Final
Decision

Access Arrangement by
AGL Pipelines (NSW) Pty Ltd
for the Central West Pipeline

Date: 30 June 2000

File No:	Commissioners:	
CR99/3	Fels	Bhojani	
Application No:	Cousins	Jones	
GR9901	Martin	Shogren	

Contents
Abbreviations and glossary of terms	iv
Executive summary	vii
Key issues	vii
The initial capital base	viii
Regulatory framework	viii
The rate of return	ix
Tariff levels	x
Non-capital costs	xi
Tariff structure	xi
Underlying forecasts	xii
Incentive mechanisms, fixed principle and price path	xii
Amendments to the access arrangement	xiv
1.	Introduction	1
1.1	The assessment process	1
1.2	The NSW gas industry structure and regulatory framework	2
1.2.1	Structure of the gas industry in NSW	2
1.2.2	Regulatory framework	3
1.3	Central West Pipeline access arrangement	4
1.4	Criteria for assessing an access arrangement	5
1.5	Consultative process	6
1.5.1	Regional development issues	6
1.6	Application of the New Tax System	10
1.7	Final decision	11
2.	Rate of return	13
2.1	Code requirements	13
2.2	AGLP’s proposal	13
2.3	Submissions by interested parties	15
2.4	Commission’s considerations	16
2.4.1	Interest rates and inflation	17
2.4.2	Debt margin and cost of debt	21
2.4.3	The market risk premium	22
2.4.4	Level of debt funding	22
2.4.5	Imputation credits	23
2.4.6	Effective tax rates	24
2.4.7	Specific risk	26
2.4.8	Systematic risk	41
2.4.9	The cost of equity	43
2.4.10	Determination of a pre-tax real WACC	44
2.4.11	Determination of a post-tax nominal WACC	48
3.	Reference tariff elements	51
3.1	Overall reference tariff methodology	51
3.2	The initial capital base	54
3.2.1	Code requirements	54
3.2.2	AGLP’s proposal	55
3.2.3	Submissions by interested parties	58
3.2.4	Commission’s considerations	58
3.3	New facilities investment and capital redundancy	64
3.3.1	Code requirements	64
3.3.2	AGLP’s proposal	66
3.3.3	Commission’s considerations	67
3.4	Depreciation and inflation	68
3.4.1	Code requirements	68
3.4.2	AGLP’s proposal	69
3.4.3	Commission’s considerations	70
3.5	Non-capital costs	73
3.5.1	Code requirements	73
3.5.2	AGLP’s proposal	74
3.5.3	Submissions by interested parties	74
3.5.4	Commission’s considerations	75
3.6	Forecast revenue	76
3.6.1	Code requirements	76
3.6.2	AGLP’s proposal	76
3.6.3	Submissions by interested parties	77
3.6.4	Commission’s considerations	77
3.7	Cost allocation and tariff setting	79
3.7.1	Code requirements	79
3.7.2	AGLP’s proposal	79
3.7.3	Submissions by interested parties	80
3.7.4	Commission’s considerations	81
3.8	Tariff path and incentive structure	86
3.8.1	Code requirements	86
3.8.2	AGLP’s proposal	87
3.8.3	Submissions by interested parties	88
3.8.4	Commission’s considerations	88
3.9	Assessment of reference tariffs and reference tariff policy	95
3.9.1	Code requirements	95
3.9.2	AGLP’s proposal	96
3.9.3	Submissions by interested parties	97
3.9.4	Commission’s considerations	97
4.	Non-tariff elements	101
4.1	Services policy	101
4.1.1	Code requirements	101
4.1.2	AGLP’s proposal	102
4.1.3	Submissions by interested parties	103
4.1.4	Commission’s considerations	104
4.2	Terms and conditions	105
4.2.1	Code requirements	105
4.2.2	AGLP’s proposal	105
4.2.3	Submissions by interested parties	107
4.2.4	Commission’s considerations	108
4.3	Capacity management policy	112
4.3.1	Code requirements	112
4.3.2	AGLP’s proposal	112
4.3.3	Submissions by interested parties	112
4.3.4	Commission’s considerations	112
4.4	Trading policy	112
4.4.1	Code requirements	112
4.4.2	AGLP’s proposal	113
4.4.3	Submissions by interested parties	113
4.4.4	Commission’s considerations	113
4.5	Queuing policy	113
4.5.1	Code requirements	113
4.5.2	AGLP’s proposal	113
4.5.3	Submissions by interested parties	114
4.5.4	Commission’s considerations	114
4.6	Extensions and expansions policy	115
4.6.1	Code requirements	115
4.6.2	AGLP’s proposal	115
4.6.3	Submissions by interested parties	116
4.6.4	Commission’s considerations	116
4.7	Review and expiry of the access arrangement	118
4.7.1	Code requirements	118
4.7.2	AGLP’s proposal	119
4.7.3	Submissions by interested parties	119
4.7.4	Commission’s considerations	120
5.	Information provision and performance indicators	124
5.1	Information provision	124
5.1.1	Code requirements	124
5.1.2	AGLP’s proposal	125
5.1.3	Submissions by interested parties	125
5.1.4	Commission’s considerations	127
5.2	Key performance indicators	128
5.2.1	Code requirements	128
5.2.2	AGLP’s proposal	128
5.2.3	Submissions by interested parties	130
5.2.4	Commission’s considerations	130
6.	Final decision	132
Appendix A:	Submissions from interested parties	133
Appendix B:	Pre-tax and post-tax WACCs in a NPV regulatory framework	134
Appendix C:	Post-tax issues	140

Abbreviations and glossary of terms
Access arrangement	arrangement for access to a pipeline provided by a pipeline owner/operator that has been approved by the regulator	
AGA	Australian Gas Association	
AGLGN	AGL Gas Networks Limited 	
AGLP	AGL Pipelines (NSW) Pty Limited 	
APIA	Australian Pipeline Industry Association	
APT	Australian Pipeline Trust	
CAPM	capital asset pricing model	
CDA	competition depreciation approach	
CEZ	Central Economic Zone Inc. 	
Code	National Third Party Access Code for Natural Gas Pipeline Systems	
Commission	Australian Competition and Consumer Commission 	
Covered pipeline	pipeline to which the provisions of the Code apply	
CPI	Consumer Price Index	
CRNGWG	Central Ranges Natural Gas Working Group	
CRP	Central Ranges Pipeline	
CWP	Central West Pipeline	
DCC	Dubbo City Council	
DEI	Duke Energy International	
DOE	Department of Energy, NSW	
DORC	depreciated optimised replacement cost	
EAPL	East Australian Pipeline Ltd 	
EAPO	EAP Operations Pty Ltd 	
Forcenergy	Forcenergy Australia Pty Ltd	
GJ	gigajoule 	
GPAL	Gas Pipelines Access Law 	
GST	Goods and Services Tax	
IPARC	Independent Pricing and Regulatory Commission (ACT)	
IPART	Independent Pricing and Regulatory Tribunal (NSW)	
KPI	key performance indicator	
LTBR	long term bond rate	
MDQ	maximum daily quantity	
MRBEC	Mudgee Region Business Enterprise Centre	
MSP	Moomba to Sydney Pipeline system	
NPV	net present value	
NTS	New Tax System	
ODEC	Orana Development and Employment Council	
ORDO	Orana Regional Economic Development Organisation	
ORG	Office of the Regulator-General, Victoria	
ORR	Office of the Rail Regulator (UK)	
PJ	petajoule (equal to 1 000 000 GJ)	
PTS	Principal Transmission System	
TJ	terajoule (equal to 1 000 GJ)	
TPA	Transmission Pipelines Australia Pty Ltd	
WACC	weighted average cost of capital	

