.3%

Argentina 46.7 46.7 47.2 48.2 49.6 2.7% 1.8% 1.4%

Brazil 31.7 37.3 39.5 41.7 36.6 -12.5% 7.9% 1.0%

Chile 4.6 4.6 3.8 4.1 4.5 11.1% -6.3% 0.1%

Colombia 9.8 10.0 10.9 10.7 10.6 -1.6% 4.8% 0.3%

Ecuador 0.6 0.6 0.7 0.6 0.6 1.5% 6.9% ♦

Peru 6.2 6.0 6.8 7.2 7.9 9.8% 16.8% 0.2%

Trinidad & Tobago 22.2 22.4 22.0 21.5 19.1 -11.4% 2.8% 0.5%

Venezuela 31.4 30.5 30.7 34.5 35.6 2.7% 2.3% 1.0%



Austria 8.9 8.6 7.9 8.3 8.7 4.4% -1.7% 0.2%

Azerbaijan 8.5 8.6 9.4 10.6 10.4 -2.2% 2.2% 0.3%

Belarus 18.5 18.5 18.3 15.6 17.0 9.0% -1.6% 0.5%

Belgium 16.0 15.8 13.8 15.1 15.4 1.8% -0.8% 0.4%

Bulgaria 2.7 2.6 2.6 2.9 3.0 3.9% -0.8% 0.1%

Czech Republic 7.6 7.7 6.9 7.2 7.8 7.9% -1.7% 0.2%

Denmark 3.9 3.7 3.1 3.2 3.2 1.4% -4.4% 0.1%

Finland 3.1 2.8 2.5 2.2 2.0 -9.2% -5.8% 0.1%

France 42.5 43.1 36.2 38.9 42.6 9.0% -1.6% 1.2%

Germany 77.5 81.2 70.6 73.5 80.5 9.2% -1.6% 2.3%

Greece 4.0 3.6 2.7 2.8 2.8 0.6% 0.5% 0.1%

Hungary 9.3 8.7 7.8 8.3 8.9 7.0% -4.7% 0.3%

Ireland 4.5 4.3 4.1 4.2 4.8 14.0% 0.8% 0.1%

Italy 68.2 63.8 56.3 61.4 64.5 4.7% -2.5% 1.8%

Kazakhstan 10.8 11.2 12.5 12.9 13.4 3.8% 6.3% 0.4%

Lithuania 2.9 2.4 2.3 2.3 2.0 -11.1% -1.8% 0.1%

Netherlands 36.0 36.5 31.8 31.5 33.6 6.4% -2.3% 0.9%

Norway 4.4 4.4 4.7 4.8 4.9 0.4% 0.8% 0.1%

Poland 16.6 16.6 16.3 16.3 17.3 5.7% 1.9% 0.5%

Portugal 4.5 4.3 4.1 4.8 5.2 8.1% 1.2% 0.1%

Romania 12.4 11.3 10.5 9.9 10.6 6.2% -4.3% 0.3%


Slovakia 4.9 5.3 4.2 4.3 4.4 1.6% -4.1% 0.1%

Spain 31.7 29.0 26.3 27.3 28.0 2.0% -1.9% 0.8%

Sweden 1.0 1.0 0.9 0.9 0.9 10.0% -0.9% ♦

Switzerland 2.9 3.1 2.7 2.9 3.0 4.8% 0.2% 0.1%

Turkey 41.4 42.0 44.6 43.6 42.1 -3.7% 5.0% 1.2%

Turkmenistan 26.3 22.9 25.6 29.4 29.5 ♦ 6.2% 0.8%

Ukraine 49.6 43.3 36.8 28.8 29.0 0.3% -8.4% 0.8%

United Kingdom 73.9 73.0 66.7 68.1 76.7 12.2% -3.3% 2.2%


Uzbekistan 47.2 46.8 48.8 50.2 51.4 2.0% 1.6% 1.4%





93

Iran 161.5 162.9 183.7 190.8 200.8 5.0% 6.4% 5.7%

Israel 2.6 6.9 7.6 8.4 9.7 14.5% 17.8% 0.3%

Kuwait 18.5 18.7 18.5 21.3 21.9 2.5% 5.7% 0.6%

Qatar 23.4 37.9 36.4 43.9 41.7 -5.4% 9.0% 1.2%

Saudi Arabia 99.3 100.0 102.4 104.5 109.4 4.4% 3.9% 3.1%




Algeria 31.0 33.4 37.5 39.4 40.0 1.2% 5.4% 1.1%

Egypt 52.6 51.4 48.0 47.8 51.3 7.0% 4.2% 1.4%

South Africa 4.4 4.6 5.0 5.1 5.1 1.3% 4.9% 0.1%

Other Africa 32.6 33.8 36.6 43.5 41.7 -4.4% 4.9% 1.2%

Total Africa 120.6 123.2 127.0 135.8 138.2 1.4% 4.8% 3.9%

Australia 33.8 35.5 38.3 42.9 41.1 -4.4% 6.6% 1.2%

Bangladesh 22.2 22.8 23.9 26.9 27.5 2.2% 6.9% 0.8%

China 150.9 171.9 188.4 194.8 210.3 7.7% 15.0% 5.9%


India 71.1 49.3 48.8 45.7 50.1 9.2% 2.5% 1.4%

Indonesia 42.2 40.8 40.9 40.4 37.7 -7.0% 1.2% 1.1%

Japan 116.9 116.9 118.0 113.4 111.2 -2.2% 3.7% 3.1%

Malaysia 35.5 40.3 42.2 41.8 43.0 2.7% 1.8% 1.2%

New Zealand 4.2 4.5 4.9 4.5 4.7 4.3% 2.3% 0.1%

Pakistan 43.8 42.6 41.9 43.5 45.5 4.2% 1.1% 1.3%

Philippines 3.7 3.4 3.6 3.3 3.8 14.3% 0.6% 0.1%

Singapore 9.4 10.5 10.9 12.2 12.5 2.5% 6.5% 0.4%

South Korea 50.2 52.5 47.8 43.6 45.5 4.0% 3.7% 1.3%

Taiwan 16.3 16.3 17.2 18.4 19.1 3.6% 6.9% 0.5%

Thailand 46.5 46.7 47.7 48.7 48.3 -1.0% 4.7% 1.4%

Vietnam 9.4 9.8 10.2 10.7 10.7 0.2% 5.2% 0.3%



Total World 3337.7 3383.8 3400.8 3480.1 3542.9 1.5% 2.3% 100.0%

of which: OECD 1580.9 1609.5 1580.6 1611.4 1644.1 1.7% 1.2% 46.4%

Non-OECD 1756.8 1774.4 1820.2 1868.7 1898.8 1.3% 3.4% 53.6%

European Union # 438.6 431.2 383.0 399.1 428.8 7.1% -2.2% 12.1%

CIS 582.9 569.6 566.4 555.4 546.7 -1.8% -0.1% 15.4%


* Excludes natural gas converted to liquid fuels but includes derivatives of coal as well as natural gas consumed in Gas-to-Liquids transformation.

^ Less than 0.05.

w Less than 0.05%.

n/a not available.


Notes: As far as possible, the data above represent standard cubic metres (measured at 15oC and 1013 mbar); as they are derived directly from tonnes

of oil equivalent using an average conversion factor, they do not necessarily equate with gas volumes expressed in specific national terms.

The difference between these world consumption figures and the world production statistics is due to variations in stocks at storage facilities

and liquefaction plants, together with unavoidable disparities in the definition, measurement or conversion of gas supply and demand data.

Annual changes and shares of total are calculated using billion cubic metres figures.



94

Natural Gas: ConsumptionShare

Billion cubic feet per day 2012 2013 2014 2015 2016 2016 2005-15 2016

US 69.8 71.7 72.9 74.8 75.1 0.4% 2.2% 22.0%

Canada 9.7 10.1 10.1 9.9 9.6 -2.8% 0.5% 2.8%

Mexico 7.7 8.1 8.4 8.4 8.6 2.5% 3.6% 2.5%


Argentina 4.5 4.5 4.6 4.7 4.8 2.7% 1.8% 1.4%

Brazil 3.1 3.6 3.8 4.0 3.5 -12.5% 7.9% 1.0%

Chile 0.4 0.4 0.4 0.4 0.4 11.1% -6.3% 0.1%

Colombia 0.9 1.0 1.1 1.0 1.0 -1.6% 4.8% 0.3%

Ecuador 0.1 0.1 0.1 0.1 0.1 1.5% 6.9% ♦

Peru 0.6 0.6 0.7 0.7 0.8 9.8% 16.8% 0.2%

Trinidad & Tobago 2.1 2.2 2.1 2.1 1.8 -11.4% 2.8% 0.5%

Venezuela 3.0 3.0 3.0 3.3 3.4 2.7% 2.3% 1.0%



Austria 0.9 0.8 0.8 0.8 0.8 4.4% -1.7% 0.2%

Azerbaijan 0.8 0.8 0.9 1.0 1.0 -2.2% 2.2% 0.3%

Belarus 1.8 1.8 1.8 1.5 1.6 9.0% -1.6% 0.5%

Belgium 1.5 1.5 1.3 1.5 1.5 1.8% -0.8% 0.4%

Bulgaria 0.3 0.3 0.3 0.3 0.3 3.9% -0.8% 0.1%

Czech Republic 0.7 0.7 0.7 0.7 0.8 7.9% -1.7% 0.2%

Denmark 0.4 0.4 0.3 0.3 0.3 1.4% -4.4% 0.1%

Finland 0.3 0.3 0.2 0.2 0.2 -9.2% -5.8% 0.1%

France 4.1 4.2 3.5 3.8 4.1 9.0% -1.6% 1.2%

Germany 7.5 7.9 6.8 7.1 7.8 9.2% -1.6% 2.3%

Greece 0.4 0.3 0.3 0.3 0.3 0.6% 0.5% 0.1%

Hungary 0.9 0.8 0.8 0.8 0.9 7.0% -4.7% 0.3%

Ireland 0.4 0.4 0.4 0.4 0.5 14.0% 0.8% 0.1%

Italy 6.6 6.2 5.5 5.9 6.2 4.7% -2.5% 1.8%

Kazakhstan 1.0 1.1 1.2 1.2 1.3 3.8% 6.3% 0.4%

Lithuania 0.3 0.2 0.2 0.2 0.2 -11.1% -1.8% 0.1%

Netherlands 3.5 3.5 3.1 3.0 3.2 6.4% -2.3% 0.9%

Norway 0.4 0.4 0.5 0.5 0.5 0.4% 0.8% 0.1%

Poland 1.6 1.6 1.6 1.6 1.7 5.7% 1.9% 0.5%

Portugal 0.4 0.4 0.4 0.5 0.5 8.1% 1.2% 0.1%

Romania 1.2 1.1 1.0 1.0 1.0 6.2% -4.3% 0.3%


Slovakia 0.5 0.5 0.4 0.4 0.4 1.6% -4.1% 0.1%

Spain 3.1 2.8 2.5 2.6 2.7 2.0% -1.9% 0.8%

Sweden 0.1 0.1 0.1 0.1 0.1 10.0% -0.9% ♦

Switzerland 0.3 0.3 0.3 0.3 0.3 4.8% 0.2% 0.1%

Turkey 4.0 4.1 4.3 4.2 4.1 -3.7% 5.0% 1.2%

Turkmenistan 2.5 2.2 2.5 2.8 2.8 ♦ 6.2% 0.8%

Ukraine 4.8 4.2 3.6 2.8 2.8 0.3% -8.4% 0.8%

United Kingdom 7.1 7.1 6.5 6.6 7.4 12.2% -3.3% 2.2%


Uzbekistan 4.6 4.5 4.7 4.9 5.0 2.0% 1.6% 1.4%





95

Iran 15.6 15.8 17.8 18.5 19.4 5.0% 6.4% 5.7%

Israel 0.2 0.7 0.7 0.8 0.9 14.5% 17.8% 0.3%

Kuwait 1.8 1.8 1.8 2.1 2.1 2.5% 5.7% 0.6%

Qatar 2.3 3.7 3.5 4.3 4.0 -5.4% 9.0% 1.2%

Saudi Arabia 9.6 9.7 9.9 10.1 10.6 4.4% 3.9% 3.1%




Algeria 3.0 3.2 3.6 3.8 3.9 1.2% 5.4% 1.1%

Egypt 5.1 5.0 4.6 4.6 4.9 7.0% 4.2% 1.4%

South Africa 0.4 0.4 0.5 0.5 0.5 1.3% 4.9% 0.1%

Other Africa 3.1 3.3 3.5 4.2 4.0 -4.4% 4.9% 1.2%

Total Africa 11.6 11.9 12.3 13.1 13.3 1.4% 4.8% 3.9%

Australia 3.3 3.4 3.7 4.1 4.0 -4.4% 6.6% 1.2%

Bangladesh 2.1 2.2 2.3 2.6 2.7 2.2% 6.9% 0.8%

China 14.6 16.6 18.2 18.8 20.3 7.7% 15.0% 5.9%


India 6.9 4.8 4.7 4.4 4.8 9.2% 2.5% 1.4%

Indonesia 4.1 4.0 4.0 3.9 3.6 -7.0% 1.2% 1.1%

Japan 11.3 11.3 11.4 11.0 10.7 -2.2% 3.7% 3.1%

Malaysia 3.4 3.9 4.1 4.0 4.2 2.7% 1.8% 1.2%

New Zealand 0.4 0.4 0.5 0.4 0.5 4.3% 2.3% 0.1%

Pakistan 4.2 4.1 4.1 4.2 4.4 4.2% 1.1% 1.3%

Philippines 0.4 0.3 0.3 0.3 0.4 14.3% 0.6% 0.1%

Singapore 0.9 1.0 1.1 1.2 1.2 2.5% 6.5% 0.4%

South Korea 4.8 5.1 4.6 4.2 4.4 4.0% 3.7% 1.3%

Taiwan 1.6 1.6 1.7 1.8 1.8 3.6% 6.9% 0.5%

Thailand 4.5 4.5 4.6 4.7 4.7 -1.0% 4.7% 1.4%

Vietnam 0.9 0.9 1.0 1.0 1.0 0.2% 5.2% 0.3%



Total World 322.1 327.4 329.0 336.7 341.8 1.5% 2.3% 100.0%

of which: OECD 152.5 155.7 152.9 155.9 158.6 1.7% 1.2% 46.4%

Non-OECD 169.5 171.7 176.1 180.8 183.2 1.3% 3.4% 53.6%

European Union # 42.3 41.7 37.1 38.6 41.4 7.1% -2.2% 12.1%

CIS 56.2 55.1 54.8 53.7 52.7 -1.8% -0.1% 15.4%



^ Less than 0.05.

w Less than 0.05%.

n/a not available.


Notes: The difference between these world consumption figures and the world production statistics is due to variations in stocks at storage facilities


Annual changes and shares of total are calculated using billion cubic feet per day figures.


96

Natural Gas: ConsumptionShare


US 657.4 675.5 690.0 710.5 716.3 0.5% 2.3% 22.4%

Canada 90.2 93.5 93.8 92.2 89.9 -2.8% 0.5% 2.8%

Mexico 71.9 74.9 78.1 78.4 80.6 2.5% 3.6% 2.5%


Argentina 42.1 42.1 42.5 43.4 44.6 2.7% 1.8% 1.4%

Brazil 28.5 33.6 35.6 37.5 32.9 -12.5% 7.9% 1.0%

Chile 4.1 4.1 3.4 3.7 4.1 11.1% -6.3% 0.1%

Colombia 8.9 9.0 9.8 9.6 9.5 -1.6% 4.8% 0.3%

Ecuador 0.5 0.6 0.6 0.6 0.6 1.5% 6.9% ♦

Peru 5.5 5.4 6.1 6.4 7.1 9.8% 16.8% 0.2%

Trinidad & Tobago 20.0 20.2 19.8 19.4 17.2 -11.4% 2.8% 0.5%

Venezuela 28.3 27.5 27.7 31.1 32.0 2.7% 2.3% 1.0%



Austria 8.1 7.7 7.1 7.5 7.9 4.4% -1.7% 0.2%

Azerbaijan 7.7 7.7 8.5 9.6 9.4 -2.2% 2.2% 0.3%

Belarus 16.7 16.7 16.5 14.0 15.3 9.0% -1.6% 0.5%

Belgium 14.4 14.2 12.4 13.6 13.9 1.8% -0.8% 0.4%

Bulgaria 2.5 2.4 2.4 2.6 2.7 3.9% -0.8% 0.1%

Czech Republic 6.9 6.9 6.2 6.5 7.0 7.9% -1.7% 0.2%

Denmark 3.5 3.3 2.8 2.8 2.9 1.4% -4.4% 0.1%

Finland 2.7 2.6 2.3 2.0 1.8 -9.2% -5.8% 0.1%

France 38.2 38.8 32.6 35.1 38.3 9.0% -1.6% 1.2%

Germany 69.7 73.1 63.5 66.2 72.4 9.2% -1.6% 2.3%

Greece 3.6 3.2 2.4 2.5 2.6 0.6% 0.5% 0.1%

Hungary 8.4 7.8 7.0 7.5 8.0 7.0% -4.7% 0.3%

Ireland 4.0 3.8 3.7 3.8 4.3 14.0% 0.8% 0.1%

Italy 61.4 57.4 50.7 55.3 58.1 4.7% -2.5% 1.8%

Kazakhstan 9.7 10.1 11.3 11.6 12.0 3.8% 6.3% 0.4%

Lithuania 2.7 2.2 2.1 2.1 1.8 -11.1% -1.8% 0.1%

Netherlands 32.4 32.8 28.6 28.3 30.2 6.4% -2.3% 0.9%

Norway 3.9 4.0 4.2 4.4 4.4 0.4% 0.8% 0.1%

Poland 15.0 15.0 14.6 14.7 15.6 5.7% 1.9% 0.5%

Portugal 4.0 3.8 3.7 4.3 4.6 8.1% 1.2% 0.1%

Romania 11.2 10.2 9.5 9.0 9.5 6.2% -4.3% 0.3%


Slovakia 4.4 4.8 3.8 3.9 4.0 1.6% -4.1% 0.1%

Spain 28.6 26.1 23.7 24.6 25.2 2.0% -1.9% 0.8%

Sweden 0.9 0.9 0.8 0.8 0.8 10.0% -0.9% ♦

Switzerland 2.6 2.8 2.4 2.6 2.7 4.8% 0.2% 0.1%

Turkey 37.3 37.8 40.1 39.2 37.9 -3.7% 5.0% 1.2%

Turkmenistan 23.7 20.6 23.0 26.5 26.6 ♦ 6.2% 0.8%

Ukraine 44.6 38.9 33.1 25.9 26.1 0.3% -8.4% 0.8%

United Kingdom 66.5 65.7 60.0 61.3 69.0 12.2% -3.3% 2.2%


Uzbekistan 42.5 42.2 43.9 45.2 46.2 2.0% 1.6% 1.4%





97

Iran 145.4 146.6 165.3 171.7 180.7 5.0% 6.4% 5.6%

Israel 2.3 6.2 6.8 7.6 8.7 14.5% 17.8% 0.3%

Kuwait 16.6 16.8 16.6 19.2 19.7 2.5% 5.7% 0.6%

Qatar 21.1 34.1 32.8 39.5 37.5 -5.4% 9.0% 1.2%

Saudi Arabia 89.4 90.0 92.1 94.0 98.4 4.4% 3.9% 3.1%




Algeria 27.9 30.0 33.7 35.5 36.0 1.2% 5.4% 1.1%

Egypt 47.3 46.3 43.2 43.0 46.1 7.0% 4.2% 1.4%

South Africa 4.0 4.1 4.5 4.6 4.6 1.3% 4.9% 0.1%

Other Africa 29.3 30.4 32.9 39.2 37.6 -4.4% 4.9% 1.2%

Total Africa 108.6 110.9 114.3 122.2 124.3 1.4% 4.8% 3.9%

Australia 30.4 32.0 34.4 38.6 37.0 -4.4% 6.6% 1.2%

Bangladesh 20.0 20.5 21.5 24.2 24.8 2.2% 6.9% 0.8%

China 135.8 154.7 169.6 175.3 189.3 7.7% 15.0% 5.9%


India 64.0 44.4 43.9 41.2 45.1 9.2% 2.5% 1.4%

Indonesia 38.0 36.7 36.8 36.4 33.9 -7.0% 1.2% 1.1%

Japan 105.2 105.2 106.2 102.1 100.1 -2.2% 3.7% 3.1%

Malaysia 31.9 36.3 38.0 37.6 38.7 2.7% 1.8% 1.2%

New Zealand 3.8 4.0 4.4 4.0 4.2 4.3% 2.3% 0.1%

Pakistan 39.4 38.4 37.7 39.2 40.9 4.2% 1.1% 1.3%

Philippines 3.3 3.0 3.2 3.0 3.4 14.3% 0.6% 0.1%

Singapore 8.5 9.5 9.8 11.0 11.3 2.5% 6.5% 0.4%

South Korea 45.2 47.3 43.0 39.3 40.9 4.0% 3.7% 1.3%

Taiwan 14.7 14.7 15.5 16.5 17.2 3.6% 6.9% 0.5%

Thailand 41.8 42.0 42.9 43.8 43.5 -1.0% 4.7% 1.4%

Vietnam 8.4 8.8 9.2 9.6 9.6 0.2% 5.2% 0.3%



Total World 3010.5 3054.4 3073.0 3146.7 3204.1 1.5% 2.3% 100.0%

of which: OECD 1429.4 1457.4 1434.8 1464.9 1495.2 1.8% 1.2% 46.7%

Non-OECD 1581.1 1596.9 1638.2 1681.8 1708.9 1.3% 3.4% 53.3%

European Union # 394.7 388.1 344.7 359.2 385.9 7.1% -2.2% 12.0%

CIS 524.6 512.6 509.8 499.8 492.0 -1.8% -0.1% 15.4%



^ Less than 0.05.

w Less than 0.05%.

n/a not available.


Notes: The difference between these world consumption figures and the world production statistics is due to variations in stocks at storage facilities





98

Natural Gas: Trade movements 2016 by pipeline in billion cubic metres

Billion cubic metres From

To US Canada Mexico Bolivia

Other S. &

Cent.

America Netherlands Norway

United

Kingdom Other Europe Azerbaijan Kazakhstan

Russian

Federation Turkmenistan Uzbekistan

US - 82.4 † - - - - - - - - - - -

Canada 21.9 - - - - - - - - - - - - -

Mexico 38.4 - - - - - - - - - - - - -

North America 60.3 82.4 † - - - - - - - - - - -

Argentina - - - 5.8 0.4 - - - - - - - - -

Brazil - - - 10.4 - - - - - - - - - -

Other S. & Cent. America - - - - 0.3 - - - - - - - - -

S. & Cent. America - - - 16.1 0.7 - - - - - - - - -

Austria - - - - - - 1.7 - - - - 5.6 - -

Belgium - - - - - 10.9 0.2 5.8 - - - 5.4 - -

Czech Republic - - - - - - 3.3 - - - - 4.2 - -

Finland - - - - - - - - - - - 2.3 - -

France - - - - - 4.6 16.6 - 0.6 - - 10.5 - -

Germany - - - - - 22.9 29.7 - 0.6 - - 46.0 - -

Poland - - - - - - - - 0.6 - - 2.5 - -

Hungary - - - - - - - - 2.1 - - 5.1 - -

Ireland - - - - - - - 2.7 - - - - - -

Italy - - - - - 9.2 5.9 - - - - 22.7 - -

Netherlands - - - - - - 18.6 1.6 3.1 - - 14.7 - -

Poland - - - - - - - - 2.4 - - 10.2 - -

Slovakia - - - - - - - - 10.0 - - 3.4 - -

Spain - - - - - - 3.2 - † - - - - -

Turkey - - - - - - - - - 6.5 - 23.2 - -

United Kingdom - - - - - 4.1 28.7 - 1.3 - - - - -

Other Europe - - - - - 0.6 1.7 † 3.6 2.1 - 10.3 - -

Europe - - - - - 52.3 109.8 10.0 24.4 8.6 - 166.1 - -

Belarus - - - - - - - - - - - 16.6 - -

Kazakhstan - - - - - - - - - - - 3.6 1.1 1.5

Russian Federation - - - - - - - - - - 16.1 - - 5.6

Ukraine - - - - - - - - 11.1 - - - - -

Other CIS - - - - - - - - † - - 4.5 - -

CIS - - - - - - - - 11.1 - 16.1 24.7 1.1 7.1

Iran - - - - - - - - - 0.2 - - 6.7 -

Oman - - - - - - - - - - - - - -

United Arab Emirates - - - - - - - - - - - - - -

Middle East - - - - - - - - - 0.2 - - 6.7 -

South Africa - - - - - - - - - - - - - -

Other Africa - - - - - - - - - - - - - -

Africa - - - - - - - - - - - - - -

Australia - - - - - - - - - - - - - -


99

China - - - - - - - - - - 0.4 - 29.4 4.3

Malaysia - - - - - - - - - - - - - -

Singapore - - - - - - - - - - - - - -

Thailand - - - - - - - - - - - - - -

Asia Pacific - - - - - - - - - - 0.4 - 29.4 4.3

Total exports 60.3 82.4 † 16.1 0.7 52.3 109.8 10.0 35.5 8.8 16.6 190.8 37.3 11.4

† Less than 0.05.


100

Iran Qatar Algeria Libya Other Africa Indonesia Myanmar Other Asia Pacific Total imports

- - - - - - - - 82.5

- - - - - - - - 21.9

- - - - - - - - 38.4

- - - - - - - - 142.8

- - - - - - - - 6.1

- - - - - - - - 10.4

- - - - - - - - 0.3

- - - - - - - - 16.8

- - - - - - - - 7.3

- - - - - - - - 22.2

- - - - - - - - 7.5

- - - - - - - - 2.3

- - - - - - - - 32.3

- - - - - - - - 99.3

- - - - - - - - 3.1

- - - - - - - - 7.2

- - - - - - - - 2.7

- - 17.2 4.4 - - - - 59.4

- - - - - - - - 38.0

- - - - - - - - 12.6

- - - - - - - - 13.4

- - 11.8 - - - - - 15.0

7.7 - - - - - - - 37.4

- - - - - - - - 34.1

- - 3.5 - - - - - 21.9

7.7 - 32.5 4.4 - - - - 415.8

- - - - - - - - 16.6

- - - - - - - - 6.2

- - - - - - - - 21.7

- - - - - - - - 11.1

0.7 - - - - - - - 5.1

0.7 - - - - - - - 60.8

- - - - - - - - 6.9

- 2.1 - - - - - - 2.1

- 17.9 - - - - - - 17.9

- 20.0 - - - - - - 26.9

- - - - 4.0 - - - 4.0

- - 4.6 - 0.1 - - - 4.7

- - 4.6 - 4.2 - - - 8.8

- - - - - - - 8.3 8.3


101

- - - - - - 3.9 - 38.0

- - - - - 0.6 - - 0.6

- - - - - 8.2 - 1.7 9.9

- - - - - - 8.8 - 8.8

- - - - - 8.8 12.7 10.0 65.6

8.4 20.0 37.1 4.4 4.2 8.8 12.7 10.0 737.5

Source: Includes data from FGE MENagas service, IHS.


102

Natural Gas: Trade movements 2016 as liquefied natural gas in billion cubic metres

From

Billion cubic metres Trinidad & Other Russian United Equatorial

To US* Brazil Peru Tobago Norway Europe* Federation Oman Qatar Arab Emirates Algeria Angola Egypt Guinea

US - - - 2.3 0.1 - - - - - - - - -

Canada † - - 0.2 0.1 - - - - - - - - -

Mexico 0.7 0.1 2.9 0.5 - - - - - - 0.1 - - 0.1

North America 0.7 0.1 2.9 3.1 0.2 - - - - - 0.1 - - 0.1

Argentina 0.4 0.4 - 1.4 0.5 0.3 - - 1.1 - 0.2 † - 0.1

Brazil 0.2 - - 0.3 0.3 0.2 - - 0.7 - - 0.1 - 0.2

Chile 0.7 - - 3.2 0.2 0.1 - - 0.1 - - - - 0.1

Other S. & Cent. America 0.1 - - 2.4 0.2 0.2 - - - - - - - 0.1

S. & Cent. America 1.5 0.4 - 7.2 1.1 0.7 - - 1.8 - 0.2 0.1 - 0.4

Belgium - - - - - 0.1 - - 2.7 - † - - -

France - - 0.2 - 0.6 † - - 0.8 - 6.2 - - -

Italy 0.1 - 0.1 - 0.1 † - - 5.2 - 0.1 - - -

Spain 0.1 - 1.7 0.6 0.7 † - - 2.5 - 2.9 0.1 - -

Turkey 0.2 - - 0.3 0.1 0.2 - - 1.0 - 4.4 - 0.1 -

United Kingdom - - - 0.1 0.2 0.1 - - 9.6 - 0.4 - † -

Other Europe & Eurasia 0.1 - - 0.2 2.4 † † - 1.9 0.1 0.9 - - -

Europe and Eurasia 0.5 - 2.0 1.2 4.1 0.5 † - 23.7 0.1 14.9 0.1 0.1 -

Middle East 0.5 - - 1.1 0.2 0.9 - 1.3 4.5 - - 0.1 0.2 1.2

Africa 0.1 - - 0.5 0.3 0.9 - - 6.4 - - - - 0.1

China 0.3 - 0.3 0.2 0.2 † 0.3 0.1 6.5 - - - 0.1 -

India 0.5 0.1 0.1 0.6 0.1 0.3 - 0.3 14.0 0.7 0.1 0.4 0.1 1.4

Japan - - - 0.1 - 0.7 9.5 3.3 15.8 6.5 0.4 - 0.1 0.4

Malaysia - - - 0.1 - 0.1 - 0.1 0.1 - - - 0.1 -

Pakistan - - - 0.2 - 0.1 - - 2.9 - - - - 0.4

Singapore - - - - - - - - 0.8 0.1 - - 0.1 0.2

South Korea 0.3 - 0.2 - 0.1 0.1 2.4 5.3 15.6 - 0.2 0.1 - 0.1

Taiwan - - - 0.1 0.1 - 1.7 0.2 8.2 0.1 0.1 - - 0.1

Thailand - - - - - - - 0.1 4.1 - - - - -

Other Asia Pacific - - - - - - - - - - - - - -

Asia Pacific 1.0 0.1 0.6 1.2 0.5 1.3 13.9 9.4 68.0 7.3 0.7 0.5 0.5 2.5

Total exports 4.4 0.6 5.5 14.3 6.3 4.2 14.0 10.6 104.4 7.4 15.9 0.8 0.7 4.3

† Less than 0.05.

* Includes re-exports


103

Papua Other

Nigeria Australia Brunei Indonesia Malaysia New Guinea Asia Pacific* Total imports

- - - - - - - 2.5

- - - - - - - 0.3

0.8 0.4 - 0.3 - - - 5.9

0.8 0.4 - 0.3 - - - 8.7

0.8 0.1 - - - - - 5.2

1.1 - - - - - - 3.0

- - - - - - - 4.3

0.1 - - - - - - 3.0

2.0 0.1 - - - - - 15.5

- - - - - - - 2.8

1.9 - - - - - - 9.7

0.1 - - - - - - 5.7

4.5 - - - - - - 13.2

1.4 - - - - - - 7.7

† - - - - - - 10.5

1.3 - - - - - - 6.9

9.2 - - - - - - 56.4

3.2 0.9 - 0.1 - - - 14.2

1.4 0.4 - - 0.1 - 0.1 10.2

0.4 15.7 0.1 3.7 3.4 2.9 0.2 34.3

2.7 1.2 - - 0.1 - - 22.5

2.5 29.2 5.5 8.7 20.2 5.5 0.2 108.5

- 0.7 0.5 - - - - 1.6

0.3 0.2 - - - - - 4.0

- 1.6 - - 0.1 - † 3.0

0.7 6.1 1.8 5.7 5.0 0.2 0.1 43.9

0.6 0.3 0.4 2.6 3.3 1.8 - 19.5

- - - - - - - 4.2

- - - 0.1 - - - 0.1

7.1 55.1 8.3 20.8 32.0 10.4 0.4 241.6

23.7 56.8 8.3 21.2 32.1 10.4 0.5 346.6


104

Gas Trade in 2015 and 2016 in billion cubic metres

Billion cubic metres 2015 2016

Pipeline LNG Pipeline LNG Pipeline LNG Pipeline LNG

imports imports exports exports imports imports exports exports

US 74.4 2.6 49.1 0.7 82.5 2.5 60.3 4.4

Canada 19.2 0.6 74.3 † 21.9 0.3 82.4 †

Mexico 29.9 7.3 † - 38.4 5.9 † -

Trinidad and Tobago - - - 16.9 - - - 14.3

Other S. & Cent. America 19.9 19.8 19.9 5.1 16.8 15.5 16.8 6.1

France 31.8 6.8 - 0.6 32.3 9.7 - 1.5

Germany 102.3 - 32.7 - 99.3 - 19.3 -

Italy 55.7 5.4 0.2 - 59.4 5.7 - -

Netherlands 33.6 2.1 47.1 1.3 38.0 1.5 52.3 0.7

Norway † - 109.6 5.9 † - 109.8 6.3

Spain 15.2 13.1 0.5 1.8 15.0 13.2 0.6 0.2

Turkey 38.4 7.7 0.6 - 37.4 7.7 0.6 -

United Kingdom 29.0 13.1 13.4 0.3 34.1 10.5 10.0 0.5

Other Europe 94.7 6.9 13.8 1.5 100.2 8.2 15.0 1.3

Russian Federation 21.8 - 179.1 14.0 21.7 - 190.8 14.0

Ukraine 17.3 - - - 11.1 - - -

Other CIS 27.0 - 72.3 - 27.9 - 74.0 -

Qatar - - 20.0 101.8 - - 20.0 104.4

Other Middle East 29.6 10.2 8.4 18.8 26.9 14.2 8.4 18.1

Algeria - - 26.3 16.6 - - 37.1 15.9

Other Africa 9.0 3.7 11.0 30.0 8.8 10.2 8.5 29.6

Australia 6.4 - - 38.1 8.3 0.1 - 56.8

China 33.6 25.8 - - 38.0 34.3 - -

Japan - 110.7 - - - 108.5 - -

Indonesia - - 9.3 20.7 - - 8.8 21.2

South Korea - 43.8 - 0.2 - 43.9 - 0.1

Other Asia Pacific 20.3 46.0 21.4 51.4 19.3 54.8 22.7 51.1

Total World 709.0 325.5 709.0 325.5 737.5 346.6 737.5 346.6

Source: Includes data from FGE MENAgas service, GIIGNL, IHS Waterborne, PIRA Energy Group, Wood Mackenzie.

† Less than 0.05.


105

Source: Includes data from FGE MENAgas service, GIIGNL, IHS Waterborne, PIRA Energy Group, Wood Mackenzie.


106


107


108

Natural Gas: Prices

US dollars per million Btu

LNG Natural gas Crude oil

Japan

Average

German import UK US Canada OECDcif price cif * (Heren NBP Index)* Henry Hub † (Alberta) ‡ countries cif

1984 5.10 4.00 - - - 5.00

1985 5.23 4.25 - - - 4.75

1986 4.10 3.93 - - - 2.57

1987 3.35 2.55 - - - 3.09

1988 3.34 2.22 - - - 2.56

1989 3.28 2.00 - 1.70 - 3.01

1990 3.64 2.78 - 1.64 1.05 3.82

1991 3.99 3.23 - 1.49 0.89 3.33

1992 3.62 2.70 - 1.77 0.98 3.19

1993 3.52 2.51 - 2.12 1.69 2.82

1994 3.18 2.35 - 1.92 1.45 2.70

1995 3.46 2.43 - 1.69 0.89 2.96

1996 3.66 2.50 1.87 2.76 1.12 3.54

1997 3.91 2.66 1.96 2.53 1.36 3.29

1998 3.05 2.33 1.86 2.08 1.42 2.16

1999 3.14 1.86 1.58 2.27 2.00 2.98

2000 4.72 2.91 2.71 4.23 3.75 4.83

2001 4.64 3.67 3.17 4.07 3.61 4.08

2002 4.27 3.21 2.37 3.33 2.57 4.17

2003 4.77 4.06 3.33 5.63 4.83 4.89

2004 5.18 4.30 4.46 5.85 5.03 6.27

2005 6.05 5.83 7.38 8.79 7.25 8.74

2006 7.14 7.87 7.87 6.76 5.83 10.66

2007 7.73 7.99 6.01 6.95 6.17 11.95

2008 12.55 11.60 10.79 8.85 7.99 16.76

2009 9.06 8.53 4.85 3.89 3.38 10.41

2010 10.91 8.03 6.56 4.39 3.69 13.47

2011 14.73 10.49 9.04 4.01 3.47 18.56

2012 16.75 10.93 9.46 2.76 2.27 18.82

2013 16.17 10.73 10.64 3.71 2.93 18.25

2014 16.33 9.11 8.25 4.35 3.87 16.80

2015 10.31 6.72 6.53 2.60 2.01 8.77

2016 6.94 4.93 4.69 2.46 1.55 7.04

* Source: 1984-1990 German Federal Statistical Office 1991-2016 German Federal Office of Economics and Export Control (BAFA).

† Source: ICIS Heren Energy Ltd.

‡ Source: Energy Intelligence Group, Natural Gas Week .

Note: Btu = British thermal units; cif = cost+insurance+freight (average prices).


109

Coal:

Total proved reserves at end 2016Anthracite Sub-bituminous

Million tonnes and bituminous and lignite Total Share of Total R/P ratio

US 221400 30182 251582 22.1% 381

Canada 4346 2236 6582 0.6% 109

Mexico 1160 51 1211 0.1% 151

Total North America 226906 32469 259375 22.8% 356

Brazil 1547 5049 6596 0.6% *

Colombia 4881 - 4881 0.4% 54

Venezuela 731 - 731 0.1% *

Other S. & Cent. America 1784 24 1808 0.2% *

Total S. & Cent. America 8943 5073 14016 1.2% 138

Bulgaria 192 2174 2366 0.2% 75

Czech Republic 1103 2573 3676 0.3% 80

Germany 12 36200 36212 3.2% 206

Greece - 2876 2876 0.3% 87

Hungary 276 2633 2909 0.3% 311

Kazakhstan 25605 - 25605 2.2% 250

Poland 18700 5461 24161 2.1% 184

Romania 11 280 291 ♦ 13

Russian Federation 69634 90730 160364 14.1% 417

Serbia 402 7112 7514 0.7% 196

Spain 868 319 1187 0.1% *

Turkey 378 10975 11353 1.0% 163

Ukraine 32039 2336 34375 3.0% *

United Kingdom 70 - 70 ♦ 17

Uzbekistan 1375 - 1375 0.1% 355

Other Europe & Eurasia 2618 5172 7790 0.7% 201

Total Europe & Eurasia 153283 168841 322124 28.3% 284

South Africa 9893 - 9893 0.9% 39

Zimbabwe 502 - 502 ♦ 186

Other Africa 2756 66 2822 0.2% 276

Middle East 1203 - 1203 0.1% *

Total Middle East & Africa 14354 66 14420 1.3% 54

Australia 68310 76508 144818 12.7% 294

China 230004 14006 244010 21.4% 72

India 89782 4987 94769 8.3% 137

Indonesia 17326 8247 25573 2.2% 59

Japan 340 10 350 ♦ 261

Mongolia 1170 1350 2520 0.2% 66

New Zealand 825 6750 7575 0.7% *

Pakistan 207 2857 3064 0.3% *

South Korea 326 - 326 ♦ 189

Thailand - 1063 1063 0.1% 63

Vietnam 3116 244 3360 0.3% 85

Other Asia Pacific 1322 646 1968 0.2% 29

Total Asia Pacific 412728 116668 529396 46.5% 102


110

Total World 816214 323117 1139331 100.0% 153

of which: OECD 319878 177264 497142 43.6% 291

Non-OECD 496336 145853 642189 56.4% 112

European Union 21813 53006 74819 6.6% 162

CIS 130162 93066 223228 19.6% 417

Source: Includes data from Federal Institute for Geosciences and Natural Resources (BGR) Energy Study 2016.


w Less than 0.05%.

Notes: Total proved reserves of coal- Generally taken to be those quantities that geological and engineering information indicates with reasonable certainty

can be recovered in the future from known reservoirs under existing economic and operating conditions. The data series for total proved coal reserves does not necessarily





Reserves-to-production (R/P) ratios are calculated excluding other solid fuels in reserves and production.

Shares of total and R/P ratios are calculated using million tonnes figures.


111

Coal: Prices

US dollars per tonne

Northwest Europe

marker price †

US Central

Appalachian coal

spot price index ‡

Japan steam spot cif

price †

China Qinhuangdao

spot price*

Japan coking coal

import cif price

Japan steam coal

import cif price

Asian marker

price †

1987 31.30 - - - 53.44 41.28 -

1988 39.94 - - - 55.06 42.47 -

1989 42.08 - - - 58.68 48.86 -

1990 43.48 31.59 - - 60.54 50.81 -

1991 42.80 29.01 - - 60.45 50.30 -

1992 38.53 28.53 - - 57.82 48.45 -

1993 33.68 29.85 - - 55.26 45.71 -

1994 37.18 31.72 - - 51.77 43.66 -

1995 44.50 27.01 - - 54.47 47.58 -

1996 41.25 29.86 - - 56.68 49.54 -

1997 38.92 29.76 - - 55.51 45.53 -

1998 32.00 31.00 - - 50.76 40.51 29.48

1999 28.79 31.29 - - 42.83 35.74 27.82

2000 35.99 29.90 - 27.52 39.69 34.58 31.76

2001 39.03 50.15 37.69 31.78 41.33 37.96 36.89

2002 31.65 33.20 31.47 33.19 42.01 36.90 30.41

2003 43.60 38.52 39.61 31.74 41.57 34.74 36.53

2004 72.08 64.90 74.22 42.76 60.96 51.34 72.42

2005 60.54 70.12 64.62 51.34 89.33 62.91 61.84

2006 64.11 62.96 65.22 53.53 93.46 63.04 56.47

2007 88.79 51.16 95.59 61.23 88.24 69.86 84.57

2008 147.67 118.79 157.88 104.97 179.03 122.81 148.06

2009 70.66 68.08 83.59 87.86 167.82 110.11 78.81

2010 92.50 71.63 108.47 110.08 158.95 105.19 105.43

2011 121.52 87.38 126.13 127.27 229.12 136.21 125.74

2012 92.50 72.06 100.30 111.89 191.46 133.61 105.50

2013 81.69 71.39 90.07 95.42 140.45 111.16 90.90

2014 75.38 69.00 76.13 84.12 114.41 97.65 77.89

2015 56.79 53.59 60.10 67.53 93.85 79.47 63.52

2016 59.87 53.56 71.66 71.35 89.40 72.97 69.91

† Source: IHS Northwest Europe prices for 1990-2000 are the average of the monthly marker, 2001-2016 the average of weekly prices. IHS Japan prices basis = 6,000 kilocalories per kilogram NAR CIF.

The Asian prices are the average of the monthly marker.

Chinese prices are the average monthly price for 2000-2005, weekly prices 2006 -2016, 5,500 kilocalories per kilogram NAR, including cost and freight (CFR).

‡ Source: Platts. Prices are for CAPP 12,500 Btu, 1.2 SO2 coal, fob.

Note: CAPP = Central Appalachian; cif = cost+insurance+freight (average prices); fob = free on board.


112

Coal: Production*Share

Million tonnes 2012 2013 2014 2015 2016 2016 2005-15 2016

US 922.1 893.4 907.2 813.7 660.6 -19.0% -2.3% 8.9%

Canada 67.3 68.4 67.3 61.2 60.3 -1.8% -1.1% 0.8%

Mexico 15.2 14.6 14.9 12.3 8.0 -34.8% -0.3% 0.1%


Brazil 6.6 8.6 7.9 8.0 8.1 - 2.5% 0.1%

Colombia 89.2 85.5 88.6 85.5 90.5 5.5% 3.7% 1.2%

Venezuela 1.9 1.2 0.8 0.8 0.3 -66.4% -19.7% ♦

Other S. & Cent. America 1.0 3.2 4.5 3.4 2.8 -18.7% 15.7% ♦

Total S. & Cent. America 98.7 98.5 101.8 97.8 101.6 3.6% 2.8% 1.4%

Bulgaria 33.4 28.6 31.3 35.9 31.5 -12.5% 3.8% 0.4%

Czech Republic 55.0 49.0 46.9 46.4 46.0 -1.2% -2.9% 0.6%

Germany 196.2 190.6 185.8 184.3 176.1 -4.7% -1.0% 2.4%

Greece 63.0 53.9 50.8 46.2 33.1 -28.7% -4.0% 0.4%

Hungary 9.3 9.6 9.6 9.3 9.3 0.6% -0.3% 0.1%

Kazakhstan 120.5 119.6 114.0 107.3 102.4 -4.9% 2.2% 1.4%

Poland 144.1 142.9 137.1 135.8 131.1 -3.8% -1.6% 1.8%

Romania 33.9 24.7 23.6 25.5 23.2 -9.2% -2.0% 0.3%


Serbia 38.2 40.3 29.8 37.8 38.4 1.4% n/a 0.5%

Spain 6.2 4.4 3.9 3.1 1.7 -43.5% -16.8% ♦

Turkey 71.5 60.4 65.2 58.4 70.6 20.5% -0.4% 0.9%

Ukraine 87.3 84.8 64.0 38.5 41.8 8.2% -7.0% 0.6%

United Kingdom 17.0 12.8 11.6 8.6 4.2 -51.5% -8.3% 0.1%


Uzbekistan 4.0 4.1 4.4 4.0 3.9 -2.2% 2.2% 0.1%


Total Europe & Eurasia 1305.2 1257.0 1207.4 1180.0 1162.0 -1.8% -0.4% 15.6%

Total Middle East 1.5 1.5 1.4 1.5 1.5 - -2.8% ♦

South Africa 258.6 256.3 261.5 252.1 251.3 -0.6% 0.3% 3.4%

Zimbabwe 1.6 3.1 5.8 4.3 2.7 -37.9% 2.6% ♦

Other Africa 7.1 8.2 9.0 9.6 10.2 5.7% 19.0% 0.1%

Total Africa 267.3 267.6 276.3 266.1 264.2 -1.0% 0.6% 3.5%

Australia 448.2 472.8 504.2 505.4 492.8 -2.8% 2.9% 6.6%

China 3945.1 3974.3 3873.9 3746.5 3411.0 -9.2% 4.7% 45.7%

India 605.6 608.5 646.2 674.2 692.4 2.4% 4.6% 9.3%

Indonesia 385.9 474.6 458.1 461.6 434.0 -6.2% 11.7% 5.8%

Japan 1.3 1.2 1.3 1.2 1.3 14.2% 0.5% ♦

Mongolia 29.9 30.1 25.3 24.2 38.1 57.0% 12.4% 0.5%

New Zealand 4.9 4.6 4.0 3.4 2.9 -15.1% -4.3% ♦

Pakistan 3.0 3.0 3.4 3.3 4.0 19.5% -0.5% 0.1%

South Korea 2.1 1.8 1.7 1.8 1.7 -2.4% -4.5% ♦

Thailand 18.1 18.1 18.0 15.2 17.0 11.8% -3.2% 0.2%

Vietnam 42.1 41.1 41.1 41.5 39.4 -5.4% 2.0% 0.5%





113

Total World 8207.7 8274.6 8197.8 7961.2 7460.4 -6.5% 2.7% 100.0%

of which: OECD 2057.8 2026.9 2056.6 1928.0 1732.2 -10.4% -1.0% 23.2%

Non-OECD 6149.9 6247.7 6141.2 6033.2 5728.2 -5.3% 4.3% 76.8%

European Union # 590.3 557.9 539.3 527.5 484.7 -8.4% -1.9% 6.5%

CIS 574.4 567.9 544.0 526.6 538.3 1.9% 1.1% 7.2%

^ Less than 0.05.

w Less than 0.05%.

n/a not available.


Notes: Annual changes and shares of total are calculated using million tonnes figures.


* Commercial solid fuels only, i.e. bituminous coal and anthracite (hard coal), and lignite and brown (sub-bituminous) coal, and other commercial solid fuels. Includes coal produced for Coal-


114

Coal: Production*Share


US 517.8 500.9 507.7 449.3 364.8 -19.0% -2.5% 10.0%

Canada 35.6 36.4 35.6 31.9 31.4 -1.8% -1.0% 0.9%

Mexico 7.4 7.2 7.3 6.9 4.5 -34.8% 1.2% 0.1%


Brazil 2.9 3.7 3.4 3.5 3.5 - 2.3% 0.1%

Colombia 61.5 59.0 61.1 59.0 62.5 5.5% 3.7% 1.7%

Venezuela 1.4 0.9 0.6 0.6 0.2 -66.4% -19.7% ♦

Other S. & Cent. America 0.5 1.7 2.4 1.9 1.5 -18.3% 16.3% ♦


Bulgaria 5.6 4.8 5.1 5.8 5.1 -12.5% 3.4% 0.1%

Czech Republic 20.1 17.7 16.8 16.8 16.3 -3.4% -3.3% 0.4%

Germany 47.8 45.1 44.1 42.9 39.9 -7.2% -2.7% 1.1%

Greece 8.0 6.7 6.4 5.7 4.1 -28.7% -4.0% 0.1%

Hungary 1.6 1.6 1.6 1.5 1.5 0.6% -1.4% ♦

Kazakhstan 51.6 51.4 48.9 46.2 44.1 -4.9% 2.2% 1.2%

Poland 57.8 57.2 54.0 53.0 52.3 -1.5% -2.7% 1.4%

Romania 6.3 4.7 4.4 4.7 4.3 -9.2% -2.0% 0.1%


Serbia 7.3 7.7 5.7 7.2 7.4 1.4% n/a 0.2%

Spain 2.5 1.8 1.6 1.2 0.7 -43.3% -15.7% ♦

Turkey 17.0 15.5 16.4 12.8 15.2 18.7% 1.3% 0.4%

Ukraine 38.0 36.6 25.9 16.4 17.1 4.3% -7.3% 0.5%

United Kingdom 10.6 8.0 7.3 5.4 2.6 -51.5% -8.2% 0.1%


Uzbekistan 1.2 1.1 1.2 1.1 1.1 -1.8% 2.3% ♦



Total Middle East 0.7 0.7 0.6 0.7 0.7 - -3.3% ♦

South Africa 146.6 145.3 148.2 142.9 142.4 -0.6% 0.3% 3.9%

Zimbabwe 1.0 2.0 3.7 2.8 1.7 -37.9% 2.6% ♦

Other Africa 4.4 5.1 5.5 6.0 6.3 5.5% 20.6% 0.2%

Total Africa 152.0 152.3 157.5 151.7 150.5 -1.0% 0.7% 4.1%

Australia 265.9 285.8 305.7 305.8 299.3 -2.4% 3.6% 8.2%

China 1873.5 1894.6 1864.2 1825.6 1685.7 -7.9% 3.9% 46.1%

India 255.0 255.7 269.5 280.9 288.5 2.4% 4.0% 7.9%

Indonesia 227.4 279.7 269.9 272.0 255.7 -6.2% 11.7% 7.0%

Japan 0.7 0.7 0.7 0.6 0.7 14.2% 0.5% ♦

Mongolia 18.1 18.0 14.8 14.5 22.8 57.0% 14.8% 0.6%

New Zealand 3.0 2.8 2.5 2.0 1.7 -15.4% -4.8% ♦

Pakistan 1.4 1.3 1.5 1.5 1.8 19.5% -0.5% ♦

South Korea 1.0 0.8 0.8 0.8 0.8 -2.4% -4.4% ♦

Thailand 4.8 4.9 4.8 3.9 4.3 10.6% -4.5% 0.1%

Vietnam 23.6 23.0 23.0 23.2 22.0 -5.4% 2.0% 0.6%



Total World 3938.9 4006.1 3992.4 3887.3 3656.4 -6.2% 2.5% 100.0%



115

of which: OECD 1005.7 1000.7 1020.9 946.6 844.8 -11.0% -1.0% 23.1%

Non-OECD 2933.1 3005.5 2971.4 2940.7 2811.6 -4.7% 3.9% 76.9%

European Union # 168.1 157.3 150.6 144.6 133.6 -7.9% -3.1% 3.7%

CIS 260.3 263.5 254.0 251.5 256.8 1.8% 1.9% 7.0%

* Commercial solid fuels only, i.e. bituminous coal and anthracite (hard coal), and lignite and brown (sub-bituminous) coal, and other commercial solid fuels. Includes coal produced for Coal-to-Liquids and Coal-to-Gas transformations.