Executive summary
On 31 December 1998 AGL Pipelines (NSW) Pty Limited (AGLP) submitted a proposed access arrangement and access arrangement information for the Central West Pipeline (CWP) to the Australian Competition and Consumer Commission (the Commission) for approval under the National Third Party Access Code for Natural Gas Pipelines Systems (the Code). 
The CWP extends from Marsden to Dubbo in NSW and links part of AGL Gas Networks Limited’s (AGLGN) NSW gas distribution network to the Moomba to Sydney Pipeline system (MSP).  The CWP, which is owned by AGLP, became operational in 1998.
The access arrangement and access arrangement information describe the terms and conditions on which the company will make access to its pipeline available to third parties.  The Commission’s assessment of the proposed access arrangement has been conducted through a process of public consultation, and is based on information provided by AGLP and interested parties.
Key issues
Central issues for any access arrangement are likely to be the expected or target revenues accruing to the service provider under the regulatory regime and any incentive mechanisms that may encourage the service provider to achieve a higher level of performance than expected.  As transmission pipelines are capital intensive businesses, the determination of regulatory revenues (and hence tariffs) largely rests on the valuation of the regulatory asset base and the allowed rate of return.
The key consideration for the Commission in assessing the CWP access arrangement has been to balance appropriate incentives and rewards for AGLP with the setting of sustainable reference tariffs which would be paid for by users and prospective users of the CWP.  While the Commission recognises the risks associated with a new regional pipeline without substantial contracts it is concerned that the approval of an excessive rate of return would result in unnecessarily high tariffs.  
Under AGLP’s proposed rate of return, users and prospective users of the CWP would pay much higher transmission charges over the life of the assets than those in other NSW regional areas.  Central West customers appear to face inherently high transmission prices due to factors such as the relatively long transportation distance on the CWP and the lack of scale economies.  The Commission understands that well-head, distribution and retail charges are generally identical or similar for similar customers across NSW regions.  Accordingly, high transmission prices would be expected to work against the regional development objectives advanced by a number of interested parties for the Central West and Central Ranges areas and they would place customers at a comparative cost disadvantage.
AGLP proposed a high rate of return for the CWP (a cost of equity in the range of 12.2 to 19.0 per cent which it considers converts to a pre-tax real WACC of 10.0 per cent).  If implemented, this return would have resulted in higher tariffs over the life of the CWP, compounding the region’s cost disadvantage substantially.  The Commission considers that such an outcome would be inappropriate and inconsistent with the reference tariff principles set out in the Code.  Accordingly, it has decided not to approve AGLP’s rate of return proposal.
The Commission’s approach has been to recognise the risks AGLP faces with the CWP and, where possible, balance those risks through the regulatory framework while determining a high ex-ante cost of equity for AGLP of 15.4 per cent.  In addition to providing explicit incentives and rewards through the regulatory framework the Commission has decided not to adjust AGLP’s projected demand volumes or costs.  Most importantly, the Commission has decided to accept AGLP’s proposal to capitalise early ‘losses’ so that they can be recovered once demand grows and to allow AGLP an extended initial access arrangement period which would allow AGLP the opportunity to earn higher returns than suggested by the ex-ante regulated rate of return.
The initial capital base
Under AGLP’s net present value (NPV) price path methodology, expected early under-recovery of costs due to low early demand projections may be recouped later in the life of the pipeline by means of a mechanism that incorporates economic depreciation in the regulatory asset base.  The regulatory asset base was determined on the basis of the actual cost of construction (after adjustments for partial oversizing and a government grant) of $25.93 million (30 June 1998).  Its value has increased to the initial capital base valuation of $28.48 million (30 June 1999), and is projected to grow to a nominal residual value of $51.75 million (30 June 2010).  Notionally, the value of the initial capital base is equal to the residual value at the end of the first year of the CWP’s operations.  The Commission has decided to approve this valuation methodology as it is consistent with the regulatory framework.  
Regulatory framework
The Commission acknowledges the uncertainty that can arise in the early phase of a recently constructed pipeline without significant foundation contracts.  It is for this reason that it has decided to accept AGLP’s NPV price path approach which is designed to compensate AGLP for expected early under-performance by providing it with the opportunity to recoup those costs later in the life of the CWP.
While the potential profitability of the CWP will largely hinge on the throughput volumes AGLP achieves over time, the regulated revenue is dependent on a recovery mechanism which is based on forecast costs and revenues during the initial access arrangement period.  The Commission notes that any conservatism by AGLP when developing its demand projections might lead to windfall gains to AGLP.  The Commission has decided to accept these forecasts for the initial access arrangement period as part of its overall approach of balancing risks and rewards. 
The Commission has taken the current immaturity and low contracted capacity of the CWP into consideration when assessing the elements of the proposed access arrangement. 
For the initial access arrangement period, the Commission will accept, in addition to the recovery mechanism, a range of mechanisms and other proposals put forward by AGLP which are expected to act to its advantage.  First, while the basis for single zone pricing is examined in the body of this Final Decision, a major outcome is that it will allow AGLP to charge what it considers the market will bear throughout the regions served by the CWP.  Second, no efficiency improvement has been factored into costs over time.  Third, the Commission has specified an extended initial access arrangement period that gives AGLP the opportunity to earn a substantially higher return than is indicated by the ex-ante rate of return determined in this Final Decision.
The rate of return
The Commission has followed essentially the same methodology, including cash flow analysis, in determining the weighted average cost of capital (WACC) as it developed through an extensive consultative process as part of its 1998 approval of the Victorian natural gas transmission access arrangements.  Allowances have been made as appropriate to accommodate factors such as differences in the prevailing conditions in the market for funds and the risk involved in delivering the reference service.
The Commission has considered in particular the appropriateness of applying additional allowances, as proposed by AGLP, to the capital asset pricing model (CAPM) framework principally because of the perceived riskiness of the CWP as a newly constructed regional project without substantial foundation contracts.  AGLP initially estimated its cost of equity as being in the range of 12.2 per cent to 19.0 per cent and proposed a pre-tax real WACC of 10.0 per cent.  Following the release of the Commission’s Draft Decision AGLP submitted that a pre-tax real WACC within the range of 9.0 to 9.5 per cent would be appropriate for the CWP. 
The Commission considers that the mechanisms described above will act substantially to reduce any special risks related to the CWP’s recent greenfields status within the regulatory environment.  It notes that the Commonwealth Government has already provided a grant of $2 million which would help to defray these risks.  Nonetheless, the commercial risk remains that the CWP may never achieve sufficient throughput volumes to be viable.
As a general methodological principle the Commission considers it inappropriate to apply additional factors to the CAPM framework.  However, the Commission acknowledges concerns expressed in submissions and at the public forum it held in Dubbo that a comparatively small pipeline serving regional users may be particularly risky during its start-up years and that a higher regulated rate of return may be needed in these circumstances to encourage and reward investment in new infrastructure projects.
As suggested by AGLP and a number of interested parties, the Commission has considered in its assessment of potential specific risks the competitive tender processes conducted in 1997 to determine tariffs for the Mildura and East Gippsland natural gas distribution systems.  These parties suggested that these distribution systems might be considered broadly comparable with the CWP in that they were recently constructed to serve regional users, although they are comparatively small in size.  The Commission has also considered concerns expressed by other interested parties about the usefulness of these outcomes as benchmarks for tariff setting.  
After allowing for factors such as changes in the prevailing conditions in the market for funds since 1997, a differential remains between the published rates of return for the Mildura and East Gippsland natural gas distribution systems and (lower) returns indicated from the CAPM framework.  Notably, the rate of return proposed by AGLP is substantially above both of these rates.  In addition, the Commission notes advice provided by the ORG that the published return for East Gippsland substantially overstated the return implicit in the access arrangement.  The Commission does not consider that these tender outcomes provide a satisfactory benchmark for tariff setting.
The CAPM parameter values used in this Final Decision are those considered most appropriate for the CWP.  These generally fall near the middle of a narrow range based on the information available.  Nonetheless, the Commission has chosen higher range values for a number of these, such as the equity beta, the market risk premium and the margin on debt, to give AGLP the benefit of associated uncertainty, as part of its approach to allow AGLP to balance its risks.
In addition, the Commission has addressed specific risks identified by AGLP through a mechanism based on an extended access arrangement period of up to ten years duration in conjunction with AGLP’s explicit discretion to submit early revisions.  The Commission cannot initiate an early review.  Under AGLP’s original proposal it would retain the benefits of any out-performance for the remainder of the initial access arrangement period which would be of approximately five years duration.  As AGLP will have the opportunity to retain these benefits for an additional five years its expected rate of return will be substantially higher than is suggested by the ex ante cost of equity.  This approach specifically responds to risks attached to the CWP as a regional pipeline built without substantial foundation contracts.  
As noted earlier, the Commission has concluded that the appropriate post-tax nominal cost of equity is 15.4 per cent.  The corresponding pre-tax real WACC is 7.8 per cent.  
Tariff levels
Under AGLP’s proposal, tariffs would rise substantially in real terms in each of the first five years.  Tariffs for the years up to the year ending 30 June 2001 have already been committed to by AGLP and communicated to the market.
Based on the pre-tax real WACC proposed by AGLP of 10.0 per cent and the other assumptions underpinning the access arrangement, tariffs would then be expected to increase at an overall rate that is consistent with CPI + 1.36 per cent.  Tariffs would rise substantially faster than inflation over the rest of the life of the pipeline, resulting in Central West customers facing substantially higher transmission costs than those in other regional areas in NSW.  
Considerably lower tariffs are consistent with the rate of return determined by the Commission.  The Commission has decided to accept the tariffs proposed by AGLP for the first two years of the access arrangement.  The tariffs will then decline slightly, in real terms, by 0.06 per cent each year for the remainder of the first access arrangement period. 
Based on AGLP’s assumptions, but with a cost of equity of 15.4 per cent, tariffs would be expected to continue to decline at this rate for the rest of the life of the pipeline.  It should be noted, however, that tariffs in future access arrangement periods will depend on information available at the time of reviews.  If AGLP’s projections prove to be conservative, lower future tariffs may be justified.  Conversely, if AGLP does not achieve these projections, higher future tariffs may be justified.
Non-capital costs
AGLP has contracted EAP Operations Pty Ltd (EAPO), which carries out operations and maintenance activities on the Moomba to Sydney Pipeline (MSP), to undertake these activities on the CWP.  Members of the AGL Group provide corporate services to AGLP, which does not have any direct employees.  AGLP contends that these arrangements allow it to achieve significantly lower costs than would be possible if it operated the CWP on a stand-alone basis.
Data on expenditure on operations and maintenance and corporate services over the access arrangement period are based on forecasts and other assumptions as the CWP has little operational history.  The Commission has assessed these costs against a limited range of comparators and concluded that they are not unreasonable over the long term and can reasonably be considered to reflect costs that would be incurred by a prudent service provider acting efficiently under the framework proposed by AGLP.  Nonetheless, the Commission is concerned that AGLP’s contracting out of non-capital expenditure activities to EAPO and businesses within the AGL Group has the effect of reducing the transparency of these operations.
Tariff structure
AGLP has proposed a single pricing zone for the CWP which it states is necessary in order to encourage sufficient demand in Forbes, Parkes, Narromine and Dubbo to justify the total investment.  AGLP states that this approach reflects a regional infrastructure development objective of ensuring that no local community will be at a price disadvantage to any other.  
The Commission has derived alternative tariffs for the CWP using distance-based and stand-alone methodologies, under a range of plausible assumptions.  The assessment confirms AGLP’s contention that alternative tariff methodologies would be likely to result in a delivered price for gas that is uncompetitive with alternative fuels.  The Commission considers it unlikely that the pipeline would have been extended to Dubbo and some of the towns under these tariff structures, and that without the combined volumes of the four centres the pipeline would not be viable.  The Commission accepts the proposed single pricing zone for the CWP during the initial access arrangement period.
AGLP has proposed a one-part commodity tariff for the initial access arrangement period.  While more complex structures that incorporate capacity charges would normally be expected to be more efficient, capacity constraints are unlikely to occur on the CWP during the initial access arrangement period.  AGLP considers that a simple tariff structure based on throughput will encourage new gas users, which will help raise demand.  AGLP states that it expects that the pattern of demand will be reasonably established by the time of the first scheduled review, and that it expects to introduce capacity charges in the second access arrangement period.  In addition to the reference service, AGLP will make negotiated services available.  The Commission has decided to accept the throughput tariff for the initial access arrangement period.  
Underlying forecasts
AGLP’s regulated revenues are based on a range of assumptions.  Apart from capital costs incurred in construction of the CWP, projections of future costs and revenues for the CWP are based on a short operational history and are generally of unknown reliability.  As AGLP’s costs are almost exclusively fixed, its financial performance will be very sensitive to any disparities between the throughput projections approved by the Commission in the access arrangement and the throughput that AGLP achieves.
As part of its approach to balance AGLP’s risks and rewards, the Commission has decided to accept these forecasts for the initial access arrangement period.  AGLP would receive the benefit of any conservatism in its demand projections under the extended initial access arrangement period specified by the Commission as part of the regulatory framework to counter asymmetric risk and to provide incentives to AGLP. 
AGLP has the power to submit revisions if these projections prove to be optimistic.  In addition, the extended initial access arrangement period gives AGLP the opportunity to earn a substantially higher return than is indicated by the ex-ante rate of return determined in this Final Decision.
Incentive mechanisms, fixed principle and price path
AGLP has nominated two incentive mechanisms: the price path approach whereby tariffs set in the access arrangement apply regardless of whether underlying estimates are realised; and the level of the reference tariff, which it considers enables it to develop the market for reference and other services.
In addition, AGLP has proposed that, as a fixed principle, reference tariffs would be determined on the basis of an NPV methodology incorporating economic depreciation with a residual value at 30 June 2004 in nominal terms of $45.12 million.  The residual value is projected under the ten year access arrangement period to be $51.75 million as at 30 June 2010, an increase of $23.28 million over the valuation of the initial capital base as of 30 June 1999.  Consequently, tariffs in future access arrangement periods, which would be based on this value, would provide the opportunity to recover costs that have not been recovered by tariffs in the initial access arrangement period.
The Commission considers that incentive mechanisms can have an important role in encouraging a service provider to achieve high performance and to develop the market.  Under the price path approach, if AGLP earns greater revenue during the access arrangement period than projected, or incurs lower costs, the benefit flows entirely to AGLP.  Conversely, AGLP bears the risk of any under performance.  However, an asymmetry is introduced into the distribution of risk as only AGLP can initiate an early review of the access arrangement.  The extended initial access arrangement period is intended to increase AGLP’s opportunity to earn higher returns than are indicated by the ex ante rate of return determined by the Commission.
Nominal tariffs in $/GJ of throughput for years ending 30 June, 1999 to 2010
Year	AGLP proposal(a)	Final Decision(b)	Final Decision(b)	
	Pre-NTS	NTS(c)	
Prior to the initial access arrangement period	
1999	1.78	1.78	na	
2000	1.98	1.98	na	
Initial access arrangement period	
2001	2.17	2.17	2.38	
2002	2.37	2.37	2.60	
2003	2.58	2.44	2.67	
2004	2.78	2.50	2.75	
2005	2.89	2.57	2.82	
2006	3.00	2.64	2.90	
2007	3.12	2.72	2.98	
2008	3.24	2.79	3.07	
2009	3.37	2.87	3.15	
2010	3.50	2.95	3.24	
Notes:	(a)	AGLP proposed tariffs for the years to 30 June 2004.  The tariffs shown for later years have been estimated using AGLP’s revenue model.
(b)	Tariffs have been pre-determined for the first two years of the initial access arrangement period.  As tariffs for the remainder of the period will be determined each year according to the CPI-X formula the Final Decision tariffs shown for the years after 2002 have been estimated using the CPI-X formula and the Commission’s inflation assumption. 
(c)	From 2000-2001 the NTS cost pass through of 9.73% is added to the tariffs determined in the revenue model.
As shown in the table above, AGLP’s price path commenced before the start of the initial access arrangement period in the year ending 30 June 1999.  AGLP’s price path commences with comparatively low tariffs, a structure that AGLP contends is designed to encourage early connection by prospective users.  AGLP proposes that tariffs would then rise substantially.  While the Commission had some initial concerns about potential competition, efficiency and equity issues arising from early tariffs that would be substantially less in real terms than the average tariff charged over time on the CWP, the lower revenue requirement resulting from amendments required by this Final Decision allows a significant reduction in tariffs towards the end of the access arrangement period.  
As noted earlier, the Commission has decided to accept AGLP’s proposed tariffs for the first two years of the access arrangement.  The tariffs would then decline in real terms by 0.06 per cent each year for the remainder of the initial access arrangement period.  The table shows the reference tariffs set for the years ending 30 June 2001 to 2002 and the estimated tariffs for the years ending 30 June 2003 to 2010 calculated using the CPI-X formula and the inflation assumption used in this Final Decision.
On the basis of the revenue model assumptions, tariffs would continue to decline each year in real terms by 0.06 per cent for the remainder of the life of the assets.  However, in practice, tariffs in future access arrangement periods will depend on information available at reviews.
The introduction of the New Tax System (NTS) has resulted in an increase in CWP tariffs of 9.73 per cent from 1 July 2000.  The table compares the pre-NTS tariffs proposed by AGLP with reference tariffs determined in this Final Decision on both a pre-NTS and post-NTS basis until 30 June 2010.  
While the Commission generally supports the mechanisms proposed by AGLP, it notes that the residual value in the proposed fixed principle was derived as a function of a number of market variable elements (including forecast sales of services, the CPI, capital costs and non-capital costs).  The Commission considers that this proposal is inconsistent with the requirement of section 8.48 of the Code that a market variable element cannot be a fixed principle.  While the Commission accepts the NPV price path methodology adopted by AGLP for the CWP, it cannot accept this proposed fixed principle as part of the CWP access arrangement.  Accordingly, the Commission requires that the fixed principle be removed from the access arrangement. 
Amendments to the access arrangement
The Commission requires the following amendments to the access arrangement.
Amendment A2.1
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the revenue model must incorporate the observed inflation rate for the financial year 1998-1999 of 1.1 per cent where appropriate and an estimated rate of 3.0 per cent for 1999-2000.  In addition, AGLP must implement into its revenue model a forecast inflation rate of 2.84 per cent per year for each remaining year of the access arrangement period.  
Amendment A2.2
In order for AGLP’s access arrangement for the Central West Pipeline to be approved the WACC estimates and associated parameters forming part of the access arrangement must be amended to more accurately reflect the current financial market settings.  In particular, the post-tax nominal cost of equity should be set at 15.38 per cent, the pre-tax real WACC should be set at 7.78 per cent and the associated inflation assumption set at 2.84 per cent.
Amendment A3.1
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the value of the initial capital base must be adjusted to $28.48 million so that it reflects the impact of changes required in this Final Decision on AGLP’s costs and revenues and the actual inflation rate to the June quarter 1999.
Amendment A3.2
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, section 4.3 of the access arrangement (the reference tariff policy) must state that new facilities investment that does not satisfy the requirements of section 8.16 of the Code may be undertaken by AGLP and may be included in the capital base to the extent to which this investment satisfies section 8.16 of the Code.  
Amendment A3.3
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the reference tariff policy must be amended to allow the Commission, at the commencement of the subsequent access arrangement period, to review, and if necessary to adjust, the asset base for wholly or partially redundant assets, within the meaning of section 8.27 of the Code.  
Amendment A3.4
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the inflation index referred to throughout the access arrangement must be the CPI (All Groups – weighted average of eight capital cities). 
Amendment A3.5
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the access arrangement must include a mechanism to replace forecast inflation in the revenue model with actual CPI outcomes prior to the determination of the residual value at the end of the access arrangement period.
Amendment A3.6
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the access arrangement must state that the projected level of economic depreciation will be adjusted prior to determining the residual value of the capital base at the end of the initial access arrangement period to correct for additional revenue collected during the initial access arrangement period due to the NTS component of the CPI.
Amendment A3.7
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, AGLP must incorporate the NTS cost pass through of 9.73 per cent in the tariffs from 2000-2001 to 2009-2010.  
Amendment A3.8
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the pre-NTS reference tariffs must be specified in terms of a price path commencing with $2.17/GJ and $2.37/GJ for the years ending 30 June 2001 and 2002 respectively, with the tariffs for the remainder of the initial access arrangement period determined each year in accordance with CPI-X as defined in the Final Decision and where X has the value of 0.06 per cent.  This tariff path is consistent with the parameters specified in Amendment 2.2.  
The access arrangement must be amended to state that AGLP will notify the Commission of its proposed tariff for the forthcoming year at least 30 business days prior to the intended commencement of the tariff.  The Commission must determine if the proposed tariff complies with the CPI-X formula within 20 business days.  If the Commission does not notify AGLP of its decision within 20 business days the Commission will be taken to have approved the proposed tariff with effect from the 21st business day after lodgement with the Commission.  The tariff may not be varied unless the Commission either approves the proposed tariff or does not notify AGLP within 20 working days of its decision.
Section 3 of the access arrangement must be amended to remove the reference to CPI adjustment of AGLP’s proposed reference tariff for the year to 30 June 2004 of $2.78/GJ.  In the event that there is a gap between the reference tariff years specified in the access arrangement and the revisions commencement date, the interim reference tariff will be determined by adjusting the final year’s reference tariff in accordance with CPI-X.  
Amendment A3.9
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the reference tariff policy must be revised to remove the second clause in section 4.6 relating to the incentive mechanism. 
In addition, the reference tariff policy must state that the prospect of retaining improved returns over the initial access arrangement period provides AGLP with an incentive to increase sales and minimise the cost of providing the reference service.  
It must also state that in determining reference tariffs for the subsequent access arrangement period AGLP will ensure that users and prospective users will benefit from the increased efficiencies achieved by AGLP during the initial access arrangement period. 
Amendment A3.10
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, AGLP must remove the fixed principle from the access arrangement.  
Amendment A4.1
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, AGLP must clearly specify that schedule 2 of the access arrangement prevails over the standard service agreement.  
Amendment A4.2
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, AGLP must include in the access arrangement the prudential requirements relevant for users and prospective users.  
Amendment A4.3
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the words ‘or the Australian Pipeline Trust’ must be inserted after ‘AGLP’ in sections 2.3(a) and (c) of the access arrangement.
Amendment A4.4
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, AGLP must amend the access arrangement to state that AGLP will, if recommendations by the AGA Gas Specification Working Group to adopt more flexible gas specifications in south-eastern Australia are approved, substitute that specification for the specification currently set out in schedule 3 of the access arrangement, subject to obligations under existing service agreements.  
Amendment A4.5
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, section 7.1 must be revised to state that should AGLP proceed with the Central Ranges Pipeline it will decide, after consultation with the Commission, whether to include the Central Ranges Pipeline in the access arrangement through the extensions/expansions policy. 
Amendment A4.6
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, AGLP must specify in the access arrangement that it will notify the Commission of the commencement of services provided through expansions and extensions to the Central West Pipeline.  
Amendment A4.7
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, section 9.2 of the access arrangement must be amended such that the revisions submission date is 9 years and 6 months after the commencement of the access arrangement. 