^ Less than 0.05.

w Less than 0.05%.

n/a not available.


Notes: Annual changes and shares of total are calculated using million tonnes oil equivalent figures.



116

Coal: Consumption*Share


US 437.9 454.6 453.5 391.8 358.4 -8.8% -3.8% 9.6%

Canada 21.0 20.8 19.7 19.6 18.7 -5.2% -4.2% 0.5%

Mexico 12.8 12.7 12.7 12.7 9.8 -22.9% 1.0% 0.3%


Argentina 1.3 1.3 1.5 1.4 1.1 -22.5% 1.9% ♦

Brazil 15.3 16.5 17.5 17.7 16.5 -6.8% 3.1% 0.4%

Chile 6.7 7.5 7.6 7.3 8.2 12.3% 10.2% 0.2%

Colombia 4.6 5.0 5.2 5.3 4.6 -14.0% 14.8% 0.1%

Ecuador - - - - - - - -

Peru 0.9 0.9 0.9 0.8 0.8 - -1.3% ♦

Trinidad & Tobago - - - - - - - -

Venezuela 0.2 0.2 0.2 0.2 0.1 -66.4% 18.4% ♦



Austria 3.2 3.3 3.0 3.2 3.2 -2.3% -2.1% 0.1%

Azerbaijan ^ ^ ^ ^ ^ - -19.8% ♦

Belarus 0.8 0.9 0.8 0.7 0.8 16.5% -0.3% ♦

Belgium 3.2 3.3 3.3 3.2 3.0 -6.7% -4.7% 0.1%

Bulgaria 6.9 5.9 6.4 6.6 5.7 -13.5% -0.4% 0.2%

Czech Republic 17.4 17.2 16.0 16.6 16.9 1.7% -2.0% 0.5%

Denmark 2.5 3.2 2.6 1.7 2.1 20.8% -7.3% 0.1%

Finland 4.5 5.0 4.5 3.8 4.1 8.0% -2.2% 0.1%

France 11.1 11.6 8.6 8.4 8.3 -1.1% -4.6% 0.2%

Germany 80.5 82.8 79.6 78.5 75.3 -4.3% -0.4% 2.0%

Greece 8.1 7.0 6.7 5.6 4.7 -16.7% -4.6% 0.1%

Hungary 2.6 2.3 2.2 2.4 2.3 -3.6% -2.5% 0.1%

Ireland 2.3 2.0 2.0 2.2 2.2 -0.7% -2.0% 0.1%

Italy 15.7 13.5 13.1 12.3 10.9 -11.9% -2.9% 0.3%

Kazakhstan 36.5 36.3 41.0 35.8 35.6 -0.8% 2.9% 1.0%

Lithuania 0.2 0.3 0.2 0.2 0.2 4.8% -0.1% ♦

Netherlands 8.2 8.2 9.1 11.0 10.3 -7.0% 3.1% 0.3%

Norway 0.8 0.8 0.9 0.8 0.8 -0.1% 1.3% ♦

Poland 51.2 53.4 49.4 48.7 48.8 ♦ -1.2% 1.3%

Portugal 2.9 2.7 2.7 3.3 2.9 -11.9% -0.2% 0.1%

Romania 7.6 5.8 5.7 5.9 5.4 -8.9% -3.9% 0.1%

Russian Federation 98.4 90.5 87.6 92.2 87.3 -5.5% -0.3% 2.3%

Slovakia 3.5 3.5 3.4 3.3 3.1 -5.0% -2.5% 0.1%

Spain 15.5 11.4 11.6 13.7 10.4 -23.9% -4.0% 0.3%

Sweden 2.2 2.2 2.1 2.1 2.2 6.0% -2.1% 0.1%

Switzerland 0.1 0.1 0.1 0.1 0.1 - -1.1% ♦

Turkey 36.5 31.6 36.1 34.7 38.4 10.3% 4.6% 1.0%

Turkmenistan - - - - - - - -

Ukraine 42.5 41.6 35.6 27.3 31.5 14.9% -3.1% 0.8%

United Kingdom 39.0 36.8 29.7 23.0 11.0 -52.5% -4.7% 0.3%


Uzbekistan 1.2 1.1 1.2 1.1 1.0 -10.1% 1.9% ♦

Other Europe & Eurasia 22.9 23.8 21.9 23.0 23.0 -0.1% 1.1% 0.6%




117

Iran 1.1 1.4 1.6 1.6 1.7 4.3% 0.5% ♦

Israel 8.8 7.4 6.9 6.7 5.7 -15.5% -1.6% 0.2%

Kuwait - - - - - - - -

Qatar - - - - - - - -

Saudi Arabia 0.1 0.1 0.1 0.1 0.1 - 13.5% ♦

United Arab Emirates 1.7 1.4 1.5 1.3 1.3 - 24.1% ♦

Other Middle East 0.6 0.5 0.7 0.5 0.5 ♦ 13.2% ♦

Total Middle East 12.3 10.9 10.8 10.2 9.3 -9.5% 0.4% 0.2%

Algeria 0.3 0.2 0.2 0.1 0.1 - -13.2% ♦

Egypt 0.4 0.4 0.4 0.4 0.4 4.3% -7.0% ♦

South Africa 88.3 88.6 89.8 83.4 85.1 1.8% 0.4% 2.3%

Other Africa 7.0 8.3 11.9 11.4 10.3 -10.3% 3.8% 0.3%

Total Africa 96.1 97.5 102.3 95.3 95.9 0.4% 0.7% 2.6%

Australia 45.1 43.0 42.6 44.1 43.8 -0.9% -1.6% 1.2%

Bangladesh 0.9 1.0 0.8 0.7 0.8 17.0% 3.7% ♦

China 1927.8 1969.1 1954.5 1913.6 1887.6 -1.6% 3.7% 50.6%

China Hong Kong SAR 7.3 7.8 8.1 6.7 6.7 -0.3% -0.2% 0.2%

India 330.0 352.8 387.5 396.6 411.9 3.6% 6.5% 11.0%

Indonesia 53.0 57.0 45.1 51.2 62.7 22.2% 7.7% 1.7%

Japan 115.8 121.2 119.1 119.9 119.9 -0.2% 0.5% 3.2%

Malaysia 15.9 15.1 15.4 16.9 19.9 17.6% 9.4% 0.5%

New Zealand 1.7 1.5 1.5 1.4 1.2 -15.4% -4.5% ♦

Pakistan 4.0 3.2 4.7 4.7 5.4 15.1% 2.2% 0.1%

Philippines 8.1 10.0 10.6 11.6 13.5 16.0% 9.7% 0.4%

Singapore ^ 0.3 0.4 0.4 0.4 -6.5% 47.4% ♦

South Korea 81.0 81.9 84.6 85.5 81.6 -4.8% 4.6% 2.2%

Taiwan 38.0 38.6 39.0 37.8 38.6 1.7% 0.7% 1.0%

Thailand 16.5 16.3 17.9 17.6 17.7 0.7% 4.3% 0.5%

Vietnam 15.0 15.8 18.9 22.3 21.3 -4.4% 9.5% 0.6%

Other Asia Pacific 17.2 13.8 16.0 16.9 20.6 21.3% -2.3% 0.6%


Total World 3817.3 3887.0 3889.4 3784.7 3732.0 -1.7% 1.9% 100.0%

of which: OECD 1047.3 1058.4 1040.9 972.7 913.3 -6.4% -1.9% 24.5%

Non-OECD 2770.0 2828.5 2848.5 2812.0 2818.7 ♦ 3.7% 75.5%

European Union # 294.3 288.0 268.4 261.1 238.4 -8.9% -1.9% 6.4%

CIS 180.7 171.8 167.8 158.9 157.9 -0.9% -0.2% 4.2%

* Commercial solid fuels only, i.e. bituminous coal and anthracite (hard coal), and lignite and brown (sub-bituminous) coal, and other commercial solid fuels.

Excludes coal converted to liquid or gaseous fuels, but includes coal consumed in transformation processes.

^ Less than 0.05.

w Less than 0.05%.

n/a not available.




Notes: Differences between these consumption figures and the world production statistics are accounted for by stock changes, and unadvoidable

disparities in the definition, measurement or conversion of coal supply and demand data.


118

Nuclear: Consumption*Share

Terawatt-hours 2012 2013 2014 2015 2016 2016 2005-15 2016

US 809.8 830.5 839.1 839.1 847.7 0.7% 0.2% 32.4%

Canada 94.2 102.7 106.5 100.7 102.6 1.6% 1.0% 3.9%

Mexico 8.8 11.8 9.7 11.6 10.6 -9.0% 0.7% 0.4%


Argentina 6.4 6.2 5.8 7.1 8.4 17.5% 0.4% 0.3%

Brazil 16.0 15.4 15.4 14.7 15.9 7.5% 4.1% 0.6%

Chile - - - - - - - -

Colombia - - - - - - - -

Ecuador - - - - - - - -

Peru - - - - - - - -


Venezuela - - - - - - - -

Other S. & Cent. America - - - - - - - -


Austria - - - - - - - -

Azerbaijan - - - - - - - -

Belarus - - - - - - - -

Belgium 40.3 42.6 33.7 26.1 43.5 66.3% -5.8% 1.7%

Bulgaria 15.8 14.2 15.9 15.4 15.8 2.3% -1.8% 0.6%

Czech Republic 30.3 30.7 30.3 26.8 24.1 -10.4% 0.8% 0.9%

Denmark - - - - - - - -

Finland 23.2 23.9 23.8 23.5 23.5 -0.5% ♦ 0.9%

France 425.4 423.7 436.5 437.4 403.2 -8.1% -0.3% 15.4%

Germany 99.5 97.3 97.1 91.8 84.6 -8.0% -5.6% 3.2%

Greece - - - - - - - -

Hungary 15.8 15.4 15.6 15.8 16.1 1.1% 1.4% 0.6%

Ireland - - - - - - - -

Italy - - - - - - - -

Kazakhstan - - - - - - - -

Lithuania - - - - - - - -

Netherlands 3.9 2.9 4.1 4.1 4.1 0.7% 0.2% 0.2%

Norway - - - - - - - -

Poland - - - - - - - -

Portugal - - - - - - - -

Romania 11.5 11.6 11.7 11.6 11.3 -3.3% 7.7% 0.4%


Slovakia 15.5 15.7 15.5 15.1 14.8 -2.7% -1.6% 0.6%

Spain 61.5 56.7 57.3 57.3 58.7 2.2% ♦ 2.2%

Sweden 64.0 66.5 64.9 56.3 62.8 11.1% -2.5% 2.4%

Switzerland 25.6 26.2 27.8 23.3 21.3 -8.7% ♦ 0.8%

Turkey - - - - - - - -


Ukraine 90.1 83.2 88.4 87.6 81.0 -7.9% -0.1% 3.1%

United Kingdom 70.4 70.6 63.7 70.3 71.7 1.7% -1.5% 2.7%


Uzbekistan - - - - - - - -





119

Iran 1.4 4.1 4.4 3.5 6.2 75.3% - 0.2%

Israel - - - - - - - -

Kuwait - - - - - - - -

Qatar - - - - - - - -

Saudi Arabia - - - - - - - -

United Arab Emirates - - - - - - - -

Other Middle East - - - - - - - -

Total Middle East 1.4 4.1 4.4 3.5 6.2 75.3% - 0.2%

Algeria - - - - - - - -

Egypt - - - - - - - -

South Africa 12.0 14.1 13.8 12.2 15.9 29.7% 0.8% 0.6%

Other Africa - - - - - - - -

Total Africa 12.0 14.1 13.8 12.2 15.9 29.7% 0.8% 0.6%

Australia - - - - - - - -

Bangladesh - - - - - - - -

China 97.4 111.6 132.5 170.8 213.2 24.5% 12.4% 8.1%

China Hong Kong SAR - - - - - - - -

India 33.1 33.3 34.7 38.3 37.9 -1.3% 8.0% 1.4%

Indonesia - - - - - - - -

Japan 18.0 14.6 - 4.5 17.7 289.7% -34.1% 0.7%

Malaysia - - - - - - - -

New Zealand - - - - - - - -

Pakistan 5.3 5.2 4.6 4.8 5.6 15.1% 6.2% 0.2%

Philippines - - - - - - - -

Singapore - - - - - - - -

South Korea 150.3 138.8 156.4 164.8 162.2 -1.8% 1.2% 6.2%

Taiwan 40.4 41.6 42.4 36.5 31.7 -13.4% -0.9% 1.2%

Thailand - - - - - - - -

Vietnam - - - - - - - -

Other Asia Pacific - - - - - - - -

Total Asia Pacific 344.6 345.2 370.7 419.7 468.2 11.3% -2.7% 17.9%

Total World 2471.5 2491.9 2541.2 2575.3 2616.5 1.3% -0.7% 100.0%

of which: OECD 1962.1 1975.9 1988.5 1974.3 1974.8 -0.2% -1.7% 75.5%

Non-OECD 509.4 516.0 552.7 600.9 641.8 6.5% 3.8% 24.5%

European Union # 882.6 877.1 876.6 857.4 839.8 -2.3% -1.5% 32.1%

CIS 270.1 258.5 271.6 285.9 279.9 -2.3% 1.8% 10.7%

* Based on gross generation and not accounting for cross-border electricity supply. Converted on the

basis of thermal equivalence assuming 38% conversion efficiency in a modern thermal power station.

^ Less than 0.05


n/a not available.


Notes: Annual changes and shares of total are calculated using terawatt-hours figures.



120

Nuclear: Consumption*Share


US 183.2 187.9 189.9 189.9 191.8 0.7% 0.2% 32.4%

Canada 21.3 23.2 24.1 22.8 23.2 1.6% 1.0% 3.9%

Mexico 2.0 2.7 2.2 2.6 2.4 -9.0% 0.7% 0.4%


Argentina 1.4 1.4 1.3 1.6 1.9 17.5% 0.4% 0.3%

Brazil 3.6 3.5 3.5 3.3 3.6 7.5% 4.1% 0.6%

Chile - - - - - - - -

Colombia - - - - - - - -

Ecuador - - - - - - - -

Peru - - - - - - - -


Venezuela - - - - - - - -

Other S. & Cent. America - - - - - - - -


Austria - - - - - - - -

Azerbaijan - - - - - - - -

Belarus - - - - - - - -

Belgium 9.1 9.6 7.6 5.9 9.8 66.3% -5.8% 1.7%

Bulgaria 3.6 3.2 3.6 3.5 3.6 2.3% -1.8% 0.6%

Czech Republic 6.9 7.0 6.9 6.1 5.5 -10.4% 0.8% 0.9%

Denmark - - - - - - - -

Finland 5.3 5.4 5.4 5.3 5.3 -0.5% ♦ 0.9%

France 96.3 95.9 98.8 99.0 91.2 -8.1% -0.3% 15.4%

Germany 22.5 22.0 22.0 20.8 19.1 -8.0% -5.6% 3.2%

Greece - - - - - - - -

Hungary 3.6 3.5 3.5 3.6 3.6 1.1% 1.4% 0.6%

Ireland - - - - - - - -

Italy - - - - - - - -

Kazakhstan - - - - - - - -

Lithuania - - - - - - - -

Netherlands 0.9 0.7 0.9 0.9 0.9 0.7% 0.2% 0.2%

Norway - - - - - - - -

Poland - - - - - - - -

Portugal - - - - - - - -

Romania 2.6 2.6 2.6 2.6 2.6 -3.3% 7.7% 0.4%


Slovakia 3.5 3.6 3.5 3.4 3.3 -2.7% -1.6% 0.6%

Spain 13.9 12.8 13.0 13.0 13.3 2.2% ♦ 2.2%

Sweden 14.5 15.0 14.7 12.8 14.2 11.1% -2.5% 2.4%

Switzerland 5.8 5.9 6.3 5.3 4.8 -8.7% ♦ 0.8%

Turkey - - - - - - - -


Ukraine 20.4 18.8 20.0 19.8 18.3 -7.9% -0.1% 3.1%

United Kingdom 15.9 16.0 14.4 15.9 16.2 1.7% -1.5% 2.7%


Uzbekistan - - - - - - - -





121

Iran 0.3 0.9 1.0 0.8 1.4 75.3% - 0.2%

Israel - - - - - - - -

Kuwait - - - - - - - -

Qatar - - - - - - - -

Saudi Arabia - - - - - - - -


Other Middle East - - - - - - - -


Algeria - - - - - - - -

Egypt - - - - - - - -

South Africa 2.7 3.2 3.1 2.8 3.6 29.7% 0.8% 0.6%

Other Africa - - - - - - - -

Total Africa 2.7 3.2 3.1 2.8 3.6 29.7% 0.8% 0.6%

Australia - - - - - - - -

Bangladesh - - - - - - - -

China 22.0 25.3 30.0 38.6 48.2 24.5% 12.4% 8.1%


India 7.5 7.5 7.8 8.7 8.6 -1.3% 8.0% 1.4%

Indonesia - - - - - - - -

Japan 4.1 3.3 - 1.0 4.0 289.7% -34.1% 0.7%

Malaysia - - - - - - - -

New Zealand - - - - - - - -

Pakistan 1.2 1.2 1.1 1.1 1.3 15.1% 6.2% 0.2%

Philippines - - - - - - - -

Singapore - - - - - - - -

South Korea 34.0 31.4 35.4 37.3 36.7 -1.8% 1.2% 6.2%

Taiwan 9.1 9.4 9.6 8.3 7.2 -13.4% -0.9% 1.2%

Thailand - - - - - - - -

Vietnam - - - - - - - -

Other Asia Pacific - - - - - - - -

Total Asia Pacific 78.0 78.1 83.9 95.0 105.9 11.3% -2.7% 17.9%

Total World 559.2 563.9 575.0 582.7 592.1 1.3% -0.7% 100.0%

of which: OECD 444.0 447.1 449.9 446.7 446.8 -0.2% -1.7% 75.5%

Non-OECD 115.3 116.8 125.1 136.0 145.2 6.5% 3.8% 24.5%

European Union # 199.7 198.5 198.3 194.0 190.0 -2.3% -1.5% 32.1%

CIS 61.1 58.5 61.5 64.7 63.3 -2.3% 1.8% 10.7%



^ Less than 0.05


n/a not available.


Notes: Annual changes and share of total are calculated using million tonnes oil equivalent figures.



122

Hydroelectricity: Consumption*Share

Terawatt-hours 2012 2013 2014 2015 2016 2016 2005-15 2016

US 274.0 266.5 255.8 246.5 261.8 5.9% -0.8% 6.5%

Canada 380.4 391.9 382.6 377.6 388.2 2.5% 0.4% 9.7%

Mexico 31.9 28.0 38.9 30.9 30.0 -3.3% 1.1% 0.7%

Total North America 686.3 686.4 677.3 655.0 680.0 3.5% ♦ 16.9%

Argentina 37.3 41.1 41.3 42.3 38.4 -9.4% 0.7% 1.0%

Brazil 415.3 391.0 373.4 359.7 384.3 6.5% 0.6% 9.6%

Chile 20.2 19.6 23.6 24.0 19.5 -18.8% -0.6% 0.5%

Colombia 47.6 44.4 44.7 44.7 47.0 5.0% 1.3% 1.2%

Ecuador 12.2 11.0 11.5 13.1 15.6 18.7% 6.6% 0.4%

Peru 22.0 22.3 22.2 23.7 23.8 0.3% 2.8% 0.6%


Venezuela 81.7 83.4 73.9 76.3 61.2 -20.0% -0.1% 1.5%



Austria 43.8 42.0 41.0 37.1 39.7 6.8% ♦ 1.0%

Azerbaijan 1.8 1.5 1.3 1.6 2.0 19.3% -5.9% ♦

Belarus 0.1 0.1 0.1 0.1 0.1 - 11.5% ♦

Belgium 0.4 0.4 0.3 0.3 0.4 22.4% 1.0% ♦

Bulgaria 3.2 4.1 4.6 5.7 3.9 -32.1% 2.9% 0.1%

Czech Republic 2.2 2.9 1.9 1.8 2.0 11.1% -2.8% ♦

Denmark ^ ^ ^ ^ ^ 2.8% -2.2% ♦

Finland 16.8 12.8 13.4 16.8 15.8 -6.1% 2.1% 0.4%

France 59.6 70.2 62.4 54.4 59.5 9.2% 0.5% 1.5%

Germany 22.1 23.0 19.6 19.0 21.0 10.4% -0.3% 0.5%

Greece 4.4 6.3 4.5 6.1 5.4 -12.3% 2.0% 0.1%

Hungary 0.2 0.2 0.3 0.2 0.3 11.1% 1.5% ♦

Ireland 0.8 0.6 0.7 0.8 0.7 -15.8% 2.5% ♦

Italy 41.9 52.8 58.5 45.5 41.0 -10.2% 2.4% 1.0%

Kazakhstan 7.6 7.7 8.3 9.3 9.3 - 1.7% 0.2%

Lithuania 0.4 0.5 0.4 0.3 0.5 29.8% -2.5% ♦

Netherlands 0.1 0.1 0.1 0.1 0.1 16.3% 0.6% ♦

Norway 141.7 128.2 135.4 137.4 143.4 4.1% 0.1% 3.6%

Poland 2.0 2.4 2.2 1.8 2.1 16.5% -1.8% 0.1%

Portugal 5.6 13.7 15.6 8.7 15.8 81.9% 6.2% 0.4%

Romania 12.1 14.8 18.5 16.6 17.9 7.4% -1.9% 0.4%


Slovakia 4.0 4.7 4.3 4.1 4.5 9.9% -1.1% 0.1%

Spain 20.5 36.8 39.2 27.9 35.6 27.3% 4.5% 0.9%

Sweden 78.9 61.4 63.8 75.3 62.4 -17.4% 0.4% 1.5%

Switzerland 37.9 37.8 37.4 37.6 34.4 -8.7% 1.9% 0.9%

Turkey 57.9 59.4 40.6 67.1 67.2 -0.2% 5.4% 1.7%

Turkmenistan - - - - - - -100.0% -

Ukraine 10.5 13.8 8.5 5.4 7.2 32.2% -8.0% 0.2%

United Kingdom 5.3 4.7 5.9 6.3 5.4 -14.9% 2.5% 0.1%


Uzbekistan 11.2 11.6 11.8 11.8 11.9 - 3.2% 0.3%





123

Iran 12.1 14.9 15.1 18.1 12.8 -29.3% 3.3% 0.3%

Israel ^ ^ ^ ^ ^ - -1.5% ♦

Kuwait - - - - - - - -

Qatar - - - - - - - -

Saudi Arabia - - - - - - - -


Other Middle East 10.2 9.0 6.0 8.0 8.0 -0.6% -1.7% 0.2%


Algeria 0.4 0.1 0.2 0.1 0.1 -50.5% -12.6% ♦

Egypt 14.1 12.9 14.0 14.0 14.0 - 1.0% 0.3%

South Africa 1.2 1.2 1.0 0.8 1.0 32.2% -5.1% ♦

Other Africa 97.2 104.0 108.5 104.0 99.0 -5.1% 3.4% 2.5%

Total Africa 112.9 118.2 123.7 118.9 114.1 -4.3% 2.9% 2.8%

Australia 17.1 19.1 14.5 13.9 17.9 27.7% -1.0% 0.4%

Bangladesh 0.8 0.7 0.6 0.9 0.9 -1.8% 1.8% ♦

China 862.8 909.6 1051.1 1114.5 1162.8 4.0% 10.9% 28.9%


India 115.8 132.0 139.0 133.3 128.8 -3.6% 3.2% 3.2%

Indonesia 12.8 16.9 15.1 13.7 14.4 4.8% 2.5% 0.4%

Japan 76.1 78.0 80.0 83.8 80.0 -4.9% 0.8% 2.0%

Malaysia 9.2 11.7 13.4 15.5 18.5 19.5% 9.9% 0.5%

New Zealand 22.9 23.1 24.4 24.6 26.0 5.4% 0.5% 0.6%

Pakistan 29.5 30.9 31.9 32.3 34.0 5.2% 0.5% 0.8%

Philippines 10.3 10.0 9.1 8.7 9.3 6.7% 0.3% 0.2%

Singapore - - - - - - - -

South Korea 4.0 4.3 2.8 2.1 2.5 14.1% -5.2% 0.1%

Taiwan 5.7 5.4 4.3 4.5 6.6 46.2% 1.2% 0.2%

Thailand 8.4 5.4 5.2 3.8 3.5 -6.0% -4.0% 0.1%

Vietnam 52.8 57.1 60.0 57.1 60.5 5.7% 13.2% 1.5%



Total World 3677.3 3797.2 3886.1 3903.3 4022.9 2.8% 2.9% 100.0%

of which: OECD 1389.1 1408.7 1388.7 1369.4 1400.3 2.0% 0.6% 34.8%

Non-OECD 2288.2 2388.5 2497.4 2533.9 2622.7 3.2% 4.5% 65.2%

European Union # 337.2 370.9 374.5 341.0 347.8 1.7% 0.9% 8.6%

CIS 229.4 246.7 236.9 228.6 248.3 8.3% -0.5% 6.2%

* Based on gross primary hydroelectric generation and not accounting for cross-border electricity supply. Converted on the


^ Less than 0.05.


n/a not available.





124

Hydroelectricity: Consumption*Share


US 62.0 60.3 57.9 55.8 59.2 5.9% -0.8% 6.5%

Canada 86.1 88.7 86.6 85.4 87.8 2.5% 0.4% 9.7%

Mexico 7.2 6.3 8.8 7.0 6.8 -3.3% 1.1% 0.7%

Total North America 155.3 155.3 153.2 148.2 153.9 3.5% ♦ 16.9%

Argentina 8.4 9.3 9.3 9.6 8.7 -9.4% 0.7% 1.0%

Brazil 94.0 88.5 84.5 81.4 86.9 6.5% 0.6% 9.6%

Chile 4.6 4.4 5.3 5.4 4.4 -18.8% -0.6% 0.5%

Colombia 10.8 10.0 10.1 10.1 10.6 5.0% 1.3% 1.2%

Ecuador 2.8 2.5 2.6 3.0 3.5 18.7% 6.6% 0.4%

Peru 5.0 5.1 5.0 5.4 5.4 0.3% 2.8% 0.6%


Venezuela 18.5 18.9 16.7 17.3 13.9 -20.0% -0.1% 1.5%



Austria 9.9 9.5 9.3 8.4 9.0 6.8% ♦ 1.0%

Azerbaijan 0.4 0.3 0.3 0.4 0.4 19.3% -5.9% ♦

Belarus ^ ^ ^ ^ ^ - 11.5% ♦

Belgium 0.1 0.1 0.1 0.1 0.1 22.4% 1.0% ♦

Bulgaria 0.7 0.9 1.0 1.3 0.9 -32.1% 2.9% 0.1%

Czech Republic 0.5 0.6 0.4 0.4 0.5 11.1% -2.8% ♦

Denmark ^ ^ ^ ^ ^ 2.8% -2.2% ♦

Finland 3.8 2.9 3.0 3.8 3.6 -6.1% 2.1% 0.4%

France 13.5 15.9 14.1 12.3 13.5 9.2% 0.5% 1.5%

Germany 5.0 5.2 4.4 4.3 4.8 10.4% -0.3% 0.5%

Greece 1.0 1.4 1.0 1.4 1.2 -12.3% 2.0% 0.1%

Hungary ^ ^ 0.1 0.1 0.1 11.1% 1.5% ♦

Ireland 0.2 0.1 0.2 0.2 0.2 -15.8% 2.5% ♦

Italy 9.5 11.9 13.2 10.3 9.3 -10.2% 2.4% 1.0%

Kazakhstan 1.7 1.7 1.9 2.1 2.1 - 1.7% 0.2%

Lithuania 0.1 0.1 0.1 0.1 0.1 29.8% -2.5% ♦

Netherlands ^ ^ ^ ^ ^ 16.3% 0.6% ♦

Norway 32.1 29.0 30.6 31.1 32.4 4.1% 0.1% 3.6%

Poland 0.5 0.6 0.5 0.4 0.5 16.5% -1.8% 0.1%

Portugal 1.3 3.1 3.5 2.0 3.6 81.9% 6.2% 0.4%

Romania 2.7 3.3 4.2 3.8 4.1 7.4% -1.9% 0.4%


Slovakia 0.9 1.1 1.0 0.9 1.0 9.9% -1.1% 0.1%

Spain 4.6 8.3 8.9 6.3 8.1 27.3% 4.5% 0.9%

Sweden 17.9 13.9 14.4 17.0 14.1 -17.4% 0.4% 1.5%

Switzerland 8.6 8.6 8.5 8.5 7.8 -8.7% 1.9% 0.9%

Turkey 13.1 13.4 9.2 15.2 15.2 -0.2% 5.4% 1.7%

Turkmenistan - - - - - - -100.0% -

Ukraine 2.4 3.1 1.9 1.2 1.6 32.2% -8.0% 0.2%

United Kingdom 1.2 1.1 1.3 1.4 1.2 -14.9% 2.5% 0.1%


Uzbekistan 2.5 2.6 2.7 2.7 2.7 - 3.2% 0.3%





125

Iran 2.7 3.4 3.4 4.1 2.9 -29.3% 3.3% 0.3%

Israel ^ ^ ^ ^ ^ - -1.5% ♦

Kuwait - - - - - - - -

Qatar - - - - - - - -

Saudi Arabia - - - - - - - -


Other Middle East 2.3 2.0 1.4 1.8 1.8 -0.6% -1.7% 0.2%


Algeria 0.1 ^ ^ ^ ^ -50.5% -12.6% ♦

Egypt 3.2 2.9 3.2 3.2 3.2 - 1.0% 0.3%

South Africa 0.3 0.3 0.2 0.2 0.2 32.2% -5.1% ♦

Other Africa 22.0 23.5 24.6 23.5 22.4 -5.1% 3.4% 2.5%

Total Africa 25.5 26.8 28.0 26.9 25.8 -4.3% 2.9% 2.8%

Australia 3.9 4.3 3.3 3.2 4.0 27.7% -1.0% 0.4%

Bangladesh 0.2 0.2 0.1 0.2 0.2 -1.8% 1.8% ♦

China 195.2 205.8 237.8 252.2 263.1 4.0% 10.9% 28.9%


India 26.2 29.9 31.5 30.2 29.1 -3.6% 3.2% 3.2%

Indonesia 2.9 3.8 3.4 3.1 3.3 4.8% 2.5% 0.4%

Japan 17.2 17.7 18.1 19.0 18.1 -4.9% 0.8% 2.0%

Malaysia 2.1 2.6 3.0 3.5 4.2 19.5% 9.9% 0.5%

New Zealand 5.2 5.2 5.5 5.6 5.9 5.4% 0.5% 0.6%

Pakistan 6.7 7.0 7.2 7.3 7.7 5.2% 0.5% 0.8%

Philippines 2.3 2.3 2.1 2.0 2.1 6.7% 0.3% 0.2%

Singapore - - - - - - - -

South Korea 0.9 1.0 0.6 0.5 0.6 14.1% -5.2% 0.1%

Taiwan 1.3 1.2 1.0 1.0 1.5 46.2% 1.2% 0.2%

Thailand 1.9 1.2 1.2 0.9 0.8 -6.0% -4.0% 0.1%

Vietnam 11.9 12.9 13.6 12.9 13.7 5.7% 13.2% 1.5%



Total World 832.1 859.2 879.3 883.2 910.3 2.8% 2.9% 100.0%

of which: OECD 314.3 318.8 314.2 309.9 316.8 2.0% 0.6% 34.8%

Non-OECD 517.8 540.5 565.1 573.4 593.4 3.2% 4.5% 65.2%

European Union # 76.3 83.9 84.7 77.2 78.7 1.7% 0.9% 8.6%

CIS 51.9 55.8 53.6 51.7 56.2 8.3% -0.5% 6.2%

* Based on gross primary hydroelectric generation and not accounting for cross-border electricity supply. Converted on the


^ Less than 0.05.


n/a not available.





126

Renewables: Consumption*Share

Terawatt-hours 2012 2013 2014 2015 2016 2016 2005-15 2016

US 228.3 266.2 296.8 315.8 370.2 16.9% 13.2% 20.0%

Canada 24.7 28.3 30.7 37.4 40.6 8.1% 13.8% 2.2%

Mexico 10.1 11.6 13.8 16.4 18.2 10.4% 7.2% 1.0%


Argentina 2.6 2.8 3.6 2.8 2.9 5.0% 8.4% 0.2%

Brazil 40.3 47.1 58.6 70.7 83.9 18.4% 17.8% 4.5%

Chile 5.2 6.3 7.3 8.4 10.1 19.9% 16.7% 0.5%

Colombia 1.3 1.3 1.7 1.8 2.1 15.4% 12.8% 0.1%

Ecuador 0.3 0.4 0.5 0.5 0.6 12.6% 18.1% ♦

Peru 0.7 1.2 1.7 1.9 2.5 29.9% 18.5% 0.1%

Trinidad & Tobago ^ ^ ^ ^ ^ - -14.1% ♦

Venezuela ^ ^ ^ ^ ^ - - ♦



Austria 7.4 8.4 8.9 10.2 10.8 6.0% 10.5% 0.6%

Azerbaijan - 0.1 0.1 0.1 0.2 66.3% - ♦

Belarus 0.1 0.1 0.1 0.2 0.3 100.5% 65.2% ♦

Belgium 10.1 11.3 11.9 14.1 14.0 -1.7% 22.8% 0.8%

Bulgaria 2.1 2.8 2.8 3.1 3.2 1.5% 90.3% 0.2%

Czech Republic 6.0 6.5 7.3 7.6 7.4 -3.5% 27.5% 0.4%

Denmark 14.8 16.0 18.0 18.9 17.9 -5.7% 6.8% 1.0%

Finland 11.6 12.7 12.8 13.7 14.9 8.6% 3.5% 0.8%

France 24.4 25.8 28.8 35.0 36.1 2.9% 21.8% 1.9%

Germany 120.3 128.3 141.8 168.4 167.4 -0.9% 14.7% 9.0%

Greece 5.7 8.0 7.7 8.8 9.2 4.7% 20.2% 0.5%

Hungary 2.4 2.6 2.8 3.0 3.5 15.8% 6.3% 0.2%

Ireland 4.5 5.0 5.7 7.1 6.7 -5.8% 19.0% 0.4%

Italy 50.3 59.2 62.1 63.4 66.3 4.3% 16.4% 3.6%

Kazakhstan ^ ^ ^ 0.2 0.4 95.1% - ♦

Lithuania 0.8 1.0 1.1 1.3 1.6 20.0% 65.2% 0.1%

Netherlands 12.4 12.1 11.6 13.6 13.7 0.8% 6.3% 0.7%

Norway 1.9 2.2 2.5 2.7 2.3 -14.6% 12.5% 0.1%

Poland 14.8 14.6 17.7 20.9 20.5 -1.8% 28.9% 1.1%

Portugal 13.8 15.7 16.0 15.7 16.5 4.4% 16.2% 0.9%

Romania 2.9 5.2 6.5 9.6 9.0 -6.0% 109.1% 0.5%

Russian Federation 0.5 0.5 0.6 0.7 0.7 6.9% 4.0% ♦

Slovakia 1.4 1.5 2.0 2.2 2.2 1.8% 49.5% 0.1%

Spain 66.4 71.9 71.1 69.1 68.7 -0.9% 10.8% 3.7%

Sweden 19.4 21.3 22.0 27.1 27.0 -0.8% 12.4% 1.5%

Switzerland 2.0 2.3 2.7 2.9 3.5 17.6% 10.3% 0.2%

Turkey 7.5 10.1 12.3 17.0 22.8 33.8% 51.0% 1.2%

Turkmenistan ^ ^ ^ ^ ^ 27.0% - ♦

Ukraine 0.8 1.3 1.7 1.7 1.5 -12.4% 46.9% 0.1%

United Kingdom 35.8 48.6 58.7 77.3 77.4 -0.1% 20.4% 4.2%


Uzbekistan - ^ ^ ^ ^ 50.0% - ♦





127

Iran 0.2 0.4 0.4 0.4 0.5 2.6% 20.0% ♦

Israel 0.5 0.5 0.9 1.3 1.7 37.1% 60.6% 0.1%

Kuwait - - ^ ^ ^ 580.0% - ♦

Qatar ^ ^ ^ ^ ^ 10.0% - ♦

Saudi Arabia ^ ^ 0.1 0.1 0.1 14.3% - ♦

United Arab Emirates ^ 0.1 0.3 0.3 0.3 2.6% - ♦

Other Middle East ^ ^ 0.1 0.2 0.7 196.8% 39.9% ♦


Algeria ^ ^ 0.1 0.1 0.2 190.2% - ♦

Egypt 1.3 1.3 1.3 1.9 2.6 35.5% 13.3% 0.1%

South Africa 0.4 0.6 2.5 6.1 7.8 26.3% 35.3% 0.4%

Other Africa 4.5 5.7 7.9 10.6 11.6 9.6% 16.6% 0.6%

Total Africa 6.3 7.6 11.8 18.7 22.2 18.5% 19.6% 1.2%

Australia 13.2 16.4 18.3 21.1 23.7 12.0% 14.9% 1.3%

Bangladesh 0.1 0.1 0.1 0.2 0.2 15.3% 40.8% ♦

China 130.1 186.9 224.3 284.5 380.6 33.4% 44.1% 20.5%

China Hong Kong SAR 0.1 0.1 0.1 0.1 0.1 -0.4% - ♦

India 45.9 51.2 52.8 56.2 72.8 29.2% 18.8% 3.9%

Indonesia 9.7 9.7 10.3 10.5 11.3 7.1% 4.7% 0.6%

Japan 34.2 41.2 52.2 65.5 83.2 26.7% 10.0% 4.5%

Malaysia 1.5 1.2 1.1 1.2 1.5 21.6% - 0.1%

New Zealand 8.9 9.0 10.1 10.8 10.8 -0.2% 10.0% 0.6%

Pakistan 0.1 0.3 0.8 1.3 2.0 47.0% - 0.1%

Philippines 10.5 9.9 10.7 12.3 13.7 10.8% 2.2% 0.7%

Singapore 0.6 0.7 0.8 0.9 1.0 14.8% 6.2% 0.1%

South Korea 8.6 10.2 14.7 17.3 19.0 9.6% 45.6% 1.0%

Taiwan 3.5 3.9 4.1 4.5 4.6 1.8% 8.8% 0.2%

Thailand 5.2 7.2 9.0 10.0 12.5 24.4% 18.3% 0.7%

Vietnam 0.1 0.1 0.1 0.2 0.3 40.5% 15.9% ♦



Total World 1054.1 1240.7 1402.1 1620.6 1854.2 14.1% 16.1% 100.0%

of which: OECD 774.1 881.3 976.7 1100.0 1193.6 8.2% 13.9% 64.4%

Non-OECD 280.0 359.5 425.5 520.6 660.7 26.6% 23.4% 35.6%

European Union # 430.5 482.1 521.6 594.8 599.4 0.5% 14.8% 32.3%

CIS 1.4 2.0 2.6 2.9 3.1 7.8% 19.1% 0.2%

* Based on gross generation from renewable sources including wind, geothermal, solar, biomass and waste, and not accounting for cross-border electricity supply.

Converted on the basis of thermal equivalence assuming 38% conversion efficiency in a modern thermal power station.

^ Less than 0.05.


n/a not available.





128

Renewables: Consumption*Share


US 51.7 60.2 67.2 71.5 83.8 16.9% 13.2% 20.0%

Canada 5.6 6.4 7.0 8.5 9.2 8.1% 13.8% 2.2%

Mexico 2.3 2.6 3.1 3.7 4.1 10.4% 7.2% 1.0%


Argentina 0.6 0.6 0.8 0.6 0.7 5.0% 8.4% 0.2%

Brazil 9.1 10.6 13.3 16.0 19.0 18.4% 17.8% 4.5%

Chile 1.2 1.4 1.6 1.9 2.3 19.9% 16.7% 0.5%

Colombia 0.3 0.3 0.4 0.4 0.5 15.4% 12.8% 0.1%

Ecuador 0.1 0.1 0.1 0.1 0.1 12.6% 18.1% ♦

Peru 0.2 0.3 0.4 0.4 0.6 29.9% 18.5% 0.1%

Trinidad & Tobago ^ ^ ^ ^ ^ - -14.1% ♦

Venezuela ^ ^ ^ ^ ^ - - ♦



Austria 1.7 1.9 2.0 2.3 2.4 6.0% 10.5% 0.6%

Azerbaijan - ^ ^ ^ ^ 66.3% - ♦

Belarus ^ ^ ^ ^ 0.1 100.5% 65.2% ♦

Belgium 2.3 2.6 2.7 3.2 3.2 -1.7% 22.8% 0.8%

Bulgaria 0.5 0.6 0.6 0.7 0.7 1.5% 90.3% 0.2%

Czech Republic 1.3 1.5 1.6 1.7 1.7 -3.5% 27.5% 0.4%

Denmark 3.4 3.6 4.1 4.3 4.1 -5.7% 6.8% 1.0%

Finland 2.6 2.9 2.9 3.1 3.4 8.6% 3.5% 0.8%

France 5.5 5.8 6.5 7.9 8.2 2.9% 21.8% 1.9%

Germany 27.2 29.0 32.1 38.1 37.9 -0.9% 14.7% 9.0%

Greece 1.3 1.8 1.7 2.0 2.1 4.7% 20.2% 0.5%

Hungary 0.6 0.6 0.6 0.7 0.8 15.8% 6.3% 0.2%

Ireland 1.0 1.1 1.3 1.6 1.5 -5.8% 19.0% 0.4%

Italy 11.4 13.4 14.1 14.3 15.0 4.3% 16.4% 3.6%

Kazakhstan ^ ^ ^ ^ 0.1 95.1% - ♦

Lithuania 0.2 0.2 0.3 0.3 0.4 20.0% 65.2% 0.1%

Netherlands 2.8 2.7 2.6 3.1 3.1 0.8% 6.3% 0.7%

Norway 0.4 0.5 0.6 0.6 0.5 -14.6% 12.5% 0.1%

Poland 3.4 3.3 4.0 4.7 4.6 -1.8% 28.9% 1.1%

Portugal 3.1 3.6 3.6 3.6 3.7 4.4% 16.2% 0.9%

Romania 0.6 1.2 1.5 2.2 2.0 -6.0% 109.1% 0.5%

Russian Federation 0.1 0.1 0.1 0.2 0.2 6.9% 4.0% ♦

Slovakia 0.3 0.3 0.5 0.5 0.5 1.8% 49.5% 0.1%

Spain 15.0 16.3 16.1 15.6 15.5 -0.9% 10.8% 3.7%

Sweden 4.4 4.8 5.0 6.1 6.1 -0.8% 12.4% 1.5%

Switzerland 0.5 0.5 0.6 0.7 0.8 17.6% 10.3% 0.2%

Turkey 1.7 2.3 2.8 3.9 5.2 33.8% 51.0% 1.2%

Turkmenistan ^ ^ ^ ^ ^ 27.0% - ♦

Ukraine 0.2 0.3 0.4 0.4 0.3 -12.4% 46.9% 0.1%

United Kingdom 8.1 11.0 13.3 17.5 17.5 -0.1% 20.4% 4.2%


Uzbekistan - ^ ^ ^ ^ 50.0% - ♦





129

Iran 0.1 0.1 0.1 0.1 0.1 2.6% 20.0% ♦

Israel 0.1 0.1 0.2 0.3 0.4 37.1% 60.6% 0.1%

Kuwait - - ^ ^ ^ 580.0% - ♦

Qatar ^ ^ ^ ^ ^ 10.0% - ♦

Saudi Arabia ^ ^ ^ ^ ^ 14.3% - ♦

United Arab Emirates ^ ^ 0.1 0.1 0.1 2.6% - ♦

Other Middle East ^ ^ ^ 0.1 0.2 196.8% 39.9% ♦


Algeria ^ ^ ^ ^ 0.1 190.2% - ♦

Egypt 0.3 0.3 0.3 0.4 0.6 35.5% 13.3% 0.1%

South Africa 0.1 0.1 0.6 1.4 1.8 26.3% 35.3% 0.4%

Other Africa 1.0 1.3 1.8 2.4 2.6 9.6% 16.6% 0.6%

Total Africa 1.4 1.7 2.7 4.2 5.0 18.5% 19.6% 1.2%

Australia 3.0 3.7 4.1 4.8 5.4 12.0% 14.9% 1.3%

Bangladesh ^ ^ ^ ^ ^ 15.3% 40.8% ♦

China 29.4 42.3 50.8 64.4 86.1 33.4% 44.1% 20.5%

China Hong Kong SAR ^ ^ ^ ^ ^ -0.4% - ♦

India 10.4 11.6 12.0 12.7 16.5 29.2% 18.8% 3.9%

Indonesia 2.2 2.2 2.3 2.4 2.6 7.1% 4.7% 0.6%

Japan 7.7 9.3 11.8 14.8 18.8 26.7% 10.0% 4.5%

Malaysia 0.4 0.3 0.3 0.3 0.3 21.6% - 0.1%

New Zealand 2.0 2.0 2.3 2.4 2.4 -0.2% 10.0% 0.6%

Pakistan ^ 0.1 0.2 0.3 0.4 47.0% - 0.1%

Philippines 2.4 2.2 2.4 2.8 3.1 10.8% 2.2% 0.7%

Singapore 0.1 0.2 0.2 0.2 0.2 14.8% 6.2% 0.1%

South Korea 2.0 2.3 3.3 3.9 4.3 9.6% 45.6% 1.0%

Taiwan 0.8 0.9 0.9 1.0 1.0 1.8% 8.8% 0.2%

Thailand 1.2 1.6 2.0 2.3 2.8 24.4% 18.3% 0.7%

Vietnam ^ ^ ^ ^ 0.1 40.5% 15.9% ♦



Total World 238.5 280.7 317.3 366.7 419.6 14.1% 16.1% 100.0%

of which: OECD 175.2 199.4 221.0 248.9 270.1 8.2% 13.9% 64.4%

Non-OECD 63.4 81.3 96.3 117.8 149.5 26.6% 23.4% 35.6%

European Union # 97.4 109.1 118.0 134.6 135.6 0.5% 14.8% 32.3%

CIS 0.3 0.5 0.6 0.6 0.7 7.8% 19.1% 0.2%

* Based on gross generation from renewable sources including wind, geothermal, solar, biomass and waste, and not accounting for cross-border electricity supply.

Converted on the basis of thermal equivalence assuming 38% conversion efficiency in a modern thermal power station.

^ Less than 0.05.


n/a not available.