1.	Introduction
On 31 December 1998 AGL Pipelines (NSW) Pty Limited (AGLP) submitted a proposed access arrangement and access arrangement information for the Central West Pipeline (CWP) to the Australian Competition and Consumer Commission (the Commission) for approval under the National Third Party Access Code for Natural Gas Pipelines Systems (the Code).  The CWP extends from Marsden to Dubbo in NSW and links part of AGL Gas Networks Limited’s (AGLGN) NSW gas distribution network to the Moomba to Sydney Pipeline system (MSP).  The CWP, which is owned and operated by AGLP, became operational in 1998.
The access arrangement and access arrangement information describe the terms and conditions on which the company will make access to its pipeline available to third parties.  The Commission’s assessment of the access arrangement has been conducted in accordance with the requirements set out in the Code and has been based on information provided by AGLP and interested parties.
This document sets out the Commission’s final decision and related amendments under section 2.16 of the Code for AGLP’s access arrangement.
This introduction includes:
•	a description of the current assessment process;
•	a description of the NSW gas industry structure and regulatory framework;
•	an outline of the CWP access arrangement submitted for approval;
•	a summary of the criteria for assessing an access arrangement under the Code;
•	a summary of the consultative process undertaken as part of the Commission’s assessment; 
•	a discussion on the impact of the New Tax System (NTS) on the access arrangement; and
•	the Commission’s final decision. 
1.1	The assessment process
The access arrangement and access arrangement information set out the terms and conditions on which AGLP will make access on the CWP available to third parties during the initial access arrangement period which AGLP proposes will last approximately five years.  AGLP will, however, have the discretion to submit revisions earlier than the scheduled review, and has indicated that it may do so in the event that it extends the CWP to Tamworth.
The Commission’s current assessment process relates to the initial access arrangement period.  However, it will also impact on subsequent access arrangement periods.  In particular, AGLP proposed a fixed principle that would not be subject to change, without AGLP agreement, when AGLP submits reviews to the access arrangement. 
Under the Code the Commission is required to:
•	inform interested parties that it has received the access arrangement from AGLP; 
•	publish a notice in a national daily newspaper which at least describes the covered pipeline to which the access arrangement relates; states how copies of the documents may be obtained; and requests submissions by a date specified in the notice;
•	after considering submissions received, issue a draft decision which either proposes to approve the access arrangement or not to approve the access arrangement and state the amendments (or nature of the amendments) which have to be made to the access arrangement in order for the Commission to approve it.  Submissions would be sought again following release of the Commission’s draft decision;
•	after considering any additional submissions and a revised access arrangement (if submitted), issue a final decision that it either approves or does not approve the access arrangement (or revised access arrangement) and states the amendments (or nature of the amendments) which have to be made to the access arrangement (or revised access arrangement) in order for the Commission to approve it; and
•	if the amendments are satisfactorily incorporated in a revised access arrangement, issue a final approval.  If not, the Commission must draft and approve its own access arrangement.
1.2	The NSW gas industry structure and regulatory framework
1.2.1	Structure of the gas industry in NSW
Briefly, the industry comprises: 
•	the Cooper Basin Producers in South Australia which have supplied natural gas to NSW since 1976 via the MSP.  The MSP is owned by East Australian Pipeline Ltd (EAPL) and its services are marketed by East Australian Pipeline Marketing Pty Ltd (EAPM).  Natural gas is delivered to the city gate at Wilton, with spur lines to several regional centres (including Lithgow, Canberra, Yass and Wagga Wagga);
•	the Interconnect pipeline, which links the MSP and the Victorian natural gas system, was commissioned in 1998 and provides a further potential source of gas supply into NSW from the Gippsland Basin;
•	Duke Energy International (DEI) is constructing the Eastern Gas Pipeline to ship gas from Longford to Port Kembla and Sydney with operation expected by September 2000;
•	the CWP which is a small (255 km) spur line from Marsden to Dubbo, the subject of this access arrangement; 
•	AGLGN which distributes natural gas to most major centres in NSW, including Sydney, Newcastle and Wollongong; 
•	the Albury Gas Company Ltd which distributes natural gas in Albury, and Great Southern Energy Gas Networks Pty Ltd which distributes natural gas in Wagga Wagga; and
•	20 authorised suppliers of gas (including retailers).
The Australian Gas Light Company (AGL) is a publicly listed corporation, which together with its wholly owned subsidiaries (including AGLGN), is referred to as the ‘AGL Group’.  Until recently AGL also owned AGLP and was the majority shareholder of EAPL and EAPO.  
An offer document was lodged with the Australian Securities and Investments Commission on 5 May 2000 with regard to the establishment of the Australian Pipeline Trust (APT).  AGL advised in the offer document that it would transfer its gas transmission pipelines (including the CWP and the MSP) to the trust and that it would hold at least a 30 per cent interest in APT.  Trading of units of the APT on the Sydney Stock Exchange commenced on 13 June 2000.
The AGL Group currently provides general, administration and marketing services to AGLP.  EAPO, which carries out operations and maintenance activities on the MSP, is also contracted by AGLP to undertake these activities on the CWP.  AGLP does not have any employees.  AGL Infrastructure Management Pty Limited, a company wholly owned by AGL, would provide technical and marketing services to APT.
1.2.2	Regulatory framework
The main legislation and relevant documents regulating access to the NSW gas transmission industry are: 
•	the Code, under which transmission service providers are required to submit access arrangements to the Commission for approval;
•	the Gas Pipelines Access (South Australia) Act 1997; and
•	the Gas Pipelines Access (New South Wales) Act 1998. 
Code and appeals bodies in NSW with respect to transmission pipelines are:
•	the Commission - regulator and arbitrator; 
•	the National Competition Council - Code advisory body;
•	the Commonwealth Minister - Coverage decision maker;
•	the Federal Court – judicial review; and
•	the Australian Competition Tribunal – administrative appeal.
The Independent Pricing and Regulatory Tribunal (IPART) is the regulator and arbitrator in NSW with respect to distribution pipelines.  IPART is at present reviewing AGLGN’s 1997 access undertaking.  The access undertaking, which was approved under the NSW Third Party Access Code for Natural Gas Distribution Networks (NSW Code), is deemed to be an access arrangement in force under the Code.  The review is being conducted under the Code, but subject to a number of provisions of the NSW Code.  This review also includes a number of transmission pipelines that are deemed to be distribution pipelines until 1 July 2002.  These are: Wilton to Horsley Park; Horsley Park to Plumpton; Plumpton to Killingworth; Killingworth to Walsh Point; and Wilton to Wollongong.
The Independent Pricing and Regulatory Commission (IPARC) is currently reviewing a proposed access arrangement submitted by AGLGN and AGL Gas Company (ACT) Ltd relating to the natural gas distribution system in the ACT, Queanbeyan and Yarrowlumla.
IPART and IPARC released draft decisions with respect to these access arrangements respectively in October 1999 and March 2000. 
1.3	Central West Pipeline access arrangement 
Section 2 of the Code specifies that the service provider is required to submit a proposed access arrangement (and associated access arrangement information) to the relevant regulator for approval.  The service provider is defined as ‘a person who owns (whether legally or equitably) or operates the whole or any part of a Pipeline’.  AGLP currently owns the CWP.  The access arrangement provides for ownership of the CWP to change over time.  The Commission expects that it will receive notification of any change in ownership or operation of the CWP as those changes occur.  
Development of the Central West project, which includes the transmission and distribution of gas to the Forbes, Parkes, Narromine and Dubbo environs, was facilitated through the Federal Government’s Regional Development Program, which provided funding of $2 million to the CWP through the Orana Regional Economic Development Organisation (ORDO).  
The CWP transports gas from the Marsden off-take on the MSP to five off-take points at Forbes, Parkes, Narromine, Dubbo and Dubbo West.  AGLGN reticulates the delivered gas in its systems in the Forbes, Parkes, Narromine, Dubbo and Wellington local government areas.
Construction of the CWP commenced in late 1997, with the sections from Marsden to Parkes and from Parkes to Dubbo being commissioned on 29 April 1998 and 1 August 1998 respectively.  Gas first flowed through the Forbes, Parkes and Dubbo off-takes on 1 May 1998, 2 May 1998 and 4 August 1998 respectively.  As the CWP came into operation shortly before 14 August 1998 (when the Code first came into operation in NSW) it is considered to be an existing pipeline for the purposes of valuing the initial capital base.
The CWP has a maximum operating pressure of 10.2MPa.  It is currently uncompressed, with a maximum delivery capability of 10.1 TJ/day (3.7 PJ/year).  Its outside diameter is 219.1mm (eight inch) for the southern leg (130km) from Marsden to Alectown, and 168.3mm (six inch) for the remaining 125km to Dubbo. 
1.4	Criteria for assessing an access arrangement
The Commission may approve a proposed access arrangement only if it is satisfied that it contains the elements and satisfies the principles set out in sections 3.1 to 3.20 of the Code, which are summarised below.  An access arrangement cannot be rejected by a regulator solely on the basis that it does not address a matter that section 3 of the Code does not require it to address.  Subject to this, the Commission has a broad discretion in accepting or opposing an access arrangement.  
An access arrangement must include a policy on the service or services to be offered which includes a description of the service(s) to be offered.  The policy must include one or more services that are likely to be sought by a significant part of the market and any service(s) which in the Commission’s opinion should be included in the policy.  To the extent practicable and reasonable, users and prospective users must be able to obtain those portions of the service(s) that they require, and the policy must allow for a separate tariff for an element of a service if requested.
An access arrangement must also contain one or more reference tariffs.  A reference tariff operates as a benchmark tariff for a particular service and provides users with a right of access to the specific service at the specific tariff.  Tariffs must be determined according to the reference tariff principles in section 8 of the Code. 
An access arrangement must also include the following elements:
•	terms and conditions on which the service provider will supply each reference service;
•	a statement of whether a contract carriage or market carriage capacity management policy is applicable;
•	a trading policy that enables a user to trade its right to obtain a service (on a contract carriage pipeline) to another person; 
•	a queuing policy to determine users’ priorities in obtaining access to spare and developable capacity on a pipeline; 
•	an extensions/expansions policy to determine the treatment of extensions and expansions of a pipeline under the Code; 
•	a date by which revisions to the arrangement must be submitted; and 
•	a date by which the revisions are intended to commence.  
In considering whether an access arrangement complies with the Code, the Commission must (pursuant to section 2 of the Code) take into account:  
•	the legitimate business interests and investment of the service provider;
•	firm and binding contractual obligations of the service provider or other persons (or both) already using the covered pipeline;
•	the operational and technical requirements necessary for the safe and reliable operation of the covered pipeline;
•	the economically efficient operation of the covered pipeline;
•	the public interest, including the public interest in having competition in markets (whether or not in Australia);
•	the interests of users and prospective users; and
•	any other matters that the Commission considers are relevant.  
1.5	Consultative process
Pursuant to the requirements of the Code, in January 1999 the Commission published a notice in a national newspaper and informed interested parties that it had received AGLP’s gas transmission access arrangement for the CWP, and invited, received and considered submissions from interested parties.  In addition, in order to help foster the consultative process, the Commission published the notice in regional newspapers, and released an Issues Paper in February 1999.  AGLP provided additional access arrangement information in February and June 1999.  Copies of relevant documents were made available from the Commission, including from its website.
On 10 September 1999 the Commission released its Draft Decision under section 2.13(b) of the Code.  The Commission proposed not to approve the CWP access arrangement in the form proposed by AGLP and identified amendments that would need to be incorporated in a revised access arrangement in order for the Commission to approve it under section 2.16(c) of the Code.
Pursuant to section 2.14 of the Code, the Commission provided copies of its Draft Decision to interested parties and requested submissions to be received by 8 October 1999.  The Commission sought to further promote and facilitate public consultation by holding a public forum in Dubbo on 6 October 1999 and extended the due date for submissions to 29 October 1999.
Six submissions were submitted prior to, and 18 following, release of the Draft Decision.  These are listed at Appendix A.
1.5.1	Regional development issues
The major concern expressed at the public forum and in a number of submissions by local councils, regional development bodies and parliamentarians was that the regulated rate of return proposed in the Draft Decision might prove inadequate to support infrastructure development in regional areas.  Most of these parties focused on the proposed extension of the CWP to Tamworth and the associated extensions to the distribution network.  Supply of natural gas to regional areas was seen as a potentially significant stimulus to economic growth and employment and to reductions in greenhouse gas emissions.  Notably, comments regarding the rate of return were generally phrased in terms of the proposed pre-tax real WACC figure rather than the cost of equity.
The Orana Development and Employment Council (ODEC) stated: 
Based on previous assumptions of a long term 10% return, progress to extend the arterial line to Tamworth was commenced.  In fact to accommodate future expansion the arterial line from Marsden to Tomingley was increased in diameter from 6” to 8”.
The draft ruling will kill off the Central Ranges project.  This line has always shown to be very marginal and to impose a 7.5% cap on the weighted average cost of capital would stop the project.  Federal Government taxation changes are also placing immense pressure on long term viability of infrastructure projects, like the Central Ranges natural gas extension.
The overall social cost and lost employment affects on the towns to be serviced by the Central Ranges line would be considerable.  The towns of Gilgandra, Mudgee, Coonabarabran, Gunnedah, Dunedoo, Werris Creek, Coolah and Tamworth would be directly affected by cancellation of the project.  These towns currently do not have natural gas as an alternate energy source. 
The Central Ranges Natural Gas Working Group (CRNGWG) raised a number of similar issues while arguing that the Central Ranges would be the ‘poor cousins’ of regional economic development if the Central Ranges Pipeline (CRP) did not proceed because they would be at a comparative disadvantage to other regions of NSW that already have natural gas.  The CRNGWG expressed the rationale for its submission as follows:
When tenders were called to bring natural gas to the Central West region no company other than AGL was prepared to fulfil the contract and AGL were selected as the preferred tenderer.  No company other than AGL have approached the CRNGWG or been prepared to extend the pipeline to the Central Ranges region.  Only AGL were prepared to take the financial risk involved in the pre-feasibility and EIS for the Central Ranges and also spend the additional $2 million involved in laying a larger than required pipe in the Marsden to Dubbo line, so that the Central Ranges project could proceed.  This decision by AGL was made expecting the WACC to be set at approximately 10.5% which was the rate at that time.  Changing the rate at a later time increases the risk for infrastructure providers. 
The Mudgee Region Business Enterprise Centre Inc (MRBEC) also suggested that the rate of return proposed in the Draft Decision might jeopardise the CRP.  MRBEC commented: 
Over 700,000 living in eight Council areas and more than fourteen towns in this region may be penalised if your decision is not reviewed.
The growth in employment which would result from the arrival of natural gas to this region from expanding business and industry, will help offset the decreases in population and employment that many town of the region have suffered in recent years. 
The Central Economic Zone Inc (CEZ) also explicitly requested that the Commission take regional development of the Central Ranges area into consideration:
The vital issue of community development must take precedence over arbitrary regulatory regimes, on the basis that the Central Ranges will be the only remaining regional area in NSW which does not have access to a natural gas supply, should the ACCC cap on the Central West pipeline result in AGL withdrawing from this project.
The “Social Benefits” and flow on employment and economic development to a region upon the arrival of natural gas are also significant.  The eight Member Councils of the Central Ranges natural gas project would be justifiably incensed if years of work to find a company who would bring natural gas to their regions was jeopardised by the decision on the Central West pipeline WACC being determined at 7.5%. 
The Commission has considered the arguments advanced by interested parties who have contended, amongst other things, that Central Ranges regional development issues should be taken into account when determining the regulated rate of return applicable for the CWP.  The Commission appreciates that these parties attach a high priority to regional development issues.  
Under the Gas Pipelines Access Law (GPAL) the Commission is the designated relevant regulator for transmission pipelines (other than in WA) and it is bound by the principles and criteria set out in the Code.  Accordingly, the Commission has considered the scope for Central Ranges regional development issues to contribute to its assessment of the regulated rate of return for the CWP within the framework of principles and criteria provided by the Code.  The relevance of the public interest criteria set out in section 2.24(e) of the Code was canvassed at the public forum the Commission held in Dubbo and subsequently in submissions.  This section states that in assessing an access arrangement, a regulator must consider ‘the public interest, including the public interest in having competition (whether or not in Australia)’.   
Parry Shire Council has expressed concern about the Commission’s interpretation of this public interest criteria, stating:
Council is most concerned that the Commission is adopting an approach to the ‘public interest’ test that is more focused on an appropriate administrative outcome, rather than seeking to measure outcomes in terms of investment viability.  The Commission appears to be taking a narrow, restrictive ‘public interest’ test rather than one which takes account of the true wider social benefits and impacts.
Your public interest test application must consider the lack of employment in rural centres and the further decreasing employment opportunities, with the loss of youth as they move to larger cities in search of work.  The last intercensal period has witnessed a population loss of over 10,000 people within the service region of the CRP.  This negative growth compounds the loss of banking, postal, shopping and other essential community and health services.  
The Commission notes concerns that if returns allowed to regulated service providers are too low a likely outcome would be a sub-optimal level of infrastructure investment.  This concern would appear to be consistent with the fundamental regulatory objective of balancing the interests of users and the legitimate business interests of the service provider.  However, interested parties appear to be advocating a higher rate of return for AGLP than would be normally justified under the reference tariff principles set out in section 8 of the Code as an incentive for investment in regional areas, in order for these regions to be able to compete against other regions which are already supplied by natural gas in attracting business.  However, too high a rate of return may also result in a sub-optimal level of infrastructure investment. 
While interested parties have encouraged the Commission to support high rates of return for regional infrastructure with a view to encouraging further investment, little focus has been placed on the nexus between the rate of return and the long-term tariff level.  This may reflect a lack of concern about tariff levels set under the Code.  For example, ODEC has stated that one of the key criteria for AGL’s successful tender was ‘prices not greater than those available to similar clients in Sydney’.  
The Commission understands that ODEC and other regional interested parties may have been comforted by the view that the tender process put a ceiling on AGLP’s tariffs.  Accordingly, the Commission sought confirmation from AGLP of any undertakings given regarding tariff levels.  While AGLP has requested that the details of its reply be kept confidential, the Commission understands that the pricing ceiling was expressed in terms of a goal rather than an undertaking.  As the information provided by AGLP in support of its access arrangement and (higher) future tariffs is inconsistent with this goal, it is the reference tariffs determined under the Code that will set a ceiling on AGLP’s charges.  Some users and prospective users may, however, be able to negotiate with AGLP to achieve a tariff that is lower than the reference tariff.
A crucial element in the inter-regional competitiveness discussed in submissions will be the price of delivered gas.  Accordingly the Commission has examined the likely impact of the regulated rate of return on the CWP (and potentially the Tamworth extension) on the price competitiveness of gas supplied in that and other NSW regions.
With few exceptions, gas delivered in regional NSW is transported from the Cooper Basin in SA through the MSP and distributed by AGLGN.  While AGL now faces some retail competition, the retail margin makes up a comparatively small part of the delivered price of gas.  The Commission understands that Cooper Basin (and Gippsland Basin) well-head prices are essentially uniform and that AGLGN’s country tariff structure applies similarly across these regions.  Accordingly, differences in the delivered price of gas in regional NSW depend almost exclusively on the level of transmission tariff.  All these users pay EAPL according to a distance-based tariff for transmission through the MSP, with users at the most distant off-takes (such as Griffith and Lithgow) proposed to pay approximately $1.00/GJ (in 2001, with an 80 per cent load factor).  Customers using less of the MSP would be charged proportionately less.  
In addition to paying EAPL approximately $0.65/GJ for transporting gas 942 km from Moomba to Marsden, under a range of plausible assumptions CWP users would pay AGLP over $2.00/GJ for delivery between Marsden and Dubbo (a maximum of 255 km), with the actual rate dependent on the level of the regulated rate of return.  Under AGLP’s proposal, the average tariff in real terms over the life of the assets would be expected to be approximately $2.80/GJ (in 2000 dollars), which indicates a combined transmission tariff of approximately $3.45/GJ, substantially higher than the tariff applicable in other NSW regions.
Achievement of the regional development goals identified in submissions will be dependent not only on a region’s ability to attract infrastructure investment but also on the competitiveness of the services that will be provided by those assets.  To the extent that the comparatively high cost of delivering gas to the Central West region is largely driven by a relative absence of the economies of scale achieved on the MSP, CWP (and potentially CRP) customers appear to be faced with a fundamentally more expensive energy source than those with direct access to the MSP.
The Commission is concerned that AGLP’s proposal for a high rate of return would result in unnecessarily high tariffs on the CWP which would be borne by existing and future users who would face unnecessarily high costs, and which would tend to inhibit investment and growth in the region.  The Commission has sought to balance objectives such as the provision of incentives for investment in regional areas and the achievement of competitive tariffs.  Its assessment of the level of tariffs and the appropriate returns and incentives for AGLP in terms of the principles and criteria set out in the Code are provided in chapters 2 and 3 of this Final Decision.  The Commission has decided to approve a number of mechanisms that provide incentives to AGLP which are expected to provide AGLP with benefits that are commensurate with the risks associated with the CWP.
The Commission has also considered arguments in submissions that building of the CRP is dependent on the Commission providing a rate of return that will encourage AGLP to undertake the investment.  Interested parties have expressed concern that the return proposed in the Draft Decision may not be sufficient for AGLP to continue with the planned CRP. 
As noted in chapter 4 of this Final Decision, the CRP is not included in this proposed access arrangement.  The Commission will assess the CRP in the event that AGLP lodges a revision to the CWP access arrangement to include the CRP or a separate CRP access arrangement.  This is the appropriate process under the Code. 
While it may be expected that an extension to a pipeline attracts the same rate of return as the pipeline itself, the Code does allow for users to make a capital contribution to the service provider for the building of the extension.  Users may also pay a surcharge for services, effectively providing the service provider with a return greater that that determined by the regulator.  In relation to the CRP, these issues can be considered in the event that AGLP lodges a revision to include that extension in the CWP access arrangement.  If the CRP is not covered (either through the CWP access arrangement or a separate access arrangement) its rate of return will not be regulated under the Code.
1.6	Application of the New Tax System
Legislation to implement a broad-based indirect tax was passed by the Commonwealth Parliament in June 1999.  The New Tax System (NTS) has been introduced to implement a Goods and Services Tax (GST) to replace a number of taxes such as the Wholesale Sales Tax (WST) and reduce marginal income tax rates.  
Under the provisions of the Trade Practices Act 1974 the Commission has an economy wide role with respect to ensuring that there is no price exploitation in relation to price changes resulting from the NTS changes.  The Commission has formulated general guidelines regarding price exploitation.  It has also has published more specific information to assist compliance by regulated industries.
In assessing the CWP access arrangement the Commission has considered the potential impact of the move to the NTS in terms of the reference tariff principles established in section 8 of the Code.  In particular, the Commission has been guided by the objective set out in section 8.1(a) that the service provider be provided the opportunity to earn a stream of revenue that recovers the efficient costs of delivering the reference service over the expected life of the assets used in delivering that service.  The Commission notes that tariffs that are higher than that required to cover efficient costs would not be in the interests of users and prospective users, a factor that it must consider pursuant to section 2.24(f) of the Code.  The Commission considers that the introduction of the NTS should be neutral with respect to the stream of revenue recovered by AGLP.  This requirement is parallel with those of the Price Exploitation Guidelines.
Two separate adjustment processes are required to ensure that the introduction of the NTS is revenue neutral to AGLP:
•	pre-NTS tariffs will be increased commensurate with a cost pass through that reflects the net impact of the introduction of the NTS.  Tariffs would be adjusted from 1 July 2000 when the GST commences in accordance with the increase resulting from the GST less reductions arising from the removal of the WST and other taxes (primary and second round effects); and
•	the impact of the NTS on the CPI adjustment used in AGLP’s revenue model will be estimated and deducted from the CPI.  This is required because an unadjusted CPI would reflect economy wide changes in cost structures for which AGLP is compensated via the cost pass through adjustment.  
Further discussion regarding this aspect of the NTS can be found in section 3.4 of this Final Decision. 
1.7	Final decision
The Commission has now made a final decision under section 2.16(b) of the Code that it does not approve the CWP access arrangement in its current form, and has set 31 July 2000 as the date by which a revised access arrangement must be lodged.  
In order for the Commission to approve a revised access arrangement under section 2.19, the Commission must be satisfied that the amendments specified in this Final Decision have been incorporated.  These amendments are set out in the relevant sections in the Final Decision and in the Executive Summary.  The Commission’s reasons for these amendments are provided in the relevant sections of this Final Decision.
If AGLP does not submit a revised access arrangement by the required date, or does so and the Commission is not satisfied it incorporates amendments specified in this Final Decision, the Commission must draft and approve its own access arrangement (section 2.20 of the Code).  Such a decision is subject to merits review by the Australian Competition Tribunal under the GPAL. 
The remainder of this Final Decision comprises: the Commission’s consideration of the regulated rate of return (chapter 2); its analysis of the reference tariffs elements of the access arrangement (chapter 3); the assessment of the access arrangement in terms of the non-tariff elements in the Code (chapter 4); information provision and performance indicators (chapter 5); and chapter 6 sets out the Commission’s final decision.  

2.	Rate of return
2.1	Code requirements
The Code (sections 8.30-8.31) states that the rate of return used should provide a return which is commensurate with prevailing conditions in the market for funds and the commercial risk associated with the provision of reference services.  As an example, it suggests using a weighted average of the returns applicable to each type of capital (equity, debt and any other source of funds) with such returns, in the case of equity, determined on the basis of a well accepted financial model such as the CAPM.  The financing structure assumed should also reflect standard industry structures and best practice.  However, a service provider may adopt other approaches if the regulator is satisfied that the objectives regarding the design of reference tariffs and the reference tariff policy set out in section 8.1 of the Code are met.  
2.2	AGLP’s proposal
AGLP has adopted a WACC approach and takes the Commission’s decision on the Victorian transmission systems (which adopted a post-tax nominal cost of equity of 13.2 per cent and set a pre-tax real WACC of 7.75 per cent) as a benchmark.  AGLP has added allowances for self-insurance costs and perceived regulatory asymmetry to the conventional CAPM based return benchmark.  It raises several factors that it believes are evidence of the CWP involving greater risk than the Victorian transmission system and consequently proposed a cost of equity in the range of 12.2 to 19.0 per cent which it considers is consistent with a pre-tax real WACC of ten per cent.  
AGLP has proposed a price path profile over time so that, given forecast volumes and costs, the cash flows are consistent with achieving the benchmark WACC.  The application of economic depreciation to this framework, as proposed by AGLP, enables the capitalisation of under recovery of costs that occur due to the low forecast initial volumes.  Thus, provided that the market for natural gas in the Central West region does develop, any early under-recovery of revenues may be compensated by higher revenues later in the life of the pipeline. 
In its model, AGLP expressed dollar amounts in real terms with the real rate of return the critical parameter for revenue determination over the long term.  The underlying parameters, equations and other assumptions used by AGLP within the CAPM/WACC framework are summarised below in Table 2.1. 
Table 2.1:	Parameter ranges proposed by AGLP for WACC calculations
Parameter			Ranges(a)	
			High	Low	
General 		Inflation(b)	2%	3%	
Economic	T	Corporate Tax Rate	36%	36%	
Parameters		Imputation Take Up Rate	25%	50%	
Gearing	D	Debt	50	60	
	E	Equity	50	40	
Cost of Debt	rf	10 Year Bond Rate	5.2%	4.8%	
	rf	2010 CPI Linked Bond Rate	3.5%	3.2%	
	DM	Debt Margin	1.45%	1.0%	
		Bank Costs	0.5%	0.5%	
Nominal Cost of Debt		Based on 10 Year Bond Rate	6.65%	5.8%	
		Based on CPI Linked Bonds	7.45%	6.7%	
Cost of Equity	rm-rf	Market Risk Premium	7.0%	6.0%	
		Asset Beta	0.9	0.55	
	e	Equity Beta	1.66	1.23	
		Margin for Asymmetric Risk	1.0%	0	
		Margin for Self Insured Risk	0.5%	0	
Nominal Cost of Equity	re	Based on 10 Year Bond Rate	18.2%	12.2%	
	re	Based on CPI Linked Bonds	19.0%	13.1%	
WACC Results		Post-tax nominal WACC	10.7%	6.0%	
		Pre-tax nominal WACC	16.9%	9.4%	
		Pre-tax real WACC	13.9%	6.8%	
Source:	Revised Access Arrangement Information, p. 13.  
Notes:	(a)	Parameter values have been categorised according to their impact on the WACC estimate, rather than on the basis of their relative size.
(b)	AGLP believes an inflation range of 2%-3% is acceptable, however all calculations in this table use an inflation rate of 2.5%.  
As noted earlier, AGLP has modified the usual CAPM calculation of the nominal cost of equity by adding a measure for asymmetric risk and an allowance for self insurance.  Consequently, AGLP’s nominal cost of equity (re) equation is: 
re = rf  + e (rm - rf ) + asymmetric risk + self insurance
The nominal cost of equity is a key variable in determining the rate of return.  AGLP has defined the post-tax nominal WACC (W) by the formula: 

AGLP has used these formulae to calculate a nominal post-tax WACC.  It subsequently adjusted, via formulae, first for tax and then for inflation, to achieve a pre-tax real rate of return. 
Based on its analysis, AGLP suggested that a range of 7.7 to 11.5 per cent for the pre-tax real WACC is reasonable.  AGLP initially nominated ten per cent as most appropriate, on the basis that a figure in the lower half of the range could be a disincentive for investment and that the lower end of the range was similar to that considered appropriate for the Victorian transmission systems.  According to AGLP this would suggest that the risk associated with the CWP is the same as that for the Victorian transmission system.  AGLP states that it does not believe this to be true.  
Following the release of the Draft Decision AGLP expressed concern relating to the calculation and quantum of the pre-tax real WACC in that decision (of 7.5 per cent).  In essence, AGLP submitted that: 
•	the Draft Decision is inconsistent with other regulatory decisions; 
•	the values given to some of the CAPM variables are not appropriate; 
•	the Draft Decision does not accommodate the risk associated with the CWP; and
•	the methodology adopted by the Commission in determining the WACC is unclear. 
In addition, AGLP submitted that a pre-tax real WACC within the range of 9.0 to 9.5 per cent would be more appropriate for the CWP.  The issues raised by AGLP are discussed further in the relevant sections within this chapter. 
2.3	Submissions by interested parties
Forcenergy Australia Pty Ltd (Forcenergy) has noted that the Code requires that the rate of return used to determine tariffs provides a return to a service provider that is commensurate with prevailing market conditions.  It believes that there is much readily available information in the market to suggest that the proposal by AGLP is not consistent with current market conditions.  
In reference to the WACC, Forcenergy states: 
There is little evidence that an increase in the current WACC of 7.5% to 7.75% is warranted.  The recent purchase prices for the gas distribution assets in Victoria at an average EBIT multiple of 15 is testimony that the ORG was generous.  The Victorian Government had to balance the following two conflicting objectives: 
•	maximise the price received from privatisations
•	establish a competitive gas market with commensurate value to end users
The trade-off was a WACC of 7.75%.  This number is not necessarily appropriate for all other service providers in Australia who own natural monopolies.  
Further comments provided by Forcenergy on the nominal cost of equity, for example, appear to be relevant to AGLGN rather than AGLP. 
In a joint submission, the Australian Pipeline Industry Association (APIA) and the Australian Gas Association (AGA) have stated that they consider that there is a number of inconsistencies and fundamental flaws in the Commission’s Draft Decision.  While these are addressed in the relevant sections of this chapter, the key concerns raised are: 
•	the Draft Decision implies a much lower rate of return (than 7.5 per cent) is appropriate for established gas pipelines; 
•	the Commission has not accommodated the risk of the CWP fully; and
•	the methodology implemented by the Commission results in a lack of transparency regarding the calculation of the WACC. 
In contrast, BHPP submitted that it supported the methodology used by the Commission in determining the appropriate WACC.  See section 2.4.10 of this Final Decision for further discussion.  
2.4	Commission’s considerations
The WACC is a critical element of pricing principles since it determines the prospective profitability of the service provider in relation to a particular pipeline.  Its value should be determined on the basis of prevailing financial market benchmarks taking into account the level of risk involved in establishing the service infrastructure.  If it is too low, the service provider would not expect to be able to recover the efficient and fair costs of service provision and perhaps, more importantly, may not have adequate incentive to augment facilities when appropriate.  However, if it is too high, the service provider would have a strong incentive for over-capitalisation and the opportunity to derive monopoly rents.  Such issues are directly relevant to the reference tariff objectives enunciated in section 8.1 of the Code. 
The issues associated with the determination of the WACC were discussed extensively in the Commission’s decision on the Victorian access arrangements.  At that time, the Commission indicated that on some issues it preferred a different approach to that proposed by the applicants for the Victorian access arrangements.  However, the Commission recognised that an alternative approach should be subject to wide examination and as such was reluctant to make changes at that time without this further work. 
The Draft Regulatory Principles has been developed for, and in accordance with, the National Electricity Code (NEC).  Some issues discussed in the Draft Regulatory Principles are specific to the national electricity market.  However, other issues, such as those relating to the rate of return are relevant to the Commission’s regulatory work in relation to regulated businesses other than electricity.  While AGLP has used the Commission’s Victorian Final Decision as a guide in developing the access arrangement for the CWP, the Commission is also guided by the principles it has developed in the Draft Regulatory Principles as they indicate the Commission’s general approach to economic regulation.  In particular, the Commission’s preference in using a post-tax nominal WACC is not limited to the electricity sector.   
The post-tax nominal WACC formula adopted by AGLP has been noted above.  AGLP has converted from a post-tax nominal WACC to a pre-tax real WACC by adjusting for tax and then inflation.  However, as noted in the Victorian Final Decision, the Commission does not consider that the formulae for the post-tax WACC or the conversion to a pre-tax real WACC are appropriate.  In that instance, the Commission used cash flow modelling to derive the pre-tax real WACC that yielded the post-tax nominal cost of equity indicated by the CAPM as the return over the lifetime of the assets when the volume forecasts and economic assumptions used to derive the WACC are fulfilled.  The Commission indicated in its Victorian Final Decision that a post-tax WACC framework is preferred to a pre-tax WACC framework.  Further discussion on this can be found in the Draft Regulatory Principles.  This view has been reiterated in the CWP Draft Decision.  
This chapter will discuss both the pre-tax real WACC and the post-tax nominal WACC.  However, regardless of whether a pre-tax real or post-tax nominal WACC is used by service providers and the Commission, the rate of return critical to the regulatory framework is the post-tax nominal cost of equity from the CAPM.  The post-tax cost of equity determines whether investors will be willing to advance equity to finance the capital infrastructure required to provide services.  
The determination of the cost of equity requires certain assumptions regarding the relevant parameters.  The values assigned to the financial parameters remain contentious and warrant discussion in some detail.  Accordingly, each parameter will be dealt with in turn in the remainder of this chapter.  
The key parameters are:
•	the risk free interest rate (rf ), the real risk free rate (rrf ) and by implication the expected rate of inflation (f) and the interest rate applicable to debt (rd );
•	the market risk premium (MRP);
•	the likely level of debt funding (D/V); 
•	the likely utilisation of imputation credits ();
•	the effective tax rate (Te); and
•	the asset beta (a) and the equity beta (e) relevant to the stand-alone operation within the proposed regulatory framework.
2.4.1	Interest rates and inflation
The Code (section 8.30) states that the rate of return should be ‘commensurate with prevailing conditions in the market for funds’.  The Commission interprets this as implying that all information for deriving the rate of return should be as up to date as possible at the point the access arrangement comes into effect and match the circumstances of the regulatory framework.  Interest rates and inflation expectations are parameters set by the financial markets on a daily basis and are readily determined.
Generally, the relevant WACC for regulatory purposes should be a forward looking measure which gives an indication of the minimum expected commercial return necessary to underwrite new investment in the facilities required to provide the reference services taking account of the commercial (and regulatory) risks involved.
AGLP has proposed the nominal ten year bond rate and the CPI capital indexed bond 2010 series plus inflation component as indicators of the risk free rate.  It recognises that these rates should be ‘on the day’ but has averaged the figures over an undefined ‘short period of time’ to avoid any short term aberration due to volatility.  
AGLP’s preference for ten year bond rates was reiterated in its submission of 19 September 1999.  AGLP considers that ten year bond rates are consistent with measurements of market risk premium; would be consistent with other regulators; and reflect the long term nature of the investment decisions undertaken.  
APIA/AGA also submitted that they considered that ten year bond rates were the most appropriate as ‘the market risk premium is typically calculated by reference to ten year bond rates’.  APIA/AGA state that it is essential that a common term be used for the market risk premium and the risk free rate.  It is suggested that the use of five year bond rates implies that the risk borne by the asset is up to five years.  APIA/AGA also note that IPART and ORG use ten year bond rates in determining the risk free rate and that the National Electricity Code identifies ten year bonds as an example of long term bonds that would normally be used for this purpose.  The result of using five year bond rates to calculate the risk free rate is, according to APIA/AGA, to understate the pre-tax real WACC by 0.2 per cent.
In the Victorian Final Decision, the Commission considered that the term associated with the risk free rate should coincide with the five year duration of the access arrangement period.  Accordingly, five year rates were used in the CAPM.  In addition, the five year bond rate has the advantage of a lower built-in premium to compensate for inflation risk.  A ten year bond rate is usually higher than the five year rate because, in part, it accommodates a risk premium for inflation uncertainty.  As the risk associated with inflation uncertainty is minimised in regulatory frameworks which adjust revenues based on actual inflation outcomes, the five year bond rate has generally been favoured by the Commission.
As noted by APIA/AGA, ten year bond rates have been used to determine the market risk premium.  However, there are various estimates for the market risk premium that use different measures of the risk free rate.  For example, Jenkinson uses a long term average of indexed five year bonds.  The Commission considers a range of information in determining an appropriate market risk premium.  Since these estimates use a variety of measures of the risk free rate there is no reason to dismiss the use of five year rates in estimating the risk free rate on the grounds of inconsistency with the market risk premium estimation. 
In the Victorian Final Decision and the CWP Draft Decision the Commission used five year bond rates to determine the risk free rates and inflation for the purposes of calculating the WACC.  The Commission has decided in this instance to use the ten year bond rates in its calculations as they coincide with the ten year initial access arrangement period (see discussion in section 4.7).  
In theory, the most appropriate indicator of the prospective risk free rate is the current rate indicated by financial markets.  However, the Commission appreciates the need to average over a short period to abstract aberrations that may occur from day to day market volatility.  The Draft Regulatory Principles propose the use of a 40 day average of the relevant bond rates covering the period prior to the decision to overcome any volatility.  This methodology has been adopted by the Commission for the present analysis, resulting in a risk free rate (rf) of 6.38 per cent and a real risk free rate (rrf) of 3.44 per cent as indicated in Table 2.2 below.  
Table 2.2:	Current financial market interest rates and inflation expectations
	(per cent pa)	
Financial indicator	Proposed by 	40 day moving average (a)	
	AGLP	Draft Decision	Final Decision (d)	
5 year government bond rate		5.83	6.34	
10 year government bond rate	4.8-5.2	6.18	6.38	
Indexed bonds (August 2005 series)		3.47	3.15	
Indexed bonds (August 2010 series)	3.2-3.5	3.64	3.45	
Estimated 5 year real rate(b)		3.44	3.14	
Estimated 10 year real rate(b)		3.50	3.44	
Implied 5 year inflation expectation(c)		2.31	3.11	
Implied 10 year inflation expectation(c)		2.59	2.84	
Notes:	(a)	Based on daily closing quotes reported by the Reserve Bank of Australia, as published in The Australian Financial Review. 
(b)	Interpolations based on indexed bond figures.  
(c)	Inferred from the difference between nominal and real interest rates over the corresponding period using the Fisher Equation. 
(d)	For the period ending 16 June 2000.  
While the inflation rate is not an explicit parameter in the basic WACC estimation, it is an inherent aspect of the nominal risk free rate and cost of debt parameters.  Also it is fundamental to deriving the real rate of return, which is used in the target revenue and economic depreciation calculations and is an important determinant of the effective tax liabilities.  AGLP has suggested a range for the annual rate of inflation of two to three per cent over its proposed initial five year price setting period but has used a rate of 2.5 per cent in all its calculations. 
An indication of the inflation rate anticipated by financial markets and corresponding to the interest rate figures is provided by the difference in the nominal bond rates and inflation indexed bonds for the same term.  The indexed bond series has maturity dates which do not correspond to current five or ten year bond rates but the corresponding figures may be inferred by interpolation and are shown in the Table 2.2 above.  These figures represent the real risk free rate corresponding to the current nominal risk free rate (based on the ten year bond yield) and indicate that the current expectation of inflation (f) over the period is 2.84 per cent.  The Commission uses this market derived inflation rate in its calculations.
In addition, part of the modelling undertaken to derive the tariffs included applying the assumed forecast inflation to historical circumstances, in particular the economic asset value for the year ending June 1998.  The Commission considers it more appropriate to use actual observed inflation in these circumstances. 
Accordingly, the Commission considers that the revenue model for the CWP should incorporate a forecast rate of inflation of 2.84 per cent and an observed inflation rate for the financial year 1998-1999 of 1.1 per cent.  An amendment to the access arrangement is specified to this effect.  AGLP has undertaken to amend the access arrangement accordingly.  
At the time of writing, the inflation outcome for the three quarters of the year 1999-2000 had been reported.  The Commonwealth’s Budget Statement 3 incorporated these outcomes in its inflation forecast for 1999-2000 of 3.0 per cent.  The Commission considers that it would be appropriate to use this up to date information in the cash flow model for the CWP.  An amendment to the access arrangement is specified to this effect. 
Amendment A2.1
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the revenue model must incorporate the observed inflation rate for the financial year 1998-1999 of 1.1 per cent where appropriate and an estimated rate of 3.0 per cent for 1999-2000.  In addition, AGLP must implement into its revenue model a forecast inflation rate of 2.84 per cent per year for each remaining year of the access arrangement period.  