130

Renewables: Consumption - Solar*Share

Terawatt-hours 2012 2013 2014 2015 2016 2016 2005-15 2016

US 9.0 16.0 29.2 39.4 56.8 43.6% 48.6% 17.1%

Canada 0.8 1.2 1.9 2.6 3.1 18.3% 64.0% 0.9%

Mexico 0.1 0.1 0.2 0.2 0.4 72.0% 39.2% 0.1%


Argentina ^ ^ ^ ^ ^ -3.1% 68.2% ♦

Brazil ^ ^ ^ 0.1 0.1 50.5% - ♦

Chile ^ ^ 0.5 1.3 2.6 96.6% - 0.8%

Colombia ^ ^ ^ ^ ^ - - ♦

Ecuador ^ ^ ^ ^ ^ 7.2% 122.0% ♦

Peru 0.1 0.2 0.2 0.2 0.2 4.7% - 0.1%

Trinidad & Tobago ^ ^ ^ ^ ^ - - ♦

Venezuela ^ ^ ^ ^ ^ - - ♦



Austria 0.3 0.6 0.8 0.9 1.1 14.2% 46.2% 0.3%

Azerbaijan - ^ ^ ^ 0.1 1242.0% - ♦

Belarus - ^ ^ ^ ^ 310.0% - ♦

Belgium 2.1 2.6 2.9 3.1 3.0 -4.0% 123.2% 0.9%

Bulgaria 0.8 1.4 1.3 1.4 1.4 1.6% - 0.4%

Czech Republic 2.2 2.1 2.1 2.3 2.1 -6.2% 183.3% 0.6%

Denmark 0.1 0.5 0.6 0.6 0.7 22.8% 75.7% 0.2%

Finland ^ ^ ^ ^ ^ 34.2% 12.8% ♦

France 4.1 4.7 5.9 7.4 8.3 11.4% 92.7% 2.5%

Germany 26.4 31.0 36.1 38.7 38.2 -1.6% 40.6% 11.5%

Greece 1.7 3.6 3.8 3.9 4.0 1.9% 128.6% 1.2%

Hungary ^ ^ 0.1 0.1 0.2 60.4% - 0.1%

Ireland ^ ^ ^ ^ ^ 229.6% - ♦

Italy 18.9 21.6 22.3 22.9 22.9 -0.5% 93.6% 6.9%

Kazakhstan - ^ ^ ^ 0.1 84.3% - ♦

Lithuania ^ ^ 0.1 0.1 0.1 -8.8% - ♦

Netherlands 0.3 0.5 0.8 1.1 1.5 36.2% 41.8% 0.5%

Norway ^ ^ ^ ^ ^ 48.8% - ♦Poland ^ ^ ^ 0.1 0.1 116.9% - ♦Portugal 0.4 0.5 0.6 0.8 0.8 2.2% 70.7% 0.2%Romania ^ 0.4 1.3 2.0 1.8 -7.2% - 0.6%Russian Federation ^ ^ ^ ^ 0.1 115.7% - ♦Slovakia 0.4 0.6 0.6 0.5 0.5 4.9% - 0.2%Spain 12.0 12.7 13.7 13.9 13.6 -2.6% 67.9% 4.1%Sweden ^ ^ ^ 0.1 0.2 74.2% 47.4% 0.1%Switzerland 0.3 0.5 0.9 1.1 1.4 23.6% 48.8% 0.4%Turkey ^ ^ ^ 0.2 0.7 253.3% - 0.2%Turkmenistan ^ ^ ^ ^ ^ 27.0% - ♦Ukraine 0.3 0.6 0.4 0.5 0.4 -17.2% - 0.1%United Kingdom 1.4 2.0 4.0 7.6 10.3 35.7% 98.4% 3.1%USSR n/a n/a n/a n/a n/a n/a n/a n/aUzbekistan - ^ ^ ^ ^ 50.0% - ♦Other Europe & Eurasia 0.3 0.4 0.6 0.8 0.8 7.3% 45.1% 0.2%Total Europe & Eurasia 71.9 86.5 98.9 110.1 114.4 3.6% 53.5% 34.4%



131

Iran - - ^ ^ ^ 700.0% - ♦Israel 0.4 0.5 0.8 1.2 1.6 39.5% - 0.5%Kuwait - - ^ ^ ^ 580.0% - ♦Qatar ^ ^ ^ ^ ^ 10.0% - ♦Saudi Arabia ^ ^ 0.1 0.1 0.1 14.3% - ♦United Arab Emirates ^ 0.1 0.3 0.3 0.3 2.6% - 0.1%Other Middle East ^ ^ 0.1 0.1 0.4 270.1% - 0.1%Total Middle East 0.4 0.7 1.3 1.7 2.5 47.0% - 0.7%

Algeria ^ ^ 0.1 0.1 0.2 252.5% - 0.1%Egypt ^ ^ ^ ^ 0.1 60.0% - ♦South Africa 0.1 0.2 1.1 2.7 3.3 18.8% 62.7% 1.0%Other Africa 0.4 0.5 0.6 0.7 1.2 69.5% 58.1% 0.4%Total Africa 0.5 0.8 1.8 3.5 4.7 33.0% 62.0% 1.4%

Australia 2.4 3.8 5.0 6.0 7.2 19.8% 53.1% 2.1%Bangladesh 0.1 0.1 0.1 0.2 0.2 15.6% 43.1% 0.1%China 3.6 8.4 23.5 38.5 66.2 71.5% 84.6% 19.9%China Hong Kong SAR ^ ^ ^ ^ ^ -5.2% - ♦India 1.4 2.8 4.4 6.6 11.9 81.3% 80.2% 3.6%Indonesia ^ ^ ^ ^ 0.1 395.8% - ♦Japan 7.4 12.9 23.5 36.6 49.5 34.8% 36.5% 14.9%Malaysia ^ 0.1 0.2 0.3 0.3 18.9% - 0.1%New Zealand ^ ^ ^ ^ 0.1 51.4% - ♦Pakistan 0.1 0.1 0.2 0.3 0.5 65.3% - 0.2%Philippines ^ ^ ^ 0.1 1.0 585.6% 57.1% 0.3%Singapore ^ ^ ^ 0.1 0.1 66.9% - ♦South Korea 1.1 1.6 2.6 4.0 5.2 31.2% 75.5% 1.6%Taiwan 0.2 0.3 0.6 0.9 1.1 29.0% 97.7% 0.3%Thailand 0.5 1.1 1.4 1.8 2.3 31.3% - 0.7%Vietnam - - ^ ^ ^ 37.5% - ♦Other Asia Pacific 0.1 0.1 0.1 0.2 0.2 18.5% 39.7% 0.1%Total Asia Pacific 16.8 31.5 61.7 95.5 146.0 52.5% 48.4% 43.8%

Total World 100.0 137.6 196.3 256.2 333.1 29.6% 50.7% 100.0%of which: OECD 91.9 120.2 159.3 197.1 236.5 19.7% 47.6% 71.0% Non-OECD 8.1 17.4 37.1 59.1 96.6 63.0% 75.9% 29.0% European Union # 71.3 85.3 97.5 108.1 111.6 2.9% 53.4% 33.5% CIS 0.3 0.6 0.5 0.6 0.7 14.5% - 0.2%

* Based on gross generation and not accounting for cross-border electricity supply. ^ Less than 0.05. ♦ Less than 0.05%. n/a not available. # Excludes Estonia, Latvia and Lithuania prior to 1985 and Slovenia prior to 1990.Notes: Annual changes and shares of total are calculated using terawatt-hours figures.Growth rates are adjusted for leap years.


132

Renewables: Consumption - Solar*Share


US 2.0 3.6 6.6 8.9 12.8 43.6% 48.6% 17.1%

Canada 0.2 0.3 0.4 0.6 0.7 18.3% 64.0% 0.9%

Mexico ^ ^ 0.1 0.1 0.1 72.0% 39.2% 0.1%


Argentina ^ ^ ^ ^ ^ -3.1% 68.2% ♦

Brazil ^ ^ ^ ^ ^ 50.5% - ♦

Chile ^ ^ 0.1 0.3 0.6 96.6% - 0.8%

Colombia ^ ^ ^ ^ ^ - - ♦

Ecuador ^ ^ ^ ^ ^ 7.2% 122.0% ♦

Peru ^ ^ ^ 0.1 0.1 4.7% - 0.1%

Trinidad & Tobago ^ ^ ^ ^ ^ - - ♦

Venezuela ^ ^ ^ ^ ^ - - ♦



Austria 0.1 0.1 0.2 0.2 0.2 14.2% 46.2% 0.3%

Azerbaijan - ^ ^ ^ ^ 1242.0% - ♦

Belarus - ^ ^ ^ ^ 310.0% - ♦

Belgium 0.5 0.6 0.7 0.7 0.7 -4.0% 123.2% 0.9%

Bulgaria 0.2 0.3 0.3 0.3 0.3 1.6% - 0.4%

Czech Republic 0.5 0.5 0.5 0.5 0.5 -6.2% 183.3% 0.6%

Denmark ^ 0.1 0.1 0.1 0.2 22.8% 75.7% 0.2%

Finland ^ ^ ^ ^ ^ 34.2% 12.8% ♦

France 0.9 1.1 1.3 1.7 1.9 11.4% 92.7% 2.5%

Germany 6.0 7.0 8.2 8.8 8.6 -1.6% 40.6% 11.5%

Greece 0.4 0.8 0.9 0.9 0.9 1.9% 128.6% 1.2%

Hungary ^ ^ ^ ^ ^ 60.4% - 0.1%

Ireland ^ ^ ^ ^ ^ 229.6% - ♦

Italy 4.3 4.9 5.0 5.2 5.2 -0.5% 93.6% 6.9%

Kazakhstan - ^ ^ ^ ^ 84.3% - ♦

Lithuania ^ ^ ^ ^ ^ -8.8% - ♦

Netherlands 0.1 0.1 0.2 0.3 0.3 36.2% 41.8% 0.5%

Norway ^ ^ ^ ^ ^ 48.8% - ♦

Poland ^ ^ ^ ^ ^ 116.9% - ♦

Portugal 0.1 0.1 0.1 0.2 0.2 2.2% 70.7% 0.2%

Romania ^ 0.1 0.3 0.4 0.4 -7.2% - 0.6%

Russian Federation ^ ^ ^ ^ ^ 115.7% - ♦

Slovakia 0.1 0.1 0.1 0.1 0.1 4.9% - 0.2%

Spain 2.7 2.9 3.1 3.1 3.1 -2.6% 67.9% 4.1%

Sweden ^ ^ ^ ^ ^ 74.2% 47.4% 0.1%

Switzerland 0.1 0.1 0.2 0.3 0.3 23.6% 48.8% 0.4%

Turkey ^ ^ ^ ^ 0.2 253.3% - 0.2%

Turkmenistan ^ ^ ^ ^ ^ 27.0% - ♦

Ukraine 0.1 0.1 0.1 0.1 0.1 -17.2% - 0.1%

United Kingdom 0.3 0.5 0.9 1.7 2.3 35.7% 98.4% 3.1%


Uzbekistan - ^ ^ ^ ^ 50.0% - ♦





133

Iran - - ^ ^ ^ 700.0% - ♦

Israel 0.1 0.1 0.2 0.3 0.4 39.5% - 0.5%

Kuwait - - ^ ^ ^ 580.0% - ♦

Qatar ^ ^ ^ ^ ^ 10.0% - ♦

Saudi Arabia ^ ^ ^ ^ ^ 14.3% - ♦

United Arab Emirates ^ ^ 0.1 0.1 0.1 2.6% - 0.1%

Other Middle East ^ ^ ^ ^ 0.1 270.1% - 0.1%


Algeria ^ ^ ^ ^ ^ 252.5% - 0.1%

Egypt ^ ^ ^ ^ ^ 60.0% - ♦

South Africa ^ 0.1 0.3 0.6 0.7 18.8% 62.7% 1.0%

Other Africa 0.1 0.1 0.1 0.2 0.3 69.5% 58.1% 0.4%

Total Africa 0.1 0.2 0.4 0.8 1.1 33.0% 62.0% 1.4%

Australia 0.5 0.9 1.1 1.3 1.6 19.8% 53.1% 2.1%

Bangladesh ^ ^ ^ ^ ^ 15.6% 43.1% 0.1%

China 0.8 1.9 5.3 8.7 15.0 71.5% 84.6% 19.9%


India 0.3 0.6 1.0 1.5 2.7 81.3% 80.2% 3.6%

Indonesia ^ ^ ^ ^ ^ 395.8% - ♦

Japan 1.7 2.9 5.3 8.3 11.2 34.8% 36.5% 14.9%

Malaysia ^ ^ 0.1 0.1 0.1 18.9% - 0.1%

New Zealand ^ ^ ^ ^ ^ 51.4% - ♦

Pakistan ^ ^ 0.1 0.1 0.1 65.3% - 0.2%

Philippines ^ ^ ^ ^ 0.2 585.6% 57.1% 0.3%

Singapore ^ ^ ^ ^ ^ 66.9% - ♦

South Korea 0.2 0.4 0.6 0.9 1.2 31.2% 75.5% 1.6%

Taiwan ^ 0.1 0.1 0.2 0.3 29.0% 97.7% 0.3%

Thailand 0.1 0.2 0.3 0.4 0.5 31.3% - 0.7%

Vietnam - - ^ ^ ^ 37.5% - ♦

Other Asia Pacific ^ ^ ^ ^ ^ 18.5% 39.7% 0.1%


Total World 22.6 31.1 44.4 58.0 75.4 29.6% 50.7% 100.0%

of which: OECD 20.8 27.2 36.0 44.6 53.5 19.7% 47.6% 71.0%

Non-OECD 1.8 3.9 8.4 13.4 21.9 63.0% 75.9% 29.0%

European Union # 16.1 19.3 22.1 24.5 25.2 2.9% 53.4% 33.5%

CIS 0.1 0.1 0.1 0.1 0.2 14.5% - 0.2%



^ Less than 0.05.






134

Renewables: Consumption - Wind*Share

Terawatt-hours 2012 2013 2014 2015 2016 2016 2005-15 2016

US 142.2 169.5 183.5 192.6 228.8 18.4% 26.8% 23.8%

Canada 13.6 16.5 20.6 24.6 27.2 10.4% 31.8% 2.8%

Mexico 3.3 4.2 6.4 8.7 10.6 20.4% 84.6% 1.1%


Argentina 0.4 0.5 0.7 0.6 0.5 -8.1% 23.5% 0.1%

Brazil 5.1 6.6 12.2 21.6 32.9 51.8% 72.5% 3.4%

Chile 0.4 0.6 1.4 2.1 2.3 8.6% 77.0% 0.2%

Colombia 0.1 0.1 0.1 0.1 0.1 -22.0% 3.3% ♦

Ecuador ^ 0.1 0.1 0.1 0.1 -15.3% - ♦

Peru ^ ^ 0.3 0.6 1.0 70.3% 86.0% 0.1%


Venezuela - - - ^ ^ - - ♦



Austria 2.5 3.2 3.8 4.8 5.2 6.3% 13.8% 0.5%

Azerbaijan - ^ ^ ^ ^ 285.9% - ♦

Belarus ^ ^ ^ ^ 0.2 500.0% 38.5% ♦

Belgium 2.8 3.7 4.6 5.6 5.7 1.6% 37.7% 0.6%

Bulgaria 1.2 1.4 1.3 1.5 1.4 -5.3% 76.3% 0.1%

Czech Republic 0.4 0.5 0.5 0.6 0.5 -13.5% 39.0% 0.1%

Denmark 10.3 11.1 13.1 14.1 12.8 -9.8% 7.9% 1.3%

Finland 0.5 0.8 1.1 2.3 3.1 31.5% 30.1% 0.3%

France 14.9 15.9 17.1 21.1 20.7 -2.2% 36.2% 2.2%

Germany 50.7 51.7 57.4 79.2 77.4 -2.5% 11.3% 8.1%

Greece 3.9 4.1 3.7 4.6 5.0 7.2% 13.8% 0.5%

Hungary 0.8 0.7 0.7 0.7 0.7 -0.9% 52.8% 0.1%

Ireland 4.0 4.5 5.1 6.6 6.2 -6.7% 19.4% 0.6%

Italy 13.4 14.9 15.2 14.8 17.6 18.4% 20.3% 1.8%

Kazakhstan ^ ^ ^ 0.1 0.3 98.3% - ♦

Lithuania 0.5 0.6 0.6 0.8 1.1 35.4% 84.2% 0.1%

Netherlands 5.0 5.6 5.8 7.5 7.9 4.9% 13.8% 0.8%

Norway 1.5 1.9 2.2 2.5 2.1 -16.1% 17.4% 0.2%

Poland 4.7 6.0 7.7 10.9 12.6 15.6% 55.1% 1.3%

Portugal 10.3 12.0 12.1 11.6 12.5 7.2% 20.7% 1.3%

Romania 2.6 4.5 4.7 7.1 6.7 -5.0% - 0.7%

Russian Federation ^ ^ 0.1 0.1 0.1 -1.0% 36.1% ♦

Slovakia ^ ^ ^ ^ ^ - -1.5% ♦

Spain 49.5 53.9 52.0 49.3 48.9 -1.2% 8.8% 5.1%

Sweden 7.2 9.8 11.2 16.3 15.1 -7.4% 32.9% 1.6%

Switzerland 0.1 0.1 0.1 0.1 0.1 -6.9% 30.0% ♦

Turkey 5.9 7.6 8.5 11.7 16.5 41.4% 69.7% 1.7%


Ukraine 0.3 0.6 1.1 1.1 1.0 -11.9% 40.4% 0.1%

United Kingdom 19.8 28.4 32.0 40.3 37.5 -7.2% 30.1% 3.9%


Uzbekistan - - - - - - - -





135

Iran 0.2 0.4 0.4 0.4 0.4 - 18.6% ♦

Israel ^ ^ ^ ^ ^ - -4.4% ♦

Kuwait - - - - - - - -

Qatar - - - - - - - -

Saudi Arabia - - - - - - - -


Other Middle East ^ ^ ^ 0.1 0.3 148.2% 45.3% ♦


Algeria - - ^ ^ ^ - - ♦

Egypt 1.3 1.3 1.3 1.9 2.5 35.0% 13.0% 0.3%

South Africa ^ ^ 1.1 3.1 4.2 35.6% 74.1% 0.4%

Other Africa 1.1 2.0 2.9 3.9 4.5 14.9% 31.1% 0.5%

Total Africa 2.4 3.3 5.3 8.9 11.2 26.3% 26.8% 1.2%

Australia 7.7 9.3 9.8 11.8 13.2 11.5% 24.7% 1.4%

Bangladesh ^ ^ ^ ^ ^ ♦ 14.8% ♦

China 96.0 141.2 156.1 185.8 241.0 29.4% 57.8% 25.1%


India 30.1 33.6 33.3 32.7 44.8 36.5% 18.5% 4.7%

Indonesia ^ ^ ^ ^ ^ 300.0% - ♦

Japan 4.7 5.1 5.0 5.2 7.1 35.1% 10.6% 0.7%

Malaysia - - - - - - - -

New Zealand 2.1 2.0 2.2 2.4 2.3 -1.9% 14.4% 0.2%

Pakistan ^ 0.2 0.5 0.7 1.1 59.4% - 0.1%

Philippines 0.1 0.1 0.2 0.7 1.0 32.7% 45.6% 0.1%

Singapore - - - - - - - -

South Korea 0.9 1.1 1.1 1.3 1.8 32.2% 26.3% 0.2%

Taiwan 1.4 1.6 1.5 1.5 1.4 -5.5% 32.5% 0.2%

Thailand 0.1 0.3 0.3 0.3 0.5 48.7% - ♦

Vietnam 0.1 0.1 0.1 0.2 0.2 56.1% - ♦

Other Asia Pacific 0.2 0.4 0.5 0.6 0.6 -4.3% 40.1% 0.1%


Total World 526.9 644.4 709.3 828.0 959.5 15.6% 23.0% 100.0%

of which: OECD 383.5 445.5 484.7 554.4 602.0 8.3% 19.3% 62.7%

Non-OECD 143.4 198.9 224.6 273.6 357.6 30.3% 39.8% 37.3%

European Union # 206.0 234.9 251.4 301.8 300.5 -0.7% 15.6% 31.3%

CIS 0.3 0.7 1.2 1.4 1.5 10.0% 41.3% 0.2%

* Based on gross generation and not accounting for cross-border electricity supply.

^ Less than 0.05.


n/a not available.





136

Renewables: Consumption - Wind*Share


US 32.2 38.4 41.5 43.6 51.8 18.4% 26.8% 23.8%

Canada 3.1 3.7 4.7 5.6 6.2 10.4% 31.8% 2.8%

Mexico 0.7 0.9 1.5 2.0 2.4 20.4% 84.6% 1.1%


Argentina 0.1 0.1 0.2 0.1 0.1 -8.1% 23.5% 0.1%

Brazil 1.1 1.5 2.8 4.9 7.4 51.8% 72.5% 3.4%

Chile 0.1 0.1 0.3 0.5 0.5 8.6% 77.0% 0.2%

Colombia ^ ^ ^ ^ ^ -22.0% 3.3% ♦

Ecuador ^ ^ ^ ^ ^ -15.3% - ♦

Peru ^ ^ 0.1 0.1 0.2 70.3% 86.0% 0.1%


Venezuela - - - ^ ^ - - ♦



Austria 0.6 0.7 0.9 1.1 1.2 6.3% 13.8% 0.5%

Azerbaijan - ^ ^ ^ ^ 285.9% - ♦

Belarus ^ ^ ^ ^ ^ 500.0% 38.5% ♦

Belgium 0.6 0.8 1.0 1.3 1.3 1.6% 37.7% 0.6%

Bulgaria 0.3 0.3 0.3 0.3 0.3 -5.3% 76.3% 0.1%

Czech Republic 0.1 0.1 0.1 0.1 0.1 -13.5% 39.0% 0.1%

Denmark 2.3 2.5 3.0 3.2 2.9 -9.8% 7.9% 1.3%

Finland 0.1 0.2 0.3 0.5 0.7 31.5% 30.1% 0.3%

France 3.4 3.6 3.9 4.8 4.7 -2.2% 36.2% 2.2%

Germany 11.5 11.7 13.0 17.9 17.5 -2.5% 11.3% 8.1%

Greece 0.9 0.9 0.8 1.0 1.1 7.2% 13.8% 0.5%

Hungary 0.2 0.2 0.1 0.2 0.2 -0.9% 52.8% 0.1%

Ireland 0.9 1.0 1.2 1.5 1.4 -6.7% 19.4% 0.6%

Italy 3.0 3.4 3.4 3.4 4.0 18.4% 20.3% 1.8%

Kazakhstan ^ ^ ^ ^ 0.1 98.3% - ♦

Lithuania 0.1 0.1 0.1 0.2 0.2 35.4% 84.2% 0.1%

Netherlands 1.1 1.3 1.3 1.7 1.8 4.9% 13.8% 0.8%

Norway 0.4 0.4 0.5 0.6 0.5 -16.1% 17.4% 0.2%

Poland 1.1 1.4 1.7 2.5 2.8 15.6% 55.1% 1.3%

Portugal 2.3 2.7 2.7 2.6 2.8 7.2% 20.7% 1.3%

Romania 0.6 1.0 1.1 1.6 1.5 -5.0% - 0.7%

Russian Federation ^ ^ ^ ^ ^ -1.0% 36.1% ♦

Slovakia ^ ^ ^ ^ ^ - -1.5% ♦

Spain 11.2 12.2 11.8 11.2 11.1 -1.2% 8.8% 5.1%

Sweden 1.6 2.2 2.5 3.7 3.4 -7.4% 32.9% 1.6%

Switzerland ^ ^ ^ ^ ^ -6.9% 30.0% ♦

Turkey 1.3 1.7 1.9 2.6 3.7 41.4% 69.7% 1.7%


Ukraine 0.1 0.1 0.3 0.2 0.2 -11.9% 40.4% 0.1%

United Kingdom 4.5 6.4 7.2 9.1 8.5 -7.2% 30.1% 3.9%


Uzbekistan - - - - - - - -





137

Iran ^ 0.1 0.1 0.1 0.1 - 18.6% ♦

Israel ^ ^ ^ ^ ^ - -4.4% ♦

Kuwait - - - - - - - -

Qatar - - - - - - - -

Saudi Arabia - - - - - - - -


Other Middle East ^ ^ ^ ^ 0.1 148.2% 45.3% ♦

Total Middle East ^ 0.1 0.1 0.1 0.2 35.6% 19.9% 0.1%

Algeria - - ^ ^ ^ - - ♦

Egypt 0.3 0.3 0.3 0.4 0.6 35.0% 13.0% 0.3%

South Africa ^ ^ 0.2 0.7 0.9 35.6% 74.1% 0.4%

Other Africa 0.3 0.4 0.7 0.9 1.0 14.9% 31.1% 0.5%

Total Africa 0.6 0.7 1.2 2.0 2.5 26.3% 26.8% 1.2%

Australia 1.7 2.1 2.2 2.7 3.0 11.5% 24.7% 1.4%

Bangladesh ^ ^ ^ ^ ^ ♦ 14.8% ♦

China 21.7 31.9 35.3 42.0 54.5 29.4% 57.8% 25.1%


India 6.8 7.6 7.5 7.4 10.1 36.5% 18.5% 4.7%

Indonesia ^ ^ ^ ^ ^ 300.0% - ♦

Japan 1.1 1.2 1.1 1.2 1.6 35.1% 10.6% 0.7%

Malaysia - - - - - - - -

New Zealand 0.5 0.5 0.5 0.5 0.5 -1.9% 14.4% 0.2%

Pakistan ^ ^ 0.1 0.2 0.3 59.4% - 0.1%

Philippines ^ ^ ^ 0.2 0.2 32.7% 45.6% 0.1%

Singapore - - - - - - - -

South Korea 0.2 0.3 0.3 0.3 0.4 32.2% 26.3% 0.2%

Taiwan 0.3 0.4 0.3 0.3 0.3 -5.5% 32.5% 0.2%

Thailand ^ 0.1 0.1 0.1 0.1 48.7% - ♦

Vietnam ^ ^ ^ ^ 0.1 56.1% - ♦

Other Asia Pacific ^ 0.1 0.1 0.1 0.1 -4.3% 40.1% 0.1%


Total World 119.2 145.8 160.5 187.4 217.1 15.6% 23.0% 100.0%

of which: OECD 86.8 100.8 109.7 125.4 136.2 8.3% 19.3% 62.7%

Non-OECD 32.5 45.0 50.8 61.9 80.9 30.3% 39.8% 37.3%

European Union # 46.6 53.1 56.9 68.3 68.0 -0.7% 15.6% 31.3% CIS 0.1 0.1 0.3 0.3 0.3 10.0% 41.3% 0.2%



^ Less than 0.05.


n/a not available.





138

Renewables: Consumption - Geothermal, Biomass and Other*Share

Terawatt-hours 2012 2013 2014 2015 2016 2016 2005-15 2016

US 77.0 80.7 84.1 83.7 84.6 0.8% 1.4% 15.1%

Canada 10.4 10.5 8.3 10.2 10.3 - 1.6% 1.8%

Mexico 6.8 7.3 7.1 7.4 7.2 -3.3% -0.9% 1.3%


Argentina 2.2 2.3 2.8 2.2 2.3 8.6% 6.3% 0.4%

Brazil 35.3 40.5 46.4 49.0 50.9 3.6% 13.7% 9.1%

Chile 4.9 5.8 5.3 5.0 5.3 4.9% 10.8% 0.9%

Colombia 1.2 1.3 1.6 1.7 2.0 17.2% 13.2% 0.4%

Ecuador 0.3 0.3 0.4 0.4 0.5 19.8% 14.8% 0.1%

Peru 0.7 1.0 1.3 1.1 1.2 12.9% 11.9% 0.2%

Trinidad & Tobago - - - - - - -100.0% -

Venezuela - - - - - - - -



Austria 4.6 4.6 4.3 4.4 4.6 3.9% 6.3% 0.8%

Azerbaijan - 0.1 0.1 0.1 0.1 -4.3% - ♦

Belarus 0.1 0.1 0.1 0.1 0.1 - - ♦

Belgium 5.2 5.0 4.4 5.5 5.3 -3.7% 13.2% 0.9%

Bulgaria 0.1 0.1 0.2 0.3 0.4 36.9% - 0.1%

Czech Republic 3.4 4.0 4.7 4.8 4.8 -1.1% 22.1% 0.8%

Denmark 4.4 4.3 4.3 4.2 4.4 4.2% 2.9% 0.8%

Finland 11.1 11.9 11.7 11.3 11.8 3.9% 1.8% 2.1%

France 5.4 5.2 5.8 6.4 7.1 9.9% 5.2% 1.3%

Germany 43.2 45.6 48.4 50.5 51.8 2.3% 13.4% 9.2%

Greece 0.2 0.2 0.2 0.2 0.2 1.3% 6.6% ♦

Hungary 1.7 1.8 2.1 2.2 2.6 18.6% 3.1% 0.5%

Ireland 0.4 0.5 0.5 0.5 0.5 5.2% 13.8% 0.1%

Italy 18.1 22.7 24.6 25.6 25.8 0.5% 8.3% 4.6%

Kazakhstan - - - ^ ^ 289.7% - ♦

Lithuania 0.2 0.4 0.4 0.4 0.4 -3.1% 51.5% 0.1%

Netherlands 7.2 6.0 5.0 4.9 4.3 -13.7% -0.7% 0.8%

Norway 0.4 0.3 0.3 0.2 0.2 - -5.1% ♦

Poland 10.1 8.6 10.0 9.9 7.8 -21.5% 20.7% 1.4%

Portugal 3.1 3.2 3.3 3.3 3.2 -4.9% 6.7% 0.6%

Romania 0.2 0.3 0.5 0.5 0.4 -14.4% 56.4% 0.1%


Slovakia 0.9 0.9 1.4 1.7 1.7 0.8% 48.4% 0.3%

Spain 5.0 5.3 5.4 5.9 6.2 5.7% 5.4% 1.1%

Sweden 12.2 11.5 10.7 10.8 11.7 8.5% 3.7% 2.1%

Switzerland 1.6 1.7 1.8 1.7 2.0 15.2% 4.8% 0.4%

Turkey 1.6 2.5 3.8 5.2 5.6 8.5% 37.4% 1.0%


Ukraine 0.1 0.1 0.1 0.1 0.1 - - ♦

United Kingdom 14.7 18.2 22.7 29.4 29.6 0.4% 12.4% 5.3%


Uzbekistan - - - - - - - -





139

Iran ^ ^ ^ ^ ^ - - ♦

Israel 0.1 ^ 0.1 0.1 0.1 - - ♦

Kuwait - - - - - - - -

Qatar - - - - - - - -

Saudi Arabia - - - - - - - -


Other Middle East ^ ^ ^ ^ ^ 6.4% 1.8% ♦

Total Middle East 0.1 0.1 0.1 0.1 0.1 0.3% 37.8% ♦

Algeria - - - - - - - -

Egypt - - - - - - - -

South Africa 0.3 0.3 0.3 0.3 0.3 - 1.3% 0.1%

Other Africa 3.0 3.3 4.4 6.0 6.0 -0.7% 11.5% 1.1%

Total Africa 3.3 3.6 4.7 6.3 6.3 -0.7% 10.7% 1.1%

Australia 3.1 3.3 3.6 3.3 3.4 - -1.5% 0.6%

Bangladesh - - - - - - - -

China 30.5 37.3 44.7 60.3 73.4 21.4% 27.5% 13.1%

China Hong Kong SAR 0.1 0.1 0.1 0.1 0.1 - - ♦

India 14.4 14.8 15.2 16.9 16.0 -5.3% 15.4% 2.9%

Indonesia 9.7 9.7 10.3 10.5 11.2 6.3% 4.7% 2.0%

Japan 22.1 23.2 23.6 23.6 26.6 12.2% 0.9% 4.7%

Malaysia 1.5 1.1 0.9 0.9 1.2 22.3% - 0.2%

New Zealand 6.8 7.0 7.9 8.4 8.4 ♦ 9.0% 1.5%

Pakistan - - 0.2 0.3 0.3 - - 0.1%

Philippines 10.4 9.8 10.5 11.4 11.7 2.3% 1.4% 2.1%

Singapore 0.6 0.7 0.8 0.8 0.9 11.4% 5.6% 0.2%

South Korea 6.6 7.4 11.0 12.0 12.0 -0.1% 46.7% 2.1%

Taiwan 1.9 1.9 2.0 2.1 2.0 -4.2% 1.4% 0.4%

Thailand 4.6 5.8 7.4 7.9 9.6 21.8% 15.6% 1.7%

Vietnam 0.1 0.1 0.1 0.1 0.1 - 1.7% ♦



Total World 427.2 458.7 496.5 536.4 561.7 4.4% 7.7% 100.0%

of which: OECD 298.8 315.6 332.7 348.5 355.1 1.6% 5.6% 63.2%

Non-OECD 128.4 143.1 163.8 187.9 206.6 9.6% 13.4% 36.8%

European Union # 153.2 162.0 172.7 184.9 187.3 1.0% 9.1% 33.4%

CIS 0.7 0.8 0.8 0.9 0.9 -0.4% 6.6% 0.2%

* Based on gross generation and not accounting for cross-border electricity supply.

^ Less than 0.05.


n/a not available.





140

Renewables: Consumption - Geothermal, Biomass and Other*Share


US 17.4 18.3 19.0 18.9 19.1 0.8% 1.4% 15.1%

Canada 2.3 2.4 1.9 2.3 2.3 - 1.6% 1.8%

Mexico 1.5 1.7 1.6 1.7 1.6 -3.3% -0.9% 1.3%


Argentina 0.5 0.5 0.6 0.5 0.5 8.6% 6.3% 0.4%

Brazil 8.0 9.2 10.5 11.1 11.5 3.6% 13.7% 9.1%

Chile 1.1 1.3 1.2 1.1 1.2 4.9% 10.8% 0.9%

Colombia 0.3 0.3 0.4 0.4 0.5 17.2% 13.2% 0.4%

Ecuador 0.1 0.1 0.1 0.1 0.1 19.8% 14.8% 0.1%

Peru 0.2 0.2 0.3 0.2 0.3 12.9% 11.9% 0.2%

Trinidad & Tobago - - - - - - -100.0% -

Venezuela - - - - - - - -



Austria 1.0 1.0 1.0 1.0 1.0 3.9% 6.3% 0.8%

Azerbaijan - ^ ^ ^ ^ -4.3% - ♦

Belarus ^ ^ ^ ^ ^ - - ♦

Belgium 1.2 1.1 1.0 1.2 1.2 -3.7% 13.2% 0.9%

Bulgaria ^ ^ ^ 0.1 0.1 36.9% - 0.1%

Czech Republic 0.8 0.9 1.1 1.1 1.1 -1.1% 22.1% 0.8%

Denmark 1.0 1.0 1.0 1.0 1.0 4.2% 2.9% 0.8%

Finland 2.5 2.7 2.6 2.6 2.7 3.9% 1.8% 2.1%

France 1.2 1.2 1.3 1.5 1.6 9.9% 5.2% 1.3%

Germany 9.8 10.3 11.0 11.4 11.7 2.3% 13.4% 9.2%

Greece ^ ^ ^ 0.1 0.1 1.3% 6.6% ♦

Hungary 0.4 0.4 0.5 0.5 0.6 18.6% 3.1% 0.5%

Ireland 0.1 0.1 0.1 0.1 0.1 5.2% 13.8% 0.1%

Italy 4.1 5.1 5.6 5.8 5.8 0.5% 8.3% 4.6%

Kazakhstan - - - ^ ^ 289.7% - ♦

Lithuania ^ 0.1 0.1 0.1 0.1 -3.1% 51.5% 0.1%

Netherlands 1.6 1.3 1.1 1.1 1.0 -13.7% -0.7% 0.8%

Norway 0.1 0.1 0.1 ^ ^ - -5.1% ♦

Poland 2.3 2.0 2.3 2.2 1.8 -21.5% 20.7% 1.4%

Portugal 0.7 0.7 0.7 0.7 0.7 -4.9% 6.7% 0.6%

Romania ^ 0.1 0.1 0.1 0.1 -14.4% 56.4% 0.1%


Slovakia 0.2 0.2 0.3 0.4 0.4 0.8% 48.4% 0.3%

Spain 1.1 1.2 1.2 1.3 1.4 5.7% 5.4% 1.1%

Sweden 2.8 2.6 2.4 2.4 2.6 8.5% 3.7% 2.1%

Switzerland 0.4 0.4 0.4 0.4 0.4 15.2% 4.8% 0.4%

Turkey 0.4 0.6 0.9 1.2 1.3 8.5% 37.4% 1.0%


Ukraine ^ ^ ^ ^ ^ - - ♦

United Kingdom 3.3 4.1 5.1 6.7 6.7 0.4% 12.4% 5.3%


Uzbekistan - - - - - - - -





141

Iran ^ ^ ^ ^ ^ - - ♦

Israel ^ ^ ^ ^ ^ - - ♦

Kuwait - - - - - - - -

Qatar - - - - - - - -

Saudi Arabia - - - - - - - -


Other Middle East ^ ^ ^ ^ ^ 6.4% 1.8% ♦

Total Middle East ^ ^ ^ ^ ^ 0.3% 37.8% ♦

Algeria - - - - - - - -

Egypt - - - - - - - -

South Africa 0.1 0.1 0.1 0.1 0.1 - 1.3% 0.1%

Other Africa 0.7 0.7 1.0 1.4 1.4 -0.7% 11.5% 1.1%

Total Africa 0.7 0.8 1.1 1.4 1.4 -0.7% 10.7% 1.1%

Australia 0.7 0.8 0.8 0.8 0.8 - -1.5% 0.6%

Bangladesh - - - - - - - -

China 6.9 8.4 10.1 13.6 16.6 21.4% 27.5% 13.1%

China Hong Kong SAR ^ ^ ^ ^ ^ - - ♦

India 3.3 3.3 3.4 3.8 3.6 -5.3% 15.4% 2.9%

Indonesia 2.2 2.2 2.3 2.4 2.5 6.3% 4.7% 2.0%

Japan 5.0 5.2 5.3 5.3 6.0 12.2% 0.9% 4.7%

Malaysia 0.3 0.2 0.2 0.2 0.3 22.3% - 0.2%

New Zealand 1.5 1.6 1.8 1.9 1.9 ♦ 9.0% 1.5%

Pakistan - - ^ 0.1 0.1 - - 0.1%

Philippines 2.4 2.2 2.4 2.6 2.6 2.3% 1.4% 2.1%

Singapore 0.1 0.2 0.2 0.2 0.2 11.4% 5.6% 0.2%

South Korea 1.5 1.7 2.5 2.7 2.7 -0.1% 46.7% 2.1%

Taiwan 0.4 0.4 0.5 0.5 0.5 -4.2% 1.4% 0.4%

Thailand 1.0 1.3 1.7 1.8 2.2 21.8% 15.6% 1.7%

Vietnam ^ ^ ^ ^ ^ - 1.7% ♦



Total World 96.7 103.8 112.3 121.4 127.1 4.4% 7.7% 100.0%

of which: OECD 67.6 71.4 75.3 78.9 80.4 1.6% 5.6% 63.2%

Non-OECD 29.1 32.4 37.1 42.5 46.7 9.6% 13.4% 36.8%

European Union # 34.7 36.7 39.1 41.8 42.4 1.0% 9.1% 33.4%

CIS 0.2 0.2 0.2 0.2 0.2 -0.4% 6.6% 0.2%



^ Less than 0.05.


n/a not available.





142

Renewable energy - Biofuels productionShare

Thousand b/doe 2012 2013 2014 2015 2016 2016 2005-15 2016

US 557 582 617 634 669 5.4% 15.2% 43.5%

Canada 19 20 22 21 22 1.2% 22.8% 1.4%

Mexico 0 1 1 1 1 - - 0.1%


Argentina 43 38 50 38 53 38.4% 71.7% 3.4%

Brazil 276 321 337 362 347 -4.3% 8.4% 22.5%

Colombia 12 12 13 13 12 -10.0% 46.2% 0.8%



Austria 7 7 6 7 8 9.8% 18.0% 0.5%

Belgium 11 10 11 10 10 - 89.9% 0.7%

Finland 5 6 7 8 8 - 51.8% 0.5%

France 40 43 48 47 42 -11.9% 18.5% 2.7%

Germany 57 52 65 60 60 -0.1% 7.2% 3.9%

Italy 6 9 11 11 11 - 5.1% 0.7%

Netherlands 24 28 33 31 31 - 87.5% 2.0%

Poland 12 13 14 18 17 -4.6% 23.2% 1.1%

Portugal 5 5 6 6 6 -7.5% 79.7% 0.4%

Spain 12 14 19 21 21 2.0% 14.0% 1.4%

Sweden 9 12 15 4 4 -5.1% 15.7% 0.3%

United Kingdom 6 10 8 6 7 12.8% 22.4% 0.4%

Other Europe & Eurasia 27 25 29 33 33 0.4% 19.2% 2.1%

Total Europe & Eurasia 219 234 271 263 258 -1.9% 15.5% 16.7%

Total Middle East 0 0 0 0 0 - - ♦

Total Africa 0 1 1 1 1 - 20.5% ♦

Australia 4 4 3 3 3 -8.5% 21.9% 0.2%

China 39 44 49 50 38 -22.8% 14.6% 2.5%

India 4 5 7 8 9 23.0% 12.7% 0.6%

Indonesia 26 33 48 25 47 84.3% 65.4% 3.0%

South Korea 5 6 6 7 8 4.7% 45.4% 0.5%

Thailand 20 25 28 30 30 0.2% 39.9% 2.0%



Total World 1250 1355 1494 1500 1539 2.6% 14.1% 100.0%

of which: OECD 799 840 913 922 952 3.2% 15.5% 61.8%

Non-OECD 451 515 581 578 587 1.6% 12.2% 38.2%

European Union 217 232 268 259 254 -2.0% 15.5% 16.5%

CIS 1 0 0 0 0 - - ♦

^ Less than 0.05.




143

Notes: Consumption of fuel ethanol and biodiesel is included in oil consumption tables.

Annual changes and shares of total are calculated using thousand barrels a day oil equivalent figures.


144

Renewable energy - Biofuels production

Share

Thousand tonnes of oil equivalent 2012 2013 2014 2015 2016 2016 2005-15 2016

US 29808 31057 32890 33849 35779 5.4% 15.2% 43.5%

Canada 1017 1056 1188 1142 1160 1.2% 22.8% 1.4%

Mexico 15 58 58 58 58 - - 0.1%


Argentina 2295 2014 2644 2038 2828 38.4% 71.7% 3.4%

Brazil 14739 17114 18005 19332 18552 -4.3% 8.4% 22.5%

Colombia 627 650 676 693 626 -10.0% 46.2% 0.8%



Austria 390 374 329 381 419 9.8% 18.0% 0.5%

Belgium 562 547 574 556 558 - 89.9% 0.7%

Finland 263 330 367 445 446 - 51.8% 0.5%

France 2145 2306 2541 2519 2226 -11.9% 18.5% 2.7%

Germany 3031 2770 3460 3191 3198 -0.1% 7.2% 3.9%

Italy 298 457 585 582 583 - 5.1% 0.7%

Netherlands 1276 1495 1756 1675 1680 - 87.5% 2.0%

Poland 652 697 750 940 898 -4.6% 23.2% 1.1%

Portugal 276 274 301 321 298 -7.5% 79.7% 0.4%

Spain 620 749 1030 1122 1148 2.0% 14.0% 1.4%

Sweden 491 635 789 222 211 -5.1% 15.7% 0.3%

United Kingdom 303 517 403 310 351 12.8% 22.4% 0.4%


Total Europe & Eurasia 11734 12503 14445 14012 13777 -1.9% 15.5% 16.7%

Total Middle East 5 5 5 5 5 - - ♦

Total Africa 23 32 40 40 40 - 20.5% ♦

Australia 239 202 169 157 144 -8.5% 21.9% 0.2%

China 2103 2346 2609 2653 2053 -22.8% 14.6% 2.5%

India 229 268 349 410 505 23.0% 12.7% 0.6%

Indonesia 1397 1750 2547 1354 2503 84.3% 65.4% 3.0%

South Korea 283 321 337 385 404 4.7% 45.4% 0.5%

Thailand 1054 1330 1490 1603 1610 0.2% 39.9% 2.0%



Total World 66863 72293 79703 80024 82306 2.6% 14.1% 100.0%

of which: OECD 42733 44808 48698 49186 50900 3.2% 15.5% 61.8%

Non-OECD 24130 27485 31005 30838 31407 1.6% 12.2% 38.2%

European Union 11593 12394 14286 13820 13580 -2.0% 15.5% 16.5%

CIS 29 23 25 25 25 - - ♦

^ Less than 0.05.


Notes: Consumption of fuel ethanol and biodiesel is included in oil consumption tables.

Annual changes and shares of total are calculated using thousand tonnes a day oil equivalent figures.




145

Electricity Generation*Share

Terawatt-hours 2012 2013 2014 2015 2016 2016 2005-15 2016

US 4310.6 4330.3 4363.3 4348.7 4350.8 -0.2% 0.1% 17.5%

Canada 629.0 651.2 648.6 652.3 663.0 1.4% 0.6% 2.7%

Mexico 296.4 297.1 303.3 310.3 314.8 1.1% 2.3% 1.3%


Argentina 136.0 139.7 141.6 145.4 146.9 0.7% 2.7% 0.6%

Brazil 552.5 570.8 590.5 581.5 581.7 -0.2% 3.7% 2.3%

Chile 69.7 73.0 73.6 75.4 77.5 2.4% 3.3% 0.3%

Colombia 69.4 71.6 74.5 77.0 78.5 1.7% 3.3% 0.3%

Ecuador 22.8 23.3 24.3 26.0 27.1 4.1% 6.8% 0.1%

Peru 41.0 43.3 45.5 48.3 51.5 6.3% 6.6% 0.2%

Trinidad & Tobago 9.1 9.5 9.9 9.7 8.9 -8.4% 3.2% ♦

Venezuela 127.9 127.6 110.4 127.8 115.6 -9.8% 2.0% 0.5%



Austria 72.4 68.0 65.1 64.9 67.6 3.8% -0.3% 0.3%

Azerbaijan 23.0 23.4 24.7 24.7 25.0 0.9% 0.8% 0.1%

Belarus 30.8 31.5 34.7 34.1 33.1 -3.1% 1.0% 0.1%

Belgium 82.9 83.5 72.7 70.6 86.9 22.7% -2.1% 0.4%

Bulgaria 47.3 43.8 47.5 49.2 45.1 -8.7% 1.0% 0.2%

Czech Republic 87.6 87.1 86.0 83.9 83.3 -1.0% 0.2% 0.3%

Denmark 30.7 34.7 32.2 28.9 30.3 4.4% -2.2% 0.1%

Finland 70.4 71.2 68.1 68.6 68.6 -0.3% -0.3% 0.3%

France 565.1 573.1 561.7 568.7 553.4 -3.0% -0.1% 2.2%

Germany 630.1 638.7 626.7 646.9 648.4 ♦ 0.4% 2.6%

Greece 61.0 57.2 50.5 51.9 52.5 0.9% -1.4% 0.2%

Hungary 34.6 30.3 29.4 30.3 31.5 3.7% -1.6% 0.1%

Ireland 27.6 26.1 26.3 28.4 30.4 6.9% 0.9% 0.1%

Italy 299.3 289.8 279.8 283.0 286.3 0.9% -0.7% 1.2%

Kazakhstan 90.6 92.6 94.6 91.6 94.5 2.8% 3.0% 0.4%

Lithuania 5.0 4.8 4.4 4.9 4.3 -13.5% -10.4% ♦

Netherlands 102.5 100.9 103.4 109.6 114.7 4.3% 0.9% 0.5%

Norway 147.7 134.0 142.0 144.5 149.5 3.2% 0.5% 0.6%

Poland 162.1 164.6 159.1 164.9 166.6 0.7% 0.5% 0.7%

Portugal 46.6 51.7 52.8 52.4 60.5 15.1% 1.2% 0.2%

Romania 59.0 58.9 63.3 66.3 64.8 -2.5% 1.1% 0.3%


Slovakia 28.4 28.6 27.3 27.2 27.5 0.7% -1.4% 0.1%

Spain 297.6 283.6 278.8 280.5 274.4 -2.4% -0.5% 1.1%

Sweden 166.3 153.2 153.7 162.1 154.9 -4.7% 0.2% 0.6%

Switzerland 73.1 73.5 74.9 70.9 66.3 -6.8% 1.3% 0.3%

Turkey 239.5 240.2 252.0 261.8 272.7 3.9% 4.9% 1.1%

Turkmenistan 17.8 18.9 20.1 21.5 22.6 4.7% 5.3% 0.1%

Ukraine 198.9 194.4 182.8 163.7 163.7 -0.3% -1.2% 0.7%

United Kingdom 363.6 358.4 338.2 339.1 338.6 -0.4% -1.6% 1.4%

Uzbekistan 52.5 54.2 55.6 57.6 58.9 1.9% 1.9% 0.2%





146

Iran 247.7 254.6 274.6 281.9 286.0 1.2% 5.2% 1.2%

Israel 63.0 61.4 61.3 65.4 67.4 2.7% 2.8% 0.3%

Kuwait 62.7 61.0 65.1 68.3 71.1 3.9% 4.6% 0.3%

Qatar 34.8 34.7 38.7 41.8 42.4 0.9% 11.3% 0.2%

Saudi Arabia 271.7 284.0 311.8 328.1 330.5 0.4% 6.4% 1.3%




Algeria 57.4 59.9 64.2 68.8 70.2 1.8% 7.3% 0.3%

Egypt 161.9 164.0 170.2 180.6 187.3 3.4% 5.7% 0.8%

South Africa 257.9 256.1 254.7 249.7 251.9 0.6% 0.2% 1.0%

Other Africa 242.3 262.6 275.8 276.3 272.7 -1.6% 4.6% 1.1%

Total Africa 719.4 742.5 764.9 775.4 782.1 0.6% 3.3% 3.2%

Australia 250.7 249.6 247.4 253.0 256.9 1.2% 0.9% 1.0%

Bangladesh 48.6 53.1 55.8 60.8 67.4 10.6% 8.7% 0.3%

China 4987.6 5431.6 5649.6 5814.6 6142.5 5.4% 8.8% 24.8%

China Hong Kong SAR 38.8 39.1 39.8 38.0 38.2 0.3% -0.1% 0.2%

India 1088.2 1141.4 1252.0 1308.4 1400.8 6.8% 6.4% 5.6%

Indonesia 200.3 216.2 228.5 234.0 248.9 6.1% 6.3% 1.0%

Japan 1106.9 1087.8 1062.7 1030.1 999.6 -3.2% -1.1% 4.0%

Malaysia 127.3 138.3 143.6 144.7 156.8 8.1% 4.4% 0.6%

New Zealand 44.3 43.3 43.6 44.3 43.9 -1.2% 0.3% 0.2%

Pakistan 99.3 102.2 107.2 110.2 115.4 4.5% 2.0% 0.5%

Philippines 72.9 75.3 77.3 82.4 89.9 8.8% 3.8% 0.4%

Singapore 46.9 48.0 49.3 50.3 51.6 2.3% 2.8% 0.2%

South Korea 531.2 537.2 540.4 545.5 551.2 0.8% 3.4% 2.2%

Taiwan 250.4 252.4 260.0 258.0 264.1 2.1% 1.3% 1.1%

Thailand 169.0 168.6 173.8 177.8 179.7 0.8% 3.1% 0.7%

Vietnam 115.1 124.5 142.3 159.7 175.7 9.7% 11.9% 0.7%



Total World 22797.3 23402.9 23844.0 24215.5 24816.4 2.2% 2.8% 100.0%

of which: OECD 10939.9 10929.3 10875.5 10911.5 10939.2 ♦ 0.2% 44.1%

Non-OECD 11857.4 12473.6 12968.5 13304.0 13877.2 4.0% 5.5% 55.9%

European Union # 3295.7 3267.3 3185.3 3234.3 3247.3 0.1% -0.3% 13.1%

CIS 1523.7 1509.0 1515.3 1499.9 1527.8 1.6% 0.9% 6.2%

* Based on gross output.

♦ Less than 0.05%

# Excludes Slovenia prior to 1990.

Notes: Annual changes and share of total are calculated using terawatt-hours figures.