AGLP has proposed tariffs that are expressed in nominal terms.  Under this approach AGLP would bear any inflation risk.  In its Draft Decision the Commission proposed that the inflation risk be removed from AGLP by approving real tariffs for the period beyond which existing contracts apply.  This was achieved by adjusting tariffs by CPI-X in the last three years of the access arrangement period.  BHPP submitted that it considered that inflation risk should lie with AGLP rather than users as it considers that AGLP is better placed to manage that risk.
The Commission remains of the view that inflation risk should be minimised for AGLP and CPI-X tariffs implemented.  Further discussion regarding the CPI-X mechanism for reference tariffs can be found in sections 3.8 and 3.9 of this Final Decision. 
2.4.2	Debt margin and cost of debt
AGLP suggested that the appropriate margin for the cost of debt (DM) is around 100-145 basis points above the relevant risk free rate and noted that the Commission had adopted 120 basis points in the Victorian Final Decision.  
Based on its analysis underlying the Victorian Final Decision and more recent changes in market conditions, the Commission considered that a range of 80 to 120 basis points was appropriate for the debt margin at the time of the CWP Draft Decision and used the mid-point of 100 basis points for its calculations.  
APIA/AGA commented that there has been some reduction in the debt margin since the release of the Victorian Final Decision for established pipelines.  AGLP submitted that while the debt margin should be calculated on current market conditions a credit rating of A- to BBB+ may not be realistic for a project such as the CWP.  It also suggests that margins have spread more recently and that a margin of 120 basis points would be appropriate for the CWP.  
The Commission notes that the recent refinancing of DEI’s debt used to purchase BHP’s power assets was reported to be priced in three tranches.  The first tranche, for five years, is priced at 110 basis points.  The second five year period is financed at 130 basis points and the third at 150 basis points.  While DEI is reported to have a solid credit rating, the financing of this debt may indicate that debt margins have increased.  This is supported by a recent report that states: 
… spreads have widened sharply this year and issuance has virtually ceased during the past few weeks because of concerns about rising interest rates and the possibility of further credit ratings downgrades.  
Accordingly, the Commission considers that, on balance, an increase in the margin is warranted at this time and has used a debt margin of 120 basis points in this Final Decision. 
The 120 basis point margin in combination with the nominal risk free rate of 6.38 per cent suggests a nominal cost of debt (rd) figure of 7.58 per cent for use in the WACC estimation.  With an inflation rate of 2.84 per cent, the corresponding real cost of debt (rrd) is 4.61 per cent.  
2.4.3	The market risk premium
The market risk premium is a parameter in the CAPM which together with the risk free rate and firm specific equity beta determine the expected cost of equity in the business.  AGLP proposed a range of 6.0-7.0 per cent for the market risk premium.  
After considering recent indications that the market risk premium may be declining, the Commission concluded in its Draft Decision that a more appropriate market risk premium for the CWP would be 5.5 per cent.  
In responding to the Draft Decision, AGLP argued that as market practitioners and various academics tend to use a market risk premium of 6.0 per cent, this would be appropriate for the CWP.  APIA/AGA supported this view, stating that: 
it is not reasonable to adjust the market risk premium on the basis of one study, especially when findings of that study conflict with the findings and opinions of experts in the field. 
APIA/AGA reported on studies carried out over recent years that suggested the market risk premium should be 6.0 per cent.  In contrast, BHPP submitted: 
we consider a market risk premium of 5.5% as overly generous in light of the empirical evidence which is referenced in the Draft Decision. 
The Commission acknowledges that indicators of a downward trend are not fully accepted by market participants and commentators.  However, there does appear to be sufficient support to suggest that the market risk premium is now unlikely to be above 6.0 per cent.  While the lower end of the range for the market risk premium remains the centre of debate, the Commission has decided to adopt the upper limit of 6.0 per cent for this Final Decision.  However, the Commission will reconsider the appropriate level of the market risk premium over time as each regulatory decision is made.  
2.4.4	Level of debt funding 
AGLP suggested the proportion of debt funding applicable to CWP to be 50-60 per cent.  However, Forcenergy suggested that a debt gearing of 60 per cent would be lazy.  It noted that the Victorian energy assets were purchased using gearing of 70 per cent and suggested a higher level of gearing for AGLGN might be appropriate.  AGL’s debt/equity ratio between 1995 and 1999 has varied between 34.2 per cent and 86.3 per cent.  The Commission is also aware that the prospectus for the APT, in which AGL now holds a 30 per cent share, states that external debt is structured to an initial gearing level of approximately 62 per cent. 
The Commission concluded in its Draft Decision that it would use a level of debt of 60 per cent.  It noted that while it is arguable that a 60-70 per cent range may be appropriate for the level of debt for the CWP, the Modigliani-Miller theorem suggests that the relevant cost of capital should be invariant over a broad range of gearing possibilities in the absence of taxes.  The proposed WACC formulation also has this property and therefore the gearing assumption used is not a critical one. 
Following the release of the Draft Decision, Interstate Pipelines submitted that a more sustainable level of debt for CWP would be 35-50 per cent.  It claims that the CWP could not sustain a level of debt of 60 per cent and that the regulatory regime will not compensate investors for a poor cash flow in the early years of the project or the lack of contracts. 
The Commission appreciates that the low level of revenues in the initial years of the pipeline life suggests that a high level of debt funding may not be sustainable.  However, the Commission considers that the nature of regulation proposed for the CWP means there is limited risk and the gearing for the company could be correspondingly high without adverse credit consequences.  It should also be noted that, prior to its transfer to APT, AGLP was a fully owned subsidiary of AGL and the debt and equity holders of AGLP were in effect the same.  
In deciding on the appropriate level of gearing for a pipeline, the Commission is mindful of section 8.31 of the Code which states that the setting of the rate of return should be in ‘reference to a financing structure that reflects standard industry structures for a going concern and best practice’.  This suggests to the Commission that a debt level of 60 per cent is appropriate as this appears to be a widely used level of gearing for utilities and has, in this instance, been accepted by AGLP and APIA/AGA.  Accordingly, the Commission has used a debt level of 60 per cent for the purpose of deriving the WACC for the CWP.  The Commission notes AGLP’s advice that its purchase by APT would not impact materially on the Commission’s assessment of this access arrangement. 
2.4.5	Imputation credits
The availability of tax imputation credits requires a modification to the standard CAPM/WACC model to reflect the return to shareholders of tax credits associated with their share dividends.  Thus, gamma () is included in the WACC assessment to represent the proportion of franking credits which are, on average, used by shareholders of the company to offset tax payable on other income.  The higher the gamma, the lower will be the required return to equity holders and therefore the lower the estimated WACC.  Consequently, gamma becomes a significant parameter. 
AGLP suggested a range of 25-50 per cent for gamma in its initial proposal.  After consideration of the empirical evidence available, the Commission concluded in its Draft Decision that a gamma of 50 per cent was appropriate in determining a WACC for a regulated business.  
Subsequent to the release of the Draft Decision, AGLP referred to decisions from IPART (in relation to electricity networks and Wagga Wagga and Albury gas distribution networks) that used a range of 30 to 50 per cent for gamma and concluded that the maximum level of gamma that would be acceptable is 50 per cent.  
On balance, the Commission is of the view that a gamma () of 50 per cent is the minimal value that should be assumed for calculating the WACC for regulated businesses.  As noted in the Transgrid Final Decision, this is consistent with the Commission’s view that it should not infer any particular ownership structure on regulated entities.  A gamma of 50 per cent is also consistent with other recent regulatory decisions. 
2.4.6	Effective tax rates
The difference between tax depreciation rates and economic depreciation rates means there is a more rapid payback of capital than assumed in the regulatory and statutory accounts.  This difference, in addition to the company’s debt shield, results in a considerable deferral of tax liabilities associated with the project.  As a result, early post-tax cash flows to the investment are elevated and this improves the internal rate of return of the project above what would otherwise be the case.  This effect may be interpreted as an effective tax rate for the return on equity (Te) which is less than the statutory rate (T).
Accordingly, if the pre-tax real WACC was to be calculated by formula the effective tax rate would be appropriate rather than the statutory tax rate as used by AGLP.  However, the appropriate level of the effective tax rate must be determined. 
At the WACC forum following the release of the Victorian Draft Decision, a number of experts argued that their preferred regulatory approach was to avoid the use of a pre-tax WACC altogether.  These experts suggested using a post-tax WACC directly available from CAPM estimates to reflect the return on assets and then capturing the impact of taxes in the cash flows.  Such taxes would simply then be added, along with other costs such as operations and maintenance, to calculate target revenues for the business.  Such an approach avoids the need for a special conversion formula and handles tax in a transparent way. 
In effect, the cash flows determine the actual effective tax rate for that business over the life of the asset.  The effective tax rate can be estimated by comparing the pre-tax nominal cost of equity with the post-tax nominal cost of equity from the cash flows. Calculation of the WACC with an effective tax rate inclusive formula therefore becomes superfluous since the cash flows also reveal the revenues necessary to deliver the desired return to equity holders that is consistent with CAPM. 
The Commission has carried out cash flow analysis to determine the revenues and the appropriate WACC for the CWP.  The cash flows reveal that the effective tax rate for the return on equity (Te) for the CWP is 2.0 per cent.  This is considerably different to the statutory tax rate (T) and reflects the lengthy projected non-tax paying period applicable to the CWP under this regulatory framework.  
The fact that the post-tax approach assesses tax obligations on an ‘as you go’ basis avoids both the need to calculate a long term effective tax rate and problems generated by post-tax returns diverging from market rates over time.  As far as the business is concerned the post-tax approach removes risks associated with future tax liabilities and provides a return that will always be commensurate with market requirements.  The value of this feature of the post-tax approach will become more evident in future reviews of the access arrangement. 
The Commission sees benefits in a post-tax approach and intends to adopt this framework across the entities under its regulatory jurisdiction over time to the extent practicable. 
The Commission does not consider it necessary to require AGLP to adopt a post-tax nominal WACC as its rate of return for the purposes of this access arrangement as, under the price path approach proposed, the outcomes are essentially the same.  Accordingly, as in the Draft Decision, the Commission will report the WACC in this Final Decision in pre-tax real and post-tax nominal terms that are consistent with the key rate of return figure, the CAPM derived post-tax nominal cost of equity.  
Impact of the Ralph Review of Taxation
In making realistic assumptions about tax it is important to apply a taxation regime that is most likely to exist over the future life of the assets.  In the absence of any proposed changes the Commission favours a conservative approach based on existing tax law.  This was the basis of calculations in the Draft Decision.  However, the Government has since released the Ralph report.  This made a number of recommendations for changes to the tax system that have subsequently been accepted by the Government.  The current implementation of the NTS adopts many of the changes recommended by the Ralph report.  The Commission considers it appropriate to adopt these changes in its analysis since it will provide a better basis for the assessment of tax over the longer term. 
The main changes likely to impact on the CWP revenues are outlined in Table 2.3 below together with a brief commentary on how they have been reflected in the present analysis.  
Table 2.3:	Impact of the Ralph report on the modelling of tax and associated cash flows  
Proposed Change	Comment	
Reduction in corporate tax rate 
1 July 2000: 36% reduced to 34%
1 July 2001: 34% reduced to 30%	T set to the relevant rate over the transition period and 30% in subsequent years.  There is no positive assessable income in the first access arrangement period. 	
Removal of accelerated depreciation provisions for plant and equipment	Accelerated depreciation preserved for assets in place but for future capital expenditures the rate of depreciation is reduced to correspond with the stated asset life	
Imputation credits to be paid as a tax rebate	This may have the effect of raising the value of imputation credits for many shareholders and move the relevant value of  towards 100%.  However, in the absence of any analytical work on this issue  has been maintained at 50%.	