147

Carbon Dioxide EmissionsShare

Million tonnes carbon dioxide 2012 2013 2014 2015 2016 2016 2005-15 2016

US 5406.0 5544.3 5599.9 5445.0 5350.4 -2.0% -1.1% 16.0%

Canada 536.0 548.2 545.5 531.6 527.4 -1.1% -0.7% 1.6%

Mexico 491.8 490.0 481.6 481.4 470.3 -2.6% 0.9% 1.4%


Argentina 182.3 188.4 189.3 193.4 194.3 0.2% 2.9% 0.6%

Brazil 447.3 486.6 508.3 491.3 458.0 -7.0% 4.0% 1.4%

Chile 88.4 90.1 90.6 91.0 95.9 5.1% 4.2% 0.3%

Colombia 81.1 83.1 88.7 91.1 89.0 -2.6% 5.8% 0.3%

Ecuador 34.0 36.2 38.1 37.3 35.0 -6.4% 4.2% 0.1%

Peru 44.2 45.4 46.7 49.2 53.1 7.6% 5.6% 0.2%

Trinidad & Tobago 27.6 29.0 28.3 28.4 25.8 -9.4% 3.7% 0.1%

Venezuela 177.7 175.1 166.6 164.0 161.0 -2.1% 1.4% 0.5%



Austria 64.3 64.5 60.1 62.2 63.2 1.3% -1.9% 0.2%

Azerbaijan 28.7 29.4 31.0 33.9 33.9 -0.2% 0.4% 0.1%

Belarus 58.6 59.1 57.7 50.7 53.7 5.7% -1.0% 0.2%

Belgium 118.6 119.3 112.0 117.6 120.2 1.9% -1.6% 0.4%

Bulgaria 45.3 39.9 42.5 45.5 42.9 -6.0% -0.6% 0.1%

Czech Republic 106.7 104.9 99.0 102.3 105.2 2.5% -1.9% 0.3%

Denmark 40.9 43.4 40.3 37.2 38.9 4.4% -3.5% 0.1%

Finland 50.3 50.8 46.1 43.1 44.6 3.1% -3.2% 0.1%

France 336.4 337.3 304.2 309.7 316.0 1.7% -2.2% 0.9%

Germany 770.7 795.1 749.4 751.1 760.8 1.0% -0.9% 2.3%

Greece 88.1 79.8 76.2 73.4 70.5 -4.3% -3.4% 0.2%

Hungary 43.7 42.3 41.6 44.4 45.8 2.8% -2.5% 0.1%

Ireland 38.2 36.9 36.6 38.4 40.5 5.4% -2.2% 0.1%

Italy 380.5 349.9 325.1 336.2 336.9 ♦ -3.3% 1.0%

Kazakhstan 200.9 202.6 225.0 207.6 207.2 -0.5% 3.5% 0.6%

Lithuania 12.3 11.6 10.9 11.3 11.6 2.0% -1.3% ♦

Netherlands 216.4 210.9 199.4 207.5 212.5 2.1% -1.6% 0.6%

Norway 37.5 37.7 37.0 37.0 37.5 1.1% -0.1% 0.1%

Poland 304.5 307.4 290.4 290.1 299.0 2.8% -0.6% 0.9%

Portugal 50.9 49.3 49.2 53.9 52.9 -2.2% -2.0% 0.2%

Romania 81.1 69.4 69.4 69.1 69.2 -0.1% -3.1% 0.2%


Slovakia 32.2 32.9 30.0 30.1 30.7 1.7% -2.4% 0.1%

Spain 306.5 275.3 272.8 289.4 282.4 -2.7% -2.5% 0.8%

Sweden 50.3 48.5 47.6 47.3 49.1 3.6% -2.4% 0.1%

Switzerland 40.6 42.7 38.0 38.9 37.5 -4.0% -1.1% 0.1%

Turkey 317.0 305.5 337.9 343.0 361.8 5.2% 4.1% 1.1%

Turkmenistan 74.5 67.6 74.2 82.8 83.2 0.2% 5.3% 0.2%

Ukraine 296.8 281.3 241.5 190.3 206.9 8.4% -4.9% 0.6%

United Kingdom 512.2 497.4 454.4 433.4 406.4 -6.5% -2.8% 1.2%


Uzbekistan 109.6 108.5 112.4 115.1 117.0 1.4% 0.7% 0.3%


Total Europe & Eurasia 6627.9 6464.8 6272.5 6240.7 6258.5 ♦ -1.0% 18.7%



148

Iran 564.2 594.7 623.7 616.5 630.9 2.1% 3.5% 1.9%

Israel 79.4 73.3 70.2 73.5 72.9 -1.1% 0.8% 0.2%

Kuwait 108.6 103.7 98.3 108.3 108.6 -0.1% 2.7% 0.3%

Qatar 60.4 92.3 91.1 108.5 106.7 -1.9% 10.3% 0.3%

Saudi Arabia 543.7 552.9 589.0 611.7 621.8 1.4% 5.2% 1.9%




Algeria 113.8 120.7 127.7 136.4 136.0 -0.5% 5.4% 0.4%

Egypt 208.4 207.1 208.8 211.4 220.6 4.1% 3.4% 0.7%

South Africa 435.6 439.4 444.0 421.8 425.7 0.6% 0.7% 1.3%

Other Africa 369.2 390.9 409.9 422.9 426.6 0.6% 3.5% 1.3%

Total Africa 1127.0 1158.2 1190.4 1192.6 1209.0 1.1% 2.6% 3.6%

Australia 397.2 393.3 398.4 413.6 408.9 -1.4% 1.1% 1.2%

Bangladesh 63.8 65.0 68.5 75.4 78.5 3.9% 7.3% 0.2%

China 8979.4 9218.8 9224.1 9164.5 9123.0 -0.7% 4.2% 27.3%


India 1872.8 1933.1 2085.9 2157.4 2271.1 5.0% 6.0% 6.8%

Indonesia 510.8 523.4 477.1 492.5 531.4 7.6% 3.7% 1.6%

Japan 1284.4 1274.6 1240.8 1206.6 1191.2 -1.5% -0.6% 3.6%

Malaysia 218.6 228.9 240.1 247.6 263.8 6.3% 3.3% 0.8%

New Zealand 35.2 34.8 35.0 35.1 35.2 0.1% -0.5% 0.1%

Pakistan 162.4 161.8 168.6 177.1 192.7 8.5% 2.7% 0.6%

Philippines 83.8 92.0 98.0 107.0 119.9 11.8% 4.2% 0.4%

Singapore 193.8 194.8 194.7 206.5 220.9 6.7% 4.8% 0.7%

South Korea 644.1 646.5 644.3 654.0 662.1 1.0% 2.3% 2.0%

Taiwan 266.1 266.2 271.8 270.3 276.2 1.9% 0.1% 0.8%

Thailand 272.0 275.4 282.5 287.7 292.0 1.2% 2.4% 0.9%

Vietnam 130.5 134.8 150.4 166.9 167.0 -0.2% 6.8% 0.5%



Total World 32759.7 33226.1 33342.5 33303.9 33432.0 0.1% 1.6% 100.0%

of which: OECD 12920.3 12979.8 12804.1 12665.9 12574.4 -1.0% -0.9% 37.6%

Non-OECD 19839.3 20246.3 20538.4 20638.0 20857.7 0.8% 3.4% 62.4%

European Union # 3738.5 3654.7 3442.7 3477.0 3485.1 ♦ -2.0% 10.4%

CIS 2379.3 2309.1 2312.2 2230.6 2220.4 -0.7% 0.1% 6.6%

w Less than 0.05%.

n/a not available.


Notes: The carbon emissions above reflect only those through consumption of oil, gas and coal for combustion related activities, and are based on

'Default CO2 Emissions Factors for Combustion' listed by the IPCC in its Guidelines for National Greenhouse Gas Inventories (2006).

This does not allow for any carbon that is sequestered, for other sources of carbon emissions, or for emissions of other greenhouse gases.

Our data is therefore not comparable to official national emissions data.



149

Renewable energy - geothemal

Cumulative installed geothermal power capacity*

Share

Megawatts 2012 2013 2014 2015 2016 2016 2005-15 2016

Australia 1 2 2 2 2 0.0% 30.2% 0.0%

Austria 1 1 1 1 1 0.0% 1.6% 0.0%

China 24 27 27 27 27 0.0% -0.3% 0.2%

Costa Rica 208 208 208 208 208 0.0% 2.5% 1.5%

El Salvador 204 204 204 204 204 0.0% 3.1% 1.5%

Ethiopia 7 7 7 7 7 0.0% 0.0% 0.1%

France (Guadeloupe) 16 17 17 17 17 0.0% 1.5% 0.1%

Germany 12 17 27 27 27 0.0% 63.1% 0.2%

Guatemala 52 48 48 48 48 0.0% 3.8% 0.4%

Iceland 665 665 665 665 665 0.0% 12.6% 4.9%

Indonesia 1339 1339 1401 1401 1590 13.5% 5.1% 11.8%

Italy 875 876 916 916 916 0.0% 1.5% 6.8%

Japan 536 537 539 544 544 0.0% 0.2% 4.1%

Kenya 217 253 450 605 676 11.7% 13.7% 5.0%

Mexico 812 834 834 887 907 2.3% -0.8% 6.7%

New Zealand 723 971 971 971 971 0.0% 8.6% 7.2%

Nicaragua 160 160 160 160 160 0.0% 7.5% 1.2%

Papua New Guinea 56 56 56 56 56 0.0% 26.1% 0.4%

Philippines 1848 1868 1917 1917 1929 0.6% -0.3% 14.4%

Portugal (The Azores) 29 29 29 29 29 0.0% 6.1% 0.2%

Russia (Kamchatka) 82 82 82 82 82 0.0% 0.4% 0.6%

Thailand 0 0 0 0 0 0.0% 0.0% 0.0%

Turkey 114 226 405 624 775 24.2% 40.8% 5.8%

US 3450 3524 3525 3596 3596 0.0% 2.2% 26.8%

Total World 11397 11917 12492 12995 13438 3.4% 3.3% 100.0%

Sources:ThinkGeoEnergy, International Geothermal Association, and national sources.

* End of year.



150

Renewable energy - solar

Cumulative installed photovoltaic (PV) power* Share

Megawatts 2012 2013 2014 2015 2016 2016 2005-15 2016

US 7328 12079 18317 25570 40300 57.6% 63.3% 13.4%

Canada 827 1272 1904 2515 2715 8.0% 65.0% 0.9%

Mexico 35 66 114 170 320 88.2% 26.0% 0.1%


Chile 2 15 218 848 1603 89.0% n/a 0.5%

Honduras 5 5 5 393 414 5.3% n/a 0.1%


Total S. & Cent. America 302 417 754 2028 2987 47.3% 98.7% 1.0%

Austria 263 626 785 923 1077 16.7% 44.0% 0.4%

Belgium 2800 3058 3153 3252 3422 5.2% 95.4% 1.1%

Bulgaria 1010 1020 1026 1029 1032 0.3% n/a 0.3%

Czech Republic 2022 2064 2068 2075 2073 -0.1% n/a 0.7%

Denmark 408 563 606 830 900 8.4% 77.3% 0.3%

Finland 8 8 11 15 20 33.3% 27.7% 0.0%

France 4094 4748 5702 6571 7130 8.5% 74.0% 2.4%

Germany 33033 36337 38343 39799 41275 3.7% 34.5% 13.7%

Greece 1536 2579 2596 2604 2611 0.3% 86.9% 0.9%

Hungary 12 35 77 168 225 33.9% n/a 0.1%

Italy 16456 18202 18606 18906 19279 2.0% 86.3% 6.4%

Netherlands 363 723 1123 1575 2100 33.3% 42.6% 0.7%

Norway 10 11 13 16 27 70.1% 8.0% 0.0%

Portugal 244 299 416 455 513 12.7% 72.1% 0.2%

Romania 41 761 1293 1326 1372 3.5% n/a 0.5%

Slovakia 513 533 533 533 540 1.3% n/a 0.2%

Spain 5104 5354 5376 5435 5490 1.0% 58.2% 1.8%

Sweden 24 43 79 115 175 52.2% 39.2% 0.1%

Switzerland 437 756 1061 1390 1640 18.0% 48.3% 0.5%

Turkey 12 18 58 248 832 235.5% 61.9% 0.3%

Ukraine 371 748 819 839 938 11.8% n/a 0.3%

United Kingdom 1771 2897 5493 9688 11727 21.0% 97.6% 3.9%


Total Europe & Eurasia 70802 81836 89864 98630 105371 6.8% 45.4% 35.0%

Israel 237 481 681 780 910 16.7% 94.6% 0.3%

Other Middle East 39 75 115 173 510 194.8% n/a 0.2%


South Africa 72 280 1034 1039 1544 48.6% 51.8% 0.5%

Other Africa 337 409 484 614 947 54.2% 40.8% 0.3%

Total Africa 409 689 1518 1653 2491 50.7% 46.6% 0.8%

Australia 2415 3226 4028 4735 5488 15.9% 54.6% 1.8%

China 6750 17740 28380 43530 78070 79.3% 90.8% 25.9%

India 1176 2320 3062 5040 9010 78.8% 75.7% 3.0%

Japan 6632 13599 23339 34151 42750 25.2% 37.4% 14.2%

Malaysia 32 139 204 232 286 23.3% n/a 0.1%



151

Pakistan 0 46 119 778 978 25.7% n/a 0.3%

Philippines 16 21 22 144 900 525.0% n/a 0.3%

South Korea 1024 1555 2481 3500 4350 24.3% 74.3% 1.4%

Taiwan 223 392 620 842 1210 43.7% n/a 0.4%

Thailand 388 824 1299 1424 2150 51.0% 50.7% 0.7%



Total World 98803 137005 177147 226380 301473 33.2% 48.9% 100.0%

Sources: IEA Photovoltaic Power Systems Programme, IRENA, Solar Power Europe, EurObserver, and national sources.

* End of year.


152

Renewable energy – wind

Cumulative installed wind turbine capacity* Share

Megawatts 2012 2013 2014 2015 2016 2016 2005-15 2016

US 60208 61292 66146 74260 82453 11.0% 23.2% 17.6%

Canada 6214 7813 9684 11209 11890 6.1% 32.3% 2.5%

Mexico 1512 1988 2510 3224 3678 14.1% 101.0% 0.8%


Argentina 166 242 295 303 303 0.0% 25.6% 0.1%

Brazil 2508 3466 5962 8726 10740 23.1% 76.9% 2.3%

Chile 202 301 764 911 1424 56.3% 84.4% 0.3%

Costa Rica 148 148 197 278 319 14.7% 13.4% 0.1%

Uruguay 56 59 529 845 1210 43.2% n/a 0.3%


Total S. & Cent. America 3976 5519 9192 13287 16747 26.0% 52.7% 3.6%

Austria 1378 1661 2072 2390 2618 9.5% 11.3% 0.6%

Belgium 1444 1720 1960 2170 2401 10.6% 28.5% 0.5%

Bulgaria 643 650 660 660 660 0.0% n/a 0.1%

Denmark 4137 4747 4778 4966 5133 3.4% 4.9% 1.1%

Finland 268 428 611 984 1512 53.7% 27.7% 0.3%

France 7583 8164 9337 10324 11670 13.0% 29.6% 2.5%

Germany 30979 33477 38614 44541 49534 11.2% 9.3% 10.6%

Greece 1749 1866 1980 2136 2374 11.2% 13.5% 0.5%

Hungary 325 329 329 329 329 0.0% 34.1% 0.1%

Ireland 1812 2100 2322 2500 2824 13.0% 17.5% 0.6%

Italy 8102 8542 8683 9137 9257 1.3% 18.2% 2.0%

Netherlands 2552 2714 2876 3402 4191 23.2% 10.8% 0.9%

Norway 705 818 859 869 885 1.8% 12.2% 0.2%

Poland 2547 3441 3885 5149 5831 13.2% 54.8% 1.2%

Portugal 4363 4557 4683 4770 5005 4.9% 15.9% 1.1%

Romania 1913 2608 2962 2985 3037 1.7% n/a 0.6%

Spain 22722 22898 23025 22988 23026 0.2% 8.7% 4.9%

Sweden 3750 4474 5524 6128 6618 8.0% 27.2% 1.4%

Turkey 2261 2760 3630 4503 5376 19.4% 71.9% 1.1%

United Kingdom 8899 11212 13037 14291 15695 9.8% 26.7% 3.3%


Total Europe & Eurasia 109689 120974 133937 147625 160530 8.7% 13.7% 34.2%

Iran 98 98 117 117 117 0.0% 19.0% 0.0%

Other Middle East 12 12 19 127 202 59.1% 30.3% 0.0%


Egypt 552 552 610 810 810 0.0% 16.2% 0.2%

Ethiopia 81 171 171 324 324 0.0% n/a 0.1%

Morocco 394 495 798 798 798 0.0% 28.7% 0.2%

South Africa 10 257 569 1079 1473 36.5% 80.1% 0.3%

Tunisia 173 200 233 245 245 0.0% 29.1% 0.1%

Other Africa 56 62 74 125 136 8.8% 26.4% 0.0%

Total Africa 1266 1737 2455 3381 3786 12.0% 28.4% 0.8%

Australia 2834 3489 4056 4436 4576 3.2% 20.0% 1.0%



153

China 62956 76560 96370 129340 148640 14.9% 58.9% 31.7%

India 18420 20150 22465 25088 28700 14.4% 18.9% 6.1%

Japan 2673 2722 2840 3084 3280 6.4% 10.3% 0.7%

New Zealand 623 623 683 690 690 0.0% 15.2% 0.1%

Pakistan 56 106 256 308 591 91.9% n/a 0.1%

Philippines 33 33 283 394 394 0.0% 31.8% 0.1%

South Korea 446 506 612 869 1089 25.3% 25.6% 0.2%

Taiwan 571 614 637 647 682 5.4% 39.1% 0.1%

Thailand 112 223 225 234 449 91.9% n/a 0.1%



Total World 271817 304615 352831 418745 468989 12.0% 21.6% 100.0%

Sources: Navigant Consulting, Global Wind Energy Council, IRENA and national sources.


154

Approximate conversion factors

To

tonnes US tonnes/

Crude oil* (metric) kilolitres barrels gallons year

From Multiply by

Tonnes (metric) 1 1.165 7.33 307.86 –

Kilolitres 0.8581 1 6.2898 264.17 –

Barrels 0.1364 0.159 1 42 –

US gallons 0.00325 0.0038 0.0238 1 –

Barrels/day – – – – 49.8

*Based on worldwide average gravity.

To convert

barrels tonnes kilolitres tonnes

Products to tonnes to barrels to tonnes to kilolitres

Liquefied petroleum gas (LPG) 0.086 11.60 0.542 1.844

Gasoline 0.120 8.35 0.753 1.328

Kerosene 0.127 7.88 0.798 1.253

Gas oil/ diesel 0.134 7.46 0.843 1.186

Residual fuel oil 0.157 6.35 0.991 1.010

Product basket 0.125 7.98 0.788 1.269

To

billion cubic billion cubic million tonnes million tonnes trillion British million barrels

Natural gas (NG) and liquefied natural gas (LNG) metres NG feet NG oil equivalent LNG thermal units oil equivalent

From

1 billion cubic metres NG 1 35.3 0.90 0.74 35.7 6.16

1 billion cubic feet NG 0.028 1 0.025 0.021 1.01 0.17

1 million tonnes oil equivalent 1.11 39.2 1 0.82 39.7 6.84

1 million tonnes LNG 1.36 48.0 1.22 1 48.6 8.37

1 trillion British thermal units 0.028 0.99 0.025 0.021 1 0.17

1 million barrels oil equivalent 0.16 5.74 0.15 0.12 5.80 1

Units

1 metric tonne = 2204.62 lb.

= 1.1023 short tons

1 kilolitre = 6.2898 barrels

1 kilolitre = 1 cubic metre

1 kilocalorie (kcal) = 4.187 kJ = 3.968 Btu

1 kilojoule (kJ) = 0.239 kcal = 0.948 Btu

1 British thermal unit (Btu) = 0.252 kcal = 1.055 kJ

1 kilowatt-hour (kWh) = 860 kcal = 3600 kJ = 3412 Btu

Calorific equivalents

One tonne of oil equivalent equals approximately:

Heat units 10 million kilocalories

42 gigajoules

40 million Btu

Multiply by

Multiply by


155

Solid fuels 1.5 tonnes of hard coal

3 tonnes of lignite amd sub-bituminous coal

Gaseous fuels See Natural gas and LNG table

Electricity 12 megawatt-hours

One million tonnes of oil or oil equivalent produces about 4400 gigawatt-hours (=4.4 terawatt hours) of electricity in a modern power station.

1 barrel of ethanol = 0.58 barrels of oil equivalent

1 barrel of biodisel = 0.86 barrels of oil equivalent

1 tonne of ethanol = 0.68 tonne of oil equivalent

1 tonne of biodiesel = 0.88 tonne of oil equivalent

Other terms

Tonnes: Metric equivalent of tons


156

Definitions

Statistics published in this Review are taken from government sources and published data.

No use is made of confidential information obtained by BP in the course of its business

Country groupings are made purely for statistical purposes and are not intended to imply any judgement about political or economic standings.

Country and geographical groupings

North America:

US (excluding US territories), Canada and Mexico.

South and Central America:

Caribbean (including Puerto Rico and US Virgin Islands), Central and South America.

Europe:

European members of the OECD plus Albania, Bosnia-Herzegovina, Bulgaria, Croatia, Cyprus, The former Yugoslav Republic of Macedonia, Georgia, Gibraltar, Latvia, Lithuania, Malta,

Montenegro, Romania and Serbia.

Commonwealth of Independent Staets (CIS):

Armenia, Azerbaijan, Belarus, Kazakhstan, Kyrgyzstan, Moldova, Russian Federation, Tajikistan, Turkmenistan, Ukraine, Uzbekistan.

Europe and Eurasia:

All countries listed above under the headings Europe and CIS

Middle East:

Arabian Peninsula, Iran, Iraq, Israel, Jordan, Lebanon, Syria.

North Africa:

Territories on the north coast of Africa from Egypt to Western Sahara.

West Africa:

Territories on the west coast of Africa from Mauritania to Angola, including Cape Verde, Chad

East and Southern Africa:

Territories on the east coast of Africa from Sudan to Republic of South Africa. Also Botswana, Madagascar, Malawi, Namibia, Uganda, Zambia, Zimbabwe.

Asia Pacific:

Brunei, Cambodia, China, China Hong Kong SAR*, China Macau SAR*, Indonesia, Japan, Laos, Malaysia, Mongolia, North Korea, Philippines, Singapore, South Asia (Afghanistan, Bangladesh,

India, Myanmar, Nepal, Pakistan and Sri Lanka), South Korea, Taiwan, Thailand, Vietnam, Australia, New Zealand, Papua New Guinea and Oceania.

*Special Administrative Region

Australasia:

Australia, New Zealand.

OECD members (Organization For Economic Co-operation and Development)

Europe: Austria, Belgium, Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Luxembourg, Netherlands, Norway, Poland, Portugal, Slovakia,

Slovenia, Spain, Sweden, Switzerland, Turkey, United Kingdom. Other member countries: Australia, Canada, Chile, Israel, Japan, Mexico, New Zealand, South Korea, US.

OPEC members (Organization of the Petroleum Exporting Countries)

Middle East: Iran, Iraq, Kuwait, Qatar, Saudi Arabia, United Arab Emirates. North Africa: Algeria, Libya. West Africa: Angola, Nigeria. South America: Ecuador, Venezuela.

European Union members


157

Austria, Belgium, Bulgaria, Croatia, Cyprus, Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Ireland, Italy, Latvia, Lithuania, Luxembourg, Malta, Netherlands,

Poland, Portugal, Romania, Slovakia, Slovenia, Spain, Sweden, UK.

Non-OECD

All countries that are not members of the OECD.

MethodologyThe primary energy values of nuclear and hydroelectric generation, as well as electricity from renewable sources, have been derived by calculating

the equivalent amount of fossil fuel required to generate the same volume of electricity in a thermal power station, assuming a conversion efficiency of 38% (the average for OECD thermal power generation)Fuels used as inputs for conversion technologies (gas-to-liquids, coal-to-liquids, and coal to gas) are counted as production for the source fuel and the outputs are counted as consumption for the

converted fuel are counted as consumption for the converted fuel."

Percentages: Calculated before rounding of actuals.

Rounding differences: Because of rounding, some totals may not agree exactly with the sum of their component parts.

Tonnes: Metric equivalent of tons


158

Country Price (USD cent/kWh) Source

Thailand 8 http://www.boi.go.th/index.php?page=utility_costs

Malaysia 9 https://www.tnb.com.my/commercial-industrial/pricing-tariffs1/

Indonesia 8.1

https://www.mrfixitbali.com/electrical/electricity-

supply/electricity-cost-Indonesia.html

Vietnam 7.4

http://www.evn.com.vn/c3/evn-va-khach-hang/Bieu-gia-ban-le-

dien-9-79.aspx

Australia

(Queensland) 9.4

http://www.qca.org.au/getattachment/f3f7d440-1910-4134-85dc-

e2e7df5e9552/QCA-Final-Determination-Regulated-electricity-

pr.aspx

0

1

2

3

4

5

6

7

8

9

10

Thailand Malaysia Indonesia Vietnam Australia(Queensland)

Price (USD cent/kWh)


159

http://www.boi.go.th/index.php?page=utility_costs

https://www.tnb.com.my/commercial-industrial/pricing-tariffs1/

https://www.mrfixitbali.com/electrical/electricity-supply/electricity-cost-Indonesia.html

https://www.mrfixitbali.com/electrical/electricity-supply/electricity-cost-Indonesia.html

http://www.qca.org.au/getattachment/f3f7d440-1910-4134-85dc-e2e7df5e9552/QCA-Final-Determination-Regulated-electricity-pr.aspx



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RETAIL ELECTRICITY TARIFF

a) Manufacturing industries

Customer group Rate (VND/kWh)

1.1 Voltage of 110kV and above

a) Standard hour 1,388


160

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b) Off-peak hour 869

c) Peak hour 2,459

1.2 Voltage of 22kV to below 110kV



c) Peak hour 2,556

1.3 Voltage of 6kV to below 22kV



c) Peak hour 2,637

1.4 Voltage of below 6kV



c) Peak hour 2,735

Customer purchasing electricity at 20kV voltage are charged at the rate for voltages of 22kV to below 110kV.

b) Administrative offices, civil service units


1 Hospitals, nurseries, kindergartens, schools

Voltage of 6kV and above 1,460

Voltage of below 6kV 1,557

2 Public lighting, administrative and civil service units

Voltage of 6kV and above 1,606

Voltage of below 6kV 1,671

c) Business


161


1 Voltage of 22kV and above


b) Off-peak hour 1,185

c) Peak hour 3,699

2 Voltage of 6kV up to below 22 kV



c) Peak hour 3,829

3 Voltage of below 6kV



c) Peak hour 3,991

d) Household


1 Retail price for household electricity

For the first 50 kWh (1 – 50 kWh) 1,484

For the next 50 kWh (51 – 100 kWh) 1,533




For the next kWh (401 kWh onwards) 2,587

2 Retail price for household electricity via prepaid card

meter 2,141

For students and laborers living in rented housing: every four registered individuals is entitled to the rate applied to one household (one individual is charged at ¼ of the rate applied to a household).


162

21/12/2016 10:04

Other News

WHOLESALE ELECTRICITY TARIFF (19/12/2016)

TIME – OF – USE ELECTRICITY CHARGE (15/12/2016)

ELECTRICITY CHARGE APPLICABLE TO POOR, LOW-INCOME HOUSEHOLDS (12/12/2016)

ELECTRICITY CHARGE CALCULATION IN MONTHS WITH CHARGE RATE (10/12/2016)

CHARGE FOR REACTIVE POWER CAPACITY (09/12/2016)

Website: http://en.evn.com.vn/d6/gioi-thieu-d/RETAIL-ELECTRICITY-TARIFF-9-28-252.aspx


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DOING BUSINESS / Cost of Doing Business in Thailand / Utility Costs

UTILITY COSTS Water Rates for Regional Areas

Commerce, Government Agency, State Enterprise and Industry

Volume (cubic meters)

Water rate per cubic meter

Baht US$

0 - 10 9.50 but not less than 90.00 Baht 0.27 but not less than 2.57

11 - 20 10.70 0.31


164

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21 - 30 10.95 0.31

31 - 40 13.21 0.38

41 - 50 13.54 0.39

51 - 60 13.86 0.40

61 - 80 14.19 0.40

81 - 100 14.51 0.41

101 - 120 14.84 0.42

121 - 160 15.16 0.43

161 - 200 15.49 0.44

Over 200 15.81 0.45

Source: Metropolitan Waterworks Authority, as of July 2016: www.mwa.co.th Electricity Tariffs Schedule 1: Residential (Applicable to households and other dwelling places, monasteries, rectories and places of worship, including its compound through a single watt-hour meter.)

1.1 Normal Rate

Energy Charge (per kWh) Service Charge

Baht US$ Baht/month US$/month

1.1.1 Consumption not exceeding 150 kWh per month 8.19 0.23

- First 15 kWh (0-15th) 2.35 0.07

- Next 10 kWh (16th-25th) 2.99 0.09

- Next 10 kWh (26th-35th) 3.24 0.09

- Next 65 kWh (36th-100th) 3.62 0.10

- Next 50 kWh (101st-150th) 3.72 0.11

- Next 250 kWh (151st-400th) 4.22 0.12

- Over 400 kWh (401st and over) 4.42 0.13

Customer, who is classified under 1.1.1, will be received free electricity for that month if consumption not exceeding 50 kWh.

1.1.2 Consumption exceeding 150 kWh per month 38.22 1.09


165

http://www.mwa.co.th/



- First 150 kWh (0-150th) 3.25 0.09

- Next 250 kWh (151st-400th) 4.22 0.12


1.2 Time of Use Rate (TOU)

Peak (per kWh)

Off Peak (per kWh) Service Charge

Baht US$ Baht US$ Baht/month US$/month

1.2.1 At voltage level between 12-24 kV 5.11 0.15 2.60 0.07 312.24 8.91

1.2.2 At voltage level less than 12 kV 5.80 0.17 2.64 0.08 38.22 1.09

Notes: 1. Customer with installed meter less than 5 Amp, 200 V., 1 phase, 2 Wires, is classified under 1.1.1. However, if monthly consumption is over 150 kWh for 3 consecutive months, the customer will be reclassified under 1.1.2 for the following month; and if monthly consumption is not over 150 kWh for 3 consecutive months, the customer will be reclassified under 1.1.1 for the following month. 2. Customer with installed meter over 5 Amp, 220 V., 1 Phase, 2 Wires, is classified under 1.1.2. 3. As for tariff No. 1.2, if meter is installed on the low voltage side of customer’s transformer, another 2% must be added to energy consumption in order to compensate for transformer losses. 4. Tariff No. 1.2 is an optional rate, and may be switched back to Tariff No. 1.1 following a minimum use of 12 months. Moreover, the customer is obligated to pay any additional cost for the installation and removal of any equipment that requires a meter, and/ or any cost charged by the PEA. Schedule 2: Small General Service (Applicable to businesses, residences, industries, government institutions, local authorities, state enterprises, embassies, establishments related to foreign countries, or international organizations, etc., Including compounds with a maximum of 15-minute integrated demand of less than 30 kW through a single watt-hour meter)

2.1 Normal Rate

Energy Charge (per kWh) Service Charge

Baht US$ Baht/month US$/month

1.1.1 At voltage level between 12-24 kV 3.91 0.11 312.24 8.91

1.1.2 At voltage level less than 12 kV 46.16 1.32

- First 150 kWh (0 - 150th) 3.25 0.09

- Next 250 kWh (151st - 400th) 4.22 0.12

- Over 400 kWh (401 - and over) 4.42 0.13

Peak (per kWh)

Off Peak (per kWh) Service Charge


166

2.2 Time of Use Rate (TOU) Baht US$ Baht US$ Baht/month US$/month



Note: 1. As for Tariff No. 2.2, if the meter is installed on the low voltage side of a customer’s transformer, another 2% must be added to energy consumption in order to compensate for the transformer’s losses. 2. Tariff No. 2.2 is an optional rate and may switched back to Tariff No. 2.1 following a minimum use of 12 months. Moreover, the customer is obligated to pay any additional cost for the installation and removal of any equipment that requires a meter, and/ or any cost charged by the PEA. 3. In any month, if the maximum integrated demand is equal to or over 30 kW, the customer will be classified under Schedule 3-5 depending on the case. Schedule 3: Medium General Service (Applicable to businesses, industries, government institutions, local authorities, state enterprises, embassies, establishments related to foreign countries or international organizations, including compounds with a maximum 15-minute integrated demand of at least 30 kW but less than 1,000 kW, and an average energy consumption in the last 3 consecutive months, that does not exceed 250,000 kWh per month through a single demand meter)

3.1 Normal Rate

Demand Charge (per kW)

Energy Charge (per kWh)

Service Charge

(per month)

Baht US$ Baht US$ Baht US$

3.1.1 At voltage level 69 kV and above 175.70 5.01 3.14 0.09 312.24 8.91





Service Charge

(per month)

Baht US$ Baht US$ Baht US$

3.2 Time of Use Rate (TOU) Peak

(per kWh) Off Peak

(per kWh)

3.2.1 At voltage level 69 kV and above 74.14 2.12 4.13 0.12 2.61 0.07 312.24 8.91

3.2.2 At voltage level between 12-24 kV 132.93 3.79 4.21 0.12 2.63 0.08 312.24 8.91


167

3.2.3 At voltage level less than 12 kV 210.00 5.99 4.36 0.12 2.66 0.08 312.24 8.91

Minimum Charge: As for Schedule 3, the minimum charge shall not be lower than 70% of the maximum demand charge during the last 12 month period ending with the current month. Note: 1. If the meter is installed on the low voltage side of customer’s transformer, another 2% must be added to both total demand and energy consumption in order to compensate for transformer losses. 2. Tariff No. 3.2 must be applied on any customer who first qualified under Schedule 3 since October 2000. 3. Tariff No. 3.2 is an optional rate for PEA customers who shall not be permitted to switch back to Tariff No. 3.1. The customer is obligated to pay any additional cost for the installation and removal of any equipment that requires a meter, and/ or any cost charged by the PEA. 4. In any month, if the maximum integrated demand is less than 30 kW, this rate will be applied, regardless. However, if such demand has dropped below 30 kW for 12 consecutive months and still below 30 kW in the 13th month, the customer will be reclassified under Tariff No. 2.1. Schedule 4: Large General Service (Applicable to businesses, industries, government institutions, local authorities, state enterprises, embassies, establishments related to foreign countries or international organizations, including compounds with a maximum 15-minute integrated demand of over 1,000 kW or applied energy consumption over the last 3 consecutive months that exceeds 250,000 kWh per month on a single demand meter)

4.1 Time of Day Rate

(TOD)

Demand Charge (per kW) Energy Charge

Service Charge

Peak Partial Off Peak (per kWh) (per month)

Baht US$ Baht US$ Baht US$ Baht US$ Baht US$

4.1.1 At voltage level 69 kV and above 224.30 6.40 29.91 0.85 0 0 3.14 0.09 312.24 8.91

4.1.2 At voltage level between 12-24 kV 285.05 8.13 58.88 1.68 0 0 3.17 0.09 312.24 8.91

4.1.3 At voltage level less than 12 kV 332.71 9.49 68.22 1.95 0 0 3.20 0.09 312.24 8.91

Peak: 06.30 PM - 09.30 PM every day Partial: 08.00 AM - 06.30 PM every day (Demand charge considers only the excess demand over peak recorded on peak period) Off Peak: 09.30 PM - 08.00 AM every day


Demand Charge (per kW) Energy Charge (per kWh)

Service Charge (per month) Peak Peak Off Peak

Baht US$ Baht US$ Baht US$ Baht US$


168




Minimum Charge: As for Schedule 4, the minimum charge shall not be lower than 70% of the maximum demand charge during the last 12 month period ending with the current month. Note: 1. Tariff No. 4.2 must be applied on either any customer who first qualified under Schedule 4 or time of use customers who became a PEA customer. 2. Tariff No. 4.2 is an optional rate for PEA customers who shall not be permitted to switch back to Tariff No. 4.1. The customer is obligated to pay any additional cost for the installation and removal any equipment that requires a meter, and/or any cost charged by the PEA. 3. In any month, if the maximum integrated demand is less than 1,000 kW or the monthly energy consumption does not exceed 250,000 kWh, this rate will be applied, regardless. However, if such demand drops below 30 kW for 12 consecutive months and remains below 30 kW on the 12th month, the customer will be reclassified under Tariff No. 2.1 instead. Schedule 5: Specific Business Service (Applicable to hotels, guest houses, or other businesses providing lodging to customers, including its compounds with a maximum 15-minute integrated demand of 30 kW and over on a single demand meter)









5.2 During Installation of TOU Meter Baht US$ Baht US$ Baht US$

5.2.1 At voltage level 69 kV and above 220.56 6.29 3.14 0.09 312.24 8.91


169



Minimum Charge: 70% of the maximum demand charge during the last 12-month period ending with the current month. Note: 1. If the meter is installed on the low voltage side of a customer’s transformer, another 2% must be added to both total demand and energy consumption in order to compensate for the transformer’s losses. 2. Tariff No. 5.1 must be applied on any customer who first qualified under Schedule 5. In addition, Tariff No. 5.2 is used temporarily during the installation of a TOU meter. 3. In any month, if the maximum integrated demand is less than 30 kW or monthly energy consumption does not exceed 250,000 kWh, this rate will be applied, regardless. However, if such demand has dropped below 30 kW for 12 consecutive months and remains below 30 kW on the 12th month, the customer will be reclassified under Tariff No. 2.1 instead. Schedule 6: Non-Profit Organization (Applicable to non-government organizations offering non-charge services on a single demand meter.)

6.1 Normal Rate


Service Charge (per month)

US$ Baht US$ Baht US$

6.1.1 At voltage level 69 kV and above 3.44 0.10 312.24 8.91

6.1.2 At voltage level between 12-24 kV 3.61 0.10 312.24 8.91

6.1.3 At voltage level less than 12 kV 20.00 0.57

- First 10 kWh (0 - 10th) 2.83 0.08

- Over 10 kWh (11th and over) 3.92 0.11









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Minimum Charge: As for Tariff No. 6.2, the minimum charge shall not be lower than 70% of the maximum demand charged during the last 12-month period ending with the current month. Note: 1. As for government institutions and local authorities, if the average energy consumption over the last 3 consecutive months exceeds 250,000 kWh, the customer will continue to be classified under Schedule 6 until the electric bill of September 2012. Subsequently, beginning with the electric bill of October 2012, the customer will be reclassified under Schedule 2-4, depending on the case. 2. If the meter is installed on the low voltage side of a customer’s transformer, another 2% must be added to both total demand and energy consumption in order to compensate for the transformer’s losses. 3. Tariff No. 6.2 is an optional rate for PEA customers who shall not be permitted to switch back to Tariff No. 6.1. The customer is obligated to pay any additional cost for the installation and removal of any equipment, and/or any costs as charged by the PEA. Schedule 7: Agricultural Pumping (Applicable to electricity consumption for the use of water pumps for agricultural purposes by government agricultural agencies, officially recognized farmers groups, agriculture co-operatives, on a single demand meter.) Monthly Rate

7.1 Normal Rate


Service Charge (per month)

US$ Baht US$ Baht US$

115.16 3.29

- First 100 kWh (0 - 100th) 2.09 0.06









Minimum Charge: As for Tariff No. 7.2, the minimum charge shall not be lower than 70% of the maximum demand charge during the last 12-month period ending with the current month. Note:


171

1. If a meter is installed on the low voltage side of a customer’s transformer or PEA’s transformer (only in case of a lower voltage meter is installed on the CT), another 2% must be added to both demand and energy consumption in order to compensate for the transformer’s losses. 2. Tariff No. 7.2 is an optional rate and shall not be able to switch back to Tariff No. 7.1. The customer is obligated to pay for any additional cost of installing and removing any equipment required to meter, and/or any costs as specified by the PEA. Schedule 8: Temporary Service (Applicable provisionally for construction uses, temporary special events, and places without a registration number, including electricity consumption that does not follow the PEA’s Rules and Regulations, through a single Watt-hour meter.)

Baht/kWh US$/kWh

Energy Charge (at All Voltage Level) 6.83 0.19

Note: Customer, classified under this schedule, who desires the use of alternative electricity or who is inspected by the PEA for such electricity consumption, is eligible for a change from the above schedule, for instance, businesses, industries, and households. When a customer reapplies for permanent consumption at the PEA including electricity wiring, installed interior equipment that adheres to PEA standards, and pays for any additional fees, according to PEA regulations, then the customer will be reclassified under schedule 1-7, depending on the case.

Peak: 09:00 am-10:00 pm Monday -Friday and Royal Ploughing Ceremony Day

Off-peak: 10:00 p.m.-09:00 a.m. Monday-Friday and Royal Ploughing Ceremony Day 00:00 a.m.-11:59 p.m. (24 hrs.) Saturday-Sunday, Labor Day, Public Holidays, (except compensation holidays), and the Royal Ploughing Ceremony Day, if it falls on Saturday or Sunday.

Conditions Related to Electricity Tariffs 1. For customers, who applied under Schedules 3, 4, and 5 and have a lagging power factor, a power factor charge of 56.07 Baht/ kVAR/ month will be added to each maximum 15-minute reactive power (kVAR demand) span that exceeds 61.97% of the maximum 15-minute active power (kW demand) span. The fraction, which is less than 0.5 kVAR, is excised and increased to 1 if it is equal to or more than 0.5 kVAR. 2. The electricity tariffs exclude a Value Added Tax (VAT). 3. Monthly Electricity Charge is composed of above electricity tariffs, Fuel Adjustment Charge (Ft), and VAT. THE ABOVE ELECTRICITY TARIFFS ARE EFFECTIVE FROM THE BILLING MONTH OF NOVEMBER 2015 Source: Provincial Electricity Authority. For more information, please contact the Electricity, Business and Tariff Division. Phone: 02-590-9125, 02-590-9127, Fax: 02-590-9133-34, Call Center: 1129 Website: www.pea.co.th, as of July 2016 Last Updated: August 2017

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Final determination

Regulated retail electricity prices for 2016–17

May 2016


176

2

We wish to acknowledge the contribution of the following staff to this report:

Dan Barclay, Jennie Cooper, Sarah Duval, Adam Liddy and Wei Fang Lim

© Queensland Competition Authority 2016

The Queensland Competition Authority supports and encourages the dissemination and exchange of information. However, copyright protects this document.

The Queensland Competition Authority has no objection to this material being reproduced, made available online or electronically but only if it is recognised as the owner of the copyright and this material remains unaltered.


177

Queensland Competition Authority Contents

i

Contents

EXECUTIVE SUMMARY III

Impacts on residential customers iii

Impacts on small business customers iv

Impacts on large business customers v

Arrangements for customers on obsolete and transitional tariffs vi

THE ROLE OF THE QCA – TASK, TIMING AND CONTACTS VII

1 INTRODUCTION 1

1.1 The review process 1

2 LEGISLATIVE REQUIREMENTS AND PRICING FRAMEWORK 2

2.1 Legislative requirements 2

2.2 Pricing framework 3

3 NETWORK COSTS 7

3.1 Introduction 7

3.2 Network tariffs for residential, small business and unmetered supply customers 8

3.3 Network tariffs for large business and street lighting customers 13

4 ENERGY COSTS 15

4.1 Wholesale energy costs 15

4.2 Other energy costs 18

4.3 Energy losses 22

4.4 Total energy cost allowances for 2016–17 22

5 RETAIL COSTS 24

5.1 Overview 24

5.2 Approach to estimating retail costs for 2016–17 26

5.3 ACIL's analysis—residential and small business tariffs 27

5.4 Determining efficient total retail cost allowances—residential and small business tariffs 30

5.5 Determining fixed and variable retail cost components—residential and small business tariffs 32

5.6 Assigning fixed and variable retail costs to residential and small business customer tariffs 35

5.7 Large and very large business customer tariffs 37

5.8 Retail cost allowances for 2016–17 38

5.9 Updating the retail cost allowances from year to year 40

6 OTHER ISSUES 41

6.1 Allowances above the efficient costs of supply 41

6.2 Cost pass-through mechanism 49

7 TRANSITIONAL ARRANGEMENTS 52


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Queensland Competition Authority Contents

ii

7.1 Transitional arrangements for obsolete and transitional tariffs 52

7.2 2016–17 transitional arrangements 57

8 FINAL DETERMINATION 58

8.1 Customer impacts 61

ACRONYMS 66

APPENDIX A : MINISTERIAL DELEGATION AND COVER LETTER 68

APPENDIX B : SUBMISSIONS 74

Submissions to the interim consultation paper 74

Submissions to the draft determination 75

APPENDIX C : RESPONSES TO ADDITIONAL ISSUES RAISED IN SUBMISSIONS 76

APPENDIX D : NETWORK TARIFF STRUCTURES 79

Comparison of Energex and Ergon Energy's tariff structures 79

Ergon Energy tariff structure options 80

APPENDIX E : TRANSITIONAL AND OBSOLETE TARIFFS—CUSTOMER IMPACTS 85

APPENDIX F : BUILD-UP OF PRICES 96

APPENDIX G : GAZETTE NOTICE 102

APPENDIX H : ASSUMPTIONS USED TO DETERMINE CUSTOMER IMPACTS 115

APPENDIX I : SUMMARY OF CONCESSIONAL ARRANGEMENTS FOR ENERGY IN QUEENSLAND 116

APPENDIX J : RETAIL COST ALLOWANCES 117

Deriving retail costs from ACIL's analysis 117

Retail costs for large and very large business customer tariffs 120

Adjusting the fixed retail cost allowance for regulatory fees 121

Other issues raised in submissions 122

APPENDIX K : COST PASS-THROUGH 126


179

Queensland Competition Authority Executive Summary

iii

EXECUTIVE SUMMARY

The Queensland Competition Authority (QCA) has made a final determination of regulated retail electricity

prices (notified prices) to apply in regional Queensland from 1 July 2016 to 30 June 2017. In general, notified

prices are paid by customers who have not entered into a negotiated or market contract with their retailer.

Notified prices are available to residential, small business and large business customers in regional

Queensland. As retail electricity prices in south east Queensland will be deregulated from 1 July 2016,

notified prices will not be available to customers in this region.

We began our review in November 2015 under a delegation from the Minister for Energy and Water Supply.

We appreciate the valuable contribution that stakeholders have made to our review, especially those who

attended workshops and made submissions. While we have not necessarily referred to all arguments or

submissions in this determination, we have carefully considered the issues raised in each submission.

Our approach to setting notified prices for 2016–17 is largely consistent with previous years. In accordance

with the Queensland Government's Uniform Tariff Policy (UTP), we have continued to base notified prices

for residential and small business customers on the costs of supplying electricity in south east Queensland.

We have also continued to base notified prices for large business customers on the lowest cost of supply in

regional Queensland.

We have also undertaken a detailed review of retail costs (which include the costs of customer

administration, call centres, billing and IT systems, and a retail margin) so that our estimates of these costs

are based on the latest information, including observations from competitive retail electricity markets in

Australia.

Our final determination is based on the most up-to-date information available at the time of publication.

As with previous determinations, we have received updated information on the estimated costs of supply

since the publication of the draft determination and have revised our estimates accordingly. In particular,

Energex and Ergon Distribution have provided updated network charges, and ACIL has provided revised

energy cost estimates. Consequently, most notified prices have increased between our draft determination

and final determination. For example, the notified prices for tariff 11 and tariff 20 have both increased

between the draft determination and the final determination. The higher tariff 11 notified price (compared

to the draft determination) is due primarily to higher network and energy costs, while the higher tariff 20

notified price is due primarily to higher retail, energy and network costs.

Impacts on residential customers1

The main retail tariff for residential customers is tariff 11. Many customers on tariff 11 are also on one of

the 'off-peak' or 'controlled load' tariffs (tariffs 31 and 33) for uses such as water heating and pool pumps.

In 2016–17, the annual bill for a typical customer on tariff 11 will increase by 2.8 per cent from $1,457 to

$1,498. For a typical customer on a combination of tariffs 11 and 31 or tariffs 11 and 33, the increases will

be slightly higher (4.8 per cent and 3.1 per cent respectively). However, the impact on individual customers

will vary depending on their consumption. Annual bills for tariff 11 customers with lower consumption than

the typical customer will either decrease or increase by less than 2.8 per cent. Almost one-third of

1 The bill impacts presented are based on typical levels of consumption. The typical customer data was

supplied by Ergon Retail and represents the median customer for all customers on the stated tariff. See Appendix H for further information. Please note that the annual bill amounts in Figure 1 have been rounded to the closest dollar.


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iv

customers on tariff 11 will face lower annual bills in 2016–17 compared to 2015–16. Annual bills for tariff

11 customers with higher consumption than the typical customer will increase by more than 2.8 per cent.

The increase in typical tariff 11 customer bills is primarily due to higher energy costs. Our consultant, ACIL,

advised that the rise in energy costs is driven largely by increasing demand from liquefied natural gas plants,

and higher Renewable Energy Target costs. Some of the impact of higher energy costs has been offset by

a decrease in network costs. For lower consumption customers, the outcome of the review of retail costs

has also helped to offset the impacts of higher energy costs as it has reduced the level of fixed retail costs.

Figure 1 Annual bills for typical residential customers (GST inclusive)

Table 1 Tariff 11 charges (GST exclusive)

2015–16 Final Determination


Change (%)

Fixed charge (cents/day) 106.728 89.572 -16.1%

Variable charge (cents/kWh) 22.238 24.610 10.7%

Impacts on small business customers2

In 2016–17, typical customers on the main small business tariff (tariff 20) will face an increase of $2363 or

11.2 per cent in their annual bill. Typical small business customers on the seasonal time-of-use tariff (tariff

22A) will face an increase of $660 or 15.8 per cent. These increases have been driven primarily by higher

energy costs and retail costs. Bill impacts will vary depending on each individual customer's level and

pattern of consumption.

2 The bill impacts presented are based on typical levels and patterns of consumption. The typical customer

data was supplied by Ergon Retail and represents the median customer for all customers on the stated tariff. See Appendix H for further information. Please note that the annual bill amounts in Figure 2 have been rounded to the closest dollar.

3 Please note that this figure does not equal the difference between the annual bill amounts for tariff 20 in Figure 2 ($235), due to rounding of the amounts in Figure 2.

$1,457

$1,744 $1,750

$1,498

$1,828 $1,806

$600

$700

$800

$900

$1,000

$1,100

$1,200

$1,300

$1,400

$1,500

$1,600

$1,700

$1,800

$1,900

T11 T11 + T31 T11 + T33

2015-16 Annual Bill 2016-17 Annual Bill


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v

Figure 2 Annual bills for typical small business customers (GST inclusive)

Impacts on large business customers4 In 2016–17, typical large business customers will face increases in their annual bills of between 11.8 per cent and 12.2 per cent. The increases have been driven primarily by higher energy costs and network costs. Bill impacts will vary depending on each individual customer's level and pattern of consumption.



$2,113

$4,186

$2,348

$4,846

$-

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

T20 T22A



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vi

Figure 3 Annual bills for typical large business customers (GST inclusive)

Arrangements for customers on obsolete and transitional tariffs

Some business customers are supplied under transitional or obsolete tariffs, which include farming and

irrigation tariffs. These tariffs have been made available for several years to allow customers to transition

to standard business tariffs and recoup some of the investments made to suit the level and structure of

transitional or obsolete tariffs. Based on information from Ergon Retail, many customers on these tariffs

may face lower electricity bills if they moved to a standard business tariff, but some customers would face

much higher bills.

We have maintained transitional arrangements for 2016–17. Our general approach in past determinations

has been to increase the charges in each transitional and obsolete tariff in line with the percentage

increases in the standard business tariffs customers would otherwise pay. We have then generally applied

an additional escalation factor to limit charges for transitional and obsolete tariffs falling further below cost

in dollar terms.

Standard business tariffs will increase in 2016–17 so transitional and obsolete tariffs will also need to

increase. Under our general approach in previous determinations, the escalation factors for most of these

tariffs in 2016–17 would be 1.25 or 1.5.

However, given the substantial price increases that customers on transitional and obsolete tariffs have

experienced in recent years and that customers on these tariffs are more than halfway through the

transition to standard business tariffs, we have decided to apply the minimum escalation factor of 1.1. This

means customers on these tariffs will face increases of between 12.3 per cent and 13.2 per cent in 2016–

17 rather than up to 16.8 per cent if the higher escalation factors were applied.

New customers will also continue to be allowed to access transitional tariffs.

$50,609

$181,043

$449,584

$56,639

$203,138

$502,759

$-

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

T44 T45 T46



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Queensland Competition Authority The Role of the QCA – Task, Timing and Contacts

vii

THE ROLE OF THE QCA – TASK, TIMING AND CONTACTS

The Queensland Competition Authority (QCA) is an independent statutory authority to promote

competition as the basis for enhancing efficiency and growth in the Queensland economy.

The QCA’s primary role with respect to electricity pricing is to set regulated retail electricity prices in

accordance with the requirements of the delegation from the Minister for Energy and Water Supply

(Appendix A) and the Electricity Act 1994 (the Electricity Act).

Contacts

Enquiries regarding this project should be directed to:

ATTN: Sarah Duval or Adam Liddy Tel (07) 3222 0555 www.qca.org.au/Contact-us

www.qca.org.au


184

http://www.qca.org.au/

http://www.qca.org.au/

Queensland Competition Authority Introduction

1

1 INTRODUCTION

The Queensland Competition Authority (QCA) has received a delegation from the Minister for

Energy and Water Supply (the Minister) to determine regulated retail electricity prices (notified

prices). The delegation specifies that the notified prices we determine will apply to non-market

customers in the Ergon Energy Corporation Limited (Ergon Distribution) distribution area from 1

July 2016 to 30 June 2017 (see Appendix A).