While some of the Ralph recommendations may be modified over time, the net pre-payment of taxes for AGLP will be monitored and reflected as early return of capital.  Therefore, if the future tax regime changes in unexpected ways, and the compensation for tax proves inappropriate, revenues can be adjusted within a future access arrangement period.
2.4.7	Specific risk
The risks faced by any business can be described as either systematic (or non-diversifiable) or specific (diversifiable).  The beta used in the CAPM is intended to represent a business’ systematic risk with respect to the financial market as a whole.  The following section will focus on systematic risk and betas for the CWP.  This section discusses the specific risks associated with the CWP. 
Specific risks are those risks unique to an asset or project.  They are independent of the market.  For an investor, exposure to the specific risk related to an asset can be reduced or countered by holding a diversified portfolio of investments.  Consequently, specific risk is not reflected in the betas for the assets and is not incorporated into CAPM analysis.  
However, it has been argued that in relation to the CWP the Commission should incorporate an allowance for specific risk in the regulatory framework for the access arrangement.  In general, it has been claimed that the greenfields nature of the CWP, and that it is a relatively small pipeline newly built without foundation contracts to supply regional NSW, raises unique circumstances which should be accommodated by the regulatory regime.  
In part, the unique circumstances of the CWP are accommodated by AGLP’s proposed NPV-economic depreciation framework which the Commission has accepted for this access arrangement.  However, interested parties, including AGLP, have sought to have the specific risk of the CWP incorporated further in the regulatory framework.  The methods suggested have included: 
•	increasing the asset beta in the CAPM; 
•	adding a premium to the CAPM for asymmetric risk and self insurance; and
•	including a premium on the WACC based on the tender outcomes for the Mildura and East Gippsland gas distribution systems.
Clearly from such comments, interested parties are of the view that the Commission’s analysis of specific risk for the CWP in its Draft Decision was unsatisfactory.  The Commission has reconsidered this issue with the first question being whether the specific risk associated with the CWP should be incorporated further in the regulatory framework of this access arrangement.  The Commission has concluded that there are features of the CWP that create a unique risk profile which could be addressed further in the access arrangement.  These features are: 
•	a relatively newly constructed small pipeline; 
•	service into regional NSW; 
•	limited number of substantial sized customers; 
•	no established market for natural gas; and 
•	no foundation contracts established prior to the building of the pipeline. 
These features work together to give the CWP particular specific risk that may compromise returns available from the regulatory framework.  Naturally, such analysis is specific to the CWP and cannot be used to infer a principle that the Commission will incorporate specific risk into access arrangements for other pipelines or in the regulatory frameworks for other businesses.  
As noted above, a number of proposals on how specific risk for the CWP could be measured and added to the regulatory framework have been raised.  These, in addition to an assessment of the impact of the access arrangement period on risk, are discussed in the remainder of this section.  
Overall specific risks
AGLP has argued that the CWP faces greater risks than those faced by Transmission Pipelines Australia Pty Ltd (TPA), the owner of the Victorian Principal Transmission System (PTS) and the Western Transmission System (WTS) at the time the access arrangements for that system were assessed in 1998.  According to AGLP, the factors leading to this higher risk include: 
•	general uncertainty due to the recent commencement of the pipeline;
•	no significant foundation contracts; 
•	markets are not yet established; 
•	smaller size of the pipeline; 
•	greater concentration of usage among several large customers; and 
•	greater exposure to competing energy options.  
The Commission accepts that there is risk for AGLP in building a pipeline without substantial foundation contracts and without an established market.  The demand forecasts used in the analysis are not based on any previous usage details due to the recent commencement of the pipeline and reticulated natural gas is new to the Central West region.  Therefore, the forecasts used in this access arrangement may prove to be substantially inaccurate.  However, the Commission considers that the risk associated with the lack of a developed market for natural gas in the Central West region is significantly reduced by the NPV-economic depreciation framework.  This framework provides for the capitalisation of early losses incurred by AGLP.  Thus, provided that the market demand does develop to the extent expected sometime during the pipeline’s life, any early under-recovery of revenue may be compensated for by higher revenues later in the pipeline’s life rather than not at all.  
The Commission does not consider that the smaller size of the CWP (compared to the PTS) implies a greater risk.  However, the Commission does accept that the limited diversity of users may increase the specific risk associated with the CWP due to the small number of commercial users that represent a significant proportion of the total expected volume.  However, as the market develops and more users are attracted to natural gas, the relative reliance on these few customers would be expected to decline.  It is in AGLP’s interest, therefore, to encourage market growth, not only to increase sales of gas but also to develop a wider customer base. 
The Commission also accepts that as a new energy source for the Central West region, natural gas faces competition from the existing energy sources of LPG, coal and electricity.  In comparison to Victoria, where natural gas has been established for many years, AGLP must establish natural gas as a viable alternative fuel.  
AGLP has also argued that to a large degree the pipeline’s risk is dependent on the risks faced by its end-users.  AGLP advised that the current large end-users are involved in agricultural processing, other resource processing and publishing.  AGLP has made reference to the asset betas for Australian Stock Exchange groups All Industrials (0.65), Diversified Industrials (0.71) and Diversified Resources (0.90), arguing that these reflect the risk that it faces.  
It states: 
In rural and regional areas, such as the Central West, demand for gas is driven by the commodities sector.  In metropolitan areas demand for gas is driven by the manufacturing and service sectors.  The commodity sector is more volatile than the manufacturing and services sectors.
In support of this AGLP notes that studies in relation to the electricity industry indicate greater risks for regional and rural areas in comparison to metropolitan areas.  
The risk profile of AGLP’s users impacts on the usage of the pipeline.  To some extent this will be driven by the movements in the wider economy and consequently, reflected in the equity beta.  However, there will be some movement that will be unique to the Central West region.  As this is not of a systematic nature, this would not normally be reflected in the equity beta.  Whether the equity beta can, and should, be adjusted to reflect some movements unique to the Central West is a question the Commission has considered, particularly as this has been raised by some interested parties.  Further discussion on equity and assets betas is contained in the following section 2.4.8. 
Asymmetry of risk and self insurance
In addition to outlining the overall risks it sees facing the CWP, AGLP has included margins for asymmetric risk and self insurance risk in its calculation of the nominal cost of equity.  AGLP has claimed there is significant asymmetry in the specific risks it faces and this should be reflected in a higher return.  This is an empirical matter.  AGLP has drawn attention to downside risks.  Downside risks considered to be facing TPA were also brought to the Commission’s attention during the assessment of the Victorian access arrangements.  However, in both cases, comparatively little assessment has been made of upside benefits, including those available as a result of the incentive based arrangements operating in the regulatory framework or a reduction in the company tax rate (as proposed by the Ralph Report).  
However, as AGLP notes, it is not easy to quantify asymmetric risk and identification of its components is not generally undertaken.  Nevertheless, AGLP has put forward a range of zero to one per cent which it suggests should be added to the cost of equity.  While AGLP argues that asymmetric risk should not be incorporated in the CAPM framework through the asset beta, it has proposed a value for that parameter which appears to incorporate a substantial premium.  
Arguing for an asymmetric risk premium to the cost of equity, AGLP has noted the possibility of the regulator limiting price and/or return rises, increasing service and quality standards, and clawing back perceived excessive returns.  The Commission does not consider these concerns to be valid.  The reassessment of prices and returns at the beginning of a new access arrangement period is not a risk for a business but the nature of applying the Code’s regulatory regime.  While the Commission would not wish to see service quality decline it must be noted that the Commission is not a technical regulator.  The ability or inclination of the Commission to claw back perceived excess returns must be considered in light of the regulatory regime in general and the framework relating to the business in particular.  For AGLP, the regulatory framework includes an incentive mechanism to earn revenues greater than those forecast.  To claw back any such revenues would have a severe impact on AGLP’s incentives and the regulatory framework established for the CWP.  Accordingly, the Commission does not consider clawing back of returns appropriate for the CWP  
AGLP also suggests that by-pass or asset stranding is an asymmetric risk faced by the business and refers to IPART’s comments that it had incorporated an allowance of 0.1 to 0.2 per cent on the rate of return for stranded assets for Great Southern Energy Gas Networks.  However, particulars of assets that could be stranded and possible by-pass events were not identified by AGLP.  The Commission does not consider the likelihood of these events occurring to be great given the nature of this pipeline.  In particular, the Commission does not expect a transmission pipeline such as the CWP, which does not have any laterals, to experience the same risk as a distribution network in regard to asset stranding. 
On the issue of insurable risks, AGLP suggests that infrastructure assets can be exposed to a variety of natural hazards.  It suggests that these hazards may not be well covered by insurance and consequently, a business needs to allow for self insurance in its returns or as a notional cost.  By not including self insured risk in a regulatory model AGLP suggests that a regulator is assuming that either self insurance has no cost or businesses do not self insure.  However, the Commission notes that a business would normally be expected to take out appropriate insurance to reduce these operational risks to the extent that is manageable by the business.  Such insurance would be included in the operational costs of a business and as such included in the determination of revenues.  This would be expected to reduce the need for a specific self insurance allowance. 
Like asymmetric risk, the risk associated with events that require self insurance is difficult to identify and quantify.  AGLP suggests the risks are often company or infrastructure specific and proposed adding a 0 to 0.5 per cent premium on the cost of equity.  Further empirical support for these figures was not provided by AGLP to the Commission. 
The Commission has considered the arguments presented that there are significant downside risks that outweigh potential upside benefits which would be in addition to the profits implied by the target revenue calculations.  It has also considered AGLP’s argument for a premium to allow for self insurance.  It acknowledges that these risks are difficult to quantify.  It also notes that for the Victorian Final Decision, such risks were taken account of to some extent by choosing beta estimates towards the top end of the plausible ranges as suggested by the financial experts at the WACC forum. 
In light of AGLP’s arguments regarding asymmetric risk and self insurance for the CWP the Commission has used an asset beta of 0.6 in its analysis.  This asset beta is at the high extreme of a plausible range and has been selected to accommodate the asymmetric risks and self insurance risks that have been raised by AGLP in so far as such risks may be exacerbated by systematic influences. 
The impact of the regulatory framework on specific risk
Submissions made in response to the Draft Decision highlighted concerns that the Commission had not fully accommodated the risk AGLP faced in respect of the CWP being a newly constructed pipeline in regional Australia without substantial foundation contracts.  As noted earlier in this section, the Commission agrees that there are unique circumstances for the CWP that give rise to a risk profile that should be accommodated into the regulatory framework.  Accordingly, the issue for the Commission to address is how this specific risk is to be accommodated.  
AGLP has claimed that investment in greenfields projects such as the CWP involve much greater inherent risks than investments related to well established gas markets.  Presuming that when a company undertakes such investments it expects the venture to be profitable, the risks of the venture yielding sub-commercial returns would be offset by a reasonable expectation that the business may also reap well above normal returns.  Since this risk is specific it is not picked up in the CAPM.  AGLP claims that when such a pipeline is subjected to regulation it is further disadvantaged because any above normal returns are pruned back by the regulatory process but on the downside there is little that can be done to restore a normal level of return.  To provide investors with an expected return that justifies undertaking a venture such as the CWP, AGLP has argued for a return premium to be added to the CAPM based cost of equity.
OXERA, as consultant to AGLP, has also raised the potential for the use of a premium to accommodate the unique regional risks associated with the CWP based on recent work by the UK Office of the Rail Regulator (ORR).  The ORR has considered whether there are additional risks for Railtrack (the rail network owner and operator) in building new infrastructure. 
OXERA suggests that there are obvious similarities between Railtrack’s ‘equity partner’ investments and the potential stranding of the CWP.  An equity partner investment model is where Railtrack is exposed to the possibility that part of its investment may become stranded in the future when the initial agreement with its equity partner expires.  OXERA suggests this is similar to the potential stranding of the CWP in respect that unforeseen variations in demand create additional risk for the business.  According to OXERA, the ORR has acknowledged that a regulator’s treatment of such an investment impacts on the rate of return and the investment may attract a rate of return higher than Railtrack’s core business.  
In suggesting that the specific risks of the CWP may be accommodated by a premium on the return calculated through the CAPM (or on the WACC itself) the question of how such a premium can be valued must also be addressed. 
OXERA suggests that a relevant regulatory precedent is the ORG decision on Envestra’s Mildura distribution pipeline system.  OXERA concluded that the: 
… minimum rate of return required for Envestra to invest in such a greenfield project, is higher than the 7.75% allowed pre-tax real rate of return by the ORG on other Access Arrangements relating to mature network businesses such as Multinet, Westar and Stratus.  The implicit premium therefore is 1.25%. 
OXERA acknowledges: 
… it is difficult to come up with a precise measurement of the extent of the premium for such projects.  However, the principle of adding a premium over and above the CAPM-based cost of capital has regulatory precedents … 
The tender processes for the Mildura and East Gippsland distribution systems were approved by the ORG in 1998.  In assessing the access arrangements that were subsequently lodged the ORG calculated that the tariffs established through the tender processes implied a pre-tax real WACC of 9.0 per cent for Mildura and 8.82 per cent for East Gippsland.  AGLP and various other parties have commented on these published estimates and their possible use as benchmark rates for tariff setting and determining the appropriate return for the CWP. 
As these tenders took place during 1997 it is expected that rates of return implicitly obtained would reflect the market conditions at that time.  Changes in market conditions since then would need to be considered before attempting to use these results as a benchmark for the CWP or any other regulatory decision.  BHPP has suggested that these tenders indicate that parties were willing to undertake these investments on the basis of a pre-tax real return equal to the CPI indexed long term bond rate (LTBR) plus 450-480 basis points. 
The Commission notes that the ten year real risk free rate declined substantially between mid 1997 and June 2000 (from 4.5 per cent to 3.5 per cent).  This would result in a reduction in the implied pre-tax real WACC to approximately 8.0 per cent, a figure that is consistent with BHPP’s analysis (which suggests a May 2000 WACC in the range of approximately 7.7 to 8.0 per cent, based on August 2005 bonds).  An adjustment to reflect the changes to bond rates over time provides a better comparison between WACCs for Mildura and East Gippsland and any WACC determined at present.  
Regardless of this adjustment relating to bond rates, BHPP has raised concerns regarding the validity of using the implied returns for the Mildura and East Gippsland systems to determine an appropriate return for the CWP.  Noting the returns implied by the tender processes, BHPP states that: 
BHP would expect that a lower risk gas asset such as the CWP would, if it were competitively tendered under the Code, attract a significantly lower WACC LTBR rate spread say 325-375 basis points.
BHPP considers that the CWP faces a lower risk than Mildura and East Gippsland since: 
•	the CWP services a larger region, which increases customer diversity and lowers risk; and
•	the Central West region is a more attractive space heating market with more intense cold weather in the months May to September. 
BHPP concluded ‘that a regulatory WACC for the CWP in the order of LTBR plus 350 basis points or 7.0% pretax real is appropriate’.  Its submission also argued that the proceeds of the privatisation of the Victorian gas transmission and distribution assets indicated that the pre-tax real WACC of 7.75 per cent set by the Commission and the ORG at that time ‘was very generous’ and ‘that the true cost of capital is significantly below that granted by the Regulator.’  In support of this contention, BHPP quoted comments by Professor Kevin Davis that the only credible explanation of the large premiums paid for these businesses was that the regulated rate of return was set ‘higher than that required by the eventual purchasers.’
AGLP raised a number of arguments in response, including that there was no evidence that the businesses that make up 70 per cent of the forecast projected load were counter cyclical (which would be needed to offset risk).  AGLP commented that ‘Mildura and East Gippsland have sufficiently cold climates to overcome what are barriers to connection in warmer climates such as Sydney’ and that ‘climate is not itself a risk factor’ as it would have been taken into account in each case in determining prices.  AGLP concluded that:
Both of these points, however, miss the most significant element of risk associated with the CWP, and that is that its viability relies on uncertain regional development over the next 20 years or so – as we have said previously, if all the potential gas load that currently exists in the region was to convert to gas tomorrow the project would not be viable.  The CWP is certainly no less risky than the projects cited by [BHPP].
The Commission has considered the arguments raised by BHPP and AGLP.  BHPP has suggested that the CWP does not face the same degree of risk as the owners of the Mildura and East Gippsland systems.  The Commission is inclined to agree.  Its own analysis of the three pipeline systems supports BHPP’s view. 
In addition to the issues raised by BHPP, the ORG has provided to the Commission background information relating to the Mildura and East Gippsland tenders and advised that it considers they should not be regarded as relevant benchmarks for the CWP.  Key issues raised include:
•	the tenders were determined on the basis of the delivered price of gas rather than solely on the transport component as would be required by the tender process under the Code;
•	the reference tariffs were subsequently derived from the bundled price;
•	related financial information reflects a mixture of transmission, retail and distribution activities;  
•	as bidders would have based their prices on a range of factors (including their individual demand and cost forecasts), the tenders did not reveal a market determined WACC;
•	the then Victorian Government owned gas distribution businesses are understood to have been required to bid on the basis of pre-tax real WACC of 10.16 per cent; and
•	the 8.82 per cent pre-tax real WACC quoted for the East Gippsland tender was derived from a target post-tax nominal return on equity figure in the tender documents which was interpreted at the time as relating to the return on assets.  While the ORG has not attempted to estimate the pre-tax real WACC using cash flow analysis, it has advised that an application of the forward transformation formula would have instead resulted in a value of 7.9 per cent.  
The Commission notes that these comments from the ORG raise important issues about the potential use of the Mildura and East Gippsland tender outcomes as indicators of the appropriate regulatory return for the CWP.  These issues, in addition to those raised by BHPP noted earlier, suggest to the Commission that it should be cautious in drawing conclusions from the very small sample of available outcomes.  It notes that individual decisions may not be made solely on the bases ascribed to those decisions and may reflect inadequate information. 
The Commission has considered all the arguments put to it in regard to the use of the Mildura and East Gippsland tender outcomes as indicators of the appropriate regulatory return for the CWP and has concluded that these tender outcomes provide limited guidance.  The Commission has not been persuaded to use the Mildura and East Gippsland outcomes as an appropriate basis for determining the rate of return for the CWP.  
Consistent with Professor Davis’ analysis, BHPP has raised concerns about the use of a WACC of 7.75 per cent as a benchmark for established infrastructure on the basis that the purchasers of the Victorian gas distribution and transmission businesses implicitly would have accepted a considerably lower rate.  The Commission notes that these outcomes provide grounds for reconsidering some of the WACC parameter values chosen by the Commission and the ORG as part of their assessments of the Victorian access arrangements.  
The Commission has and will take this market based information into consideration when assessing proposed access arrangements.  Nonetheless, it does not consider it appropriate to use the market rates implicit from these outcomes as a benchmark to replace the CAPM methodology in determining the rate of return.  The Code specifically refers to CAPM as an example of a well accepted financial model used for determining the rate of return (section 8.31). 
The Commission notes the potential for asymmetry but does not favour an approach involving a return premium for several reasons: 
•	as discussed elsewhere the NPV price path approach takes away much of the return risk associated with slow development of the market;
•	adding a premium to the CAPM cost of equity may be distorted by the level of gearing used; and 
•	the approach suffers from the absence of information that would allow the value of the premium necessary to cover residual risk not compensated elsewhere to be determined.
In conclusion, the use of a premium (on either the cost of equity or WACC) or an adjusted cash flow would require the Commission to quantify this specific risk.  In the absence of sound empirical evidence the selection of method and value would largely be a matter of regulatory judgement.  The Commission does not consider either proposed method to be satisfactory.  In both cases, but in particular with the premium, the impact on the reported cost of equity and WACC is a concern.  In addition, the Commission does not consider the Mildura and East Gippsland competitive tender outcomes to provide an appropriate guide as to the quantification of any premium.  Accordingly, the Commission has decided that the use of this approach to accommodate the specific risk relating to the CWP is not appropriate.  The Commission considers that a method that does not detract from the theoretical underpinning of the CAPM/WACC approach would be preferable. 
Length of the access arrangement period
As an alternative to the premium on the cost of equity or WACC, the Commission proposed to AGLP that the access arrangement period could be extended from five to ten years.  This would give AGLP an additional five years in which to reap the ‘blue sky’ potential of the project before a regulatory review re-established prospective returns to a normal level.
Regulatory decisions to date have tended to extend for five years.  At the end of this period the regulated business would be reassessed and a new rate of return calculated for the future regulatory period.  For a framework such as that proposed for the CWP a business may exceed its performance forecasts and earn greater revenue than anticipated.  Under this framework the higher revenues are retained until the end of the access arrangement period.  This provides an incentive to the business to outperform its forecasts.
However, if the regulatory period was not five years but longer, AGLP would be able to retain for a longer period the higher returns it earns from outperforming its forecasts.  In effect, the business has the potential to earn, and retain for an extended period, a rate of return noticeably higher than that set by the Commission.  At the end of the period the Commission will reassess the business and determine a rate of return for the forthcoming period.  However, the longer period will provide a larger incentive to AGLP to improve its performance and build its markets.  
The Commission has considered this framework in light of the Code.  It does not consider that there are any provisions of the Code that would prove to be an impediment to an access arrangement period being longer than a five year duration. 
The Commission has proposed to AGLP that the initial access arrangement period could be extended from five to ten years.  This would give AGLP an additional five years in which to reap the ‘blue sky’ potential of the project before a scheduled review re-established prospective returns to a normal level.
AGLP’s initial response was that an extended access arrangement period only served to broaden the range of possible returns and chose to interpret this as generating additional uncertainty justifying an even higher risk premium.  This was supported by a study by OXERA commissioned by AGLP.  OXERA used Monte Carlo simulations to show that when forecast revenues deviated from costs randomly over time following the pattern of a random walk (as might be expected in the absence of a review) the dispersion of returns was indeed greater the longer the regulatory period.  
However, the arguments and analysis from AGLP and OXERA did not include the fact that the Code allows a service provider to seek an early review of the access arrangement if forecasts associated with it prove inappropriate.  In contrast, the Commission has no recourse to an early review under the Code.  Consequently, in situations where demand proves less than expected AGLP may seek a review to raise tariffs.  If the market could not sustain price rises at the time, the NPV framework facilitates a capitalisation of revenue shortfalls through a further escalation of the regulatory asset base.  This permits a recovery of returns at a later date when the market is better established or enhanced through extensions of the pipeline.  
Therefore, the proposal for an extended access arrangement period benefits AGLP by creating an asymmetry in the regulatory framework which is to its advantage.  The effect is to raise expected returns above those indicated by the CAPM and used to establish the benchmark revenues.  In effect a return premium is generated, but this approach has the advantage that a specific premium does not have to be quantified in advance.  Instead, the inherent uncertainties in the market determine the value of the premium.
To illustrate the effect the Commission undertook its own Monte Carlo simulation studies of potential outcomes following the OXERA approach but incorporating the feature that AGLP could call an early review if forecast demand proved less than expected.  Technical details of the simulations are summarised in Box 2.1.  The results shown in the graphs and tables below in Figure 2.1 and Figure 2.2 illustrate a number of points: 
•	the dispersion of ten year returns is greater than for five year returns as found by OXERA;
•	in both cases dispersion increases with the magnitude of the random variation in costs relative to revenues;
•	the expected value of the return premium increases with the level of uncertainty in market demand (reflected by the magnitude of the random variation); and 
•	the expected value of the return premium is greater the smaller the downward deviation in demand relative to forecasts and used as a ‘trigger’ before a review is called by the applicant.
While these simulations (following the analysis used by OXERA) assume a random variation in revenues from costs accumulating from one year to the next, it is more realistic to assume that there is a greater uncertainty associated with initial market entry.  To capture this effect a second set of simulations was performed where the random deviation of the forecast revenues in the first year has a standard deviation triple that assumed in subsequent years.  Only one set of  results from this second set of simulations is reported in Figure 2.2. 
The conclusion to be drawn from these simulations is that the ability of the service provider to call for an early review (whenever there is a significant shortfall in forecast revenues) raises the expected return available to investors in the project.  In other words the regulatory framework effectively adds a premium to the CAPM based return which formed the basis of initial revenue forecasts.  The value of this premium is not fixed but increases with the level of uncertainty or risk in supplying services to the market.  For the level of volatility modelled (eight per cent standard deviation) and a ten per cent shortfall trigger this premium was estimated at about one per cent.  However, it could be two per cent or more if uncertainty associated with initial demand was a multiple of the assumed year to year variability.  With triple the standard error on the first year variation the simulations indicate that the premium above the CAPM cost of equity of 15.4 per cent would be 1.9 per cent. 
These levels of premium are similar to those initially proposed by AGLP but are only this great if the assumed level of uncertainty exists.  If it does not, then the effective premium may be less.  The benefit of using a ten year access arrangement period is that: 
•	it does not interfere with the calculation or interpretation of CAPM parameters and results; and 
•	the expected value of the premium reflects the level of uncertainty. 
Box 2.1:	Monte Carlo simulation of investor returns when profits are uncertain