The Queensland Government (the Government) has legislated to remove retail price regulation

in the Energex distribution area (covering south east Queensland) from 1 July 2016. As a result,

notified prices will only apply to customers in Ergon Distribution's distribution area.5

1.1 The review process

On 11 December 2015, we released an interim consultation paper advising interested parties of

the commencement of the review. We received 12 submissions in response (see Appendix B).

On 23 March 2016, we released our draft determination and ACIL's draft reports on the cost of

energy and retail costs. In April 2016, we held workshops in five locations (Brisbane, Bundaberg,

Cairns, Toowoomba and Townsville) to discuss the draft determination, and a webinar hosted by

the Chamber of Commerce and Industry Queensland. We received 70 submissions to the draft

determination (see Appendix B).

This final determination publishes final regulated retail tariffs and prices for 2016–17 and

explains how they were determined. In making our final determination, we have taken into

account the requirements of the Electricity Act 1994 (the Electricity Act) and the delegation,

matters raised in submissions, ACIL's final reports on the cost of energy and retail costs, and our

own investigations.

We appreciate the valuable contribution that stakeholders have made to this process, especially

those who attended workshops and made submissions. While we have not necessarily referred

to all arguments or submissions in this report, we have carefully considered each submission.

Issues raised in submissions that are outside the scope of our review are discussed in

Appendix C.

All non-confidential documents relating to this review are available on our website.6

5 Note that customers in the Essential Energy distribution area in southern Queensland do not have access to

notified prices, although Origin Energy receives a subsidy from the Queensland Government to ensure that non-market customers pay no more than similar customers that have access to notified prices.

6 http://www.qca.org.au/Electricity/Regional-consumers/Reg-Electricity-Prices/In-Progress/Regulated-Electricity-Prices-2016-17.


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Queensland Competition Authority Legislative requirements and pricing framework

2

2 LEGISLATIVE REQUIREMENTS AND PRICING FRAMEWORK

When we receive a delegation to determine notified prices, we must make the determination in

accordance with our obligations under the Electricity Act. In this chapter, we explain these

obligations, as well as how we decided on the framework we applied to set notified prices for

2016–17.

2.1 Legislative requirements

The Electricity Act does not specify criteria or principles that we must apply when making a price

determination. Rather, we are directed to have regard to various matters. In accordance with

section 90(5) of the Electricity Act, the matters we are required to have regard to in making a

determination are:

the actual costs of making, producing or supplying the goods or services

the effect of the price determination on competition in the Queensland retail electricity

market

any matter required by delegation

any other matter we consider relevant.

When we make a determination, we also have regard to the objects of the Electricity Act, which

are to:

set a framework for all electricity industry participants that promotes efficient, economical

and environmentally sound electricity supply and use

regulate the electricity industry and electricity use

establish a competitive electricity market in line with the national electricity industry reform

process

ensure that the interests of customers are protected

take into account national competition policy requirements.

2.1.1 Key matters we are required to consider by delegation

The delegation sets out additional matters we are required to consider. Consistent with the

approach of previous price determinations, we are required to consider applying the network (N)

plus retail (R) cost build-up methodology and the Queensland Government's uniform tariff policy

(UTP).

When determining the network cost component, we must consider continuing with the same

general approach we applied in the 2015–16 determination. For residential and small business

customer tariffs, this means using Energex's network charges and tariff structures for non–time-

of-use tariffs (i.e. tariffs 11, 20, 31, 33, 41 and 917). Adopting this approach means that network

charges would be below cost, because they would be based on network costs in south east

Queensland, not regional Queensland. This is consistent with the Government's UTP. As stated

7 Tariff 91 applies to unmetered supplies (except street lighting).


186


3

in the delegation, the UTP 'provides that, wherever possible, non-market customers of the same

class should pay no more for their electricity, regardless of their geographic location'.8

The Minister's covering letter clarifies how the Government expects the UTP to apply for

residential and small business customers (small customers):

… [R]egulated prices in regional Queensland for small customers should broadly reflect the

expected prices for customers on standing offers in south east Queensland.9

For small customer time-of-use and seasonal demand tariffs (i.e. tariffs 12A, 14, 22A and 24) we

must also consider basing the network cost component on the price level of Energex's network

charges, while utilising the relevant Ergon Distribution network tariff structures. Under this

approach, network charges would still be below cost, while (because Ergon Distribution's tariff

structures are used) price signals would improve and customers would be encouraged to reduce

usage during peak periods, as pointed out in the delegation.

For large business customer tariffs, we must consider using Ergon Distribution's network charges.

This is the approach we have adopted in previous decisions.

We are also required to consider maintaining transitional arrangements for transitional and

obsolete tariffs, which include farming and irrigation tariffs.

2.2 Pricing framework

The matters we are required to consider according to the Electricity Act and the objects of the

Electricity Act indicate that cost-reflective prices and promoting retail competition are important

guiding principles. Cost reflectivity is important for efficiency and equity reasons. Previous

determinations have also been designed to support retail competition in south east Queensland

and the large business customer segment in regional Queensland.

These principles conflict with the requirement in the delegation to consider the Government's

UTP.

2.2.1 Residential and small business customers

Given that we are required to consider conflicting matters in making our price determination, we

have explored a spectrum of possible pricing approaches. These range from setting fully cost-

reflective prices to basing notified prices on the cost of supply in south east Queensland (our

previous approach).

Cost base

Setting cost-reflective notified prices (in this context, prices that reflect the costs of supplying

customers in each region of Ergon Distribution's area) would avoid the need to subsidise

electricity prices and promote retail competition. However, network costs vary across regional

Queensland. Setting cost-reflective prices would result in notified prices for customers that

varied by region, which would be inconsistent with the Government's UTP. It would also lead to

significant price increases, particularly for customers in western parts of the state and those

supplied by isolated systems.10

8 Section 5(b) of the Minister's delegation (Appendix A to this document). 9 Cover letter of the delegation (Appendix A to this document). 10 A typical tariff 11 customer paying cost-reflective prices in 2015–16 would pay around 120 per cent more in

western Queensland than customers on notified prices in south east Queensland.


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4

Notified prices could also be set to reflect the lowest costs of supply in regional Queensland11,

which is the approach we have used to set notified prices for large business customers since

2012. This approach would mitigate adverse price impacts for some customers and maintain

uniform tariffs. Compared to our approach in previous determinations, it would improve cost-

reflectivity and reduce the subsidy paid by taxpayers to subsidise electricity prices. However, it

would be inconsistent with the UTP and may result in significant price increases. For example, in

2015–16, the costs of supplying residential customers in the east pricing zone were about 23 per

cent higher12 than in south east Queensland.

At the other end of the spectrum, notified prices could continue to be based on the costs of

supply in south east Queensland. This would be consistent with the UTP and the requirement in

the delegation to consider basing the network cost component on Energex price levels. However,

it would result in customers continuing to pay much less than the cost of supply, potentially

leading to inefficient investment and decision-making, as well as ongoing costs to taxpayers.

Cotton Australia, Ergon Energy Queensland (Ergon Retail), Master Electricians Australia and the

Queensland Farmers' Federation (QFF) supported an approach based on south east Queensland

costs. The Chamber of Commerce and Industry Queensland (CCIQ) considered that notified

prices based on the cost of supply in regional Queensland would be prohibitively expensive for

small business customers. Canegrowers argued that the UTP subsidy should apply to the N

component, and that the R component should be set based on the costs of supply in regional

Queensland, including energy costs.

QCA position

We have decided to base notified prices for residential and small business customers on the cost

of supply in south east Queensland. We consider this reasonable because it is consistent with the

Government's UTP, which provides for notified prices to be based on the costs of supply in south

east Queensland. This approach also avoids the potentially large price increases associated with

the other approaches.

Framework to determine notified prices

To establish an appropriate framework for setting notified prices based on the costs of supply in

south east Queensland, we have considered the Government's policy that notified prices for

small customers in regional Queensland should broadly reflect the expected prices for customers

on standing offers in south east Queensland.13

Customers on standing offers are supplied on a standard retail contract14, as defined under the

National Energy Customer Framework (NECF). In areas where there is retail competition,

customers may opt for a market contract. Market contracts often have different terms and

conditions to standard retail contracts, and prices under market contracts can be lower than

standing offer prices.

Customers who do not, or cannot, opt for market contracts are, by default, supplied

understanding offers. In markets without price regulation, as will be the case in south east

Queensland from 1 July 2016, standing offer prices are set by retailers.

11 Ergon Distribution's east pricing zone, transmission region one. 12 This is the estimated impact in 2015–16 on a typical tariff 11 customer in the Ergon Distribution east pricing

zone (transmission region one) paying cost-reflective notified prices. 13 Cover letter of the delegation (Appendix A to this document). 14 Schedule 1, National Energy Retail Rules.


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5

Ergon Retail supported setting notified prices based on expected standing offer prices in south

east Queensland, in line with the Government's UTP. However, Canegrowers, Canegrowers Isis,

CCIQ, Cotton Australia and QCOSS argued that notified prices should be set below expected

standing offer prices in south east Queensland. CCIQ and QCOSS argued that the QCA should

base notified prices somewhere between market contract prices and standing offer prices.

Cotton Australia acknowledged that the delegation specified that small customer prices should

be set at standing offer levels under the UTP, but argued that it would be more appropriate to

base prices on the average discounted offer in south east Queensland. Canegrowers Isis argued

that prices should be based on a weighted average of all prices available in south east

Queensland.

QCA position

Our final decision is to determine notified prices based on expected standing offer prices in south

east Queensland. The delegation's cover letter15 makes it clear that setting prices below expected

standing offer prices in south east Queensland, as suggested by some stakeholders, would be

inconsistent with the UTP.

In addition, market contracts generally have different terms and conditions to standard retail

contracts, so their prices are not directly comparable. Like notified prices, standing offer prices

in south east Queensland will apply to customers on standard retail contracts.

We have estimated the costs of supply for each retail tariff using an N+R cost build‐up approach,

where we treat the N (network cost) component as a pass‐through, and determine the R (energy

and retail cost) component.

2.2.2 Large business customers

As noted above, we have previously determined notified prices for large business customers

based on the lowest cost of supplying customers in regional Queensland. This approach has the

benefit of being more cost-reflective than an approach based on south east Queensland costs,

which supports the development of competition among retailers for large business customers in

the lower-cost areas of regional Queensland. It is also consistent with the requirement in the

delegation to consider basing the network cost component on Ergon Distribution's network

charges.

Ergon Distribution, Ergon Retail and Origin Energy supported this approach. Cotton Australia

supported basing all notified prices on south east Queensland costs.

QCA position

Consistent with the requirements in the Minister's delegation, and with previous determinations,

our final decision is to set notified prices for large business customers based on the lowest costs

of supply in regional Queensland, which is Ergon Distribution's east pricing zone, transmission

region one. We have estimated the costs of supply for each retail tariff using an N+R cost build‐

up approach. This is consistent with our approach to setting notified prices for residential and

small business customers, as discussed above. We consider the effect of our decision on

competition in Chapter 6.

15 See Appendix A.


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2.2.3 Metering services charges

While most customers who pay notified prices also pay metering services charges, under the

Electricity Act these charges cannot be included in notified prices.16 For this reason, all prices and

figures quoted in this document exclude metering services charges.

Metering services charges for customers on notified prices can be found on Ergon Retail's

website.17

16 Since 2015–16, the Australian Energy Regulator (AER) has classified metering charges as alternative control

services which are not included in network tariffs. Distributors recover these costs through ACS charges (or distribution non-network charges) that are calculated and levied separately to network tariffs. We consider that the reclassification of metering charges means that they now meet the definition of 'distribution non-network charges' in the Electricity Act. Distribution non-network charges cannot be included in notified prices (s. 90(3)(d) of the Electricity Act).

17 https://www.ergon.com.au/retail/residential/tariffs-and-prices/changes-to-your-bill/what-is-the-metering-services-charge.


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Queensland Competition Authority Network costs

7

3 NETWORK COSTS

A retailer incurs network costs when electricity is supplied to its customers. These costs are

associated with transporting electricity through the transmission and distribution networks and

account for around 50 per cent of the final cost of electricity for small customers.

As regulated monopoly businesses, Powerlink, Energex and Ergon Distribution earn regulated

revenues that are determined by the Australian Energy Regulator (AER). In addition to recovering

their own distribution network costs, Energex and Ergon Distribution pass Powerlink's

transmission network costs on to customers in network charges that are approved by the AER as

well.

This chapter sets out our decisions on the network charges to be used as the basis of notified

prices for 2016–17. In summary, we have decided to:

base the flat rate retail tariffs and controlled load retail tariffs for residential and small

business customers on Energex’s network tariff structures and prices (consistent with our

previous determinations)

base the time-of-use retail tariffs for residential and small business customers (tariffs 12A and

22A) on Ergon Distribution’s network tariff structures and Energex’s price levels (consistent

with our 2015–16 determination)

base the obsolete time-of-use retail tariff for small business customers (tariff 22) on Energex’s

network tariff structure and prices (consistent with our 2015–16 determination)

base the seasonal time-of-use demand retail tariffs for residential and small business

customers (tariffs 14 and 24) on Ergon Distribution’s network tariff structures and Energex’s

price levels (consistent with our 2015–16 determination)

base all retail tariffs for large business customers on Ergon Distribution’s network tariff

structures and prices (consistent with our previous determinations)

retain retail tariffs 41, 47 and 48.

3.1 Introduction

A retailer incurs network costs when electricity is supplied to its customers. Network costs are

the costs associated with transporting electricity through transmission and distribution

networks.

In the ‘Network plus Retail’ (N+R) cost build-up approach that we use to set notified prices, the

network cost component is treated as a pass-through. To determine the network cost

component to be passed through to retail customers, the QCA must decide:

(a) the level at which network charges should be set (Energex levels or Ergon Distribution

levels)

(b) the network tariff structure on which the network cost component should be based.

Network tariff structures can include, for example, combinations of fixed charges, demand

charges and usage charges.


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3.2 Network tariffs for residential, small business and unmetered supply customers

This section discusses our approach to setting the network cost components of retail tariffs for

residential, small business and unmetered supply customers (excluding street lighting

customers—see Section 3.3).

For the 2016–17 determination, we are only setting notified prices for regional Queensland; in

particular, the delegation requires that we consider:

for residential and small business customer retail tariffs (except tariffs 12A, 14, 22A and 24),

basing the network cost component on Energex network charges and tariff structures

for residential and small business customer time-of-use retail tariffs (tariffs 12A and 22A) and

time-of-use demand retail tariffs (tariffs 14 and 24), basing the network cost component on

Energex network charges, but using the relevant Ergon Distribution network tariff structures.

Adopting the approach proposed in the delegation would be consistent with our approach in the

2015–16 determination. Under this approach, the network cost component of each retail tariff

broadly reflects the costs of supplying customers in south east Queensland, but the network tariff

structures used as the basis for setting those retail tariffs vary with the network cost components

of:

flat rate retail tariffs (retail tariffs with usage charges that do not vary with the time and/or

level of consumption) based on Energex’s network tariff structures

time-of-use and time-of-use demand retail tariffs (retail tariffs with usage and other charge

rates that vary with the time and/or level of consumption) based on Ergon Distribution’s

network tariff structures.

This section explains our decision to continue with this approach in our 2016–17 determination.

We also explain our decision to continue to use Energex network tariff structures for the obsolete

time-of-use retail tariff for small business customers (tariff 22) and to retain tariff 41.

3.2.1 Energex or Ergon Distribution network price levels

In determining the network cost components of regulated retail tariffs, the first issue we must

consider is the level at which network charges should be set (Energex levels or Ergon Distribution

levels).

As discussed in Section 2.2.1, our decision is to base notified prices for residential and small

business customers on south east Queensland costs. Consistent with this decision, we will set

network charges to reflect Energex cost levels. Setting network charges at Energex cost levels

means that customers in regional Queensland will generally pay the same for network services

as customers in south east Queensland.

3.2.2 Energex or Ergon Distribution network tariff structures

The second issue we must consider is whether to use the network tariff structures of Energex or

Ergon Distribution.

There are some key differences between the Energex and Ergon Distribution network tariff

structures, including:

the proportion of costs recovered through fixed charges


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9

the approach to usage charge rates (e.g. flat usage rates versus three-part inclining block

tariffs)

the applicable time-of-use and demand charging periods (for example, different peak and off-

peak periods)

the methodology for calculating demand charges.

Further information on differences between the network tariff structures is provided in

Appendix D.

The delegation directs us to consider using Energex network tariff structures for the residential

and small business flat rate retail tariffs and controlled load tariffs, and Ergon Distribution

network tariff structures for the residential and small business time-of-use retail tariffs (tariffs

12A and 22A) and time-of-use demand retail tariffs (tariffs 14 and 24).

Consistent with our approach in the 2015–16 determination and with the delegation, we have

decided to continue to use a mix of Energex and Ergon Distribution network tariff structures as

the basis for setting retail tariffs. Ergon Retail, Toowoomba Regional Council, CCIQ, and the

Queensland Consumers’ Association supported this approach.

We consider that using Ergon Distribution’s network tariff structures for the time-of-use and

time-of-use demand retail tariffs (excluding tariff 22, which is an obsolete tariff) would be more

cost-reflective than using Energex’s network tariff structures. We also consider that it is more

important that time-of-use and time-of-use demand retail tariffs reflect Ergon Distribution’s

network tariffs structures, rather than flat rate retail tariffs, as the first-mentioned tariffs send

signals to customers about the costs to retailers that arise due to the time or level of electricity

consumption. As pointed out by the Queensland Productivity Commission (QPC), time-of-use

and time-of-use demand tariffs are more efficient than single rate and inclining block tariffs.18

The delegation also points out that using Ergon Distribution’s network tariff structures for time-

of-use and time-of-use demand retail tariffs would encourage customers to reduce consumption

during peak periods on Ergon Distribution’s network.

Ergon Distribution and Origin were both of the view that we should base all residential and small

business customer retail tariffs on Ergon Distribution’s network tariff structures, on the basis that

it would be a further step towards improving cost-reflectivity. However, this would result in a

change of network tariff structure for residential and small business flat rate retail tariffs, and

controlled load tariffs, as these tariffs were based on Energex’s network tariff structures in the

2015–16 determination. This change would have significant distributional impacts on the

customers who are on these tariffs, with lower-usage customers in particular likely to face

substantially higher bills.19 QCOSS did not support using Ergon Distribution’s network tariff

structure for the main residential flat rate retail tariff (tariff 11), as it considered that the change

in the network tariff structure would create confusion and impact adversely on smaller-usage

customers.

We also note that Ergon Distribution has acknowledged that its inclining block network tariffs

will, over time, need to be phased out in favour of network tariffs that better satisfy the pricing

principles in the National Electricity Rules (NER).20 This suggests that there may be some

uncertainty about the future of these network tariff structures. We consider it would be

18 Queensland Productivity Commission, Electricity Pricing Inquiry, draft report, February 2016, pp. 76–79. 19 See Appendix D for more information on the customer impacts. 20 Ergon Distribution, Tariff Structure Statement 2017–18 to 2019–20, November 2015, p. 36.


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10

preferable to have more certainty about future network tariff structures before making major

changes that would affect nearly all regional customers.

For the reasons above, we do not agree with the suggestion that we should adopt Ergon

Distribution’s network tariff structures for the flat rate retail tariffs and controlled load tariffs.

Tariff 22

Tariff 22 is an obsolete tariff that is based on an Energex network tariff structure. Consistent

with our 2015–16 determination, we will continue to make this tariff available to customers until

30 June 2017, when it will be replaced by tariff 22A (which is based on the Ergon Distribution

network tariff structure).21 Tariff 22 will also continue to be closed to new regional customers.

Customers may move to tariff 22A (or another retail tariff that suits their needs) earlier than 30

June 2017 if they choose.22

QCA position

Consistent with our draft decision, our final decision is to use:

Energex’s network tariff structures as the basis for setting the network cost components of

flat rate retail tariffs, tariff 22 and controlled load tariffs

Ergon Distribution’s network tariff structures as the basis for setting the network cost

components of time-of-use and time-of-use demand retail tariffs.

3.2.3 Adjusting Ergon Distribution network tariff structures to Energex price levels

As discussed, we have decided to use Ergon Distribution’s tariff structures as the basis for setting

time-of-use and time-of-use demand retail tariffs for residential and small business customers

(excluding tariff 22), while reducing the overall level of prices to Energex levels.

To adjust these network tariff structures to Energex price levels, we have decided to use the

same adjustment process as in our 2015–16 determination. This process involves adjusting:

the residential time-of-use retail tariff (tariff 12A) by adopting the Ergon Distribution usage

charges and reducing the Ergon Distribution fixed charge towards Energex’s price level (as far

as possible)

the small business time-of-use retail tariff (tariff 22A) by adopting the Energex fixed charge

and reducing the Ergon Distribution usage charges

the residential and small business time-of-use demand retail tariffs (tariffs 14 and 24) by

uniformly decreasing the Ergon Distribution fixed and usage charges.

We have adopted different adjustment approaches for the four tariffs to prevent our

adjustments resulting in adjusted network prices being set higher than the levels that may be

approved by the AER.

The only difference from our approach in 2015–16 is in the mechanics of adjusting the Ergon

Distribution network charges to align with Energex price levels. These changes are required due

to changes in data availability and reliability.

21 In our 2015–16 determination, we decided to make tariff 22 available to customers until 30 June 2017 to

mitigate customer impacts and address metering issues. 22 This is subject to customers having appropriate metering in place and meeting the terms and conditions of

their chosen retail tariff.


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11

Appendix D provides more information on the adjustment approach.

QCA position

Consistent with our draft decision, our final decision is to adjust:

the residential time-of-use retail tariff (tariff 12A) by adopting the Ergon Distribution usage

charges and reducing the Ergon Distribution fixed charge towards Energex’s price level (as far

as possible)

the small business time-of-use retail tariff (tariff 22A) by adopting the Energex fixed charge

and reducing the Ergon Distribution usage charges

the residential and small business time-of-use demand retail tariffs (tariffs 14 and 24) by

uniformly decreasing the Ergon Distribution fixed and usage charges.

3.2.4 New controlled load tariff

In the interim consultation paper, we noted that Ergon Distribution was proposing to introduce

a new controlled load tariff from 1 July 2016. If approved, this tariff would only have been

available in conjunction with the residential time-of-use demand tariff. Ergon Distribution has

subsequently advised that this tariff will not be introduced in 2016–17. Therefore, we have not

created a new retail controlled load tariff.

3.2.5 Removal of tariff 41

In the interim consultation paper, we indicated that we were considering removing tariff 41 on

the basis that Ergon Distribution does not have an equivalent network tariff available for small

business customers with this structure, and fewer than 300 customers are on this tariff.23 Tariff

41 is a low voltage demand tariff that has fixed, usage and demand charges and is based on an

Energex network tariff. While Energex designates this network tariff as a large business customer

network tariff, it is made available to small business customers on a voluntary basis.

Ergon Retail advised that its customers on this tariff would need to transition to other tariffs, and

considered that the tariff should be closed to new customers and phased out by 30 June 2017.

QCA position

Given that our approach is to use Energex tariff structures for flat rate tariffs and that the Energex

tariff is available to small business customers in south east Queensland, our decision is to retain

tariff 41.

3.2.6 Network tariffs and charges for 2016–17

Our final decision is to base regulated retail tariffs for residential, small business and unmetered

supply customers on:

Energex network tariffs and charges for tariffs 11, 20, 31, 33, 41 and 91

Energex network tariffs and charges for obsolete tariff 22, which will be available until 30 June

2017

calculated network tariffs and charges for retail tariffs 12A and 22A, which are based on Ergon

Distribution’s seasonal time-of-use network tariffs. To maintain the uniform tariff policy

23 Based on data from Ergon Retail.


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12

(UTP), the level of charges has been reduced to a level where regional customers will, on

average, pay the same as they would pay on tariffs 11 and 20

calculated network tariffs and charges for retail tariffs 14 and 24, which are based on Ergon

Distribution’s seasonal time-of-use demand network tariffs. As with tariffs 12A and 22A, the

level of charges has been reduced to a level where regional customers will on average pay

the same as they would pay on tariffs 11 and 20 in south east Queensland.

Our final decision on the network charges to apply to each retail tariff is presented in the

following tables. It should be noted that these tables are based on the draft network tariffs that

Ergon Distribution and Energex have provided to the AER. In the event that the final network

tariffs approved by the AER differ from those submitted by distributors, the QCA will consider

utilising a cost pass-through mechanism.

Table 2 Energex network charges for 2016–17 for retail tariffs 11, 20, 22 (obsolete), 31, 33, 41 and 91 (GST exclusive)

Retail tariff Energex network tariff

code

Fixed chargea c/day

Usage charge (peak) c/kWh

Usage charge (flat or off-

peak)

c/kWh

Demand charge

$/kW/month

Tariff 11—Residential (flat rate)

8400 50.200 11.624

Tariff 20—Business (flat rate)

8500 72.000 12.486

Tariff 22—Business (time-of-use, transitional)

8800 72.000 14.395 9.683

Tariff 31—Night rate (super economy)

9000 6.421

Tariff 33—Controlled supply (economy)

9100 9.686

Tariff 41—Low voltage (demand, obsolete)b

8300 532.100 2.056 24.351

Tariff 91— Unmetered 9600 10.298

a Charged per metering point.

b The kVA equivalent demand charge for tariff 41 is $21.860/kVA/month. A conversion factor of 0.8977 has been used, as advised by Energex.

Table 3 Calculated network charges for 2016–17 for retail tariffs 12A, 14, 22A and 24 (GST exclusive)

Retail tariff Fixed chargea c/day

Usage charge (peak)

c/kWh

Usage charge (flat or off-

peak)

c/kWh

Demand charge (peak)

$/kW/month

Demand charge (off-

peak)

$/kW/month

Tariff 12A—Residential (time-of-use)

61.375 38.375 7.558

Tariff 22A—Business (time-of-use)

72.000 30.462 10.236

Tariff 14—Residential (time-of-use demand)

22.525 3.386 52.885 9.636

Tariff 24—Business (time-of-use demand)

24.540 4.322 71.601 11.765



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3.3 Network tariffs for large business and street lighting customers

For the 2015–16 determination, we based retail tariffs for large business customers and street

lighting customers on the network tariffs and charges applying to Ergon Distribution’s east pricing

zone, transmission region one. We have decided to continue with this approach for 2016–17,

because it is consistent with our decision, discussed in Section 2.2.2, to set notified prices for

large business customers based on the lowest costs of supply in regional Queensland.

Submissions from Toowoomba Regional Council, Ergon Distribution and Ergon Retail supported

maintaining this approach for 2016–17. While Origin expressed similar support, it considered

that there was merit in transitioning large business prices to more cost-reflective levels to satisfy

the NER pricing principles. Cotton Australia did not support maintaining this approach and

considered that notified prices should be based on south east Queensland costs.

3.3.1 Tariffs 47 and 48

In its submission on the interim consultation paper, Ergon Distribution requested that we

consider amending the eligibility requirements for tariff 47 so that it is not available to new

customers from 1 July 2016. Ergon Distribution also proposed that we use different network

tariff(s) as the basis for tariff 48. Ergon Distribution proposed these changes because it intends

to phase out its Standard Access Customer (SAC) Large Demand High Voltage network tariff,

which underpins tariffs 47 and 48, in 2017–18.

As these changes were not canvassed in the interim consultation paper, our decision is to leave

the eligibility requirements for tariff 47 unchanged and to continue to base tariff 48 on the SAC

Large Demand High Voltage network tariff. We consider that any changes to tariff 48 in particular

should be the subject of more extensive consultation, given the potentially significant adverse

impacts on some customers.

We also note that the QPC, in its Electricity Pricing Inquiry draft report, considered that there was

not a strong case for allowing very large customers to continue to have access to notified prices.24

3.3.2 Network tariffs and charges for 2016–17

Our final decision is to continue to base retail tariffs for large business customers and street

lighting customers on the network tariffs and charges applying to Ergon Distribution’s east pricing

zone, transmission region one.

Our final decision on the network charges to apply to each retail tariff is presented in Table 4. It

should be noted that these tables are based on the draft network tariffs that Ergon Distribution

and Energex have provided to the AER. In the event that the final network tariffs approved by

the AER differ from those submitted by distributors, the QCA will consider utilising a cost pass-

through mechanism.

24 Queensland Productivity Commission, Electricity Pricing Inquiry, draft report, 3 February 2016, p. 169.


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Table 4 Ergon Distribution network charges for 2016–17 large business and street lighting customer retail tariffs (GST exclusive)

Retail tariff Ergon Distribution network tariff

codec

Fixed chargea c/day

Usage charge (peak)

c/kWh

Usage charge (flat or off-peak)

c/kWh


$/kW/month

Demand charge (flat/off-peak) $/kW/month

Tariff 44—over 100 MWh small (demand)

EDSTT1 4568.700 2.201 35.801

Tariff 45—over 100 MWh medium (demand)

EDMTT1 14751.500 2.283 28.422

Tariff 46—over 100 MWh large (demand)

EDLTT1 39607.000 2.467 25.257

Tariff 47—high voltage (demand)

EDHTT1 37183.400 2.078 23.257

Tariff 48—over 4 GWh high voltage (demand)

EDHTT1 37183.400 2.078 23.257

Tariff 50—seasonal time-of-use (demand)

ESTOUDCT1 3822.400 1.779 4.863 54.966 13.257

Tariff 71—street lightingb

EVUT1 0.700 19.445


b The fixed charge for street lighting applies to each lamp.

c Some Ergon Distribution network tariff codes have a ‘base’, ‘C’ or ‘X’ variant. The base code applies the relevant Alternative Control Service (ACS) regulated metering capital and non-capital charges; the ‘X’ code applies the relevant ACS regulated metering capital charge; and the ‘C’ code does not apply any ACS regulated metering charges.


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Queensland Competition Authority Energy costs

15

4 ENERGY COSTS

A retailer incurs energy costs when purchasing electricity to meet the electricity demand of its

customers. Energy costs can be split into three general categories:

(1) wholesale energy costs

(2) other energy costs

(a) Renewable Energy Target (RET) costs

(b) National Electricity Market (NEM) participation fees and ancillary services charges

(c) prudential capital costs

(3) energy losses.

As with previous determinations, we have determined energy costs based on advice from our

consultant, ACIL. ACIL has estimated that overall energy costs will increase for all customers in

2016–17, with increases driven primarily by increased wholesale energy costs and Large-scale

Renewable Energy Target (LRET) costs.

An overview of how each energy cost component was calculated is provided below. A more

detailed explanation appears in ACIL's report, which is available on our website.25

4.1 Wholesale energy costs

Retailers incur wholesale energy costs when purchasing electricity from the National Electricity

Market (NEM) to meet the electricity demand of their customers. The NEM is a volatile market

where prices are settled every half hour and can range from –$1000 per MWh to $14,000 per

MWh.26 Retailers use the following strategies to reduce price volatility risk:

pursuing a 'hedging strategy' by purchasing financial derivatives like swaps and options

entering long-term power purchase agreements with generators

investing in their own electricity generators.

In 2015–16, ACIL estimated wholesale energy costs using a hedging strategy approach. We

considered that ACIL's approach was transparent and best reflected the costs retailers incur when

purchasing electricity from the NEM. Hedging strategy approaches have been endorsed by the

Australian Energy Market Commission (AEMC) as best practice27 and have been adopted by other

Australian regulators.

Ergon Retail and QCOSS supported ACIL's hedging strategy approach. Origin Energy raised some

technical concerns with regard to ACIL's approach to estimating contract prices and generating

load profiles. Canegrowers argued that the QCA should base the wholesale energy cost

calculation on the Ergon load profile for all tariffs.

25 http://www.qca.org.au/Electricity/Regional-consumers/Reg-Electricity-Prices. 26 Minimum spot price is defined in clause 3.9.6(b) of the National Electricity Rules. The Market Price Cap is

published by the AEMC every February (http://www.aemc.gov.au/News-Center/What-s-New/Announcements/AEMC-publishes-the-Schedule-of-Reliability-Set-(4)).

27 AEMC, Final Report, Advice on best practice retail price methodology, 27 September 2013.


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http://www.aemc.gov.au/News-Center/What-s-New/Announcements/AEMC-publishes-the-Schedule-of-Reliability-Set-(4)

http://www.aemc.gov.au/News-Center/What-s-New/Announcements/AEMC-publishes-the-Schedule-of-Reliability-Set-(4)


16

Consistent with previous years, ACIL estimated wholesale energy costs using a hedging strategy

approach. ACIL has provided a detailed explanation of its calculation of wholesale energy costs in

chapter 4 of its report, and addressed issues raised in submissions related to its calculations in

chapter 3 of that report.

ACIL estimated that wholesale energy costs will increase for all retail tariffs. The overall increase

in prices has been driven by an increase in electricity demand from Queensland-based liquefied

natural gas (LNG) projects. The increased activity in LNG production has also resulted in higher

fuel costs for gas-fired generators. ACIL found that the increase in contracted gas prices has more

than doubled the cost of gas-fired generation compared to the beginning of 2015–16.28 Electricity

futures contract prices, which are used in retailer hedging strategies, have increased since the

draft determination, as can be seen in Figure 4 below.

Figure 4 Queensland base futures contract prices

Source: ASX energy data.

The latest electricity forecasts from the Australian Energy Market Operator (AEMO) show

electricity demand from LNG production increasing in the short term, and remaining high for the

remainder of the forecast period (see Figure 5 below).

28 ACIL, Estimated Energy Costs 2016–17 Retail Tariffs, 17 May 2016, p. 6.

$65

$70

$75

$80

$85

$/M

Wh

Draft Determination Post draft determination


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17

Figure 5 Historical and forecast Queensland annual electricity demand by sector

Source: Australian Energy Market Operator, National Electricity and Gas Forecasting (medium scenario).29

In addition to increases in demand and fuel costs, ACIL found that increased solar generation is

continuing to reduce daytime demand but has no effect on peak demand30, which is resulting in

the net system load profile (NSLP) becoming peakier and more expensive to hedge. Figure 6

below shows how the NSLP has become peakier over time.

Figure 6 Energex net system load profile

Note: The term 'relative MW' means the loads for each tariff have been scaled so that they sum to one. This removes differences in absolute scale between years, and preserves the relative shape of the profile.

Source: ACIL analysis.

29 Data available at http://forecasting.aemo.com.au/. 30 Peak demand generally occurs between 6:30 pm and 8:30 pm.

0

10

20

30

40

50

60

70

2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

TWh

Residential & commercial Manufacturing Other industries LNG

0.000

0.005

0.010

0.015

0.020

0.025

0.030

0.035

0.040

MW

(re

lati

ve)

2009-10 2010-11 2011-12 2012-13 2013-14 2014-15


201

http://forecasting.aemo.com.au/


18

As a result, ACIL estimated:

Wholesale energy costs for the Ergon Energy NSLP will increase by $9.99 per MWh compared

to 2015–16, which is slightly less than the increase in the Energex NSLP ($11.59 per MWh).

The outcomes are slightly different because the load profile of the Ergon Energy NSLP is less

peaky than the Energex NSLP.

Wholesale energy costs for controlled load tariffs will also increase. Tariff 31 will increase by

$6.21 per MWh compared to 2015–16, while tariff 33 will increase by $5.76 per MWh. The

difference in outcomes is due to the load profile for tariff 33 becoming flatter compared to

previous years, resulting in a smaller increase.

QCA position

We consider that ACIL's methodology adequately takes into account the issues raised in

submissions and is likely to produce the most reliable estimates of the efficient costs of supply.

Retaining the same approach for 2016–17 will also provide certainty to stakeholders.

We accept ACIL's advice on this matter and its wholesale energy cost estimates, which are

provided in Table 5. Consistent with the UTP31, the QCA will apply the Energex NSLP cost estimate

for residential, small business and unmetered tariffs.

Table 5 Estimated wholesale energy costs at the Queensland regional reference node for 2016–17

Settlement class Retail tariff $/MWh % change from 2015–16

Energex NSLP and unmetered supply

11, 12A, 14, 20, 22, 22A, 24, 41, 91

$75.32 18.2%

Energex Controlled Load 9000 31 $42.31 17.2%

Energex Controlled Load 9100 33 $56.15 11.4%

Ergon Energy NSLP and streetlights

44, 45, 46, 47, 48, 50, 71

$65.69 17.9%

Source: ACIL, Estimated Energy Costs for 2016–17, 17 May 2016, p. 22.

4.2 Other energy costs

In addition to wholesale energy costs, we must account for other energy costs that retailers incur

when purchasing electricity from the NEM, which are:

Renewable Energy Target (RET) costs

NEM participation fees and ancillary services charges

prudential capital costs.

4.2.1 Renewable Energy Target costs

The RET scheme, comprised of the Large-scale Renewable Energy Target (LRET) and Small-scale

Renewable Energy Scheme (SRES), provides incentives for the electricity sector to increase

generation from renewable sources and reduce greenhouse gas emissions. The costs of these

31 See section 2.2.1 for further details.


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incentives are paid by retailers who are required to purchase large-scale generation certificates

(LGCs) and small-scale technology certificates (STCs).

LRET costs

The LRET sets annual targets for the amount of electricity that must be sourced from large-scale

renewable energy projects like wind farms, with an ultimate target of generating 33,000 GWh of

electricity from large-scale renewable sources in 2020.32 Retailers must purchase a set number of

LGCs according to the amount of electricity they have sold to customers in the calendar year.

For the 2015–16 final determination, ACIL estimated LRET costs using a market-based approach.

This approach based LGC prices on forward prices for certificates published by the Australian

Financial Markets Association (AFMA). ACIL used the 2015 renewable power percentage (RPP) for

the first half of the pricing period, and the latest published 2016 LRET target for the second half

of the pricing period.

Ergon Retail supported calculating LRET costs using a market-based approach. However, it

highlighted that the 2014 RET review had suppressed LRET prices during the review period and

considered that ACIL's approach, whereby retailers purchase LGCs over a two-year period, did

not reflect retailer behaviour during the review period. Canegrowers considered that the LRET

allowance should be reduced to reflect the efficient costs of producing large-scale renewable

energy.

ACIL forecast LRET costs using an approach consistent with previous years. A detailed explanation

of its calculations is provided in chapter 4 of its report prepared for the QCA, along with

information on LGC prices and assumptions underpinning the implied RPPs used. Chapter 3 of

ACIL's report addresses issues raised in submissions. ACIL examined market prices over a number

of years and considers that its market-based approach, whereby retailers purchase LGCs over a

two-year period to satisfy their obligations, provides the best estimate of LRET costs for the

purposes of setting notified prices for 2016–17.

ACIL's report shows that there has been a significant increase in forward LGC prices since the

revised 33,000 GWh LRET target was implemented in June 2015 (see Figure 7 below). ACIL

explained that this is due to a hiatus in new renewable energy project construction. As a result,

ACIL forecast that LRET costs for 2016–17 will be $7.83 per MWh for all retail tariffs, an increase

of $3.45 per MWh compared to 2015–16.

32 Section 40, Renewable Energy (Electricity) Act 2000.


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Figure 7 Large-scale Generation Certificate (LGC) prices

Source: AFMA and ACIL analysis.

QCA position

We remain of the view that ACIL's market-based approach, using the most up-to-date targets and

price information published by AFMA, is likely to produce the most reliable estimate of LRET costs

to be incurred by retailers in 2016–17. Retaining a consistent approach for 2016–17 will also

provide certainty to stakeholders.

We accept ACIL's advice on this matter and its LRET cost estimates, which are outlined in Table 6.

SRES costs

The SRES provides an incentive for individuals and small businesses to install eligible small-scale

renewable energy systems such as solar panel systems, small-scale wind systems, small-scale

hydro systems, solar hot water systems and heat pumps. Customers installing these systems

receive STCs, which retailers must purchase according to the amount of electricity they have sold

to those customers.

For the 2015–16 determination, ACIL estimated SRES costs using the final 2015

small-scale technology percentage (STP) target for the first half of the pricing period and the latest

available non-binding 2016 STP target for the second half of the pricing period. STC prices were

based on the clearing house price.

ACIL estimated SRES costs using the same approach as 2015–16. It forecast a decrease in SRES

costs of $0.60 per MWh compared to 2015–16. This estimate is based on the final 2016 STP target

and the latest available non-binding STP target for 2017.33

33 The final STP for 2016 is lower the non-binding STP used in the 2015–16 final determination. We consider

this difference as part of our cost pass-through mechanism discussed in section 6.2.

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QCA position

We remain of the view that ACIL's approach is likely to produce the most reliable estimate of SRES

costs to be incurred by retailers in 2016–17. Retaining a consistent approach for

2016–17 will also provide certainty to stakeholders.

We accept ACIL's advice on this matter and its SRES cost estimates, which are outlined in Table 6.

4.2.2 NEM participation fees and ancillary services charges

NEM participation fees are levied on retailers by the AEMO to cover the costs of operating the

NEM and funding Energy Consumers Australia. Ancillary services charges cover the costs of the

services used by AEMO to manage power system safety, security and reliability.

As with the 2015–16 determination, ACIL used AEMO budget and fee projections to estimate

NEM participation fees for 2016–17. Its ancillary services charges were based on the average

historical costs observed over the preceding 52 weeks.

QCA position

We remain of the view that ACIL's approach is likely to produce the most reliable estimate of NEM

participation and ancillary services costs to be incurred by retailers in 2016–17. Retaining a

consistent approach for 2016–17 will also provide certainty to stakeholders.

We accept ACIL's advice on this matter and its cost estimates, which are outlined in Table 6.

4.2.3 Prudential capital costs

Prudential capital costs are the costs a retailer incurs to provide financial guarantees to AEMO

and to lodge initial margins with hedge providers for futures contracts. These costs must be

accounted for, as futures contracts are relied upon to derive wholesale energy cost estimates.

In the 2015–16 determination, prudential capital costs were considered as part of retail operating

costs, as they were implicitly included in the retail operating cost benchmark we used. However,

as discussed in section 2.3.3 of ACIL's report on retail costs, these costs vary according to the

amount of electricity being purchased by the retailer, as well as the level of volatility in the

electricity market. As such, ACIL considered they should be included in the energy cost allowance.

To avoid double counting, prudential costs have been excluded from the retail cost allowance.

QCOSS supported the QCA's approach to account for prudential capital costs as part of the energy

cost allowance, provided these costs were separated out from retail operating costs.

Canegrowers supported the methodology for estimating prudential operating costs but argued

they should be based on costs for the Ergon NSLP.

As with the 2014–15 determination, ACIL calculated prudential capital costs for 2016–17 in line

with the latest published AEMO requirements and margin requirements for trading in the futures

market.

QCA position

We remain of the view that ACIL's approach is likely to produce the most reliable estimate of

prudential capital costs to be incurred by retailers in 2016–17.

ACIL considered the issues raised by stakeholders. As discussed in section 2.3.3 of ACIL's report

on retail costs, prudential costs were not included within the retail cost allowance, so they were

not double counted. However, ACIL calculated prudential costs based on the Energex NSLP. We


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consider this appropriate, as under the Government's UTP34 most regional customers will pay

notified prices based on energy costs in south east Queensland.

We accept ACIL's advice on this matter and its prudential capital cost estimates, which are

outlined in Table 6.

4.2.4 Summary of other energy costs for 2016–17

Table 6 sets out other energy costs for 2016–17, which will be added to the wholesale energy

cost components for all retail tariffs.

Table 6 Other energy costs (excluding losses)—all retail tariffs

Cost component $/MWh % change from 2015–16

LRET $7.83 78.8%

SRES $3.74 -13.8%

NEM fees $0.48 2.1%

Ancillary services $0.33 -8.3%

Prudential capital $0.99 naa

Total $13.37 40.0%b

a Prudential capital costs were considered as part of the retail operating cost allowance in 2015–16.

b As other energy costs in 2016–17 includes an additional allowance for prudential capital costs, the percentage change between 2015–16 and 2016–17 is greater than the sum of changes in each individual component of other energy costs.

Note: Totals may not add due to rounding.

Source: ACIL, Estimated Energy Costs for 2016–17, 17 May 2016, p. 26-29.

4.3 Energy losses

Some electricity is lost when it is transported across transmission and distribution networks. As a

result, retailers must purchase sufficient electricity to supply their customers' load and allow for

losses. As with previous determinations, ACIL has accounted for these losses by applying

transmission and distribution loss factors published by AEMO in a manner that aligns with AEMO's

settlement process.

QCA position

We are satisfied with ACIL's approach and accept its loss factor calculations, which are outlined

in Table 7. These losses are based on AEMO's 2016–17 published loss factors.

4.4 Total energy cost allowances for 2016–17

Table 7 summarises energy cost allowances for each retail tariff for 2016–17.

34 See section 2.2.1 for further details.


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Table 7 Total energy cost allowances for 2016–17

Settlement class Retail tariff

Wholesale energy

Other energya

Energy losses

Total energy allowance

Change from

2015–16b

$/MWh $/MWh % $/MWh c/kWh %

Energex NSLP and unmetered supply

11, 12A, 14, 20, 22, 22A, 24, 41, 91

$75.32 $13.37 6.5% $94.45 9.445 21.0%

Energex Controlled Load 9000

31 $42.31 $13.37 6.5% $59.30 5.930 22.0%

Energex Controlled Load 9100

33 $56.15 $13.37 6.5% $74.04 7.404 16.0%

Ergon Energy NSLP—small, medium and large demand and streetlights

44, 45, 46, 50, 71

$65.69 $13.37 12.0% $88.55 8.855 20.9%

Ergon Energy NSLP—high voltage demand and customers over 4 GWh

47, 48 $65.69 $13.37 5.2% $83.17 8.317 19.6%

a Other energy costs include an allowance for prudential capital costs. Prudential costs were considered as part of the retail operating cost allowance in 2015–16.

b As other energy costs in 2016–17 include an additional allowance for prudential capital costs, the percentage change between 2015–16 and 2016–17 is greater than the sum of changes in each individual component of energy costs.


Source: ACIL, Estimated Energy Costs for 2016–17, 17 May 2016, p. 31.


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Queensland Competition Authority Retail costs

24

5 RETAIL COSTS

The second element in the N+R approach, the retail costs component (R), includes retail operating

costs and a retail margin.

In previous decisions, we benchmarked other regulatory decisions to set retail operating costs and

margins. However, we consider it may no longer be appropriate to continue with this approach,

given that many comparable jurisdictions (including NSW and South Australia) have removed

retail price regulation in recent years. We consider it is timely to review these cost components

and have engaged ACIL to undertake a comprehensive review of retail costs based on market

observations and confidential data supplied by electricity retailers.

In summary, we have decided to:

adopt separate retail cost allowances for residential, small business, large business and very

large business customer tariffs

estimate total retail cost allowances for residential and small business customer tariffs based

on benchmarking observations, applied as fixed and variable components

for large and very large business customer tariffs, maintain the 2015–16 retail cost allowances

in real terms.

5.1 Overview

Retail costs include retail operating costs (ROC) and a retail margin.

ROC are the costs associated with services provided by a retailer to its customers, which typically

include customer administration, call centres, corporate overheads, billing and revenue

collection, IT systems, regulatory compliance, and customer acquisition and retention costs

(CARC).

The retail margin represents the return to investors for retailers' exposure to systematic risks

associated with providing retail electricity services. The margin can also include other costs

incurred by retailers, such as depreciation, amortisation, interest payments and tax expenses.

In previous determinations, we estimated allowances for ROC based on publicly reported data

and benchmark observations of other regulatory decisions, predominantly those of IPART. For

the retail margin, we applied an allowance of 5.7 per cent of total costs, which was based on the

retail margin adopted by IPART in its 2013–16 decision on regulated retail electricity prices in

NSW.35

Notwithstanding retailers' preference to maintain our previous approach, we consider it is no

longer preferable to rely on benchmarking of other regulators' decisions to estimate retail costs,

given that many comparable jurisdictions (including NSW and South Australia) have removed

retail price regulation in recent years. Reliance on other regulatory decisions also generates

circularity, which will lead to regulatory error over time. For these reasons, we have conducted

a comprehensive review of this cost component for 2016–17.

35 IPART, Review of regulated retail prices and charges for electricity from 1 July 2013 to 30 June 2016, June

2013, chapters 7 and 8.


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We engaged ACIL to provide advice on efficient retail costs for our 2016–17 determination. As a

first step, ACIL prepared a methodology paper outlining its proposed approach, which we

released along with our interim consultation paper in December 2015. ACIL also produced a

preliminary report, released with our draft determination in March 2016, and a final report in

May 2016, released with this final determination.

Submissions

Consumer groups (QCOSS and the Queensland Consumers Association) supported a

comprehensive review of retail operating costs and margins. QCOSS noted:

It is timely to undertake a more thorough assessment of these costs as the QCA had previously

used a 2013 IPART estimate as the benchmark. The Victorian market has been deregulated since

2009 and prices in NSW and South Australia have been deregulated more recently. Tariffs and

retailers’ cost structures will have changed since 2013 as retail markets become more mature.36

In contrast, Origin Energy considered the QCA's existing approach to estimating retail costs was

sufficient, if augmented by benchmarking against actual retailer data:

Origin’s preferred approach to determine a representative retailer's costs is to use the current

Queensland retail operating cost benchmark and to escalate this allowance on an annual basis. To

give the QCA confidence in its own benchmark, Origin believes the QCA can construct an indicative

retail operating cost for a representative retailer based on indicative data provided by retailers.37

Ergon Retail also preferred to largely retain the existing approach:

EEQ supports the continuation of the benchmarking approach employed in 2015–16. As ACIL Allen

has clearly stated the intention to use both a benchmarking and bottom-up approach, EEQ

requests the QCA give consideration to the continuing evolution of the regulatory and market

environment. This should include recognition of the characteristics of the retail electricity supply

to regional Queensland when setting prices for 2016–17 and subsequent periods.38

Both Origin and Ergon Retail acknowledged the problems in relying solely on bottom-up retailer

data due to different cost allocation approaches and cost categorisation. Origin noted:

Origin believes that relying on data provided by retailers to determine an appropriate retailer

operating cost is problematic as retailers have different accounting methodologies and how they

allocate costs to electricity and gas customers [sic].

…

We thus believe a benchmarking approach with some comparison to actual costs to assure validity

is the most effective mechanism to determine these costs.39

Similarly, Ergon Retail submitted:

EEQ generally supports ACIL Allen’s approach to estimating retail margin. EEQ does however

acknowledge, and agree with the concerns raised by other market participants, that a bottom-up

approach may have some practical barriers to being an effective method of estimating ROC and

margin. EEQ is also concerned that relying too heavily on a bottom-up methodology for estimating

36 QCOSS, submission to the QCA interim consultation paper, Regulated retail electricity prices 2016–17 p. 4. 37 Origin Energy, submission to the QCA interim consultation paper, Regulated retail electricity prices 2016–17,

29 January 2016, p. 3. 38 Ergon Energy Queensland, submission to the QCA interim consultation paper, Regulated retail electricity

prices 2016–17, 20 January 2016, p. 7. 39 Origin Energy, submission to the QCA interim consultation paper, Regulated retail electricity prices 2016–17,

29 January 2016, p. 3.


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ROC may distort the estimation of efficient costs. This is true for ROC allowances for both small

and large customers.40

With regard to the retail margin component of retail costs, Origin supported a retail margin based

on a percentage of total costs as previously adopted. Origin considered a margin of at least 5.7

per cent is appropriate.41

The Queensland Consumers Association questioned how the cost of capital would be calculated

and included in any estimates of retail costs and margin. We note that, while this was a

component of IPART's assessment of the retail margin, ACIL's benchmarking approach for 2016–

17 does not hinge on estimates of the cost of capital.42

In response to the draft determination, COTA Queensland supported the new approach to retail

costs. In contrast, CCIQ considered that the QCA should return to the previous approach to

estimating retail costs.

QCOSS and the Queensland Consumer's Association suggested that the benchmark retail cost

values should be derived based on the weighted average of retail costs, weighted toward the

most prominent retailers, by market share. We have considered this proposal and addressed this

matter in section 5.4.2.

The Minister lodged a submission raising concerns about price impacts on small business

customers. The Minister requested that the QCA consider a transitional arrangement for the

updated retail cost estimates for small business customers on the basis that the estimates

represent a step change and will:

…result in a significant price increase at a time when they [small business customers] could

reasonably have expected a more stable outcome.43

This issue is addressed in section 5.6.

Some stakeholders raised specific methodology-related issues regarding ACIL's analysis, which

have been addressed in ACIL's final report. Other issues raised in submissions—and QCA

responses where appropriate—are set out in Appendix J.

5.2 Approach to estimating retail costs for 2016–17

We have considered ACIL's advice and stakeholder feedback when making our final decisions.

ACIL used a combination of bottom-up and benchmarking methods to estimate retail costs,

informed by analysis of publicly available data, observed retail market offers, and detailed

confidential information provided by retailers.

ACIL analysed competitive retail market offers available across several competitive jurisdictions

to derive the implied level of retail costs incurred by retailers. This analysis was conducted on

both flat rate (non-time-of-use) residential tariff offers, and flat rate small business tariff offers.

40 Ergon Energy Queensland, submission to the QCA interim consultation paper, Regulated retail electricity

prices 2016–17, 20 January 2016, p. 10. 41 Origin Energy, submission to the QCA interim consultation paper, Regulated retail electricity prices 2016–17,

29 January 2016, p. 4. 42 Discount rates, using a weighted average cost of capital methodology, are however necessary for estimating

the time value of money associated with amortising discounts (see, ACIL's final report, May 2016), cost pass-through and some components of wholesale energy purchase costs.

43 Minister for Energy and Water Supply, submission to the QCA draft determination, Regulated retail electricity prices 2016–17, 3 May 2016.


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ACIL estimated the retail costs in each market offer by deconstructing the components of retail

tariffs, and benchmarking the retailer costs. It started with total average customer bills based on

retailer market offers, before deducting network costs and estimated energy purchase costs. The

residual amount reflects the total retail cost component of each tariff.

ACIL normalised the data for known cost differences between jurisdictions, for example, costs

associated with state-based energy efficiency schemes, and the estimated higher costs of smart

metering in Victoria. This normalisation process produced retail cost observations that, as far as

possible, can be compared on a like-for-like basis across retailers and distribution regions.44

While ACIL was engaged to estimate retail costs for small, large and very large business

customers, it was not possible to benchmark competitive market prices available to large and

very large businesses, as retailers tend to develop tailored offers for these customers. As a result,

no useful information is available on competitive market prices for these segments. Our

considerations of retail costs for large and very large business customers are set out at section

5.7.

Nonetheless, significant data is available on market offer prices to residential and small business

customers, which has allowed ACIL to perform useful benchmarking analysis in these market

segments.

To support ACIL's benchmarking analysis, the QCA issued formal information requests under the

Electricity Act to retailers operating in regional Queensland, requiring them to supply cost data.

This data is commercially sensitive and cannot be reproduced here.

The information provided by retailers was not sufficiently robust for ACIL to use it as the primary

basis for estimating efficient retail costs. The data was of varying quality and completeness' and

highlighted significant differences in the way retailers categorise costs. This outcome was not

unexpected and confirms our and ACIL's view that the benchmarking approach should be the

primary method of establishing efficient retail costs, with the bottom-up assessment used to test

the reasonableness of the benchmark market observations.

5.3 ACIL's analysis—residential and small business tariffs

5.3.1 Market data benchmarking

In summary, ACIL's analysis indicates that:

Average total retail costs for residential retail tariffs are close to the QCA's existing allowance.

However, retailers appear to recover more of these costs from the variable component of

retail tariffs than previously assumed.

Average total retail costs are higher for small business customers than for residential

customers. As is the case for residential tariffs, the market data indicates that retailers recover

a greater proportion of retail costs from the variable component of small business tariffs,

compared to our previous assumptions.

There are significant differences in how retailers allocate retail costs between fixed and

variable components. This also differs across customer tariff classes. For example, the data

indicates that the proportion of retail costs that are recovered through the variable

44 For a comprehensive explanation of ACIL's methodology, please see its methodology paper (December

2015), preliminary report (March 2016) and final report (May 2016), which are available on the QCA website: www.qca.org.au.


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28

component is higher in the case of small business tariffs than in the case of residential

customer tariffs.

Residential customers

Figure 8 illustrates the total retail costs derived from residential tariff observations, and the

allocations between fixed and variable components by retailer, based on an average usage of

4,640 kWh per year.45

Figure 8 Benchmark average total retail costs by retailer—residential customers

Note: Assumes average annual consumption of 4,640 kWh.

Based on this analysis, the total average retail cost ranges from $195 to $308 per customer per

year, with the majority of observations falling between around $200 and $230 per year. Across

the entire sample of observations, the average total retail cost component is $232 per year. This

is similar to the equivalent total allowance in the QCA's 2015–16 determination of $246.46

The fixed component of total retail costs ranges from $92 to $168 per customer per year, and the

variable component from 0.67 to 3.74 cents per kWh.

Small business customers

Figure 9 illustrates the total retail costs derived from small business tariff observations, and the

allocations between fixed and variable components by retailer, based on an average usage of

16,370 kWh per year.47

45 This represents the average usage in 2014–15 for tariff 11 customers, as advised by Energex. 46 Based on the total retail operating costs, and margin costs incurred by a tariff 11 customer consuming 4,640

kWh per year, consistent with ACIL's average usage assumptions. 47 This represents the average usage in 2014–15 for tariff 20 customers, as advised by Energex.

47% 75% 84% 54% 54% 44% 51% 60% 55% 44%

53%

25%

16%

46% 46%

56%

49%

40%45%

56%

$195.06 $198.03 $198.83 $215.00 $218.79 $222.74 $227.61

$249.84

$285.84

$308.15

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Figure 9 Benchmark average total retail costs by retailer—small business customers

Note: Assumes average annual consumption of 16,370 kWh.

Based on this analysis, the total average retail cost ranges from $408 to $781 per customer per

year. Across the complete sample of observations, the average total retail cost component is

$604 per year. The fixed component of total retail costs ranges from $130 to $242 per customer

per year, and the variable component from 1.26 to 3.62 cents per kWh.

This analysis indicates that serving customers on small business tariffs carries higher retail costs

than serving residential customers, on average. Possible reasons for this cost difference include:

different customer risk profiles and potentially a greater likelihood of default for small

business customers—as a result, retailers may require a higher return on their small business

customers

the need for different marketing approaches and customer acquisition and retention

strategies—for example, small businesses may be 'stickier', which might require retailers to

adopt more intensive and costly marketing approaches to win new customers

greater use of manual processes and more individual contact with small business customers

compared to residential customers.

The analysis also suggests that retailers recover a greater proportion of retail costs through

variable charges from small business customers, compared to residential customers. This is not

unexpected, as small businesses typically have a higher usage than residential customers, which

means the fixed component tends to be a smaller proportion of the overall bill than it is for

residential customers.

5.3.2 QCA position

ACIL's analysis presents a range of benchmark retail cost allowances that could be adopted, along

with approaches for allocating these costs to fixed and variable tariff components. Based on

ACIL's analysis, we have adopted the following approach:

49% 51% 40% 27% 30% 38% 31% 20% 21% 24%

51%

49%

60%

73%70%

62% 69%

80% 79%76%

$407.86

$478.47 $484.63 $488.86 $498.48

$546.18

$690.40 $719.26

$746.94 $780.69

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(1) Establish an efficient total retail cost amount (inclusive of retail operating costs and

margin), based on ACIL's recommended range of benchmark retail costs.

(2) Determine how the total efficient retail cost allowance should be allocated to the fixed

and variable components of retail tariffs, based on ACIL's analysis of competitive market

data.

(3) Assign a retail cost allowance, and fixed/variable allocation assumption to each regulated

retail tariff.

This approach differs from our previous methodology, and that used by IPART in its 2013–16

determination. However, we consider it is a robust and transparent approach, as it relies heavily

on outcomes observed in competitive retail markets.

Our approach means that the retail margin cannot be isolated from any other component of the

overall total retail cost. However, we do not consider it necessary to estimate an efficient retail

margin, or any other discrete retail cost component. Rather, our approach focuses on estimating

an efficient total level of retail costs, which implicitly includes some retail margin, portions of

which are recovered through fixed and variable charges. The relationship between total retail

costs and the implied retail margin is further explained in ACIL's final report.48

Our approach also means that variable retail costs are recovered as a percentage of underlying

variable costs, similar to the way the retail margin was applied in previous years. The reasons for

this approach, and how it is used to derive variable retail costs, is explained further in Appendix J.

5.4 Determining efficient total retail cost allowances—residential and small business tariffs

ACIL's analysis produced a range of potential efficient total retail cost allowances based on market

data. However, we need to determine point estimates from this data to establish efficient

benchmark retail cost allowances to apply to each regulated retail tariff.

5.4.1 Representative retailer characteristics

We have previously applied a ‘representative retailer’ model when considering retail cost

allowances. This approach established a hypothetical retail entity with specific characteristics,

which could be used to inform our decision on the efficient level of costs. The assumption was

that certain business characteristics, such as scale and integration, are likely to influence overall

retail costs.

However, it is not clear that the representative retailer concept remains useful when establishing

efficient levels of retail costs, for two reasons. First, very few retailers have the characteristics of

the QCA's representative retailer, and benchmarking the costs incurred by these businesses only

is therefore unlikely to deliver robust results. Second, as illustrated in Figures 8 and 9, ACIL's

analysis does not suggest any clear relationship between the overall level of retail costs and

retailer characteristics, particularly in terms of scale. In fact, some of the smaller retailers appear

to have lower retail costs than some larger incumbents.

For these reasons, we do not consider it necessary to strictly observe the previous definition of a

'representative retailer' when determining efficient retail cost allowances. Instead, we consider

it appropriate to include the entire sample of observations from ACIL's analysis, rather than

48 ACIL, Regulated retail prices for 2016-17: Estimating the efficient retailer costs, final report, 13 May 2016.


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limiting our analysis to observations from those retailers that satisfy our definition of a

'representative retailer'.

5.4.2 Total retail cost allowances

In the draft decision we proposed using the simple average of the derived retail costs from ACIL's

market observations to estimate efficient total retail cost allowances for serving small customers.

In response to the draft determination, consumer groups suggested that the retail cost

allowances should be derived based on the average cost weighted by the number of customers

served by each retailer (i.e. market share). ACIL modelled this approach and found that the

difference in the overall retail cost for an average customer is negligible. However, the weighted-

average approach results in a slightly higher fixed component for residential tariffs and a slightly

higher variable component for small business tariffs. It should be noted that ACIL's analysis was

based on a number of assumptions regarding retailer market shares, due to the lack of a complete

publicly-available data set.

Table 8 compares the retail cost estimates based on simple averages (as used in the draft

determination) with ACIL's market share weighted-average estimates.

Table 8 Comparison of simple average and market share weighted-average retail cost estimates

Customer class Simple average Weighted-average

Fixed charge ($/year)

Variable charge

(c/kWh)

Total retail cost ($/year)

Fixed charge ($/year)

Variable charge

(c/kWh)

Total retail cost

($/year)

Residential 127.93 2.25 232.21 130.50 2.21 233.04

Small business 181.56 2.58 603.79 175.21 2.62 604.10

Notes: Based on average annual consumption in 2014–15 of 4,640 kWh for residential tariffs and 16,370 kWh for small business tariffs, as advised by Energex. Totals may not add up due to rounding.

The suggestion to weight retail cost observations by customer numbers appears to be based on

the assumption of an inverse relationship between retailer size and total retail costs. If this

assumption is true, weighting the observations by market share would be expected to produce

retail cost estimates that are lower than the simple average outcomes. However, this is not the

case, as illustrated in Table 8 above. In addition, as noted in section 5.4.1, ACIL's benchmarking

does not reveal any clear relationship between retail costs and retailer size (see Figures 8 and 9).

Using a weighting approach also has other limitations. Firstly, accurately weighting observations

by retailer market share requires data that is not publicly available in all jurisdictions. Relying on

data that is not publicly available results in a less transparent methodology, which is contrary to

the requests of consumer groups for improved transparency around the modelling approach.

Secondly, it adds complexity and may result in the need to re-estimate retail costs in response to

any significant changes in market shares.

For these reasons, we remain of the view that using the simple average of all observations is an

appropriate method for determining point estimates from the benchmarking observations, for

this determination.

ACIL's analysis reveals there is a marked difference between the average retail costs of serving

small business and residential customers. We consider this difference is sufficient to warrant


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separate retail cost allowances. This means that typical small business customers will pay a higher

retail cost than typical residential customers on average, compared to 2015–16.

Inflating retail costs to 2016–17 values

ACIL's market observations reflect retail costs from 2015–16 prices. As a result, we need to

consider whether those values should be indexed to 2016–17 dollar terms.

ACIL has proposed that the fixed retail costs be held at the 2015–16 level for 2016–17. ACIL

formed this view after reviewing confidential information provided by retailers, and published

financial results, which suggest that that the expected growth in wages and materials costs in

2016–17 appears to be offset by expected productivity improvements.

No stakeholders commented on this matter.

Our final decision is to accept ACIL's advice that the 2015–16 benchmark retail costs should be

applied without escalation in 2016–17 notified prices. We will need to revisit this issue in the

future (discussed in section 5.9).

5.4.3 QCA position

Our final decision is to establish two separate retail cost allowances to reflect the estimated

efficient costs of supplying residential and small business customers, based on the averages of

ACIL's benchmarking observations. Table 9 sets out the total retail cost allowances for residential

and small business customer tariffs for 2016–17. These are based on the simple average of market

observations derived from ACIL's benchmarking analysis, summarised in Figures 8 and 9.

Table 9 Benchmark average retail costs—residential and small business customers

Customer class Total retail costs ($/annum)

Residential $232.21

Small business $603.79

Note: Based on average annual consumption of 4,640 kWh for residential tariffs and 16,370 kWh for small business tariffs. These averages represent averages across the entire data samples, and do not represent averages of the values depicted in Figures 8 and 9.

5.5 Determining fixed and variable retail cost components—residential and small business tariffs

Having determined an aggregate retail cost amount based on an average level of consumption,

we need to consider whether these costs should be recovered through fixed or variable charges,

or a combination of both.

Generally, the principle of cost reflectivity informs the decision on where the retail cost

allowances should apply in each tariff. If retail costs are mostly fixed, they should generally be

applied to the fixed tariff component; if they are mostly variable (they change with the level of

usage), they should generally apply to the variable tariff components. In previous

determinations, we allocated the retail operating costs allowances to the fixed component of

retail tariffs only, as we had no strong evidence to conclude that these costs varied with energy

usage. The retail margin was applied as a percentage of total costs, which means it had a fixed

and variable component.

Stakeholders expressed mixed views on how retail costs should be allocated between fixed and

variable components. In response to the interim consultation paper, the Queensland Consumers

Association submitted:


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The Association emphasises the need for these to be accurately and fairly allocated given that they

have major impacts on the bills of different types of consumers and on incentives to change

consumption.

In this regard the Association requests that the review of ROC establish the extend [sic] to which

any significant retail costs, for example financing costs, are volume related and take these into

account when deciding whether to continue to regard all retails costs as fixed and to add them to

the daily charge. 49

In contrast, Toowoomba Regional Council considered that:

…the [retail operating costs] should be a fixed rate for each account and should not be linked with

consumption and hence the variable component. 50

Ergon Retail also considered the majority of retail costs are fixed, stating:

EEQ supports the principle of cost reflectivity, in the application of ROC, to fixed and variable

charges. In EEQ’s view, a majority of the costs included in the QCA’s definition of [retail operating

costs] represent fixed charges. Applying the ROC to the fixed component of notified prices is likely

to be the most appropriate approach. However, consideration should be given to the impact of

fixed charges on customers with low usage, in particular, those who are vulnerable or experiencing

financial hardship. 51

Ergon Retail also noted, in the context of estimating the retail margin, that amortisation and

depreciation should be captured in the fixed retail cost component, rather than the variable

(margin) component. It noted:

Many retailers are reducing the number of acquired assets and instead using service arrangement

for their systems and required assets (e.g. IT systems, buildings, etc). The reclassification of

depreciation and amortisation expenses from retail margin to ROC will assist with future

benchmarking process. 52

Origin Energy also considered that the fixed component should be higher, stating:

Origin does not agree with the proposed rebalancing of the fixed and variable components of the

retail tariff. It does not reflect a true allocation of costs to customers in Queensland and it may

lead to the cross subsidisation between customer segments as retailers attempt to recover fixed

costs.53

The preference for higher fixed charges among retailers is understandable, as it provides greater

revenue certainty, particularly when consumption is declining. It is also understandable that large

customers would prefer a fully fixed retail cost allowance, as this means retail costs would likely

represent a relatively smaller portion of their overall bill.

In practice, fixed and variable retail costs are closely related and dependent on retailer

preferences, as ACIL noted:

The allocation of costs between the two categories may sometimes be arbitrary and for a given

retailer may change over time. A retailer could, for example, invest in IT and increase the level of

49 Queensland Consumers Association, submission on the QCA interim consultation paper, Regulated retail electricity prices for 2016–17, 18 January 2016, p. 2. 50 Toowoomba Regional Council, submission on the QCA interim consultation paper, Regulated retail electricity prices for 2016–17, 17 December 2015, p. 2. 51 Ergon Energy Queensland, submission on the QCA interim consultation paper, Regulated retail electricity

prices for 2016–17, 20 January 2016, p. 9. 52 Ergon Energy Queensland, submission on the QCA interim consultation paper, Regulated retail electricity

prices for 2016–17, 20 January 2016, p. 9. 53 Origin Energy, submission on the QCA draft determination, Regulated retail electricity prices for 2016–17, 20

April 2016, p. 1.


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automation in the business, which may decrease the fixed retailer cost (the costs to serve a

customer) and increase the variable retailer cost (the return on and of the IT assets).54

In setting its fixed retail cost allowance at the mid-point of the estimated range for its 2013–16

determination, IPART also acknowledged this trade-off between fixed and variable costs:

[Setting the retail operating cost allowance at the mid-point] ... takes account of the fact that

retailers’ capital expenditure decisions are not captured in the methodology used to estimate the

retail margin. If retailers have lower ROC because of higher capital expenditure, then setting ROC

at the low end of the range may understate their total costs given our method for estimating the

retail margin. Further, choosing the lower end of the range may place too much weight on one

retailer’s data, given that the differences across retailers’ data are driven partly by differences in

their reporting and cost allocation methods. 55

5.5.1 Market data benchmarking

Our previous methodology for applying retail costs implies recovery of around 77 per cent of total

retail costs (retail operating costs and margin) through the fixed component for residential tariffs

and around 50 per cent for small business tariffs.56 However, ACIL's analysis indicates the fixed

component is generally smaller on average.

For residential customers, the market data analysis reveals that 45 per cent of retail costs are

recovered through variable charges and 55 per cent through fixed charges, on average. This

allocation is quite different for small business tariffs, where around 30 per cent of costs are

recovered through fixed retail charges, and 70 per cent through variable charges, on average. This

is understandable, as small businesses typically have higher usage than residential customers,

which means the fixed component tends to be a smaller proportion of the overall bill than it is

for residential customers.

ACIL's analysis also reveals differences in how individual retailers recover retail costs from fixed

and variable tariff components. Notwithstanding these differences, there is a clear inverse

relationship between the two components—higher fixed retail costs tend to be offset by lower

variable retail costs and vice versa.

5.5.2 Confidential retailer data—bottom-up analysis

Confidential data supplied by retailers was varied and did not allow us to draw any firm

conclusions on the appropriate allocation of retail costs between fixed and variable components.

However, it has provided some guidance on the likely reasonable range of the fixed retail

component.

ACIL analysed the confidential retailer data and derived a reasonable range for the fixed

component of retail costs for small customers of between $80 and $175 per customer per year.

This range effectively reflects the upper and lower limit of costs that could potentially be treated

as fixed retail costs by a retailer. The lower limit includes only those costs that are typically

considered to be directly related to customer numbers such as call centres, billing and revenue

collection and customer acquisition and retention costs. The upper limit includes those same

costs and others that could be considered fixed, but which retailers may choose to recover

through variable charges. These costs include depreciation, amortisation, tax and interest

54 ACIL, Regulated retail prices for 2016–17: Estimating the efficient retailer costs, final report, 13 May 2016. 55 IPART, Review of regulated retail prices and charges for electricity from 1 July 2013 to 30 June 2016, June

2013, p. 105. 56 Based on 2015–16 tariff 11 notified prices with the average annual usage of 4,640 kWh, and 2015–16 tariff

20 notified prices with annual average usage of 16,370 kWh.


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payments, which have typically been considered as recovered through the variable retail

component (the retail margin in previous determinations).

The mid-point of the estimated range of the fixed retail cost component derived from the retailer

data is $127.50. This is very close to the average fixed component of residential retail costs

derived from the market data analysis, which supports the validity of the benchmarking

observations.

5.5.3 QCA position

While retailers considered that the fixed component of retail costs should be higher, no new

information or evidence was provided to support this view. On this basis, we consider using the

allocation implied by the average fixed and variable retail cost allowances derived from ACIL's

market observations remains a reasonable approach to allocating total benchmark retail costs.

Details on how the fixed and variable components have been applied are set out in Appendix J.

Adopting the average benchmark allocation between fixed and variable components would see

residential and small business notified prices 'rebalanced' to place greater weight on recovery of

costs through variable charges. For tariff 11 customers, this would result in a reduction in the

fixed daily charge of around 17 cents per day, and an increase in the variable charge of 1.17 cent

per kWh. For small business customers, this would result in a reduction in the fixed daily charge

of around 3.8 cents per day, and an increase in the variable charge of 1.59 cents per kWh.57

The allocation between fixed and variable components has distributional implications for

different customers. Recovering a larger proportion of retail costs from the fixed component will

have a proportionally greater impact on low-usage customers (as fixed costs are a relatively larger

part of their bill), while recovering more costs through the variable component will have a

relatively greater impact on high-usage customers.

5.6 Assigning fixed and variable retail costs to residential and small business customer tariffs

After establishing the total retail cost allowances, and the benchmark allocation between the

fixed and variable components, we then determined the appropriate way to assign these

allowances to each individual retail tariff.

Flat rate tariffs and time-of-use tariffs—tariffs 11, 12A, 20, 22 and 22A

Tariffs 11 and 12A can be accessed by residential customers and small business customers.

However, they can only be accessed by small business customers in conjunction with a primary

small business tariff. Likewise, tariffs 20 and 22 can be accessed by residential customers in some

circumstances. However, the predominant users of tariffs 11 and 12A are residential customers,

and small business customers are the predominant users of tariffs 20 and 22. As such, we have

decided to apply the small business retail cost allowance to tariffs 20, 22 and 22A, and the

residential retail cost to tariffs 11 and 12A.

Demand tariffs—tariffs 14, 24, 41

Tariff 14 is a residential tariff and tariffs 24 and 41 are small business tariffs. We have applied the

corresponding retail cost allowance to each of these tariffs.

57 This represents the impact on the retail cost component only and assumes all other costs are held constant.


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In previous decisions we applied the retail margin equally (on a percentage basis) to all

components of each retail tariff, including demand charges. We consider this approach remains

appropriate for apportioning variable retail costs to tariff components that are not volume

related, such as demand charges. We have applied the relevant variable retail cost percentage

allocators set out in Table 37, column E (Appendix J) to the demand and usage components of

each of these tariffs.

Controlled load tariffs—tariffs 31 and 33

Tariffs 31 and 33 are available to both residential and small business customers. However, we

note the majority of customers accessing these tariffs are residential, and we have therefore

applied the benchmark retail cost allowance for residential customers.

We previously decided not to apply fixed retail cost allowances to the controlled load retail tariffs,

because we assumed that customers accessing those tariffs would also access another general

supply tariff (e.g. tariff 11 or 20) and pay their fixed retail costs through that tariff.

In 2016–17, we will continue with this approach and apply only a variable retail cost to tariffs 31

and 33.

Unmetered loads—tariff 91

Tariff 91 is available for small unmetered supplies (other than street lighting) as approved by the

distribution business. This tariff is primarily used for loads that are predictable and reasonably

calculated without metering, or where it would not be cost-effective to install a meter. As tariff

91 is intended for small loads, we have applied the small business variable cost percentage

allocator to the usage charge of tariff 91.

In previous decisions, we did not apply a fixed retail cost component to tariff 91, because

customers accessing this tariff were also likely to be supplied under another general supply

business tariff. We have decided to continue this approach in 2016–17.

Transitional arrangement for small business retail costs

As noted in section 5.3, adopting ACIL's analysis means higher retail costs for small business

customers compared with 2015–16. In isolation, the shift from the IPART benchmark to ACIL's

benchmark estimate is responsible for around four percentage points of the overall 11.2 per cent

increase in a typical tariff 20 customer bill in 2016–17. We have considered the suggestion by the

Minister to transition the impact of this change over more than one determination period.

While we previously transitioned the rebalance of tariff 11 after the move away from the

Benchmark Retail Cost Index (BRCI) approach to setting notified prices, that was about removing

a cross-subsidy within the residential customer group, not holding prices below cost for an entire

customer group. We have also previously transitioned the move from some BRCI tariffs to

standard business tariffs, but only where there were very substantial customer impacts.

In contrast, we have not previously transitioned the impacts of changes in individual cost

components, even where those changes have been very substantial. The reasoning behind that

approach has been that transitioning changes in individual cost components would mean setting

prices that are below the actual costs of supply (or further below the actual costs of supply in

regional Queensland).

Transitioning the change in retail costs for small business customers would result in prices being

set at a level that is further below the actual costs of supply in regional Queensland. Setting prices

further below cost will also have an adverse impact on retailers, other than Ergon Retail, that


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supply small business customers in regional Queensland. Based on information provided by

Ergon Distribution, these retailers supply almost 3,500 small business customers in regional

Queensland. They are likely making a significant loss on these customers, as they do not receive

the Customer Service Obligation (CSO) payment that allows Ergon Retail to provide subsidised

prices; they also cannot transfer these customers back to Ergon Retail.

Further, transitioning the change in retail costs would likely result in notified prices that are lower

than expected standing offer prices in south east Queensland, which would be inconsistent with

the UTP. In addition, it would necessitate a 'catch-up' of costs in 2017–18, which would likely see

notified prices for small business customers increase again, regardless of any increases in actual

underlying costs.

For these reasons, we have decided that the change in the retail cost allowances for small

business should be passed through in full in 2016–17.

5.6.1 QCA position

Our final decision is to apply the total retail cost allowances to the fixed and variable components

of retail tariffs based on the average allocation derived from ACIL's analysis (see Table 8), and the

variable cost percentage allocators set out in Table 38 (Appendix J). Table 39 (Appendix J)

summarises the application of these costs to each retail tariff. Consistent with our previous

determinations, secondary retail tariffs do not attract a fixed retail cost allowance.

5.7 Large and very large business customer tariffs

For the reasons set out in section 5.2, ACIL has advised that there is no compelling evidence that

the retail costs for large and very large business customers should vary from the QCA's previous

allowances.

Stakeholders expressed differing views on the appropriate level of retail costs for large business

customers. Toowoomba Regional Council stated:

Council questions the finding that the costs to serve large and very large customer is higher than

for small and residential customers. In fact, Council believes the opposite to be true. Large and very

large accounts are likely to be controlled by organisations with multiple accounts and hence

availing themselves of electronically issued consolidated invoices. Whereas small and residential

customers are invoiced on paper for each individual account [sic]. Council considers that the cost

to administer a large or very large account would be similar if not less than the cost to administer

a small account, and hence does not support the proposal to continue to charge larger accounts

with a higher ROC. 58

In contrast, Ergon Retail submitted that large customers are more costly to serve than small

customers and supported separate allowances for large customers:

The requirements of large and very large customers often result in more tailored product offerings

and bespoke servicing. This impacts operational activities across multiple functions within a

business including:

Customer administration (call centre specialists and dedicated customer service

representatives)

Trading

Billing and revenue collection

58 Toowoomba Regional Council, submission to the QCA interim consultation paper, Regulated retail electricity

prices 2016–17, 17 December 2015, p. 2


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CARC. 59

We note Toowoomba Regional Council's suggestion that retail costs should be lower for large and

very large customers. While potential cost savings could be made by consolidating billing for large

customers with multiple accounts, other characteristics of the relationship between a retailer and

large customer may lead to higher costs, as noted by Ergon Retail.

We also note that Frontier Economics previously examined this issue and found that it costs

considerably more to serve large customers than small customers.60 This cost difference was

based on the higher costs of marketing, account management, and pricing of large customer

loads.

5.7.1 QCA position

On balance, we consider there is no conclusive evidence to suggest that the retail cost allowances

for large and very large business customers in 2016–17 should be materially different from those

allowed in 2015–16.

Therefore, our final decision is to base retail costs for large and very large business customers on

our 2015–16 allowances, with the fixed retail components escalated by forecast inflation to

maintain them in real terms. Details on how we have applied retail costs to each pricing

component are set out in Appendix J.

Table 12 sets out our decision on retail cost allowances for each large and very large business

tariff.

5.8 Retail cost allowances for 2016–17

Tables 10 to 12 set out our final decisions on the retail cost allowances for each regulated retail

tariff for 2016–17. Each fixed retail cost component includes an allowance for QCA regulatory

fees, as set out in Table 41 of Appendix J.

59 Ergon Energy Queensland, submission to the QCA interim consultation paper, Regulated retail electricity

prices 2016–17, 20 January 2016, p. 8. 60 Frontier Economics, Retail Operating Costs, report prepared for the Economic Regulation Authority of

Western Australia, February 2012.


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Table 10 Final determination—retail costs for residential customers and controlled loads for 2016–17 (GST exclusive)

Retail tariff Pricing component

Fixed retail component

(c/day)

Usage (c/kWh) Demand ($/kW/month)

Peak Off-peak/flat Peak Off-peak/flat

T11 35.107 2.376

T12A 35.107 5.392 1.917

T14 35.107 1.447 5.963 1.086

T31 n/a 1.393

T33 n/a 1.927

Table 11 Final determination—retail costs for small business customers for 2016–17 (GST exclusive)



(c/day)



T20 49.790 2.807

T22A 49.790 5.108 2.519

T24 49.790 1.762 9.165 1.506

T41 49.790 1.472 3.117

T91 2.527

T22 (transitional) 49.790 3.052 2.448

Table 12 Final determination—retail costs for large business, very large business and street lighting customers for 2016–17 (GST exclusive)



(c/day)



T44 492.445 0.668 2.164

T45 1117.230 0.673 1.718

T46 2632.909 0.684 1.527

T47 2372.031 0.628 1.406

T48 2787.627 0.628 1.406

T50 456.956 0.643 0.829 3.322 0.801

T71 n/a 1.711


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5.9 Updating the retail cost allowances from year to year

A thorough bottom-up and benchmark review of the efficient retail cost allowance represents a

time-consuming and costly exercise, and places a significant reporting burden on electricity

retailers. We consider that the cost of doing this exercise on a yearly basis would most likely

outweigh any incremental benefit over the short term. Rather, we envisage that a thorough

review of retail costs for the 2016–17 determination should produce robust estimates that can

then be updated annually using a defined escalation method.

Any form of annual escalation could not be conducted indefinitely, and a further detailed review

of retail costs would need to be conducted in due course. This would become particularly

important if there were material changes in cost drivers that flowed through to retail costs.

5.9.1 QCA position

With the exception of retail costs for large and very large business customer tariffs, the escalation

of benchmark retail cost allowances is not necessary in 2016–17. For this reason, we have

deferred our consideration of this issue to next year, should we be delegated the task of setting

notified prices.


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Queensland Competition Authority Other issues

41

6 OTHER ISSUES

This chapter sets out our final decisions on the inclusion of additional allowances above the

estimated efficient costs of supply, and the cost pass-through mechanism. Our final decisions are

to:

provide an allowance for headroom of five per cent of the estimated efficient costs of supply

for all large business customer retail tariffs, consistent with our 2015–16 determination

include a five per cent allowance above the estimated efficient costs of supply in south east

Queensland for all residential and small business customer tariffs, to reflect the difference

between the expected level of market offer prices and standing offer prices in 2016–17

require the negative pass-through of a small over-recovery of Small-Scale Renewable Energy

Scheme (SRES) costs incurred during 2015–16.

6.1 Allowances above the efficient costs of supply

Under section 90(5)(a) of the Electricity Act, we are required to have regard to the effect of our

price determination on competition in the Queensland retail electricity market. We must also

have regard to the objects of the Electricity Act, which include:

(a) establishing a competitive electricity market in line with the national electricity industry

reform process

(b) taking into account national competition policy requirements.

Where it is effective, we consider that competition provides the best means of delivering the

goods and services that customers demand at prices that reflect efficient costs. In previous

determinations, we have included an allowance for 'headroom' to facilitate the development of

retail competition in south east Queensland for residential and small business customers, and in

regional Queensland for large business customers. The headroom allowance is an amount, in

addition to the estimated efficient cost of providing customer retail services, included in notified

prices for the purpose of encouraging customers to engage in the market and seek out more

attractive market offers. Since the 2012–13 determination, we have set this allowance at five per

cent of total estimated efficient costs.

Retail competition in the residential and small business customer market is very limited outside

of south east Queensland. This is largely because the Queensland Government's Uniform Tariff

Policy (UTP) delivers a subsidy to Ergon Retail to supply electricity at notified prices which are, in

most cases, well below the true cost of supply. Other retailers cannot access this subsidy and

therefore typically cannot compete with Ergon Retail's subsidised notified prices. While

headroom has performed the function of encouraging competition in the south east Queensland

market where there is a choice of retailers, the inclusion of headroom in notified prices for small

customers in regional Queensland has been a consequence of the UTP, rather than a means of

promoting competition.

While we are setting notified prices to apply in regional Queensland only, headroom remains a

relevant issue for 2016–17. Firstly, headroom is an important consideration when setting notified

prices for large and very large business customers in the Ergon Distribution area, as many of these

customers have access to competition. This is discussed further in section 6.1.2. In the draft

determination, we applied a headroom allowance of five percent of total costs for large and very

large business customer tariffs, consistent with our approach in previous years.


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Headroom is also a relevant concept when determining the expected level of standing offer prices

for small customers in south east Queensland. Conceptually, headroom can be likened to the

increment of standing offer prices over market offer prices where we assume that market offer

prices are based on the efficient costs of supply. In the draft determination, we considered that

there would likely be differentials between market and standing offer prices in south east

Queensland in 2016–17, and there were no reasons to conclude that those would be any different

to the differentials between market offer prices and notified prices observed in the market in

2015–16. On this basis, we proposed to apply an allowance of five per cent above the estimated

efficient costs of supply, to reflect expected standing offer prices for small customer tariffs.

Submissions

Canegrowers Isis, Canegrowers, Cotton Australia, FNQEUN, QCOSS, and QFF opposed the

inclusion of headroom in regulated retail tariffs on the basis that it increases prices for regional

customers, most of whom do not have access to competitive market offers.

In contrast, Ergon Retail and Origin Energy supported the continued application of a five per cent

headroom allowance for large and very large business customer tariffs.

Ergon Retail supported a standing offer differential of five per cent for small customer tariffs, but

recommended the QCA review this approach in following years as the deregulated market in

south east Queensland matures. The Queensland Consumers Association suggested that the QCA

should consider weighting each observed discount by the retailer's market share when

determining the differential required to establish expected standing offers prices.

QCOSS suggested that the analysis of price differentials should include market offers that are

above the notified price level, which the QCA purposely excluded from the analysis. These issues

are addressed below.

6.1.1 Estimating price differentials in south east Queensland—residential and small business customers

Notwithstanding some stakeholders' opposition to the concept of headroom, the Queensland

Government's definition of the UTP leads the QCA to set 2016–17 notified prices for small

customers in regional Queensland that broadly reflect the expected level of standing offer prices

in south east Queensland (see section 2.2.1). As discussed below, market prices in south east

Queensland reveal that most retailers' best market offers are generally lower than notified prices

in 2015–16, albeit by varying amounts. In essence, these price differentials represent a form of

'headroom' reflecting the amount competed away through conditional and non-conditional

discounts.

The QCA uses an N+R bottom-up approach to derive the estimated efficient costs of supplying

small customers in south east Queensland. In broad terms, this produces price levels that we

would expect to reflect efficient market offer prices. To estimate the expected level of standing

offer prices, it is necessary to add an amount that represents a reasonable expectation of the

difference between expected efficient market offer prices and expected standing offer prices.

Why is there a difference between market and notified prices?

There are a number of possible reasons why notified prices tend to be higher than market offer

prices. In many cases, the difference reflects the fact that the notified price contracts often

provide terms and conditions that are more favourable to the customer. The premium could then

be considered as compensation to the retailer for accepting the additional costs and risks

associated with providing those terms and conditions.


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Through market offers, retailers are able to adopt different terms and conditions designed to

reduce their direct costs or risks, which may enable them to offer a better price or other

incentives to the customer. For example:

Incentivising customers to pay on time can reduce a retailer's bad debt risk, improve its cash

flow position and reduce costs.

Requiring customers to use direct debit payment methods achieves a similar outcome, and

many retailers offer discounts to customers who use it, to reflect the lower risk of default

and bad debts.

Requiring customers to subscribe to online-only (paperless) billing allows retailers to save on

printing and postage costs.

The difference between market and notified prices may also be an indication of differential

pricing strategies, whereby retailers target different customer segments with different prices,

according to their sensitivity to price changes. Standing offer prices will most likely be taken up

by non-price-sensitive customers (e.g. Solar Bonus Scheme and small consumers) and as such will

be set artificially high.

What is an appropriate price differential to apply to efficient costs?

In previous price determinations, when notified prices were also being set for south east

Queensland customers, we estimated the efficient cost of providing customer retail electricity

services and increased that amount by five per cent to reflect the headroom allowance. However,

when setting small customer notified prices for the 2016–17 determination, our aim is to form a

view on the expected price differential between market offers and expected standing offers, and

build that amount onto our estimate of the efficient costs of supply in south east Queensland to

arrive at an expected standing offer price level. We have considered the following matters when

estimating this expected price differential:

the potential effect of deregulation on retail prices

the experience in other deregulated jurisdictions

observed price differentials in the south east Queensland market.

Price deregulation

From 1 July 2016, retail electricity prices will be deregulated in south east Queensland and

retailers will be able to set standing offer prices at levels of their own choosing, rather than using

notified prices. This clearly has the potential to influence the differential between market and

standing offer prices in 2016–17.

There are differing views on the likely effect of price deregulation on standing offer prices in

2016–17. Canegrowers considered that standing offer prices would fall following deregulation,

noting:

the change to price monitoring in SEQ is likely to trigger further changes to prices and innovation

in the value propositions that retailers offer customers connected to the Energex network. It is

likely that 'standing offer prices' in SEQ will be below existing price levels and well below the prices

foreshadowed in QCA's [2016–17] draft determination.61

61 Canegrowers, submission to the QCA Draft Determination Regulated Retail Prices for 2016–17, 21 January

2016, p. 4.


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A contrasting view is that deregulation will lift the constraints on retailers and allow them to

potentially set standing offers that are higher than the notified prices that applied in south east

Queensland in 2015–16. As Canegrowers Isis observed:62

Standing offer prices will most likely be taken up by non-price-sensitive customers (eg. Solar bonus

scheme and small consumers) and as such will be set artificially high.

However, there are countervailing factors that may influence retailers' pricing decisions. First,

the legislative provisions which give effect to price deregulation in south east Queensland from 1

July 2016 include provisions for independent price monitoring, and the option for the Queensland

Government to reinstate retail price regulation if necessary. These factors are likely to moderate

incentives to set standing offer prices in 2016–17 that are significantly higher than the notified

prices that applied in south east Queensland in 2015–16.

Second, there is likely to be some circularity between the notified prices we determine for

regional Queensland, and standing offer prices that eventuate in the deregulated south east

Queensland market in 2016–17. As the Queensland Productivity Commission (QPC) noted:

The QCA’s approach to setting regulated retail electricity prices in regional Queensland based on

the cost of supplying customers in SEQ is also likely to provide a benchmark price for standing

offers in SEQ going forward.63

Therefore, while retailers may have plausible reasons to set their standing offer prices in 2016–

17 at levels above or below the notified prices which applied in south east Queensland in 2015–

16, these reasons do not provide a sufficient basis to predict how standing offer prices might be

set immediately after deregulation.

Experience in other deregulated jurisdictions

Jurisdictional experience of standing offer price movements following retail market deregulation

is mixed. In Victoria, where the electricity retail market was deregulated in 2009, the difference

between market and standing offers has increased considerably in the eight years since

deregulation, reaching up to 18 per cent in some cases.64 This is likely indicative of increased

rivalry in a more mature market, with increased discounting made possible by differential pricing

and a base of price-insensitive or 'sticky' customers remaining on standing offers. In South

Australia and New South Wales (NSW), where the governments have deregulated more recently

(February 2013 and July 2014, respectively), standing offer prices in the early years of

deregulation have been influenced by other factors and are not likely to be representative of

expected outcomes in the south east Queensland market in 2016–17.

When the South Australian retail market was deregulated on 1 February 2013, the South

Australian Government reached an agreement with AGL (the incumbent first tier retailer) to

lower its residential standing offer prices by 9.1 per cent and small business tariffs by 4.5 per cent

following deregulation, and to cap increases in the retail component of the standing offers for

two years.65 Preliminary observations of South Australian market prices from early March 2016,

immediately after the controls on standing offers were lifted, indicate that the difference

62 Canegrowers Isis, Submission to interim consultation paper, 18 January 2016, p. 1. 63 QPC 2016, Electricity pricing inquiry, draft report, 3 February 2016, p. 124. 64 See AER, State of the Energy Market 2015, p. 137. 65 Government of South Australia, Lower prices for South Australia, media release, 18 December 2012.

Available at http://archives.premier.sa.gov.au/images/news_releases/12_12Dec/energyprice.pdf, accessed 19 February 2016.


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45

between standing offer prices and retailers' cheapest market offer prices for residential customer

tariffs ranges between zero and 20 per cent, with an average of around 8 per cent.66

Similarly, when the NSW retail market was deregulated on 1 July 2014, small customers who were

on a regulated contract were moved to a 'transitional tariff' for up to two years, after which they

would be required to move to a market offer. In the first year of deregulation, the NSW

Government approved arrangements that would see the transitional tariff decrease by at least

1.5 per cent from existing standing offer prices. In the second year, average increases in the retail

component of the transitional tariff were capped at CPI.

Evidence of price differentials in south east Queensland

We also analysed standing offers and market offers available to customers in south east

Queensland using the AER's 'Energy Made Easy' online price comparison facility to reveal the

current price differentials in the market.

Standing offers are basic contracts with regulated terms and conditions. In markets with price

regulation (such as south east Queensland in 2015–16), standing offer prices are the notified

prices. In markets without price regulation, standing offers are set by the retailer. They also tend

to be the benchmark price from which retailers offer discounted market prices.

From our analysis, it is clear that the market offers of most south east Queensland retailers are

materially lower than standing offers set at 2015–16 notified price levels. At the time of our

observations in early February 2016, retailers' best discounts off a typical annual residential bill

based on a flat rate tariff (i.e. a tariff 11 equivalent) ranged from zero to 10.2 per cent67, with an

average of around 5.5 per cent.68

Analysis conducted on offers available to small businesses in south east Queensland yielded

similar results. Based on the sample of market offers available to small businesses on a flat-rate

tariff (i.e. a tariff 20 equivalent), net discounts off a typical annual small business customer bill

are in the range of zero to 10 per cent, with an average of 5.6 per cent. Figures 10 and 11 illustrate

the results of this analysis.

66 QCA analysis of results from https://www.energymadeeasy.gov.au/, accessed on 11 March 2016. Based on

typical annual residential usage of 3,870 kWh and excluding zero-discount offers, except where they are the only tariff offered by the retailer.

67 QCA analysis of data from www.EnergyMadeEasy.com as at 3 February 2016. This analysis assumes a typical annual usage of 3,860 kWh, which is the median tariff 11 consumption in 2014–15 as advised by Energex. Net discounts are calculated as the net impact of one-off sign-up bonuses, conditional and non-conditional discounts, as well as any account establishment or connection fees that might offset some of the headline discount available. The analysis does not take account of those market offers that feature prices higher than the notified prices. These offers have been excluded from our analysis as it is not clear that a significant number of customers would take up these offers.

68 We note that the AER has published market discount analysis in its 2014 and 2015 State of the Energy Market reports which suggest lower average discounts, closer to two per cent. However, we do not have access to the underlying assumptions of this analysis and as such have been unable to replicate these results.


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Figure 10 Discounts available in south east Queensland at February 2016: Residential flat rate tariffs

Note: Discounts are calculated based on the estimated annual bill of a typical customer consuming 3,860 kWh per year.

Figure 11 Discounts available in south east Queensland at February 2016: Small business flat rate tariffs

Note: Discounts are calculated based on the estimated annual bill of a typical customer consuming 6,470 kWh (the median tariff 20 consumption in 2014–15 as advised by Energex) per year.

This analysis is indicative only for illustrating the existence of price differentials in the south east

Queensland market, and has some limitations. Most notable is the constraint created by

regulated prices in 2015–16, which means that retailers' standing offer prices are set at notified

price levels. As a result, the differential between market and standing offer prices can only be

driven by retailers changing their market offer prices. In deregulated markets, retailers are able

0%

1%

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Average discount - All retailers (%)

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to change the level of both their standing offer and market offer prices.69 For this reason, we do

not consider it appropriate to use the observed average price differential in 2015–16 as a direct

proxy for the expected price differential in 2016–17. Other limitations of this analysis include:

Point-in-time observations such as these taken from price comparison websites do not

capture market offers that some customers may currently be receiving, but which are no

longer available (or advertised) to new customers.

We do not have sufficient information to determine how many customers are receiving each

market offer, so it is not possible to determine a weighted-average effective discount across

the whole market, which would offer a more representative estimate of the level of price

differentiation in the market.

This analysis is sensitive to the annual usage assumptions, particularly given that most retailers

offer discounts off the usage component only, rather than the whole bill. Usage only discounts

mean that high-usage customers tend to receive discounts that represent a relatively larger

proportion of their overall bill than low-usage customers.

It is also important to note that each individual retailer's capacity to discount is highly dependent

on its own underlying costs. These costs can vary significantly between businesses due to many

factors, including degrees of efficiency, scale, productivity, risk profile, marketing strategies and

other characteristics. We have not attempted to normalise the samples for these differences.

These different characteristics are likely to be major drivers of the variation seen in the level of

discounts across the samples, as illustrated in Figures 10 and 11.

QCA position

Based on the information available, the QCA considers that differentials between market offer

and standing offer prices will prevail in south east Queensland for small customer tariffs in 2016–

17. Ultimately, the size of the differential between market and standing offer prices immediately

following deregulation is uncertain and will likely be the result of individual retailers' pricing

strategies, changes in underlying costs of supply, and other incentives created by the regulatory

and legislative environment.

As we cannot predict the size of the expected price differential with any certainty, we consider it

reasonable to assume it will remain at a level similar to the differential between notified price

standing offers and market offers in the south east Queensland market at the moment.

Analysis of the existing differential between notified price standing offers and retailer market

offers reveals the average level of discounting is around five to six per cent for a typical small

customer's total annual bill. The five per cent headroom allowance applied in 2015–16 has likely

been a major contributor to the existence of this differential, among other factors.

We note the suggestion by the Queensland Consumers Association to establish the standing offer

differential based on the average of discounts available in south east Queensland, weighted by

each retailers' market share. This is not necessary as, in this case, the average observed discounts

are not used as a direct proxy for the expected price differential in the south east Queensland

market in 2016–17. Rather, the analysis of discounts above simply confirms the presence of a

differential between market and standing offers (notified prices). As we have noted, this simple

69 In the absence of temporary price controls or other negotiated outcomes, such as those seen in New South

Wales and South Australia.


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discount analysis has limitations, most notably that the observed differentials are influenced by

regulation which has constrained standing offer price levels in 2015–16.

For the same reason, adopting QCOSS's suggestion to include market offers that are above the

2015–16 notified price level would not lead us to a different conclusion; rather, it would only

change the level of observed average discount.

While stakeholders challenged our analysis and offered alternative approaches intended to

produce a smaller standing offer adjustment, no evidence was provided that differentials

between market and standing offer prices in 2016–17 will be any different to those currently

observed in the market.

On this basis, our final decision is to add an amount above the efficient costs of supply in south

east Queensland that would deliver a similar average price differential in 2016–17, all other things

being constant. We consider that an amount of five per cent of total costs—equal to the

headroom allowance applied in previous years' determinations—is a reasonable estimate of the

amount required to deliver similar price differentials to those observed in 2015–16.

The QCA will consider whether this approach remains appropriate, should it be delegated the

task of setting notified prices at standing offer price levels for 2017–18.

6.1.2 Estimating headroom for large business customer tariffs

In the draft determination we applied a headroom allowance of five per cent to large business

customer notified prices. We considered this appropriate so that notified prices are not an

impediment to the further development of competition in the large customer market in regional

Queensland. This approach was supported by Ergon Retail and Origin Energy.

Since our 2012–13 determination, we have included an allowance for headroom of five per cent

of efficient costs to facilitate and encourage competition in the large customer market in regional

Queensland.

Competition in regional Queensland

While there is very limited competition in the small customer market in regional Queensland,

competition in the large customer segment shows greater promise of developing further,

particularly in areas where notified prices more closely reflect the actual costs of supply.

Competition in this market segment can be supported by applying an appropriate level of

headroom to notified prices with the aim of encouraging customers to engage in the market and

seek out better offers.

The use of a headroom allowance is a generally accepted approach to stimulating competition

and customer engagement in emerging competitive markets. The QPC highlighted the role that

headroom plays in supporting competition in regional Queensland:

Evidence demonstrates that some level of headroom is needed in electricity prices to support the

development of a competitive retail market. Competition is already in effect in certain customer

segments in regional Queensland. The number of large and very large customers on market

contracts is a direct result of competitive market offers made possible through the retail headroom

allowance. Removing the headroom component of notified prices for regional customers would

effectively preclude any further development of regional competition. It also would raise issues

around customers who have already taken up market offers.70

70 QPC 2016, Electricity pricing inquiry, draft report, 3 February 2016, p. 159.


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How much headroom should be included?