To capture the impact of market uncertainty on investor returns it was assumed that the uncertainty took the form of a random change in the level of market demand from one year to the next.  This random variation is expressed as a random walk stochastic process defining the level of demand as a percentage deviation from the forecast demand level.  
Deviation(t) = Deviation(t-1) + t
That is, a random percentage t is added to the deviation observed in the previous year.  t is modelled as a random normal variate with a mean of zero and a standard deviation of eight per cent (or four per cent depending on the simulation).
This deviation changes estimated revenues and the impact on profits in the year is calculated.  The internal rate of return to investors is then estimated over the life of the asset on the assumption that costs remain as forecast and the expected regulated return is restored at the end of the regulatory period (five or ten years).  The deviation could be equally well considered as a difference between fixed forecast revenues and a cost structure which changes in a random manner (the OXERA interpretation) or a combination of costs and revenue variation.  In the case of CWP the demand volatility interpretation is more appropriate and consistent with the nature of the risk the applicant claims it faces.
To capture the impact of early review the deviation is reset to zero as the review would normally be expected to restore parity between forecast revenues and costs.  The trigger for early review is based on revenue shortfalls of set percentages (>30%, >20% and >10%).  The no review option is simply modelled with the trigger set at >100%. 
To reflect reality in the review scenarios no reviews were considered for the first two or last two periods of the ten regulatory period.  This was based on the presumption that some time would be required for a the lower demand level to be established and towards the end of the review period incurring the cost of an extra review is probably not warranted when there is one scheduled a year or two ahead.
Each scenario considered included 10 000 simulations based on random variation in the demand patterns.  In each case the return to investors was averaged over all simulations and the standard deviation of this return was also calculated.  To improve the efficiency with which the simulated averages could be estimated antithetic combinations of random variables were used (that is, if one set of t’s was used in one simulation the set with the same values but opposite signs was used in another).  

Figure 2.1:	Comparison of spread in average post-tax return on equity for 5 and 10 year review periods for selected levels of revenue volatility in the absence of early reviews

(a)
Year to year
demand volatility
4 per cent
standard deviation 

(b)
Year to year
demand volatility
8 per cent
standard deviation 

Statistical Summary(a)	
Annual variability (standard deviation)	4 per cent	8 per cent	
	5 year period	10 year period	5 year period	10 year period	
standard deviation of cost of equity(b)	1.0%	1.4%	2.1%	2.8%	
Notes:	(a)	Each estimate is based on 10 000 simulations. 
(b)	CAPM based cost of equity benchmark forming basis of forecast revenues 15.4%. 

Figure 2.2:	Comparison of spread in average returns with 10 year regulatory period for revenue volatility of 8 per cent standard deviation when the trigger for review is set at a nominated level below forecasts 

Statistical Summary(a) annual variability 8% standard deviation	
trigger level
(per cent below forecast)	no trigger	>30%	>20%	>10%	>10% (c)	
average cost of equity (per cent pa)(b)	15.4	15.6	16.0	16.4	17.3	
standard deviation of cost of equity 	2.9%	2.5%	2.2%	1.9%	3.1%	
proportion of early reviews (%) 	0	12	31	46	36	
Notes:	(a)	Each estimate is based on 10 000 simulations.
(b)	CAPM based cost of equity benchmark forming basis of forecast revenues was 15.4%
(c)	Standard deviation of variability in first year treble that in subsequent years.

In light of this analysis and following discussions with AGLP and its consultants OXERA, the Commission has determined that a ten year period would provide AGLP with the appropriate incentives and opportunities to overcome the perceived negative specific risk associated with regulation of the CWP.  It will provide the incentive and opportunity to grow demand and retain any revenues earned over the level forecast for an extended period.  It must be noted that while the Commission is unable to instigate a review of the access arrangement during the ten year initial access arrangement period, AGLP is able to seek revisions to the access arrangement as and when it chooses.  
This extended access arrangement period is in addition to the allowance for asymmetric and self insurance risks that have been made in selecting a high asset beta (as discussed in the following section).  Further discussion on the implementation of the ten year access arrangement period is located in section 4.7.4 of this Final Decision.  
2.4.8	Systematic risk
The CAPM provides for systematic (or non-diversifiable) risk through the equity beta, a statistical measure that indicates the riskiness of one asset or project relative to the whole market (usually taken to be the Australian stock market).  This is the risk that cannot be eliminated through a well balanced and diversified portfolio.  A higher beta value (that is, greater than one) is associated with a more risky investment whose returns vary more than the market average. 
To compare the risk associated with a number of businesses independent of the financial structure employed asset betas are used.  The asset beta takes account of the effect of different levels of gearing and can be derived by ‘de-levering’ an equity beta.  While there are a number of levering and de-levering formulae, the Commission prefers the formula developed by Monkhouse: 
e = a + (a - d ) 
To implement the Monkhouse formula to determine an equity beta a value for the debt beta (d) is required.  The debt beta is a measure of the systematic default risk of an investment relative to the overall market. 
In the Draft Decision the Commission considered that the appropriate value for the debt beta was zero.  This estimate was supported by the fact that debt funding for AGLP was underwritten by its equity participant AGL.  Hence, the equity holders are essentially assuming non-performance risk that would in other circumstances be borne by lenders.  The Commission noted that the impact of this adjustment is a small increase in the equity beta commensurate with the slight increase in risk assumed by equity holders.  
The Commission did not receive any comments from interested parties regarding the debt beta and notes that the debt beta does not have a large impact on the WACC.  It notes AGLP’s advice that its purchase by the APT would not impact materially on the Commission’s assessment of the access arrangement.  The Commission has concluded that a debt beta (d) of zero remains appropriate.  
In relation to its perception of the higher risk of CWP compared to the PTS, AGLP suggests that the Victorian Final Decision was released prior to an understanding of the full impact of the Longford gas plant incident.  It argues that the risk of a Longford type incident may not have been fully taken into account in the Victorian Final Decision.
The Commission considered when making that decision that the risk of an incident such as the Longford explosion was small and this was fully taken into account in the Victorian Final Decision.  The proposed tariff structure for the CWP consists only of a volume charge for the initial access arrangement period.  Thus, the loss of income resulting from a reduction or cessation of transportation will be proportionally greater than it would be for a pipeline with a capacity charge or a peak charge such as the PTS.  
AGLP’s comparisons with the PTS ignore one crucial factor – the regulatory framework.  If the regulatory frameworks applying to the Victorian transmission system and CWP were the same then the arguments put forward by AGLP regarding its greater relative risk may be valid to some extent.  However, the frameworks are not the same.  AGLP has proposed a NPV framework with economic depreciation.  If the framework is retained over the longer term, as understood by the Commission, much of the demand uncertainty is removed by the fact that forecast shortfalls in revenue are capitalised into the regulatory asset base.  Thus, the shortfalls are likely to be fully recovered by natural growth in the market even if it is slower than expected.  This suggests to the Commission that the high end of the range 0.55-0.90 proposed by AGLP for the asset beta is not valid. 
As noted previously, AGLP has suggested that the risk faced by its significant customers impacts on the risk faced by the CWP.  Reference has been made to the asset betas calculated by IPART for All Industrials, Diversified Industrials and Diversified Resources.  The Commission does not consider that the grouping Diversified Resources, which consists of mining companies, is relevant to the CWP.  While the beta data relevant for major customers of AGLP may suggest there is a degree of systematic risk faced by the CWP, the Commission considers this information of limited value.  
An asset beta range of 0.4-0.5 has been used by IPART and IPARC in relation to gas distribution businesses at Wagga Wagga, Albury and the NSW-ACT networks.  A range of 0.35-0.50 has been used by the Commission in relation to Transgrid’s electricity networks in NSW and ACT. 
On balance, the Commission considers that an asset beta of 0.60 is appropriate for the CWP.  This value incorporates substantial allowance for the asymmetric and self-insurance risks claimed by AGLP as discussed earlier.  It also reflects the risk faced by businesses in the Central West region insofar as that is dependent on the systematic risk of the whole market.  The Commission considers this asset beta is quite generous in comparison to the values determined for other regulated entities, particularly those in Australia.  
Equity beta data available to the Commission from the Australian Graduate School of Management (AGSM) are shown in Table 2.4.  The Commission has included data in relation to the Infrastructure and Utilities Group as it considers this to be of particular relevance to gas pipeline owners, including AGLP.  These data indicate to the Commission that Infrastructure and Utility Group businesses have, on average, less systematic risk than the All Industrials Group.  However, it appears that AGL has, on average, higher systematic risk than the Infrastructure and Utilities Group and, particularly, Envestra.  It should be noted in the case of AGL that the beta is not limited to its former gas transmission pipeline businesses and reflects its involvement in distributing and retailing gas and electricity and more speculative ventures overseas. 
Table 2.4:	Selected equity betas 
	March 1998(a)	March 1999(b)	June 1999(b)	Sept. 1999(b)	Dec. 1999(b)	March 2000(b)	
Diversified resources	1.22	1.24	1.36	1.31	1.38	1.46	
Infrastructure and utilities	0.61	0.63	0.65	0.68	0.73	0.78	
Diversified industrials	1.11	1.03	0.91	0.83	0.80	0.83	
All industrials	0.89	0.89	0.89	0.91	0.92	0.91	
AGL	—	0.85	0.81	0.85	0.81	0.80	
Envestra	—	—	0.47	0.50	0.48	0.48	
Notes:	(a)	IPART, The rate of return for electricity distribution networks: discussion paper, November 1998, p. 32. 
(b)	AGSM, Risk Management Service, various. 
An asset beta of 0.60 and debt beta of zero have been factored into the Commission’s calculations of an equity beta for the CWP.  The accurate calculation of the equity beta also requires the inclusion of the effective tax rate.  The Commission has used the 2.0 per cent from the cash flows rather than the statutory rate (see section 2.4.6 of this Final Decision).  However, the difference in the equity beta and cost of equity from the two tax rates is marginal in the case of the CWP.  Using the Monkhouse formula previously noted, the Commission has derived an equity beta (e) of 1.50 for the CWP. 
2.4.9	The cost of equity 
As noted earlier, the rate of return critical to the regulatory framework is the expected post-tax nominal cost of equity (re) for the business since it determines whether investors will be willing to advance equity to finance the capital infrastructure required. 
Table 2.5 summarises the parameter values proposed by AGLP and the Commission in its Draft Decision and this Final Decision based on the discussions and reasoning contained in the preceding sections of this chapter.  The resulting post-tax nominal cost of equity for this decision is 15.38 per cent.  The corresponding real cost of equity is 12.19 per cent.  
Table 2.5:	Comparison of WACC parameters used by AGLP and ACCC
CAPM parameter	AGLP proposal	ACCC Draft Decision	ACCC Final Decision	
Real Risk Free Rate (rrf )  %	3.2-3.5	3.44	3.44	
Expected Inflation Rate (f)  %	2.0-3.0	2.31	2.84	
Nominal Risk Free Rate (rf )  %	4.8-5.2	5.83	6.38	
Cost of debt margin (DM)  %	1.0-1.45	1.00	1.20	
Cost of debt (rd )  %	5.8-7.45	6.83	7.58	
Real cost of debt (rrd )  %	na	4.42	4.61	
Market Risk Premium (rm-rf )  %	6.0-7.0	5.50	6.0	
Corporate Tax Rate (T)  %	36	36(a)	30(a)	
Usage of Imputation Credits ()  %	25-50	50.00	50.00	
Debt Funding (D/V)  %	50-60	60.00	60.00	
Debt Beta (d ) 	na	0.00	0.00	
Asset Beta (a )	0.55-0.9	0.60	0.60	
Equity Beta (e) (b)	1.23-1.66	1.48	1.50	
Margin for Asymmetric Risk	0.0-1.0	0.00	0.00	
Margin for Self Insured Risk	0.0-0.5	0.00	0.00	
Nominal Cost of Equity  re = rf+e (rm-rf) %	12.2-19.0	14.0	15.38	
Real Cost of Equity  rre = (1+re)/(1+f)-1 %	na	11.4	12.19	
Source:	Revised Access Arrangement Information, p. 13 and ACCC analysis. 
Notes:	(a)	The corporate tax rate is an input to the Commission’s cash flow analysis.  The effective tax rate is estimated at approximately 2% for the Final Decision (6% for the Draft Decision).  
(b)	The Commission uses the Monkhouse formula which reflects an assumption of an active debt policy aimed at maintaining a specific gearing ratio as assumed in the regulatory model. 
2.4.10	Determination of a pre-tax real WACC
AGLP has chosen to convert from a formula derived nominal post-tax WACC to a pre-tax real WACC by first adjusting for tax and then for inflation.  An alternative is to reverse the order of the transformation.  That is, adjust the post-tax nominal WACC for inflation and then for tax to give a pre-tax real WACC.  The Commission does not consider either approach to be valid.  For the conversion formulae to be accurate they must accommodate the difference in tax depreciation and regulatory depreciation that arises due to differences in timing.  This can be done by the use of an effective tax rate.  However, this is a source of uncertainty over the long term.  
Given the known shortcomings of the conversion formulae, the Commission has decided to focus primarily on analysis of cash flows over the life of the pipeline to find the WACC consistent with the CAPM parameters determining the nominal cost of equity.  Cash flow analysis has been used by the Commission in this way for the Victorian Final Decision, the Transgrid Final Decision, for decisions relating to Adelaide, Brisbane and Perth airports and for the CWP Draft Decision.  The Commission has found that cash flow modelling provides a more robust and accurate WACC figure than the formulae approaches.  
A cash flow model was used by the Commission for the CWP Draft Decision to determine the pre-tax real WACC that would achieve cash flows consistent with the post-tax nominal cost of equity calculated by the CAPM.  For the Draft Decision the Commission proposed that a pre-tax real WACC of 7.5 per cent be applied by AGLP to determine revenues for the CWP.  
This approach has been criticised by AGLP and APIA/AGA.  APIA/AGA state that they oppose the use of cash flow analysis because, among other things, it is not transparent, it is based on forecasts and has been used by the Commission to justify a lower WACC.  
In contrast, BHPP submits: 
We support the use of financial modelling of the pipeline by the ACCC and the disclosure of the financial model.  This has provided great rigour in the analysis and transparency in the process, both of which reduce regulatory risk. 
The Commission acknowledges that the use of cash flow analysis is not as simple as the implementation of a formula to derive a WACC for a business.  However, a basic cash flow model is still required under AGLP’s proposal for calculating the shortfall in revenues and the incorporation into the roll-forward of the regulatory asset base.  While it would be ideal to have the CWP cash flow model publicly available, the Commission has accepted AGLP’s arguments that some details used in the cash flow model (which covers the pipeline’s life of 80 years) are commercially sensitive and should be considered confidential.  To assist interested parties in understanding the Commission’s analysis a worked example of an NPV cash flow model was included in the Draft Decision.  This example is provided as Appendix B to this Final Decision.  
A cash flow analysis over 80 years will clearly be based on forecast information.  As discussed in the relevant sections of this Final Decision, the Commission has assessed AGLP’s forecast costs and revenues as being reasonable. 
The Commission also notes AGLP’s suggestion that the use of cash flow analysis is a new development by the Commission: 
In converting a post tax nominal WACC to a pre tax real WACC two methodologies have previously been used by regulators: 
•	adjusting for statutory tax rate and then adjusting for inflation; and
•	adjusting for inflation and then adjusting for statutory tax rate. 
These approaches give a range of results.  Using the range of results regulators have selected a figure from the higher end of the range.  For example, the Commission used both approaches in the decision on the Victorian pipelines … 
This view is supported by APIA/AGA, who state: 
In this latest draft decision on the CWP, the Commission has introduced a new transformation method which relies on analysis of cash flows.  This method produces results which are closer to the lower figure given by the reverse transformation.  The Commission has then given more weight to this new approach to arrive at a proposed WACC which is towards the lower end of the range produced by the earlier two transformation methodologies.  
The Commission is concerned that key industry participants may have misunderstood the Commission’s analysis and reasoning for not relying on either of the transformation formulae when determining the WACC for a business.  It must be emphasised that the application of a cash flow analysis has not been ‘trialed’ on the CWP access arrangement.  The Commission employed cash flow analysis in relation to the Victorian transmission assets, the assessment of the multi-user integrated terminal at Adelaide airport, the assessments of new investment at Brisbane and Perth airports and determination of the revenues for the NSW and ACT electricity transmission network.  The ORG has also employed cash flow analysis in its final decision in relation to Multinet, Westar and Stratus gas distributors and its 2001 Electricity distribution price review: draft decision, May 2000.  
The Commission noted in its Draft Regulatory Principles with regard to the decision for the Victorian access arrangements: 
In that decision the Commission concluded that none of the formulations for the real pre-tax WACC proposed delivered to investors the return suggested as appropriate by the CAPM.  Instead of choosing a formula based WACC the Commission, in that instance, used cash-flow modelling to deduce what real pre-tax WACC, when applied within the regulatory framework, was likely to deliver the required return on equity.  This is equivalent to having available the correct conversion formula for the WACC, if an analytical expression of such a formula exists. 
The Commission anticipates that it will continue to use cash flow analysis in the assessment of the appropriate WACC for gas transmission pipeline access arrangements and for other regulatory decisions that require determination of a rate of return.  
The Commission has discussed in various documents its preference for determining a post-tax nominal WACC for regulated utilities.  However, under the Code service providers are able to propose a rate of return in terms other than a post-tax nominal basis.  In this instance, AGLP proposed a pre-tax real WACC for the CWP.  Accordingly, the Commission considers that it is appropriate to respond to AGLP’s proposal in the same terms.  
A pre-tax cash flow model has been used by the Commission to determine the pre-tax real WACC that will achieve cash flows which are consistent with the post-tax nominal cost of equity that has been calculated through the CAPM.  The Commission has found that a pre-tax real WACC of 7.78 per cent is consistent with a post-tax nominal cost of equity of 15.38 per cent. 
As mentioned above, formulae have been proposed for transforming a cost of equity into a WACC as well as the cash flow analysis adopted by the Commission.  There are also various forms of WACC that can be reported.  Table 2.6 below shows the results of the alternative formulae used by AGLP as well as the results from the Commission’s cash flow analysis carried out in line with the NPV-economic depreciation framework and the costs and parameters as determined in this Final Decision.  
Table 2.6:	WACC estimates based on parameters given in Table 2.5 
	per cent	
	AGLP proposal	ACCC
Draft Decision	ACCC
Final Decision	
Nominal Cost of Equity 
   re = rf + e (rm-rf)	12.2-19.0	14.0	15.38	
Post-tax nominal WACC 
   W = re [(1-Te)/(1-Te(1-))].E/V + rd (1-T).D/V	6.0-10.7		10.55(b)	
Post-tax real WACC 
   Wr = (1+W)/(1+f) -1	5.83-10.41(a)	4.6	7.49	
Pre-tax nominal WACC 
   Wt = re /(1-Te(1-)).E/V + rd .D/V	9.4-16.9	9.8(b)	10.84(b)	
Pre-tax real WACC 
   Wtr = (1+Wt)/(1+f)-1  (applicant transformation)	6.8-13.9	8.4(c)	na	
Pre-tax real WACC 
   Wtr = Wr/(1-T)  (reverse transformation)	9.11-16.27(a)	7.1	na	
Pre-tax real WACC 
   (cash flow analysis by the Commission)	na	7.3	7.78	
Source:	Revised Access Arrangement Information, p. 13 and ACCC analysis. 
Notes:	(a)	ACCC calculation from AGLP data. 
	(b)	ACCC calculation from cash flow analysis. 
(c)	This figure is derived from the post-tax nominal WACC using the formula noted in the table.  The tax rate used was the statutory rate of 36%.  