It is difficult to assess the impact of more cost-reflective notified prices and the inclusion of

headroom on competition. There has only been a small increase in the proportion of large

regional customers on market contracts over the last few years. As at 30 June 2015, around 28

per cent of large regional customers were supplied under a market contract.

However, in the Ergon Distribution east pricing zone, transmission region one—where notified

prices are based on the estimated efficient costs of supply—the proportion of large customers on

market contracts is higher and has been increasing. In 2012–13, around 44 per cent of large

customers in this area were on market contracts; that number has increased to 47 per cent as of

June 2015. Notwithstanding this increase, some barriers to the development of widespread

competition in the regional large customer market remain:

Setting uniform retail tariffs means that customers in higher-cost areas of regional

Queensland are not paying cost-reflective notified prices and very large customers are paying

a notified price based on a network charge for high-voltage demand customers (rather than

their site-specific network charge).

Many customers are still accessing obsolete and transitional tariffs, which are not cost‐

reflective.

Once customers accept a market contract with a second tier retailer, they are not allowed to

return to Ergon Retail, which may discourage them from accepting a market offer.71

Even if headroom is set at a reasonable level, these barriers will likely continue to limit the extent

to which competition develops throughout regional Queensland in the foreseeable future.

However, we consider that it is appropriate to continue to include an allowance for headroom so

that the level of notified prices does not create a barrier to competition—to the extent possible—

and to encourage customers to engage with the market and actively seek out better offers.

QCA position

In the absence of any further information, or compelling reasons to change the level of headroom,

our final decision is to continue to include an allowance for headroom in notified prices for large

and very large business customers and to maintain the allowance at five per cent of total costs.

6.2 Cost pass-through mechanism

Cost pass-through mechanisms are used by regulators to mitigate the risk that the costs allowed

for in regulated prices are higher or lower than actual efficient costs. Cost pass-through

mechanisms are usually restricted to events that are outside the control of the regulated entity.

Consistent with the Government's stated intent of the UTP, our final decision is to continue to

base notified prices for residential and small business customers on the costs of supply in south

east Queensland. Not allowing a true-up of costs resulting from events that are outside retailers'

control may result in notified prices being out of alignment with south east Queensland costs,

which could deviate from the intent of the UTP.

We applied a cost pass-through mechanism for the first time in our 2014–15 determination to

pass through an under-recovery of costs in 2013–14 associated with the SRES. We also decided

71 This restriction also applies to any future occupants of that premises (e.g. if the premises is sold or occupied

by a new tenant).


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that the mechanism could be used to account for material differences in network charges, in the

event that the charges billed to retailers (usually the AER-approved charges) differed from those

used to set notified prices. However, this application of the mechanism has not been needed to

date.

In the draft determination, we proposed to consider passing through differences in SRES costs,

where the costs provided in the 2015–16 determination were under- or overstated as a result of

differences between the non-binding and binding small-scale technology percentage (STP) for

2016. The approach to calculating SRES costs is set out in detail in Section 4.2.1 and in ACIL's

report on estimating energy costs.

Ergon Retail and Origin Energy supported the continued use of the pass-through mechanism for

differences in SRES costs. No other stakeholders commented on this issue.

Pass through of SRES costs incurred in 2015–16

As discussed in Section 4.2.1, a retailer's SRES liabilities are determined by the STP, which is the

prescribed value that retailers use to determine the number of small-scale technology certificates

(STCs) they must surrender to discharge their SRES liabilities. The STP is set by the Clean Energy

Regulator (CER) and changes from year to year.

Retailers incur SRES liabilities for each calendar year, but notified prices are determined for each

financial year. While the binding STP for the first and second quarters of the prospective financial

year is known when setting notified prices, the binding STP for the third and fourth quarters is

not. To overcome this, ACIL estimates SRES costs using the average of the final STP (for the first

two quarters of the financial year) and the preliminary or 'non-binding' STP (for the last two

quarters of the financial year). Where the final STP for the last two quarters turns out to be

different from the non-binding STP, the SRES allowance provided through notified prices may

under- or overcompensate retailers operating in south east Queensland for their actual SRES

liabilities during a financial year.

Based on the binding STP for 2016, retailers with customers on non-market contracts are likely to

have over-recovered the costs of complying with the SRES in 2015–16. This is because the binding

STP target for the second half of 2015–16 of 9.68 per cent, was lower than the non-binding target

of 9.98 per cent, which was used for setting notified prices in 2015–16.

We estimate that returning these over-recovered SRES costs to customers would reduce the

usage charge for residential and small business tariffs by approximately 0.008 c/kWh (including

the application of the losses, retail margin and headroom that applied in 2015–16). The

calculation of the SRES pass-through amount is set out in more detail in Appendix K. Table 13

presents our assessment of the 2015–16 over-recovered amounts.

Table 13 Total SRES over-recoveries in 2015–16

Settlement class Retail tariff SRES over-recovery

(c/kWh)

Energex NSLP – Residential, small business, unmetered supply and controlled loads

11, 12A, 14, 20, 22, 22A, 24, 41, 91, 31 and 33

0.0077

Ergon Energy – NSLP - SAC demand and street lighting 44, 45, 46, 50, 71 0.0081

Ergon Energy – NSLP - SAC HV, CAC and ICC 47, 48 0.0077

a. Includes allowances for losses, margin and headroom recovered in 2015–16.


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QCA position

Our final decision is to require the negative pass-through of a small over-recovery of 2015–16

SRES costs into 2016–17 notified prices, as set out in Table 13 above.

Although these are relatively small amounts, we consider this pass-through is appropriate given

that the QCA's intent for the pass-through mechanism has always been for it to operate

symmetrically. It also ensures that notified prices are aligned with south east Queensland costs,

which is consistent with the intent of the UTP.

We have previously considered the cost pass-through mechanism could be used to account for

differences in network charges. However, as the final 2015–16 network charges billed to retailers

did not differ from those used to set 2015–16 notified prices, no adjustment is required.

Depending on the regulatory framework that will apply to future price determinations, and

whether any changes are made to the UTP or the subsidy arrangements underpinning it, the pass-

through provisions discussed here may or may not remain appropriate in the future. Therefore,

the QCA cannot commit to the continued availability of a cost pass-through mechanism beyond

this price determination.


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Queensland Competition Authority Transitional arrangements

52

7 TRANSITIONAL ARRANGEMENTS

The delegation requires that we consider maintaining transitional arrangements for tariffs classed

as transitional or obsolete, which include farming and irrigation tariffs.

For the 2016–17 tariff year, we have decided to:

maintain the transitional arrangements for tariffs classed as transitional or obsolete because

there would be significant price impacts for some customers moving to standard business

tariffs

continue to allow all customers access to transitional tariffs

increase transitional and obsolete tariffs in line with increases in standard business tariffs, and

apply an escalation factor of 1.1 to limit charges for transitional and obsolete tariffs from

falling further below cost in dollar terms.

7.1 Transitional arrangements for obsolete and transitional tariffs

Since 2012–13 the QCA has set notified prices based on a network plus retail costs (N+R)

approach. The introduction of this approach meant that a number of existing retail tariffs did not

align with a network tariff. These included farming and irrigation tariffs.72

In previous determinations, we decided that most of these tariffs should continue to be available

for a transitional period before customers are required to move to standard business tariffs

because some customers would face significant financial impacts if they moved to a standard

business tariff immediately.

The delegation requires that we consider maintaining these transitional arrangements and

continuing to allow all customers access to transitional tariffs. Canegrowers and Cotton Australia

supported retaining transitional and obsolete tariffs.

QCA position

We have decided to maintain transitional arrangements for 2016–17. We consider it appropriate

to maintain these arrangements, as analysis from Ergon Retail (see Appendix E) shows that, while

a significant number of customers on transitional and obsolete tariffs may face lower electricity

bills on standard business tariffs, some customers are paying electricity bills significantly below

their cost of supply and would face significant price impacts if they immediately moved to the

standard business tariffs paid by other businesses in regional Queensland.

7.1.1 Transitional periods

We established transitional periods for each transitional and obsolete tariff in our 2013–14

determination. In subsequent determinations we decided to maintain these periods. Tariffs 20

(large), 21, 22 (small and large), 37, 62, 65 and 66 were made available until 2020 to allow time

72 We note that the QPC is examining issues around transitional and obsolete tariffs as part of its electricity

pricing inquiry, and has made a draft recommendation for the government to develop an industry assistance arrangement to help businesses on transitional and obsolete tariffs to adjust to standard business tariffs. See www.qpc.qld.gov.au for further information on the QPC's electricity inquiry.


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for businesses to prepare for the transition to standard business tariffs and recoup some of the

value of investments made to suit the level and structure of these tariffs.73

Toowoomba Regional Council supported allowing transitional periods to run their full course to

allow customers to continue to explore options to adapt their operations to standard business

tariffs. Cotton Australia and the QFF did not support transitional and obsolete tariffs being

removed in 2020, with Cotton Australia arguing for transitional tariffs to remain available to

existing customers indefinitely. Cotton Australia highlighted that electricity costs for some of their

members would triple if they were to move to standard business tariffs. The QFF had reservations

about the removal of transitional arrangements in 2020, as it considered farmers were poorly

informed about the transition to new tariffs and there was no transitional program to assist them.

QCA position

We have decided to maintain the existing transitional periods, established in our 2013–14 final

determination. We consider this will provide certainty to businesses and allow them to prepare

for moving to standard business tariffs. We do not propose to remove transitional tariffs earlier

than scheduled as, based on customer impact analysis (see Appendix E), some customers would

experience significant price impacts if they moved to a standard business tariff immediately.

We have decided not to extend existing transitional periods beyond 2020 for two reasons. Firstly,

as explained in previous determinations, we decided on the transitional period by using the

Australian Taxation Office's defined depreciable life of an irrigation pump of 12 years as a starting

point and then reducing it, because we considered that most investments of this type would have

already been partly, if not fully, depreciated. Secondly, indefinitely subsidising prices beyond

already subsidised UTP levels will encourage further uneconomic investment by businesses and

networks.

7.1.2 Access to obsolete tariffs

The delegation requires that we consider continuing to allow all customers access to transitional

tariffs.

In the 2013–14 determination, we decided that all business customers should have access to

transitional tariffs throughout the transitional period, subject to individual tariff terms and

conditions. The transitional tariffs are tariffs 20 (large), 21, 22 (small and large), 62, 65, and 66.74

We made this decision so that all businesses could be treated equitably. In subsequent

determinations, we noted that we would consider closing access to transitional tariffs to new

customers if there was a significant increase in the number of customers accessing transitional

tariffs, and thereby an increase in the subsidy paid by taxpayers. However, as we found no

significant increase, we decided to continue to allow open access.

Origin suggested that access to transitional tariffs should only be available to those customers

who have made investments on the expectation that these tariffs would remain. Cotton Australia

supported transitional tariffs being available to existing customers on transitional tariffs.

73 Tariffs 41 (large) and 43 (large) were made available until 30 June 2015, on the basis that a significant

number of customers would be better off on a standard business tariff. 74 New customers cannot access tariffs classified as obsolete. We made this decision on the basis that they had

been obsolete for some time (tariff 37), or that they would be removed in a shorter timeframe (tariffs 41 (large) and 43 (large), which were removed on 30 June 2015).


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QCA position

We have decided to continue to allow all business customers to have access to transitional tariffs.

Our analysis shows that there has not been a significant increase in the number of customers

accessing transitional tariffs. We consider that limiting transitional tariff access to customers

based on their expectations at the time of making their investments, as suggested by Origin,

would not be equitable and may prevent customers from moving to a standard business tariff.

7.1.3 Escalation of transitional and obsolete tariffs

Transitional and obsolete tariff charges, unlike other tariffs, are not determined using an N+R

approach. In past determinations, our general approach to setting charges for each transitional

and obsolete tariff was to escalate the charges based on the percentage increase in the charges

in the standard business tariff that customers would otherwise pay. We then applied additional

escalation factors to these increases to limit charges for transitional and obsolete tariffs falling

further below cost in dollar terms.75 Escalation factors of 1.1, 1.25 or 1.5 were applied, depending

on the gap between customer bills under transitional and obsolete tariffs, and corresponding

standard business tariffs. Where most customer bills would likely be impacted by 10 per cent or

less, an escalation factor of 1.1 was applied; where impacts were between 10 per cent and 100

per cent, an escalation factor of 1.25 was applied; and where impacts exceeded 100 per cent, an

escalation factor of 1.5 was applied.

In the 2015–16 determination, the charges in standard business tariffs fell slightly. We

determined that maintaining charges in transitional and obsolete tariffs at their 2014–15 levels

would be sufficient to limit these charges from falling further below cost in dollar terms.

Bundaberg Regional Irrigators Group, Canegrowers and Canegrowers Isis highlighted the impact

of significant price increases in previous years on their members' operations. Canegrowers stated

increases in transitional tariffs would exacerbate what they consider to be an already

unsustainable regulated price structure. Canegrowers Isis highlighted that a recent study had

shown that it was more economical to run a diesel irrigation pump than an electric pump on tariff

22A.

Canegrowers and Cotton Australia stated that further increases in transitional tariffs were

unjustified. Canegrowers and Pioneer Cane Growers Organisation (PCGO) disputed that irrigation

tariffs (tariffs 62, 65 and 66) were below cost. PCGO argued that, as a number of irrigators may

pay less on tariff 20 or 22A, escalation factors were not warranted. Cotton Australia opposed the

escalation of transitional tariffs.

QCA position

We have decided to increase transitional and obsolete tariffs in line with increases in standard

business tariffs, and apply an escalation factor of 1.1 to limit charges for transitional and obsolete

tariffs falling further below cost in dollar terms.

Table 14 maps transitional and obsolete tariffs to small and large customer tariffs and shows the

percentage increase in the standard business tariffs in 2016–17. Unlike previous determinations,

we have used only small business tariff 20 as the basis for escalating small customer transitional

tariffs 21, 62, 65 and 66, rather than the combination of tariff 20 and tariff 22. This is because

75 As any given percentage increase in a higher (such as a standard business tariff) bill will be greater in dollar

terms than the same percentage increase in a smaller (such as a transitional or obsolete tariff) bill. For example, if two bills of $1,000 and $2,000 each increased by 10% to $1,100 and $2,200 respectively, the dollar difference between the two bills would increase from $1,000 to $1,100.


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tariff 22 is no longer suitable as a benchmark, as it is now an obsolete tariff which customers on

transitional tariffs are not able to access. While small business customers on obsolete and

transitional tariffs also have access to a seasonal time-of-use tariff, tariff 22A, we also do not

consider this to be an appropriate benchmark, as charges under this tariff are adjusted by the

QCA based on the price level of tariff 20.76

Table 14 Alignment of tariffs and underlying cost increases

Standard business tariff Standard business tariff annual bill increase

Transitional or obsolete tariff

Tariff 20 11.2% Tariffs 21, 62, 65, 66

Tariffs 44–46a 12.0%b Tariffs 20 (large), 22 (small and large), 37c

a The most appropriate tariff depends on the customer's demand and voltage requirements.

b This is the average of typical customer bill increases across tariffs 44, 45 and 46. Tariffs 47 and 48 are omitted because only a very small number of customers are on these tariffs, which may skew the results.

c Small customers on tariff 37 will most likely move to tariff 20 or 22A; however, as most customers on this tariff are large, it is aligned with the large customer tariffs for this purpose.

Table 15 summarises the likely percentage impacts on electricity bills for customers on each

transitional and obsolete tariff moving to an equivalent standard business tariff (see Appendix E

for further details). Applying escalation factors consistent with previous determinations would

result in the QCA applying escalation factors of 1.25 or 1.5 to 2016–17 standard business tariff

increases for most transitional and obsolete tariffs.77

76 See Chapter 3. 77 Tariffs 62 and 65 would have an escalation factor of 1.1 under the approach in previous determinations.


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Table 15 Likely impact on electricity bills for customers on transitional and obsolete tariffs moving to equivalent standard business tariffs in 2015–16

Transitional tariff

Standard business tariff

Percentage of customers who

would experience

reduced bills

Percentage of customers who would

experience less than 10%

increase in bills

Percentage of customers who would experience

10% to 100% increase in

bills

Percentage of customers who would experience

greater than 100% increase

in bills

Tariff 20 (large) Tariff 44 to 46a 8.2% 18.6% 73.2% 0.0%

Tariff 21 Tariff 20 7.0% 9.0% 39.0% 45.0%

Tariff 22 (large) Tariff 44 to 46a 2.3% 5.8% 91.9% 0.0%

Tariff 37 Tariff 20 11.5% 45.5% 39.0% 4.0%

Tariff 22A 59.5% 24.0% 13.0% 3.5%

Tariff 44 to 46a 0.0% 0.0% 100.0% 0.0%

Tariff 62 Tariff 20 29.0% 16.6% 53.8% 0.6%

Tariff 22A 36.2% 13.4% 48.2% 2.2%

Tariff 44 to 46a 2.1% 4.1% 93.8% 0.0%

Tariff 65 Tariff 20 38.9% 20.8% 40.0% 0.3%

Tariff 22A 61.7% 12.2% 24.9% 1.2%

Tariff 44 to 46a 0.0% 1.6% 98.4% 0.0%

Tariff 66 Tariff 20 50.5% 20.3% 29.2% 0.0%

Tariff 22A 73.0% 19.1% 7.8% 0.1%

Tariff 44 to 46a 0.0% 0.0% 100.0% 0.0%

a Standard business tariff determined based on individual customer usage and demand levels.

Note: Ergon Retail data applies a derived demand profile for customers where demand data is unavailable. Cost impacts may be over- or understated for individual customers depending on their unique demand profile.

Source: QCA analysis of Ergon Retail data.

We disagree with suggestions that transitional and obsolete tariffs should not be increased at all,

or that escalation factors are unwarranted. As discussed above, Ergon Retail analysis shows that

while a number of customers may pay lower prices on standard business tariffs, there are some

customers on transitional tariffs, particularly those with higher usage levels, who pay significantly

less than they would pay on standard business tariffs. As standard business tariffs are estimated

to increase in 2016–17, leaving transitional and obsolete tariffs unchanged, and not applying

escalation factors, would result in charges for most of these customers falling further below cost.

This would risk encouraging further uneconomic investment, and leaving customers further away

from standard business tariffs at the end of the transitional period.

Having said that, we acknowledge stakeholders' concerns about price increases in previous years

and the impact that further price increases may have on their businesses. For this reason, we

have decided not to apply the higher escalation factors of 1.25 and 1.5 used previously, and

instead apply only the lower escalation factor of 1.1 to all transitional and obsolete tariffs. We

note that this will result in more customers facing price increases at the end of the transitional

period than if higher escalation factors were applied.


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57

As noted by the PCGO, a number of customers on transitional tariffs, especially those with lower

levels of consumption, could pay less by changing to a flat standard business tariff, like tariff 20.

It is possible that some customers could also benefit from time-of-use or demand tariffs.

However, we note that the need to install appropriate meters may be deterring some customers.

We encourage customers on transitional tariffs to contact their retailer about options they may

have to save on their electricity costs.78

7.2 2016–17 transitional arrangements

A summary of transitional arrangements for 2016–17 is provided in Table 16.

Table 16 Transitional arrangements for 2016–17

Obsolete or transitional tariff Period to be retained 2016–17 price increase

Tariff 20 (large)—transitional 4 years 13.2%

Tariff 21—transitional 4 years 12.3%

Tariff 22 (small and large)—transitional 4 years 13.2%

Tariff 37—obsolete 4 years 13.2%




78 We understand Ergon Retail wrote to around 2,000 customers in this situation to encourage them to change

to standard business tariffs and lower their electricity costs. However, less than 100 of those contacted opted to do so.


241

Queensland Competition Authority Final determination

58

8 FINAL DETERMINATION

This chapter sets out our final determination of regulated retail electricity prices (notified prices)

to apply from 1 July 2016 to 30 June 2017, as well as customer impacts.

Under the network plus retail (N+R) approach, retail tariffs are aligned with network tariffs

approved by the AER. For the final determination Energex and Ergon Energy have provided 2016–

17 network tariffs and charges (as submitted to the AER). The network tariffs used to develop

retail tariffs are discussed in Chapter 3.

Chapters 4, 5 and 6 set out our decisions on energy costs, retail costs and other costs, which

comprise the R component of the retail tariff calculation.

Chapter 7 sets out our decisions on notified prices and transitional arrangements for retail tariffs

that have been declared transitional or obsolete.

The regulated retail tariffs and notified prices are published in a tariff schedule, which includes

other information, including the eligibility criteria and terms and conditions for each tariff. The

tariff schedule for 2016–17 is provided in Appendix G.

The following tables set out our final determination of regulated retail tariffs and prices for 2016–

17. All tariffs are presented exclusive of goods and services tax (GST).

Table 17 2016–17 Regulated retail tariffs and prices for residential customers (excl GST)

Retail tariff Fixed chargea

Usage charge (peak)

Usage charge

(flat/off-peak)


Demand charge

(off-peak)

c/day c/kWh c/kWh $/kW/mth $/kW/mth

Tariff 11 - Residential (flat rate) 89.572 24.610

Tariff 12A - Residential (time-of-use)b

101.306 55.865 19.859

Tariff 14 - Residential (time-of-use demand)c

60.514 14.984 61.790 11.258

Tariff 31 - Night rate (super economy)

14.423

Tariff 33 - Controlled supply (economy)

19.960

a. Charged per metering point.

b. Peak – 3:00pm to 9:30pm (December, January and February); off peak - all other times.

c. Peak demand – 3:00pm to 9:30pm (December, January and February); off peak demand - 3:00pm to 9:30pm (March to November).


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59

Table 18 2016–17 Regulated retail tariffs and prices for small business and unmetered supply customers, other than street lighting (excl GST)

Retail tariff Fixed chargea

Usage charge (peak)

Usage charge

(flat/off-peak)


Demand charge

(off-peak/flat)


Tariff 20 - Business (flat rate) 127.879 25.968

Tariff 22 - Business (time-of-use) (transitional)b

127.879 28.229 22.648

Tariff 22A - Business (time-of-use)c

127.879 47.258 23.303

Tariff 24 - Business (time-of-use demand)d

78.046 16.299 84.804 13.935

Tariff 41 - Low voltage (demand)

610.984 13.615 28.841

Tariff 91 - Unmetered 23.376


b. Peak - 7:00am to 9:00pm, weekdays; off-peak - all other times. This tariff is only available to customers who were supplied under Tariff 22 at 30 June 2015.

c. Peak - 10:00am to 8:00pm on weekdays (December, January and February); off-peak - all other times.

d. Peak demand - 10:00am to 8:00pm on weekdays (December, January and February); off peak demand - 10:00am to 8:00pm on weekdays (March to November).


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60

Table 19 2016–17 Regulated retail tariffs and prices for large business and street lighting customers (excl GST)

Retail tariff Fixed charge

Usage charge (peak)

Usage charge (flat/off-

peak)

Demand charge

(peak)

Demand charge

(off-peak/flat)


Tariff 44 - Over 100 MWh small (demand)

5314.202 12.302 39.863

Tariff 45 - Over 100 MWh medium (demand)

16662.167 12.393 31.647

Tariff 46 - Over 100 MWh large (demand)

44351.904 12.599 28.123

Tariff 47 - High voltage (demand)

41533.203 11.567 25.896

Tariff 48 - Over 4 GWh high voltage (demand)

41969.578 11.567 25.896

Tariff 50 - Over 100 MWh seasonal time-of-use (demand)a

4493.324 11.832 15.266 61.203 14.761

Tariff 71 - Street lightingb

0.735 31.503

a. Peak demand charged on maximum metered demand exceeding 20 kilowatts on weekdays between 10:00am to 8:00pm in Summer months (December, January and February). Off-peak demand charged on maximum metered demand exceeding 40 kilowatts during non-summer months (March to November). Peak usage charged on all usage in Summer months (December, January and February). Off-peak usage charged on all usage during non-summer months (March to November).

b. The fixed charge for street lighting applies to each lamp.

Table 20 2016–17 Transitional and obsolete regulated retail tariffs and prices (excl GST)

Retail tariff Fixed charge

Min Charge

Usage rate 1b

Usage rate 2c

Usage rate 3d

Usage rate (flat)

Capacity (Up to 7.5kw)

Capacity (Over

7.5kw)

c/day c/day c/kWh c/kWh c/kWh c/kWh $/kW/yr $/kW/yr

Tariff 37a 28.460 20.267 50.691

Tariff 20 (lge) 71.429 34.940

Tariff 21 69.107 46.962 44.124 33.590

Tariff 22 171.670 46.301 16.304

Tariff 62 74.644 44.259 37.427 15.650

Tariff 65 74.644 35.305 19.446

Tariff 66 164.512 18.505 35.888 107.903

a. Tariff 37 became obsolete on 1 July 2007. It is only available to customers taking supply under tariff 37 on 30 June 2007.

b. Tariff 21 – first 100 kWh, tariff 22 – 7am-9pm M-F, tariff 37 – 10:30pm-4:30pm, tariff 62 – 7am-9pm M-F first 10,000kWh, tariff 65 – 12hr peak.

c. Tariff 21 – 101-10,000 kWh, tariff 62 – 7am-9pm M-F over 10,000kWh.

d. Tariff 21 – over 10,000 kWh, tariff 22 – all other times, tariff 37 – 4:30pm-10:30pm, tariffs 62, & 65 – all other times.


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61

8.1 Customer impacts

Impacts on residential customers79

The main retail tariff for residential customers is tariff 11. Many customers on tariff 11 are also

on one of the 'off-peak' or 'controlled load' tariffs (tariffs 31 and 33) for uses such as water heating

and pool pumps.

In 2016–17, the annual bill for a typical customer on tariff 11 will increase by 2.8 per cent from

$1,457 to $1,498. For a typical customer on a combination of tariffs 11 and 31 or tariffs 11 and

33, the increases will be slightly higher (4.8 per cent and 3.1 per cent respectively). However, the

impact on individual customers will vary depending on their consumption. As Table 21 below

shows, annual bills for tariff 11 customers with lower consumption than the typical customer will

either decrease or increase by less than 2.8 per cent. Almost one-third of customers on tariff 11

will face lower annual bills in 2016–17 compared to 2015–16. Annual bills for tariff 11 customers

with higher consumption than the typical customer will increase by more than 2.8 per cent.

Table 21 Changes in electricity bills in 2016-17 for tariff 11 customers (GST inclusive)

Description Annual consumption

(kWh)

2015-16 Annual Bill

($)

2016-17 Annual Bill

($)

Changes

($)

Changes

(%)

25th Percentile usagea 2055 $931.50 $916.19 -$15.31 -1.6%

Median usageb 4203 $1,456.94 $1,497.67 $40.74 2.8%

75th Percentile usagec 6412 $1,997.30 $2,095.67 $98.37 4.9%

a One quarter of regional Queensland customers will use less electricity than the 25th percentile customer.

b Half of regional Queensland customers will use less electricity than the median customer.

c Three quarters of regional Queensland customers will use less electricity than the 75th percentile customer.

Note: 25th percentile, median and 75th percentile usage data for regional Queensland customers are supplied by Ergon Retail, who calculate these figures based on all their customers on the stated tariff(s). See Appendix H for more information. Totals may not add up due to rounding.

The increase in typical tariff 11 customer bills is primarily due to higher energy costs. Our

consultant, ACIL, advised that the rise in energy costs is driven largely by increasing demand from

liquefied natural gas plants, and higher Renewable Energy Target costs. Some of the impact of

higher energy costs has been offset by a decrease in network costs. For lower consumption

customers, the outcome of the review of retail costs has also helped to offset the impacts of

higher energy costs as it has reduced the level of fixed retail costs.

79 The bill impacts presented are based on typical levels of consumption. The typical customer data was

supplied by Ergon Retail and represents the median customer for all customers on the stated tariff. See Appendix H for further information. Please note that the annual bill amounts in Figure 12 have been rounded to the closest dollar.


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62

Figure 12 Annual bills for typical residential customers (GST inclusive)

Table 22 Tariff 11 charges (GST exclusive)



Change (%)

Fixed charge (cents/day) 106.728 89.572 -16.1%

Variable charge (cents/kWh) 22.238 24.610 10.7%

Impacts on small business customers80

In 2016–17, typical customers on the main small business tariff (tariff 20) will face an increase of

$23681 or 11.2 per cent in their annual bill. Typical small business customers on the seasonal

time-of-use tariff (tariff 22A) will face an increase of $660 or 15.8 per cent. These increases have

been driven primarily by higher energy costs and retail costs. Bill impacts will vary depending on

each individual customer's level and pattern of consumption.


data is supplied by Ergon Retail and represents the median customer for all customers on the stated tariff. See Appendix H for further information.

81 Please note that this figure does not equal the difference between the annual bill amounts for tariff 20 in Figure 13 ($235), due to rounding of the amounts in Figure 13.

$1,457

$1,744 $1,750

$1,498

$1,828 $1,806

$600

$700

$800

$900

$1,000

$1,100

$1,200

$1,300

$1,400

$1,500

$1,600

$1,700

$1,800

$1,900

T11 T11 + T31 T11 + T33



246


63

Figure 13 Annual bills for typical small business customers (GST inclusive)

Impacts on large business customers82

In 2016–17, typical large business customers will face increases in their annual bills of between

11.8 per cent and 12.2 per cent. The increases have been driven primarily by higher energy costs

and network costs. Bill impacts will vary depending on each individual customer's level and

pattern of consumption.



$2,113

$4,186

$2,348

$4,846

$-

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

T20 T22A



247


64

Figure 14 Annual bills for typical large business customers (GST inclusive)

Arrangements for customers on obsolete and transitional tariffs

Some business customers are supplied under transitional or obsolete tariffs, which include

farming and irrigation tariffs. These tariffs have been made available for several years to allow

customers to transition to standard business tariffs and recoup some of the investments made to

suit the level and structure of transitional or obsolete tariffs. Based on information from Ergon

Retail, many customers on these tariffs may face lower electricity bills if they moved to a standard

business tariff, but some customers would face much higher bills.

We have maintained transitional arrangements for 2016–17. Our general approach in past

determinations has been to increase the charges in each transitional and obsolete tariff in line

with the percentage increases in the standard business tariffs customers would otherwise pay.

We have then generally applied an additional escalation factor to limit charges for transitional

and obsolete tariffs falling further below cost in dollar terms.

Standard business tariffs will increase in 2016–17 so transitional and obsolete tariffs will also need

to increase. Under our general approach in previous determinations, the escalation factors for

most of these tariffs in 2016–17 would be 1.25 or 1.5.

However, given the substantial price increases that customers on transitional and obsolete tariffs

have experienced in recent years and that customers on these tariffs are more than halfway

through the transition to standard business tariffs, we have decided to apply the minimum

escalation factor of 1.1. This means customers on these tariffs will face increases of between

12.3 per cent and 13.2 per cent in 2016–17 rather than up to 16.8 per cent if the higher escalation

factors were applied.

New customers will also continue to be allowed to access transitional tariffs.

$50,609

$181,043

$449,584

$56,639

$203,138

$502,759

$-

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

T44 T45 T46



248


65

Table 23 Transitional arrangements for 2016–17

Obsolete or transitional tariff Period to be retained 2016–17 price increase

Tariff 20 (large) –transitional 4 years 13.2%

Tariff 21–transitional 4 years 12.3%

Tariff 22 (small and large) –transitional 4 years 13.2%

Tariff 37–obsolete 4 years 13.2%





249

Queensland Competition Authority Acronyms

66

ACRONYMS

A

AEMC Australian Energy Market Commission

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

AFMA Australian Financial Markets Association

B

BRCI Benchmark Retail Cost Index

C

CARC Customer acquisition and retention costs

CPI Consumer Price Index

c/day cents per day

E

Ergon Distribution Ergon Energy Corporation Limited (electricity distribution arm)

Ergon Retail Ergon Energy Queensland (electricity retail arm)

Electricity Act Electricity Act 1994 (Qld)

G

GST Goods and services tax

GWh Gigawatt hour

Government Queensland Government

I

IPART Independent Pricing and Regulatory Tribunal

J

K

kWh Kilowatt hour

kVA Kilovolt Ampere

L

LGC Large-scale generation certificate

LNG Liquefied natural gas

LRET Large-scale Renewable Energy Target

M

Minister Minister for Energy and Water Supply

MWh Megawatt hour


250


67

N

N Network costs

NECF National Energy Customer Framework

NEM National Electricity Market

Notified prices Regulated retail electricity prices

NSLP Net System Load Profile

N + R Network + Retail cost build-up methodology

NSW New South Wales

O

Origin Origin Energy

Q

QCA Queensland Competition Authority

QCOSS Queensland Council of Social Services

QPC Queensland Productivity Commission

R

R Energy and retail cost

RET Renewable Energy Target

ROC Retail operating costs

RPP Renewable power percentage

S

SAC Standard Asset Customer

SBS Solar Bonus Scheme

SRES Small-scale Renewable Energy Scheme

STC Small-scale technology certificate

STP Small-scale technology percentage

T

TWh Terawatt hour

U

UTP Uniform Tariff Policy


251


68

APPENDIX A: MINISTERIAL DELEGATION AND COVER LETTER


252


69


253


70


254


71


255


72


256


73


257


74

APPENDIX B: SUBMISSIONS

Submissions to the interim consultation paper

Organisation

Bundaberg Regional Irrigators Group

Canegrowers

Canegrowers Isis

Cotton Australia

Ergon Energy Corporation Ltd

Ergon Energy Queensland Pty Ltd

Master Electricians Australia

Origin Energy

Queensland Consumers' Association

Queensland Council of Social Services

Queensland Farmers' Federation

Toowoomba Regional Council


258


75

Submissions to the draft determination

Organisation

AFL Cairns

Australian Chocolate Pty Ltd

Australians in Retirement

Axiom A1 Advice Services

Banora International Group

Big4 Atherton Woodlands Tourist Park

Birdwing Business Solutions

Blazing Saddles

Blenners Transport

Cairns Chamber of Commerce

Cairns Coconut Holiday Resort (G Olholm)

Cairns Coconut Holiday Resort (K Thomas)

Cairns Hockey Association

Cairns Tropical Gardens

Canegrowers

Canegrowers Isis

Chamber of Commerce and Industry

Queensland

Coffee Bean Estate

COTA Queensland

Coral Coast Catering

Cotton Australia

D Hyde

D Simpson

Eaglerider Cairns

Energy Guru

Ergon Energy Corporation Limited (Ergon

Distribution)

Ergon Energy Queensland (Ergon Retail)

Expressway Signs and Printworks

Far North Queensland Electricity Users

Network

Future Investment Group

Genesis Engineering (NQ) Pty Ltd

Golden Boat Chinese Restaurant

Gordon Gould Ipson Architects

H Crossley

Independent Capital Advisers

Kurrimine Beach Holiday Park

Local Government Association of Queensland

M Avolio

M Kitchen

Minister for Energy and Water Supply

Missing Link Pty Ltd

Mission Beach Dive - Mission Beach Dunk

Island Water Taxi

Moeba

Mt Ruby Station

Mungalli Falls Outdoor Education Centre

Natural Resource Assessments Pty Ltd

NQ Exhibitions

Oriental and Gourmet Store

Origin Energy

Pioneer Cane Growers Organisation Limited

Primo Produce

QCOSS

Queensland Consumers Association

Queensland Farmers Federation

Sanreef Pty Ltd

Sarayi Boutique Hotel

Savannah Productions

Sunshine Day Care Centre

T Bowater

T Buzolich

The Jade Cosmetic Clinic

The Reef Retreat - Palm Cove

Thirkell Consulting Engineers

Townsville City Council

Union Jack Hotel

Warrawong Lodge

Wavelength Reef Cruises

Worklife Directions

Confidential submission


259

Queensland Competition Authority Appendix C: Responses to additional issues raised in submissions

76

APPENDIX C: RESPONSES TO ADDITIONAL ISSUES RAISED IN

SUBMISSIONS

In this section we provide responses to a number of additional issues raised in submissions, which were not

addressed in our final decision.

83 http://www.qpc.qld.gov.au/. 84 http://www.qpc.qld.gov.au/. 85 http://www.qpc.qld.gov.au/.

Issue Stakeholder QCA position

The QCA has not complied with monopoly investigation provisions of the Queensland Competition Authority Act 1997 (QCA Act), including having regard to social welfare and equity considerations and economic and regional development issues.

Australians in Retirement

FNQEUN

The QCA determines notified prices under the Electricity Act.

The monopoly investigation provisions of the QCA Act referred to in submissions do not apply when the QCA is determining notified prices.

Specific network tariffs should be introduced to cater for food and fibre producers.


Canegrowers

The QCA has no role in setting network tariffs. Network tariffs are established by distributors and approved by the Australian Energy Regulator (AER).

The Queensland Productivity Commission (QPC) is conducting an inquiry into electricity pricing and will make recommendations to the Queensland Government on a range of electricity issues, including those relevant to agricultural customers. Further information can be found on the QPC's website.83

The QCA should recommend the regulated asset base of distributors be revalued.


The QCA has no role in determining distributor regulated asset bases. This issue is a matter for the AER and the distribution businesses.

The QPC is conducting an inquiry into electricity pricing and will make recommendations to the Queensland Government on a range of electricity issues, including on network costs. Further information can be found on the QPC's website.84

The QCA should recommend the solar feed-in tariff be funded out of general government revenue.


Canegrowers

The QCA has no role in determining how the solar bonus scheme is funded. This is a matter for the Queensland Government and distribution businesses.

We note that the QPC is conducting inquiries into electricity pricing and solar feed-in pricing and will make recommendations to the Queensland Government on a range of issues around solar and its impact on other electricity users. Further information can be found on the QPC's website.85


260








77

86 http://www.aemc.gov.au/. 87 http://www.qpc.qld.gov.au/. 88 http://www.qpc.qld.gov.au/.

The QCA should investigate the impact of Queensland energy companies gaming the system to maximise their profitability, and adjust all energy cost estimates to compensate for reported generator rebidding behaviour.


Canegrowers

ACIL has considered this issue as part of their estimation of energy costs. It is discussed in chapter 3 of ACIL's final report.

The QCA has no role in regulating the conduct of generators in the National Electricity Market. The Australian Energy Market Commission (AEMC) has investigated reports of generator re-bidding, and has made changes to the National Electricity Rules in response. Further information can be found at the AEMC website.86

The QPC is also considering this issue as part of its inquiry into electricity pricing and will make recommendations to the Queensland Government. Further information can be found on the QPC's website.87

There needs to be further investigation into alternative tariffs for irrigated agriculture, including controlled supply options.

Canegrowers Isis The QCA has no role in setting network tariffs or determining customer eligibility for specific network tariffs. Network tariffs, and their eligibility requirements, are established by the distributors and approved by the AER.

Costs for the solar bonus scheme should not be borne by irrigators as they do not have the ability to participate.

Canegrowers Isis The QCA has no role in determining the funding arrangements for the solar bonus scheme. This is a matter for the Queensland Government and distribution businesses.

The allocation of solar bonus scheme costs across tariff classes is determined by distributors and approved by the AER.

The costs of the solar bonus scheme should be paid per connection or from general revenue to prevent large industrial users and irrigators paying a disproportionate amount of its cost.

Canegrowers Isis The QCA has no role in determining the funding arrangements for the solar bonus scheme. This is a matter for the Queensland Government and distribution businesses.

The QCA should write to the Minister for Energy and Water Supply to request changes to the definition of the UTP.

Cotton Australia The Queensland Government is responsible for determining the definition of, and the level of subsidy provided by, the UTP.

The QPC is conducting an inquiry into electricity pricing and will make recommendations to the Queensland Government on a range of issues including the UTP. Further information can be found on the QPC's website.88

The QCA should inform the Queensland Government that it must take into consideration the affordability of electricity.

FNQEUN The QCA must set notified prices in accordance with the requirements of the Electricity Act and the Minister's delegation. Chapter 2 outlines legal requirements for the QCA when determining notified prices under the Electricity Act.

The Government has considered affordability issues through implementing and maintaining the UTP, which subsidises electricity prices for regional customers. The notified prices set by the QCA are consistent with the UTP.


261

http://www.aemc.gov.au/



http://www.aemc.gov.au/




78

89 http://www.qpc.qld.gov.au/. 90 http://www.qpc.qld.gov.au/.

The QPC is the appropriate body to recommend changes to the pricing framework. The QPC is conducting an inquiry into electricity pricing and will make recommendations to the Queensland Government on a range of electricity issues, including the framework under which notified prices are determined. Further information can be found on the QPC's website.89

The requirement for controlled load appliances to be hard-wired to electrical systems should be removed to encourage greater take up of controlled load tariffs.


The terms and conditions of the controlled load retail tariffs reflect the terms and conditions of the underlying network tariffs.

Network tariffs, and their eligibility requirements, are established by distributors and approved by the AER.

A tariff structure should be introduced to reward users of battery banks for solar PV. This tariff structure could be similar to a maximum demand tariff.


The QCA has no role in determining the availability, or structure, of demand tariffs. The availability and structure of network tariffs are determined by the distributors and approved by the AER.

We note that the QPC is examining issues around solar PV and battery storage in its inquiries into electricity pricing and solar feed-in pricing and will make recommendations to the Queensland Government. Further information can be found on the QPC's website.90

Any increase in electricity prices will affect the viability of businesses in regional Queensland.

Multiple submissions The QCA must set notified prices in accordance with the requirements of the Electricity Act and the Minister's delegation. Chapter 2 outlines legal requirements for the QCA when determining notified prices under the Electricity Act.

The Government has considered affordability issues through implementing and maintaining the UTP, which subsidises electricity prices for regional customers. The notified prices set by the QCA are consistent with the UTP.

The QCA should show the impacts on bills for a range of customer consumption levels and for different regional centres.

QCOSS

Townsville Water and Waste

The QCA has included bill impacts for customers who use more (75th percentile) than the typical (median) customer, as well as customers who use less (25th percentile). See Appendix H for more information.

The QCA should include metering costs in bill impacts and fact sheets.

QCOSS The QCA provides information to show the impact on customer bills of the QCA's determination on notified prices. As metering charges do not form part of our determination on notified prices (see Chapter 2), and are not determined by the QCA, we do not consider it appropriate to include them in our customer impact analysis.


262





Queensland Competition Authority Appendix D: Network tariff structures

79

APPENDIX D: NETWORK TARIFF STRUCTURES

This appendix provides further information on decisions made in Chapter 3. This appendix compares

Energex and Ergon Distribution network tariff structures and outlines how tariffs are adjusted to make them

consistent with the UTP.

Comparison of Energex and Ergon Energy's tariff structures

Table 24 Comparison of Energex and Ergon Distribution residential and small business customer time-of-use and demand tariffs

Distributor Peak Shoulder Off-peak

Residential (time-of-use)

Energex

(retail tariff 12)

Usage 4 pm–8 pm Mon–Fri

1,044 hours per year

7 am–4 pm, 8 pm–10 pm Mon–Fri

7 am–10 pm weekends


10 pm–7 am every day


Ergon Distribution

(retail tariff 12A)

Usage 3 pm–9:30 pm any day of the week, summera only

585 hours per year

All other times


Residential (time-of-use and demand)

Energex

(to be introduced on 1 July 2016)

Usage Flat usage charge

Demand 4 pm–8 pm weekdays


Ergon Distribution

(retail tariff 14)


Demand 3 pm–9:30 pm any day of the week, summera months only

585 hours per year

3 pm–9:30 pm any day of the week, non-summera months

1755 hours per year

Small business (time-of-use)

Energex

(retail tariff 22)

Usage 7 am–9 pm, week days


All other times


Ergon Distribution

(retail tariff 22A)

Usage 10 am–8 pm on summera week days

540 hours per year

All other times


Small business (time-of-use demand)

Energex No network tariff.

Ergon Distribution

(retail tariff 24)


Demand 10 am–8 pm on summera weekdays

540 hours per year

10 am–8 pm weekdays in non-summera months

1620 hours per year

a Summer months are December, January and February.


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80

Table 25 Comparison of Energex and Ergon Distribution non time-of-use tariffs

Type Distributor Fixed Usage

Residential (tariff 11)

Energex c/day Flat rate c/kWh

Ergon Distribution

c/day c/kWh 1st 1,000 kWh/year

c/kWh next 5,000 kWh/year

c/kWh >6,000 kWh/year

Small business (tariff 20)

Energex c/day Flat rate c/kWh

Ergon Distribution

c/day c/kWh 1st 1,000 kWh/year

c/kWh next 19,000 kWh/year

c/kWh >20,000 kWh/year

Small business demand (tariff 41)

Energex c/day Flat rate c/kWh $/kVA/month

Ergon Distribution

No network tariff

Night controlled load (tariff 31)

Energex n/a Flat rate c/kWh

Ergon Distribution

c/day Flat rate c/kWh

Controlled load (tariff 33)


Ergon Distribution


Unmetered (tariff 91)


Ergon Distribution


Note: In the Interim Consultation Paper we advised that Ergon Distribution intended to introduce a new controlled load tariff on 1 July 2016. Ergon Distribution has now advised that this tariff will not be introduced in 2016–17.

Ergon Energy tariff structure options

This section outlines the methodology we used in section 3.2.3 to adjust Ergon Distribution network charges

to reflect Energex price levels. Our approach to this task is generally consistent with that taken in the 2015–

16 determination. The only difference in our approach from 2015–16 is that, due to changes in data

availability and reliability, tariffs 11 and 20 have been used as the reference point for Energex price levels.

Establishing network prices

To calculate network prices that reflect Ergon Distribution tariff structures and Energex price levels, we use

information on network charges provided by the distributors and customer usage data provided by Ergon

Retail. Using this data, we then lower charges under the Ergon Distribution network tariff91 to a level where

the average customer pays the same as they would under the equivalent Energex network tariff.

This calculated network tariff is then used as the basis of a retail tariff.

Seasonal time-of-use tariffs

Ergon Distribution has seasonal time-of-use network tariffs for residential and small business customers.

These form the basis of retail tariffs 12A (residential) and 22A (small business). To create retail tariffs that

reflect Ergon Distribution network tariff structures, while broadly reflecting Energex price levels, the QCA

91 The applicable network tariff for Ergon Distribution's east zone, transmission region one.


264


81

adjusted all charges under the Ergon Distribution network tariff so that the total network cost for the

average customer was the same as the equivalent Energex flat-rate network tariff.

The results are shown in tables 26 and 27.

Table 26 Network prices for tariff 12A

Fixed

c/day

Peak/flat

c/kWh

Off-peak

c/kWh

Energex 8400 50.200 11.624 n/a

Ergon Distribution ERTOUT1 156.000 38.375 7.558

QCA adjusted Ergon Distribution ERTOUT1 61.375 38.375 7.558

Note: Based on data provided by Ergon Distribution, an annual usage of 5,093 kWh was used, with 10.6% peak usage and 89.4% off-peak.

Table 27 Network prices for tariff 22A

Fixed

c/day

Peak/flat

c/kWh

Off-peak

c/kWh

Energex 8500 72.000 12.486 n/a

Ergon Distribution EBTOUT1 156.000 35.161 11.815

QCA adjusted Ergon Distribution EBTOUT1 72.000 30.462 10.236

Note: Based on data provided by Ergon Distribution, an annual usage of 13,302 kWh was used, with 11.1% peak usage and 88.9% off-peak.

Time-of-use demand tariffs

Ergon Distribution has seasonal time of use and demand tariffs for residential and small business customers.

These form the basis of retail tariffs 14 (residential) and 24 (small business). To calculate network prices for

these retail tariffs, we uniformly reduced all charges in the Ergon Distribution network tariff to equalise the

average customer's network bill with the bill they would face on the equivalent Energex flat-rate network

tariff. While Ergon Distribution considered that this option did not provide a sufficient differential between

peak and off-peak demand charges for tariff 14, we considered that this approach preserves the relativities

within the tariff structure and we do not consider that the differential between peak and off-peak demand

charges needs to be adjusted under this option.

The resulting network prices are shown in tables 28 and 29.

Table 28 Network prices for tariff 14

Fixed

c/day

Usage

c/kWh

Peak demand

$/kW/mth

Off-peak demand

$/kW/mth

Energex 8400 50.200 11.624 n/a n/a

Ergon Distribution ERTOUDCT1 31.000 4.660 72.782 13.261

QCA adjusted Ergon Distribution ERTOUDCT1 22.525 3.386 52.885 9.636

Note: Based on data provided by Ergon Distribution, a peak demand of 1.38 kW per month, an off-peak demand of 3.48 kW per month, and a usage level of 5,093 kWh per annum were used.


265


82


Fixed

c/day

Usage

c/kWh

Peak demand

$/kW/mth

Off-peak demand

$/kW/mth

Energex 8500 72.000 12.486 n/a n/a

Ergon Distribution EBTOUDCT1 31.000 5.460 90.448 14.862

QCA adjusted Ergon Distribution EBTOUDCT1 24.540 4.322 71.601 11.765

Note: Based on data provided by Ergon Distribution, a peak demand of 2.9 kW per month, an off-peak demand of 6.02 kW per month, and a usage level of 13,302 kWh per annum were used.

Non time-of-use tariffs

As discussed in Chapter 3, the QCA examined the impact of using Ergon Distribution's inclining block tariff

(IBT) structure as the basis for flat-rate retail tariffs 11 and 20. For the purposes of this assessment, we

calculated network prices by uniformly reducing all charges in the Ergon Distribution network tariff to

equalise the total network revenue recovered by Ergon Distribution under an inclining block tariff with the

network revenue it would have otherwise recovered under a flat rate tariff.

The resulting network prices and charts demonstrating the impact on consumers are shown below.


Fixed

c/day

Flat/first blocka

c/kWh

Second blockb

c/kWh

Third blockc

c/kWh

Energex 8400 50.200 11.624 n/a n/a

Ergon Distribution ERIBT1 156.000 4.768 11.146 14.904

QCA adjusted Ergon Distribution ERIBT1 107.814 3.295 7.703 10.300

a. All usage under Energex network tariff, usage of less than 2.74 kWh per day under Ergon Distribution network tariff

b. Usage greater than 2.74 kWh per day and less than 16.43 kWh per day (Ergon Distribution network tariff only)

c. All usage above 16.43 kWh per day (Ergon Distribution network tariff only)


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83

Figure 17 Impact on tariff 11 customers adopting Ergon Distribution inclining block tariff structure


Fixed

c/day

Flat/first blocka

c/kWh

Second blockb

c/kWh

Third blockc

c/kWh

Energex 8500 72.000 12.486 n/a n/a

Ergon Distribution EBIBT1 156.000 5.180 13.454 17.078

QCA adjusted Ergon Distribution EBIBT1 122.492 4.067 10.564 13.410

a. All usage under Energex network tariff, usage of less than 2.74 kWh per day under Ergon Distribution network tariff

b. Usage greater than 2.74 kWh per day and less than 54.76 kWh per day (Ergon Distribution network tariff only)

c. All usage above 54.76 kWh per day (Ergon Distribution network tariff only)

-10.0%

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

0 1,500 3,000 4,500 6,000 7,500 9,000 10,500 12,000 13,500 15,000 16,500 18,000 19,500

0

2,000

4,000

6,000

8,000

10,000

12,000

Ch

ange

s in

an

nu

al b

ill (

%)

kWh/year

Nu

mb

er o

f cu

sto

me

rs

# Customers (RHS) % Change in Annual Bill

3699.06 kWh/annum

44% of customersworse off with T11 IBT


267


84

Figure 18 Impact on tariff 20 customers adopting Ergon Distribution inclining block tariff structure

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

0 1,750 3,500 5,250 7,000 8,750 10,500 12,250 14,000 15,750 17,500 19,250 21,000 22,750 24,500

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

Ch

ange

s in

an

nu

al b

ill (

%)

kWh/year

Nu

mb

er o

f cu

sto

me

rs

# Customers (RHS) % Change in Annual Bill

45.1 % of customersworse off under T20 IBT

5126.72 kWh/annum


268

Queensland Competition Authority Appendix E: Transitional and obsolete tariffs—customer impacts

85

APPENDIX E: TRANSITIONAL AND OBSOLETE TARIFFS—CUSTOMER

IMPACTS

In Chapter 7 we discuss our decision on arrangements for customers on transitional and obsolete retail

tariffs. This appendix contains the analysis of bill impacts for customers moving from their transitional or

obsolete 2015–16 tariff to an alternative 2015–16 standard business tariff.

The customer impacts are calculated on an individual tariff basis. As some customers are supplied under

multiple tariffs, the overall impact to an individual customer may be a combination of the impacts shown

below.

Tariff 21

Tariffs 21 is a declining block tariff that aligns with tariff 20 for small business customers. Figure 19 below

shows the distribution of potential impacts for existing customers moving to this standard business tariff.

Figure 19 Change in electricity bills for small business customers on tariff 21 moving to tariff 20

Source: Ergon Retail

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)


269


86

Tariff 22

Tariff 22 is a time-of-use small business tariff which is based on an Energex tariff structure. This tariff is

being phased out and will be replaced by tariff 22A, which is based on the equivalent Ergon Distribution

seasonal time-of-use small business tariff structure. Depending on how they consume electricity customers

may also opt to move to tariff 20, a flat rate tariff. Figures 20 and 21 below show the distribution of potential

impacts for existing customers moving to tariff 20 or 22A.



Figure 21 Change in electricity bills for small business customers on tariff 22 moving to tariff 22A


0%

5%

10%

15%

20%

25%

30%

35%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)

0%

5%

10%

15%

20%

25%

30%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)


270


87

Tariff 37

Tariff 37 is a business time-of-use tariff that aligns with tariff 20 or 22A for small business customers and

one of tariffs 44 to 48 for large business customers. Figures 22–24 below show the distribution of potential

impacts for existing customers moving to these standard business tariffs.





0%

5%

10%

15%

20%

25%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)

0%

5%

10%

15%

20%

25%

30%

35%

40%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)


271


88

Figure 24 Change in electricity bills for large business customers on tariff 37 moving to one of tariffs 44 to 48

Note: For this analysis Ergon Retail has applied a derived demand profile for customers where demand data is unavailable. Therefore individual cost impacts may be over- or under-stated for individual customers depending on their unique demand profile.


0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)


272


89

Tariffs 62 and 65

Tariffs 62 and 65 are time-of-use tariffs for farming and irrigation customers. These tariffs align with tariff

20 or 22A for small business customers and tariffs 44 and 45 for large business customers. Figures 25–30

below show the distribution of potential impacts for existing customers moving to these standard business

tariffs.





0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

20%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)

0%

5%

10%

15%

20%

25%

30%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)


273


90

Figure 27 Change in electricity bills for large business customers on tariff 62 moving to tariff 44 or 45

Note: For this analysis Ergon Retail has applied a derived demand profile for customers where demand data is unavailable. Therefore, individual cost impacts may be over- or under-stated for individual customers depending on their unique demand profile.




0%

5%

10%

15%

20%

25%P

rop

ort

ion

of

Cu

sto

me

rs

Cost Impact (%)

0%

5%

10%

15%

20%

25%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)


274


91



Figure 30 Change in electricity bills for large business customers on tariff 65 moving to tariff 44 or 45



Tariff 66

Tariff 66 is a flat-rate tariff for irrigation customers. This tariff aligns with tariff 20 or 22A for small business

customers and tariffs 44 and 45 for large business customers. Figures 31–33 below show the distribution of

potential impacts for existing customers moving to these standard business tariffs.

0%

10%

20%

30%

40%

50%

60%P

rop

ort

ion

of

Cu

sto

me

rs

Cost Impact (%)

0%

5%

10%

15%

20%

25%

30%

35%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)


275


92





0%

5%

10%

15%

20%

25%

30%

35%

40%

45%P

rop

ort

ion

of

Cu

sto

me

rs

Cost Impact (%)

0%

10%

20%

30%

40%

50%

60%

70%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)


276


93

Figure 33 Change in electricity bills for large business customers on tariff 66 moving to tariff 44 or tariff 45

Note: For this analysis Ergon Retail has applied a derived demand profile for customers where demand data is unavailable. Therefore, individual cost impacts may be over- or under-stated for individual customers depending on their unique demand profile


0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)


277


94

Large business customer tariffs

Transitional large tariffs 20 (large) and 22 (small and large) align with tariffs 44 to 48, which are based on

Ergon Energy network tariffs and charges. Figures 34 and 35 show the likely impacts for large business

customers moving from these transitional tariffs to the most appropriate of the standard large business

customer tariffs.

Figure 34 Change in electricity bills for business customers on tariff 20 (large) moving to one of tariffs 44 to 48



0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)


278


95

Figure 35 Change in electricity bills for business customers on tariff 22 (small and large) moving to one of tariffs 44 to 48



0%

5%

10%

15%

20%

25%

30%

Pro

po

rtio

n o

f C

ust

om

ers

Cost Impact (%)


279

Queensland Competition Authority Appendix F: Build-up of prices

96

APPENDIX F: BUILD‐UP OF PRICES

Table 32 Regulated retail tariffs and prices for residential customers (GST exclusive)

Tariff Tariff component Fixeda

(c/day)

Peak usage

(c/kWh)

Off-peak/flat

usage

(c/kWh)

Peak demand

($/kW/month)

Off-peak/flat demand

($/kW/month)

Tariff 11

(flat rate)

Network 50.200 11.624

Energy 9.445

Fixed Retail 35.107

Variable Retail 2.376

Standing offer adjustment

4.265 1.172

SRES cost pass-through

-0.0077

Total 89.572 24.610

Tariff 12A

(time-of-use)

Network 61.375 38.375 7.558

Energy 9.445 9.445

Fixed Retail 35.107

Variable Retail 5.392 1.917


4.824 2.661 0.946


-0.0077 -0.0077

Total 101.306 55.865 19.859

Tariff 14

(time-of-use demand)

Network 22.525 3.386 52.885 9.636

Energy 9.445

Fixed Retail 35.107

Variable Retail 1.447 5.963 1.086


2.882 0.714 2.942 0.536


-0.0077

Total 60.514 14.984 61.790 11.258


280


97


(c/day)

Peak usage

(c/kWh)

Off-peak/flat

usage

(c/kWh)

Peak demand

($/kW/month)


($/kW/month)

Tariff 31

(controlled load)

Network 6.421

Energy 5.930

Fixed Retail



0.687


-0.0077

Total 14.423

Tariff 33

(controlled load)

Network 9.686

Energy 7.404

Fixed Retail



0.951


-0.0077

Total 19.960


Note: totals may not add due to rounding.


281


98

Table 33 Regulated retail tariffs and prices for small business and unmetered supply customers, except street lighting customers (GST exclusive)


(c/day)

Peak usage

(c/kWh)

Off-peak/flat

usage

(c/kWh)

Peak demand

($/kW/month)


($/kW/month)

Tariff 20

(flat rate)

Network 72.000 12.486

Energy 9.445

Fixed Retail 49.790



6.089 1.237


-0.0077

Total 127.879 25.968

Tariff 22

(time-of-use - obsolete)

Network 72.000 14.395 9.683

Energy 9.445 9.445

Fixed Retail 49.790



6.089 1.345 1.079


-0.0077 -0.0077

Total 127.879 28.229 22.648

Tariff 22A

(time-of-use)

Network 72.000 30.462 10.236

Energy 9.445 9.445

Fixed Retail 49.790



6.089 2.251 1.110


-0.0077 -0.0077

Total 127.879 47.258 23.303

Tariff 24

(time-of-use demand)

Network 24.540 4.322 71.601 11.765

Energy 9.445

Fixed Retail 49.790

Variable Retail 1.762 9.165 1.506


282


99


(c/day)

Peak usage

(c/kWh)

Off-peak/flat

usage

(c/kWh)

Peak demand

($/kW/month)


($/kW/month)


3.716 0.776 4.038 0.664


-0.0077

Total 78.046 16.299 84.804 13.935

Tariff 41

(low voltage - demand)

Network 532.100 2.056 24.351

Energy 9.445

Fixed Retail 49.790



29.094 0.649 1.373


-0.0077

Total 610.984 13.615 28.841

Tariff 91

(unmetered)

Network 10.298

Energy 9.445

Fixed Retail



1.114


-0.0077

Total 23.376




283


100

Table 34 Regulated retail tariffs and prices for large business and street lightning customers (GST exclusive)


(c/day)

Peak usage

(c/kWh)

Off-peak/flat

usage

(c/kWh)

Peak demand

($/kW/month)


($/kW/month)

Tariff 44

(over 100 MWh small (demand))

Network 4568.700 2.201 35.801

Energy 8.855

Fixed Retail 492.445


Headroom 253.057 0.586 1.898


-0.0081

Total 5314.202 12.302 39.863

Tariff 45

(over 100 MWh medium (demand))

Network 14751.500 2.283 28.422

Energy 8.855



Headroom 793.437 0.591 1.507


-0.0081

Total 16662.167 12.393 31.647

Tariff 46

(over 100 MWh large (demand))

Network 39607.000 2.467 25.257

Energy 8.855



Headroom 2111.995 0.600 1.339


-0.0081

Total 44351.904 12.599 28.123

Tariff 47

(high voltage (demand))

Network 37183.400 2.078 23.257

Energy 8.317



Headroom 1977.772 0.551 1.233


284


101


(c/day)

Peak usage

(c/kWh)

Off-peak/flat

usage

(c/kWh)

Peak demand

($/kW/month)


($/kW/month)


-0.0077

Total 41533.203 11.567 25.896

Tariff 48

(over 4 GWh high voltage (demand))

Network 37183.400 2.078 23.257

Energy 8.317



Headroom 1998.551 0.551 1.233


-0.0077

Total 41969.578 11.567 25.896

Tariff 50

(over 100 MWh time-of-use and demand)

Network 3822.400 1.779 4.863 54.966 13.257

Energy 8.855 8.855


Variable Retail 0.643 0.829 3.322 0.801

Headroom 213.968 0.564 0.727 2.914 0.703


-0.0081 -0.0081

Total 4493.324 11.832 15.266 61.203 14.761

Tariff 71

(street lighting)

Network 0.700 19.445

Energy 8.855

Fixed Retail


Headroom 0.035 1.501


-0.0081

Total 0.735 31.503




285

Queensland Competition Authority Appendix G: Gazette notice

102

APPENDIX G: GAZETTE NOTICE


286


103


287


104


288


105


289


106


290


107


291


108


292


109


293


110


294


111


295


112


296


113


297


114


298

Queensland Competition Authority Appendix H: Assumptions used to determine customer impacts

115

APPENDIX H: ASSUMPTIONS USED TO DETERMINE CUSTOMER

IMPACTS

Typical customer figures are based on the annual consumption of the median customer on each tariff in

regional Queensland in the most recent tariff year (2014–15). The median customer is the middle customer

in terms of consumption out of all customers on each tariff. As such, approximately half of all customers

will use less electricity than the typical figure, and half will use more.

Stakeholders requested the QCA provide a range of bill impacts for residential customers. For this final

determination the QCA has provided tariff 11 bill impacts for the 25th and 75th percentile customers. One

quarter of customers will use less electricity than the 25th percentile customer, while three quarters of

customers will use less electricity than the 75th percentile customer.

Ergon Retail provides these figures to the QCA.

Stakeholders noted that the typical customer figures provided by Ergon Retail appear lower than those on

the Australian Energy Regulator's Energy Made Easy website. The reason for the discrepancy is that the

Energy Made Easy website uses average consumption figures based on a survey of 4,000 customers across

Australia in 2014, while Ergon Energy uses actual consumption figures from their customer base of over

700,000 electricity customers in regional Queensland.

Retail tariff Consumption

(kWh per year)

Demand threshold

(kW per month)

Demand

(kW per month)

Peak usage

(%)

Off-peak usage

(%)

Tariff 11 25th percentile

(all customers)

2,055

Tariff 11 median

(all customers)

4,203

Tariff 11 75th percentile

(all customers)

6,412

Tariff 11 median

(for customers who also have Tariff 31)

4,372

Tariff 31 median 1,792

Tariff 11 median

(for customers who also have Tariff 33)

3,989


Tariff 12A median 4,915 10.6% 89.4%


Tariff 221 median 26,970 48.7% 51.3%

Tariff 22A median 15,169 11.1% 88.9%

Tariff 44 median 258,396 30 61

Tariff 45 median 991,944 120 232

Tariff 46 median 2,328,684 400 494

Tariff 47 median 3,338,364 400 803

Tariff 48 median 7,670,400 400 1,304

1. Obsolete tariff



299

Queensland Competition Authority Appendix I: Summary of concessional arrangements for energy in Queensland

116

APPENDIX I: SUMMARY OF CONCESSIONAL ARRANGEMENTS FOR

ENERGY IN QUEENSLAND

Concession Name Eligibility Criteria Annual Amount

Electricity Rebate Customers with a Pensioner Concession Card issued by either Centrelink or Department of Veterans’ Affairs, a Department of Veterans’ Affairs Gold Card (and recipient of the War Widow Pension or special rate TPI Pension) or a Queensland Government Seniors Card.

$320.97

Reticulated Natural Gas Rebate

As for Electricity Rebate. $68.56

Medical Cooling and Heating Electricity Concession Scheme

Queensland residents with a qualifying medical condition requiring cooling or heating to prevent the decline of symptoms, who reside at their principal place of residence which has an air-conditioning unit.

$320.97

Home Energy Emergency Assistance Scheme

Customers must either hold a current, eligible concession card, or have a base income of no more than the Commonwealth Government’s maximum income rate for part-age pensioners, or be on their retailer’s hardship program or payment plan.

Up to $720 per household per year for a maximum of two consecutive years.

Electricity Life Support Concession Scheme

Customers must be medically assessed in accordance with the eligibility criteria determined by Queensland Health. In addition, oxygen concentrators must be provided rent-free by Queensland Health to persons who hold an eligible concession card and meet the eligibility criteria of the Medical Aids Subsidy Scheme. Kidney dialysis machines must be provided rent-free by Queensland Health to persons based on clinical needs and supplied through Queensland hospitals.

$653.72 per year for each oxygen concentrator;

$437.76 for each kidney dialysis machine.

Drought relief Certain farmers who use electricity for irrigation pumping during periods of very low or no water availability.

The fixed electricity charge is waived for Ergon Energy customers, and reimbursed by the Department of Energy and Water Supply for customers of other retail entities.

Note: Information current as of April 2016 and is provided as a guide only. Full details are available from: http://www.dews.qld.gov.au/energy-water-home/electricity/rebates.


300

Queensland Competition Authority Appendix J: Retail cost allowances

117

APPENDIX J: RETAIL COST ALLOWANCES

This appendix provides details on how we have derived the retail cost allowances for 2016–17 notified prices, as set out in Chapter 5. Three issues are addressed here:

(1) deriving the final retail cost allowances from the results of ACIL's benchmarking analysis,

specifically:

(a) determining benchmark total retail cost allowances

(b) determining the benchmark allocations between fixed and variable retail cost components

(c) applying these allocations to fixed and variable components of retail tariffs

(2) estimating retail costs allowances for large and very large customer tariffs

(3) adjusting fixed retail costs for regulatory fees.

This appendix also addresses a number of retail-cost-related matters raised in response to our draft

determination.

Deriving retail costs from ACIL's analysis

Total retail cost allowances for small customer tariffs

We have taken the average of all total retail cost observations derived from ACIL's benchmarking analysis,

in each sample, for small business tariffs and residential tariffs. These averages represent averages across

all data points in each sample (residential and small business); they do not represent averages of the total

retail costs depicted in Figures 8 and 9 (Chapter 5). The total average retail cost allowances used to set our

retail costs are set out in Table 35.

Table 35 Benchmark average retail costs—residential and small business customers

Customer class Fixed retail costs

($/annum)

Variable retail costs

($/annum)

Total retail costs

($/annum)

Fixed costs

(as a % of total retail

costs)

Variable costs

(as a % of total retail

costs)

Residential $127.93 $104.28 $232.21 55% 45%

Small business $181.56 $422.23 $603.79 30% 70%

Note: Based on average annual consumption of 4,640 kWh for residential tariffs and 16,370 kWh for small business tariffs, as advised by Energex.

Allocation between fixed and variable retail components

After deciding on the total benchmark retail cost allowance, we then determine how that should be applied

to retail tariffs.

ACIL's analysis reveals differences in how individual retailers recover retail costs from fixed and variable

tariff components. For residential tariffs, the amount of total retail costs recovered through fixed charges

ranges from 44 to 84 per cent across the sample. For small business tariffs, the allocation appears more

biased toward recovery through variable components, with between 20 and 51 per cent of total retail costs

recovered through fixed charges. Table 36 illustrates this variability across retailers' observations.


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118

Table 36 Percentage of total retail costs recovered through fixed and variable components

Retailer Residential tariffs Small business tariffs

Fixed (%) Variable (%) Fixed (%) Variable (%)

Simply 47% 53% 27% 73%

Energy Australia 75% 25% 24% 76%

Alinta 84% 16% 51% 49%

Origin 54% 46% 30% 70%

Red Energy 54% 46% 21% 79%

Lumo 44% 56% 40% 60%

M2 51% 49% 20% 80%

AGL 60% 40% 38% 62%

Momentum 55% 45% 31% 69%

Click 44% 56% 49% 51%

Minimum 44% 16% 20% 49%

Maximum 84% 56% 51% 80%

Notes: Based on ACIL's benchmarking analysis. These values represent the average recovery of retail costs from fixed and variable components, derived from the average of all market prices offered by each retailer.

This variation in how individual retailers recover their retail costs could be due to, among other things:

underlying cost structures—for example, outsourcing of functions such as billing, customer service and

energy trading could result in a different cost structure to a retailer that performs these functions in-

house

actual energy purchase costs—which are a function of the retailer's exposure to the spot market, its

appetite for risk and its hedging strategy

accounting and reporting policies—including capitalisation policies (for example, some retailers treat

depreciation and amortisation as fixed costs, while others consider them variable costs) and different

marketing strategies (for example, electing to offer discounts off fixed daily charges and usage

charges, or usage charges alone).

Using the market observations, ACIL derived estimated benchmark allocations between fixed and variable

components based on the mathematical relationship between the size of the two components. These

relationships were derived using regression analysis which establishes a line of best fit through each

normalised sample. These relationships are discussed further in ACIL's final report.

We have not needed to use the regression relationships derived by ACIL to determine the variable retail

component, as our final decision applies the average fixed and variable allocation that corresponds to the

average total retail cost based on ACIL's benchmarking analysis. These are the implied allocations that

correspond to the average retail costs in Table 37.

Applying fixed and variable retail components to small customer retail tariffs

After deciding on the benchmark allocation of the total retail cost allowance to fixed and variable

components, each component must be allocated to retail tariff components.


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119

To allocate the fixed retail cost component, the total annual fixed benchmark retail cost (not including an

allowance for regulatory fees) is divided by 365.25 days to derive a daily charge. This is expressed in cents

per day and applied to the fixed component of retail tariffs.

To apply the variable retail cost components to each retail tariff, we have derived variable retail cost

allocators, as set out in Table 37, column E below. These allocators represent the variable retail cost

component (column B) as a percentage of total variable costs, excluding the variable retail cost component

(column D). This approach generates percentage factors which allow us to apply the variable retail cost

components evenly across tariff components, even when they are not expressed on a cent per kWh basis,

such as demand charges. It also allows us to apply variable retail costs to time-of-use use tariff components,

where the average cents per kWh estimate cannot be applied.

Using this approach means that the variable retail cost component changes in line with the underlying

variable cost base. For example, if wholesale energy costs or network charges increased, the variable retail

cost would also increase, as it is derived as a percentage of underlying variable costs. This is consistent with

how the retail margin was applied in previous years. Conceptually, we consider it reasonable to assume

that variable retail costs (including the required margin) would increase as underlying costs increase. This

is because retailers face greater risk as underlying costs (and customer bills) increase—retailers should be

compensated for this additional risk.

For the final decision we have updated our derivation of the variable cost allocator based on the total

variable costs (less retail costs) included in 2015–16 notified prices, rather than 2016–17 variable costs. We

consider this approach is more appropriate, as it produces variable retail cost allocators that better align

with ACIL's retail cost observations (which are drawn from retail tariffs offered in 2015–16). This change

has resulted in a slight increase in the variable retail cost allocators compared with the draft determination.

Table 37 Allocation of fixed and variable retail costs and variable cost allocators

Customer class

A

Benchmark fixed retail component

($/customer/yr)

B

Benchmark variable retail

component ($/customer/yr)

C

Benchmark variable retail

component (c/kWh)

D

Benchmark total variable cost a

($/customer/yr)

E

Variable retail costs allocator b

(%)

Residential 127.93 104.28 2.25 924.89 11.27%

Small business 181.56 422.23 2.58 3,298.72 12.80%

a. The total variable cost excludes the variable retail cost based on 2015–16 costs for an average tariff 11 customer consuming 4,640 kWh per year, and an average small business customer consuming 16,370 kWh per year, based on data from Energex.

b. The variable retail cost allocator (column E) is derived by dividing column B by column D.

To derive the variable retail cost component of each tariff, we multiply the underlying variable cost

component of each tariff (net of variable retail costs) by the appropriate variable retail cost allocator (either

residential or small business). The choice of allocator for each retail tariff is based on the category of

customer accessing the tariff, as set out in Table 38.


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120

Table 38 Allocation of total retail costs to fixed and variable components—small customer tariffs

Tariff Customer category for assigning retail cost

allowance


Variable retail cost allocator

Residential (T11, 12A & 14) Residential Yes 11.27%

Controlled loads (T31 & 33) Residential No 11.27%

Small business (T20, 22, 22A, 24 & 41) Business—small Yes 12.80%

Other unmetered loads—T91 Business—small No 12.80%

Table 39 illustrates the application of the variable retail cost allocators using tariff 24 as an example, which

features usage and demand components.

Table 39 Example application of variable retail cost allocators—tariff 24

Tariff 24 Usage (c/kWh) Demand ($/kW/month)


A Base costs before variable retail costs a

– 13.768 71.601 11.765

B Apply variable retail cost allocator (%)

– 12.80 12.80 12.80

C Variable retail component (A x B)

– 1.762 9.165 1.506

D Variable charges including variable retail costs (A + C)b

– 15.530 80.766 13.271

a Includes network and energy costs.

b Does not include five per cent adjustment to escalate to standing offer price levels or SRES pass-through amounts (see Chapter 6).


Retail costs for large and very large business customer tariffs

As ACIL was not able to benchmark retail costs for large and very large business customer tariffs, we have

decided to retain the 2015–16 large business customer retail operating cost allowances in real terms.

We have escalated the 2015–16 estimated retail operating costs (including margin allocated to the fixed

component) to 2016–17 values using forecast change in the consumer price index (CPI) consistent with our

approach in previous years. We have assumed an inflation rate of two per cent which is consistent with the

mid-range of the Reserve Bank of Australia's inflation forecast of 1.5 to 2.5 per cent for the 12 months to

June 2017.92

In previous determinations, we estimated and applied retail operating costs and the retail margin as

discrete components. Retail operating costs were considered a fully fixed cost. The retail margin was

estimated and applied as a percentage of total costs, recovered through both fixed and variable tariff

components.

92 Reserve Bank of Australia, Statement on Monetary Policy, May 2016, p. 61.


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121

To apply a methodology consistent with that applied to small customer tariffs, the retail operating cost

(ROC) allowance (including margin allocated to the fixed component) is taken as the fixed retail cost

component and the variable component is equal to the margin of 5.7 per cent that we applied in 2015–16.

To allocate the variable component across the total variable costs we have used a variable retail cost

allocator of 6.0445 per cent of total variable costs, excluding variable retail costs. This allocator represents

the percentage required to establish a variable retail cost component equal to 5.7 per cent of total variable

costs, including the variable retail cost.

Fixed retail costs will be applied in the same way as in previous determinations, as set out in Table 40. All

large and very large business tariffs will include both fixed and variable retail cost components, except tariff

71 (street lighting) which is considered a secondary tariff and attracts a variable retail cost only.

Table 40 Allocation of total retail costs to fixed and variable components—large business customer tariffs

Tariff Customer category for assigning retail cost

allowance


Variable retail cost allocator

Tariffs 44, 45, 46, 47 & 50 Business—large Yes 6.0445%

Tariff 71 Business—large No 6.0445%

Tariff 48 Business—very large Yes 6.0445%

Adjusting the fixed retail cost allowance for regulatory fees

We have previously included an allowance for the regulatory fees that we charge retailers to recover the

costs of performing our regulatory functions in the electricity industry. These fees are legitimate costs

incurred by retailers in Queensland. Regulatory fees are charged to retailers on the basis of customer

numbers and are therefore applied to the fixed component of retail tariffs only.

As not all jurisdictions have equivalent regulatory fees, ACIL has adjusted the observed benchmark retail

allowances to exclude any regulatory fees applying in each jurisdiction. For this reason, it is appropriate to

add the QCA's regulatory fees back into the benchmark retail estimates.

For 2016–17, we are estimating the costs of supply in south east Queensland for residential and small

business customers, and the costs of supply in regional Queensland for large and very large business

customers. Consistent with previous determinations, we have determined the 2016–17 allowances for

regulatory fees as follows:

for residential and small business customers, an allowance of $0.297 per customer, which was

calculated by dividing the total fees estimated to be paid by retailers operating in south east

Queensland by the total number of customers they supply93

for large and very large business customers, an allowance of $2.071 per customer, which was

calculated by dividing the fees estimated to be paid by Ergon Retail by the number of customers that

Ergon Retail supplies.94

Table 41 sets out our final decision on the regulatory fee allowances for 2016–17 notified prices.

93 The total fee estimate for south east Queensland retailers is $417,615 and the number of customers in south

east Queensland is 1,407,927 (based on AER data as at 31 December 2015). 94 The total fee estimate for Ergon Retail is $1,454,125 and the number of customers supplied by Ergon Retail is

701,977 (based on AER data as at 31 December 2015).


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122

Table 41 Regulatory fees for 2016–17 retail cost allowances

Customer/tariff category Retail tariffs Regulatory fees ($ per customer per year)

Residential 11, 12A & 14 $0.297

Small business (< 100 MWh per year) 20, 22, 22A, 24 & 41 $0.297

Large business (100 MWh—4 GWh per year) 44, 45, 46, 47 & 50 $2.071

Very large business (> 4 GWh per year) 48 $2.071

Note: Regulatory fees are not applied to tariffs 31, 33, 71 and 91 for the reasons discussed in Chapter 5 and this appendix.

Other issues raised in submissions

Stakeholders raised a number of issues regarding retail costs in response to the QCA's draft determination,

which are addressed below. Issues relating specifically to ACIL's methodology have been addressed by ACIL

in its final report (May 2016), while the remaining issues have been addressed either below or in Chapter

5.

Table 42 Specific issues raised in submissions on the draft determination

Issue Stakeholder QCA response

The QCA's benchmark retail costs fail to recognise the costs of maintaining and supplying standard customers in Queensland.

Adopting the QCA’s draft approach could lead to an under-recovery of retail costs by a retailer which could have a negative impact on competition and the willingness of retailers to engage in the market.

Origin Energy The QCA is required to set notified prices based on expected standing offer prices in SEQ.

While retail costs have been derived from observed market offer prices, the QCA has applied a standing offer adjustment of five per cent to bring overall prices to an estimated standing offer price level.

Origin would expect retail operating costs (including customer acquisition and retention costs) and margin to be set separately to encourage new entrants, competition and business efficiencies in the Ergon network.

Origin supports a retail margin based on a calculation of total costs as previously utilised by the QCA. It has been widely recognised that each of these elements need to be estimated to provide an efficient build-up of costs for an energy retailer.

Origin Energy As the benchmark retail costs are based on competitive market offers, the allowances include some amount of CARC and margin. It is not clear why these allowances would need to be separately identified to facilitate competition and business efficiencies.

Headroom is applied separately to notified prices for large customers to encourage competition in regional Queensland.

Origin does not agree with the proposed rebalancing of the fixed and variable components of the retail tariff. The rebalancing does not reflect a true allocation of costs to customers in Queensland and it may lead to the cross subsidisation between customer segments as retailers attempt to recover fixed costs.

Origin Energy The allocation between fixed and variable costs is based on the average allocation observed in market prices across four competitive jurisdictions, including south east Queensland.

The QCA has not received any further information from retailers detailing specifically how retail costs should be allocated between fixed and variable components.

There is no one-size-fits-all approach. Ultimately, the QCA needs to estimate a value for these costs. Costs, and the allocation of those costs, differ markedly between retailers. Therefore, using the average allocation is a more reasonable approach than using the costs and


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123


allocations that align with any particular retailer.

The market offers selected by ACIL are the lowest in the market and thus there is a statistical bias. Costs to supply a standard customer in Ergon’s region are likely to be higher.

Origin Energy The QCA is required to set notified prices for small customers based on expected standing offer prices in south east Queensland. This means the QCA must consider costs of serving customers in south east Queensland, not regional Queensland.

ACIL has applied all conditional and unconditional discounts and product offers in the calculation of total electricity bills. These are likely to reflect the lowest cost to serve and are not reflective of the costs of supplying the market as a whole.

Origin Energy While retail costs have been derived from observed market offer prices, the QCA has applied a standing offer adjustment of five per cent to bring overall prices to an estimated standing offer price level.

The accuracy of the benchmarking approach hinges on ACIL’s ability to estimate the wholesale costs of an efficient retailer. Notwithstanding some directional offsetting of error between wholesale and retail cost estimates it seems like an unnecessary complication to base an estimate of efficient operating costs upon a consultant’s modelled wholesale prices

Origin Energy The QCA refers to ACIL's final report, May 2016.

Retail cost and margin allowances need to cover a retailer’s risk-weighted investment in order to entice them to the market. The QCA’s approach effectively limits future market entry to retailers able to compete at below the cost to serve and margin requirement inferred from the average of the lowest priced market offers.

Origin Energy Notified prices for large and very large business customers include a headroom allowance as means of facilitating competition.

Notified prices for small customers are not being set based on costs in regional Queensland. They are set in accordance with the UTP and are not intended to be set at a level that would directly encourage competition in the small customer market in regional Queensland at this time.

The QCA uses the allocation implied by the average fixed and variable retail cost allowances derived from ACIL’s market offer observations. Origin does not support this approach and believes ACIL’s analysis of the fixed and variable components of market offers is not representative of a retailer’s true allocation of costs.

Origin Energy The allocation is based on ACIL's observations of actual prices in competitive markets. No further evidence been provided to the QCA to support the assertion that the allocation is not representative.

There is no one-size-fits-all approach. Ultimately, the QCA needs to estimate a value for these costs. Costs, and the allocation of those costs, differ markedly between retailers. Therefore, using the average allocation is a more appropriate approach than using the costs and allocations that align with any particular retailer.

The high degree of variability in the characteristics of retailers and their customers may not reflect the allocation of an efficient retailer supplying regional Queensland customers. EEQ requests the QCA review this allocation in future price determinations.

Ergon Retail As above.

EEQ supports the QCA’s position that it would not be beneficial to conduct a bottom-up review of retail costs on an annual basis and that annual cost increases should be calculated using a defined escalation method. EEQ also supports the QCA’s

Ergon Retail The QCA will consider the matter of escalating retail cost allowances in the course of determining 2017–18 notified prices, should it be delegated that role.


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position that detailed reviews should be conducted where material changes in cost drivers emerge.

To provide customers and other stakeholders with visibility, EEQ asks the QCA to share the detail of their approach to escalation and definition of material change in cost drivers.

The QCA should ensure the methodology for estimating energy costs that is used and applied is exactly the same in the estimation of energy costs and the estimation of retail costs.

QCOSS ACIL has applied the same methodology across all estimates of energy purchase costs.

In its retail costs report, ACIL undertook a full analysis of energy costs in every other jurisdiction. In future, additional data and accompanying spreadsheets should be provided for the other jurisdictions as for Queensland.

QCOSS All energy cost estimates used in ACIL's retail cost modelling are set out in ACIL's final report (May 2016).

The QCA should weight the retail costs by customer numbers. This would give a more accurate reflection of costs across the sector. It would avoid the anomalies that a large number of small retailers could skew the overall results.

Consideration should be given to using weighted rather than simple averages and the weightings should be based on retailers' market shares.

QCOSS

Qld. Consumers Association

Addressed in section 5.4.2.

The current tariff 11 fixed charge (N+R) remains well below the Ergon Energy Distribution fixed rate. Therefore, the QCA’s decision further increases the gap to cost reflective pricing. This reduces the possibility of moving towards the use of Ergon Energy Distribution’s network tariff structures in the near future.

Ergon Distribution

The QCA considers the updated retail cost estimates are more cost-reflective than those previously used as they rely on real market data. The use of new retail cost estimates should in no way impede the use of cost reflective network charges in the future.

The QCA should set the 'R' component of the retail price using the R' related costs that apply in the Ergon retail market.

Canegrowers The QCA sets notified prices for small customers based on estimated costs in south east Queensland, which is consistent with the UTP.

The market benchmark incorporates substantial competition related costs (previously referred to as customer acquisition and retention costs) that simply are not incurred in Ergon’s retail markets where Ergon retail has an effective retail monopoly.

Given the balance of evidence, there is no basis for the QCA to conclude that the market benchmarks it is using reflect efficient costs in Ergon retail markets.

Canegrowers As above.

The proposed allowance for retailer costs in the draft determination is excessive. The available evidence indicates substantial reductions in retailer costs due to a combination of modern customer information and billing systems and economies of scope and scale. In other words, the QCA’s current allowance for retailer costs already exceeds efficient costs.

Canegrowers The market benchmarking exercise did not reveal such evidence, nor has any other evidence to support this been tendered to the QCA for consideration.

While CCIQ understands that there have been calls for the QCA to undertake a more comprehensive review of retail costs, this has resulted in detrimental impacts on pricing for small businesses. CCIQ believe that the QCA should reconsider continuing the

CCIQ As noted in section 5.1, the QCA's previous estimates of retail costs are dated. We consider it appropriate to apply the latest updated cost estimates wherever possible.


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previous approach of using the Queensland retail operating cost benchmark.


309

Queensland Competition Authority Appendix K: Cost pass-through

126

APPENDIX K: COST PASS‐THROUGH

This appendix provides further information about how the SRES pass-through amounts presented in section

6.2 were calculated.

First, we recalculated the actual cost of SRES compliance during 2015–16, in dollars per megawatt hour

($/MWh), based on the binding STP for the 2016 calendar year, using the same approach as ACIL. We then

subtracted the SRES allowance included in 2015–16 notified prices from the actual 2015–16 SRES cost. This

revealed an SRES over-recovery of $0.06 per MWh (0.006 c/kWh), as shown in Table 43.

Table 43 2015–16 SRES over-recovery for all settlement classes

Period

STP (%)a

Clearing House Pricea

($/MWh)

SRES cost

($/MWh)

2015–16 average

SRES cost

($/MWh) Binding Non-binding

2015–16 Final determination allowance

1 Jul–31 Dec 2015 11.71% $40.00 $4.684 $4.34

1 Jan–30 Jun 2016 9.98% $40.00 $3.992

2015–16 Actual cost

1 Jul– 31 Dec 2015

11.71% $40.00 $4.684 $4.28

1 Jan–30 Jun 2016 9.68% $40.00 $3.872

Over-recovery in 2015–16 (before losses, margin and headroom) $0.06

a Published by the Clean Energy Regulator.

Next, we made an adjustment to the over-recovery to account for network losses to determine the SRES

liabilities based on energy acquired. In the 2015–16 determination, we applied a loss factor to energy

purchase costs for each settlement class to reflect transmission and distribution losses for each settlement

class. We applied the same network loss factors to the over-recovered SRES amounts calculated above,

consistent with the 2015–16 determination.

To restore the real values of the over-recovered amounts, we made an adjustment to reflect the time-value

of money for retailers over that 12-month period, proxied by a nominal weighted-average cost of capital of

8.47 per cent.95 Finally, we applied the retail margin of six per cent96 and a headroom allowance of five per

cent (which reflect the allowances applying in the year the over-recovery was incurred) to arrive at the final

SRES pass-through amounts. The result is three discrete pass-through amounts, which are applied at the

final stage of the build-up of 2016–17 notified prices, according to the relevant underlying network tariff

class.

The calculations and pass-through amounts to apply to each settlement class are set out in Table 44.

95 Estimated in accordance with the QCA's weighted average cost of capital methodology. 96 A retail margin of 6.0445 per cent of total costs (excluding the margin) is equivalent to the 2015–16 retail

margin of 5.7 per cent of total costs (including the margin).


310

Queensland Competition Authority Appendix K: Cost pass-through

127

Table 44 SRES pass-through amounts for 2016–17 by settlement class

Energex NSLP—Residential, small business, unmetered supply and controlled load 9000 and 9100

Base SRES over-recovery in 2015–16 (c/kWh) 0.0060

+ Energy losses (total loss factor) 1.0650

+ Time value of money (%) 8.47%

Total over-recovery before application of retail margin and headroom ($2016–17 c/kWh) 0.0069

+ 2015–16 Retail margin (%) 6.0445%

+ Headroom allowance (%) 5%

SRES pass-through 2016–17 (c/kWh) –0.0077

Ergon Energy NSLP - Small, medium and large SAC demand and street lighting





+ 2015–16 Retail margin (%) 6.0445%



Ergon Energy NSLP—High-voltage demand and customers over 4 GWh (SAC HV, CAC and ICC)





+ 2015–16 Retail margin (%) 6.0445%




311

No. Company’s name Address Phone number Website

1

Hung Thinh Trading &

Construction Co., ltd

186 Giang Vo Street, Ba Dinh district, Hanoi,

Vietnam 043 8561381

2

Xuan HoaTrading & Service

Co., ltd

350 Buoi Street, Ba Dinh district, Hanoi,

Vietnam 043 8347524

3 Thanh Tu Co., ltd

D5/25 Lang Ha street, Ba Dinh district, Hanoi,

Vietnam 043 5638454

4 Nam Cuong Corporation

70 Linh Lang street, Ba Dinh district, Hanoi,

Vietnam 043 7663511http://namcuong.com.vn

5 Minh Quan JSC

158 Tran Duy Hung street, Cau Giay district,

Hanoi, Vietnam 043 7845157

6

Nam Thanh Trading and

Investment Consultancy JSC

21/199 Truong Chinh street, Dong Da district,

Hanoi, Vietnam 043 5635 793 http://www.cotanagroup.vn

7 Ngoc Bich Trading Co., ltd

260 Lang street, Dong Da district, Hanoi,

Vietnam 043 8531 303

8 Thinh Vuong Trading Co., ltd


Vietnam 043 7751 070

9 Dang Dao co., ltd


Vietnam 043 8531 620

10 Vinh Phuc Trade Co., ltd

P404B, 105 Lang Ha street, Dong Da district,

Hanoi, Vietnam 043 5623 011

11 Nhan Luat Co., ltd


Vietnam 043 5145 862 http://nhanluat.com.vn

12

Binh Minh Production, Trading,

Import & Export Co., ltd

2 Lang Ha street, Dong Da district, Hanoi,

Vietnam 043 8353 303

13 Phu Minh Co., ltd

49 Vu Ngoc Phan street, Cau Giay district,


Examples of Rod in coils agents and retailer in Vietnam


312

http://namcuong.com.vn/

http://www.cotanagroup.vn/

http://nhanluat.com.vn/

14 Dong Do Material Co., ltd

59 Nguyen Hong street, Ba Dinh district,


15 Constrenxim Co., ltd

2 Nguyen Hong street, Ba Dinh district, Hanoi,

Vietnam 091 3343 877

16 Thanh Do Co., ltd 39 Tay Son, Dong Da district, Hanoi, Vietnam 043 5332 927

17

Ha Minh Services And Trading

JSC

20 Hoang Ngoc Phach street, Ba Dinh district,


18

Hong Duong Engineering and

Trading Co., ltd

79B Vu Ngoc Phan street, Cau Giay district,


19 C&T Material JSC

Room 706, 115 Le Duan street, Dong Da

district, Hanoi, Vietnam 043 9426 538

20

Kim Khi Trading & Processing

Co., ltd

621 Tam Trinh street, Hoang Mai district,


21 Xuan Phuong Trading Co., ltd



22

Vinh Cat Material &




23 Viet Anh Trading Co., ltd

394 Minh Khai street, Hai Ba Trung district,


24

Investment Construction

Trading I JSC



25 Minh Phuong Trading Co., ltd

261 Vong street, Hai Ba Trung district, Hanoi,

Vietnam 043 8697 077

26 Minh Phuong Trading Co., ltd

221 Vong street, Hai Ba Trung district, Hanoi,

Vietnam 043 8697 077

27 Hong Ha Material Co., ltd



28

Hanoi Construction Material

JSC

205 Ba Trieu street, Ha Ba trung district,

Hanoi, Vietnam 043 9760 303 http://www.cmchanoi.com.vn

29

Delta Civil Engineering


183 Ba Trieu street, Ha Ba trung district,



313

http://www.cmchanoi.com.vn/

30

TanCo Consulting and Trading

JSC

55 Lac Trung street, Hai Ba Trung district,

Hanoi, Vietnam 043 6362 414 http://tanco.com.vn

31 Thi Huong Trading Co., ltd

6 Tan Ap street, Ba Dinh district, Hanoi,

Vietnam 043 7165 325

32

Toan Dat Constrcution &

Trading JSC

32 Cau Tien – Giai Phong street, Hai Ba Trung

district, Hanoi, Vietnam 043 6414 726

33 Hanoi Steel & Trading Co., ltd

Km14, QL 6, Phu Lam Ward, Ha Dong district,

Hanoi, Vietnam 02433 504 735 http://thephanoi.com.vn

34 Hiep Huong Trading JSC

3 Vien May lane, Cau Giay district, Hanoi,

Vietnam 043792133 http://hiephuong.com.vn

35 Minh Duc Steel & Iron Co., ltd

10 M2 TT6 Bac Linh Dam, Dai Tu street,

Hoang Mai district, Hanoi, Vietnam 02439653333 http://satthepxaydung.com

36 Dai Ly Thep (agency)

204 Ho Tung Mau street, Bac Tu Liem district,

Ha Ni city, Vietnam 0123.623.6868 http://dailythep.com

37

Hai Phong Transportation &

Supplies Co., ltd

388 Le Thanh Tong street, Ngo Quyen district,

Hai Phong city, Vietnam 0313 750 534

38 Song Thin Co., ltd

1A Ton Duc Thang street, Le Chan district, Hai

Phong city, Vietnam 0313 701 290

39 MISCO Co., ltd

23 Le Thanh Tong street, Ngo Quyen district,

Hai Phong city, Vietnam 0313 767 451

40

Viet Han Industrial

Transportation & Supplies Co.,

ltd

42 Ho Sen street, Le Chan district, Hai Phong

city, Vietnam 0313 739 808

41 Thai Hung Trading JSC

10/5 Gia Sang street, Thai Nguyen province,

Vietnam 0280 3855 276 http://www.thaihung.vn

42 Thanh Hung Co., ltd

50 Phan Dinh Phung street, Vinh city, Nghe An

province, Vietnam 038 3841 519

43

Hanoi Construction

Corporation (CT 6)

205 Le Duan street, Vinh city, Nghe An

province, Vietnam 038 3844 737 http://www.hancorp.com.vn

44

Hoang Long Steel Import

Export Co., ltd

557/5 Huong Lo 3 street, Binh Tan district, Ho

Chi Minh, Vietnam 0286065402616 http://satthephoanglong.com

45 Tan Thanh Loi Co., ltd

629 Hung Vuong Highway, Cam Ranh city,

Khanh Hoa province, Vietnam 05803857681 http://thepxaydung.bizz.vn/


314

http://tanco.com.vn/

http://thephanoi.com.vn/

http://hiephuong.com.vn/

http://satthepxaydung.com/

http://dailythep.com/

http://www.thaihung.vn/

http://www.hancorp.com.vn/

46 Ngoc Linh Co., ltd

212 Ky Dong distric, Thanh Khe district, Da

Nang, Vietnam 02363725858 http://www.ngoclinhdn.com.vn

47

Hoang Viet Construction Steel

Co., ltd

121A Kenh19-5, Tan Phu district, Ho Chi Minh,

Vietnam 0866576779 http://thephoangviet.com

48

Nguyen Phat Steel Trading Co.,

ltd

9/11 Phung Chi Kien street, Tan Phu district,

Ho Chi Minh, Vietnam 0838473749 http://thepnguyenphat.com

49 Ngoc Chinh Steel Co., ltd

264/40A Le Van Quoi street, Binh Tan district,

Ho Chi Minh, Vietnam 0902 835 379 http://thepngocchinh.bizz.vn

50 Haminco Co., ltd

34, 882 street, 9 district, Ho Chi Minh,

Vietnam 0904 411 822 http://haminco.com.vn

51

Van Vinh Trading, Service and

Manufacturing Co., ltd

20/5 Khu pho 2, 12 district, Ho Chi Minh,

Vietnam 0837156690 http://vanvinh.com.vn

52 Nhat Truong Vinh Co., ltd

Lot 1, 1A street, Tan Tao Industrial Zone, Binh

Tan district, Vietnam 028 37547000 http://ntv.com.vn

53 Nguyen Thinh Co., ltd

1A Highway, Dien Ban district, Quang Nam

province, Vietnam 0235 3715757 http://nguyenthinhvlxd.com

54

Son Tra Trading,

Manufacturing and


5/10 Khu pho 1, Bien Hoa city, Dong Nai

province, Vietnam 0251 3829041 http://satthepsontra.bizz.vn

55 Kho Vinh Tam Co., ltd

K71/9 Tran Khanh Du street, Ngu Hanh Son

district, Da Nang, Vietnam 0236 3922889 http://khoivinhtam.com.vn

56 Hoa Loi Steel Co., ltd

557/35/9 Huong Lo 3 street, Binh Tan district,

Ho Chi Minh, Vietnam 0902534377 http://www.thephoaloi.vn

57 Van Thanh Cong Co., ltd

412 Group 5, 2 Neighborhood, Bien Hoa city,

Dong Nai province, Vietnam 0251 3899962 http://vanthanhcong.bizz.vn

58 Ha Noi Industrial Steel Co., ltd

53 Warehouse, Long Bien district, Ha Noi,

Vietnam 024 85892918 http://www.thepcongnghiep.com.vn

59

Tuan Phat Steel Trading,

Import Export Co., ltd

48/8 Me Linh street, Binh Thanh district, Ha

Noi, Vietnam 028 54274048 http://www.tuanphatsteel.com

60 Truong Son Steel JSC

110 Hoa Cuc street, Phu Nhuan district, Ho

Chi Minh, Vietnam 028 35173804 http://truongsonsteel.vn/

61 Tan Hung Steel JSC

1.5 Lane, Dau 2 Village, Hoai Duc district, Ha

Noi, Vietnam 024 22213826 http://www.theptanhung.com.vn


315

http://www.ngoclinhdn.com.vn/

http://thephoangviet.com/

http://thepnguyenphat.com/

http://thepngocchinh.bizz.vn/

http://haminco.com.vn/

http://nguyenthinhvlxd.com/

http://truongsonsteel.vn/

http://www.theptanhung.com.vn/

62 Minh Tu Co., ltd

Tra Noc Industrial Zone, O Mon district, Can

Tho province, Vietnam 0292 3861500 http://www.minhtu.com.vn

63 Phuoc Loc Thanh BBS JSC

299F6, Song Giong Group, 2 district, Ho Chi

Minh, Vietnam 028 37430658 http://www.minhtu.com.vn

64

Thai Hoang Hung Investment

Trading JSC

68 Nguyen Hue street, 1 district, Ho Chi Minh,

Vietnam 028 62883067 http://thaihoangsteel.com

65 Bao Tin Steel Co., ltd

100 Tran Thi Co street, 12 district, Ho Chi

Minh, Vietnam 028 62593033 http://www.thepbaotin.com/

66

Mai Khoa Steel Import Export

Co., ltd

1016 Truong Sa street, 3 district, Ho Chi Minh,

Vietnam 028 39310958 http://www.maikhoasteel.com

67

Phuong Hoang Diêu Steel Co.,

ltd

3 Group, Dinh Hoa ward, Thu Dau Mot

district, Binh Duong, Vietnam 0274 3884809 http://www.thepphuonghoangdieu.com

68

Viet Nhat Steel Trading &

Manufacturing Co., ltd

205 Nguyen Duy Trinh, 2 district, Ho Chi

Minh, Vietnam 028 37430844 http://www.tonthepvietnhat.com

69 Viet Tin Steel Co., ltd

107, Map no.13, Da Hoi Group, Chau Khue

ward, Tu Son district, Bac Ninh, Vietnam 0932283783 http://thepviettin.bizz.vn

70

Tan Quang Material &

Construction JSC

8, 10 Doan Ke Thien street, Cau Giay district,

Hanoi, Vietnam 024 37644234 http://tanquangsteel.com.vn/

71

Vu Gia VNT Investment

Trading Co., ltd

4/23/2A, 3 street, 5 group, Thu Duc district,

Ho Chi Minh, Vietnam 028 37267150 http://www.thepvugia.com

72 Thanh Loi Co., ltd

78 Ngo Quyen street, 10 district, Ho Chi Minh,

Vietnam 028 39573966 http://thanhloisteel.com

73 An Phu JSC

42 Truong Chinh street, Dong Da district,

Hanoi, Vietnam 02436285648 http://thepanphu.com

74 Sai Gon Steel Trading Co., ltd

685/13H Xo Viet Nghe Tinh street, Binh Thanh

district, Ho Chi Minh, Vietnam 028 62586459 http://thepsaigon.vn

75 Hai Long Steel Co., ltd

112/12 An Nhon street, Di An Town, Ho Chi

Minh, Vietnam 028 62702334 http://tonthephailong.com

76

Kim Ngan Steel Investment,

Import Export Co., ltd

82/15 Huynh Van Nghe street, Tan Binh

district, Ho Chi Minh, Vietnam 028 66706868 http://tonthephailong.com


316

http://thaihoangsteel.com/

http://thepsaigon.vn/

77 Thu Duc Steel JSC

Km9, Hanoi Highway, Thu Duc district, Ho Chi

Minh, Vietnam 028 38969612 http://www.thepthuduc.com.vn/

78 Dang Nguyen Steel Co., ltd

20B/8, Binh Thung 2 street, Di An Town, Binh

Duong, Vietnam 0274 3772628

http://satthepdangnguyen.blogspot.co

m

79 Thuan Loi Steel Co., ltd

240 Thoai Ngoc Hau street, Tan Phu district,

Ho Chi Minh, Vietnam 0909037678 http://www.thuanloisteel.com

80 Thuy Si Steel & Investment JSC

61 Nguyen Phuoc Tan street, Cam Le district,

Da Nang, Vietnam 0236 2816146 http://thuysisteel.com.vn


317

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