Amendment A2.2
In order for AGLP’s access arrangement for the Central West Pipeline to be approved the WACC estimates and associated parameters forming part of the access arrangement must be amended to more accurately reflect the current financial market settings.  In particular, the post-tax nominal cost of equity should be set at 15.38 per cent, the pre-tax real WACC should be set at 7.78 per cent and the associated inflation assumption set at 2.84 per cent.

Amendment A3.7 specifies a tariff path that is consistent with these parameter values.
2.4.11	Determination of a post-tax nominal WACC
As noted in the Draft Regulatory Principles, the Commission considers that the post-tax nominal WACC (established by a post-tax cash flow model on the post-tax nominal cost of equity) is preferred to the pre-tax real WACC.  The Commission believes that a post-tax nominal framework has the benefits of being better understood by financial markets and that the treatment of depreciation is transparent.  In addition, the treatment of tax avoids the difficulties in the pre-tax real framework as outlined in the section below.  While the Commission has responded to AGLP’s proposed pre-tax real WACC, it considers it appropriate to explain in more detail the considerations relevant to developing a post-tax framework and why this is desirable.  
Application to the CWP access arrangement
The Commission has applied a post-tax framework to the analysis of the CWP access arrangement.  It has also maintained a parallel analysis in an equivalent pre-tax framework.  The main reason for this is that the post-tax approach was not applied in the context of the Draft Decision and interested parties may not therefore have given the approach due consideration in submissions when responding to the Draft Decision.  To maintain equivalence between the two frameworks, the Commission has decided to implement a normalisation procedure for tax compensation in conjunction with the proposed pre-tax regulatory framework considered in the Draft Decision.  This enhancement does not alter the prospective revenue path for the service provider under the proposed framework but it will facilitate a transition to an alternative framework at a future review in a way which is fair to both AGLP and to users. 
The Draft Decision and this Final Decision have recognised a number of the problems, which plague the implementation of pre-tax real frameworks.  Accordingly, the use of a formula based approach to determining the WACC was avoided.  Instead, a cash flow analysis (maintaining the assumptions of the regulatory framework and the CAPM) over the life of the asset was used to determine the pre-tax real WACC that was consistent with the expected cost of equity resulting from the CAPM.  This cash flow approach already required reasonable estimates of the taxation treatment of the assets and associated income to be established, so it is a fairly minor analytical step to implement the normalisation calculations.
The assessment of tax relied on revenues generated under the regulatory framework and estimated allowable costs recognised by the Australian Taxation Office (ATO) to derive the taxable income in each year.  The allowed tax costs included:
•	Operation and maintenance costs - these were equated directly to those costs recognised in the regulatory framework;
•	Interest costs – these were derived from estimated debt levels and the proposed cost of debt.  Debt levels were assumed to vary with changes in the regulatory asset base so as to maintain the debt to equity assumption used in the CAPM; and
•	Tax depreciation – the rates of depreciation recommended by the ATO were applied to each category of assets represented in the regulatory asset base.  The straight line depreciation method was applied although a diminishing value method would give greater allowances over the short to medium term.
Tax is assumed to apply on estimated taxable income at the corporate tax rate and assumed payable at the end of the financial year for which the income is assessed.  
In a price path approach as used in the CWP access arrangement the assessment of the pre-payment of taxes implicit in a pre-tax framework is somewhat more convoluted than in the standard cost of service model.  Firstly, revenues are determined on the basis of a CPI-X adjustment rule and therefore a simple comparison with the revenues that would apply under a ‘no-tax’ scenario (T = 0) is not helpful.  Instead, it is necessary to examine the impact of the return of capital on economic depreciation (which is determined as a residual after subtracting operation and maintenance costs and return on capital estimates from the revenue).  
The return on capital in period n, is estimated as [Wt . An ] where Wt is the assessed pre-tax nominal WACC and An is the value of the regulatory asset base at the start of the period.  The pre-tax nominal WACC estimated from the cash flow modelling includes a premium above the ‘no-tax’ rate to compensate for expected tax payments over the life of the assets.  This raises the question as to what the ‘no-tax’ WACC should be.  It could be estimated on the same basis as Wt but setting the corporate tax rate T to zero in the calculations.  Fortunately, there is a more direct estimate available.  In the absence of tax the pre-tax and post-tax WACC all converge to the vanilla WACC (Wv) given by: 
Wv = re . E/V + rd . D/V
where all of the parameters have their interpretation as noted earlier in this chapter.
Consequently, the provision for pre-payment of tax can be readily calculated for each year as: 
Pre-payment of tax = (Wt - Wv) . An
To track the net pre-payment of tax (that is, over or under compensation for tax liabilities) it is necessary to subtract from this figure the assessed tax for the same year.  The accumulation of these under or over payments for tax liabilities over time provides a mechanism to ensure that there is no long term over or under compensation for tax liabilities due to errors in the long term forecast of inflation or errors in assumptions regarding the tax regime applicable over the longer term.  Unfortunately, a simple accumulation of these amounts does not adequately reflect the value of the pre-payments to AGLP because the amounts effectively reflect a return of capital.  To the extent that this is not explicitly modelled in the pre-tax framework the future revenues are enhanced by an amount equal to the earnings on the accumulation of net pre-payments of tax.  This augmented accumulation is the amount that needs to be monitored to provide the correct assessment of the net compensation for tax at any point in time.  Table B.2 in Appendix B provides an example of the estimation of net tax pre-payments over the course of an initial access arrangement period.  

3.	Reference tariff elements
The Code specifies a set of mandatory elements with which an access arrangement must comply.  This chapter considers matters relating to reference tariffs including depreciation and asset value.  Chapter 4 discusses AGLP’s compliance with the non-tariff elements of the Code. 
Sections 3.3 to 3.5 of the Code require an access arrangement to include a reference tariff for at least one service that is likely to be sought by a significant part of the market and other services for which the Commission considers a reference tariff should be included.  An access arrangement must also include a policy describing the principles that are to be used to determine a reference tariff (a reference tariff policy).  The reference tariff and reference tariff policy must comply with the reference tariff principles in section 8 of the Code.
In addition to the access arrangement and access arrangement information, AGLP has provided the Commission with a spreadsheet file which contains the model used to construct the revenues from forecast volume and cost data.  This spreadsheet has not been made publicly available although the resulting revenues and tariffs are included in this Final Decision. 
This chapter assesses compliance of the proposed reference tariff elements of the access arrangement using the structure below, taking into account specific requirements of the Code, proposals by AGLP, and submissions from interested parties: 
3.1	Overall reference tariff methodology
3.2	The initial capital base 
3.3	New facilities investment and capital redundancy
3.4	Depreciation and inflation
3.5	Non-capital costs
3.6	Forecast revenue
3.7	Cost allocation and tariff setting
3.8	Tariff path and incentive structure 
3.9	Assessment of reference tariffs and reference tariff policy.
The amendments required by the Commission relating to reference tariffs are located in the relevant sections of this chapter.  All amendments are replicated in the Executive Summary. 
3.1	Overall reference tariff methodology
Section 8 of the Code contains the general objectives for a reference tariff and certain factors about which the relevant regulator must be satisfied before approving reference tariffs and the reference tariff policy.  A discussion of reference tariffs and the reference tariff policy in relation to sections 8.1 and 8.2 of the Code is contained in section 3.9 of this Final Decision.  
The reference tariff principles of section 8.4 of the Code permit a choice of three methodologies for determining the total revenue:
•	cost of service:  where the total revenue is set to recover costs with those costs to be calculated on the basis of a return (rate of return) on the value of the assets that form the covered pipeline (capital base), depreciation on the capital base (depreciation) and the operating, maintenance and other non-capital costs (non-capital costs) incurred in delivering all services;
•	internal rate of return:  where the total revenue is set to provide an acceptable internal rate of return (IRR) for the covered pipeline on the basis of forecast costs and sales; or
•	net present value:  where the total revenue is set to deliver a net present value (NPV) for the covered pipeline (on the basis of forecast costs and sales) equal to zero, using an acceptable discount rate.
While these methodologies are different ways of assessing the total revenue, their outcomes should be consistent (for example, it is possible to express any NPV or IRR calculation in terms of a cost of service calculation by the choice of an appropriate depreciation schedule).  In addition, other methodologies that can be translated into one of these forms are acceptable under section 8.5 of the Code. 
AGLP has provided an access arrangement and access arrangement information which specify an initial tariff for the transportation service.  This is the only reference service.  In the documents provided AGLP states the principles on which the tariff is based, outlines the incentive mechanism and proposes to set (as a fixed principle) the residual asset value at the end of the access arrangement period (30 June 2004) to be $45.12 million.  
AGLP has adopted a price path approach (which is permitted under section 8.3(c) of the Code) based on an application of the NPV methodology.  The proposed tariff would apply to actual throughput only with no penalty for overruns (until the pipeline achieves a contracted capacity of 85 per cent).  There is no capacity component to the tariff.  AGLP has stated that it expects that the pipeline’s pattern of usage will be sufficiently known at the time of the proposed scheduled review of the access arrangement for it to introduce a two-part tariff (with a capacity-commodity split), and that it is AGLP’s present intention to offer such a service as a reference service at that time. 
The early tariffs have been set low in order to be competitive with alternate fuels and to encourage market growth.  The tariffs then rise steeply throughout the proposed access arrangement period.  AGLP anticipates that the tariffs in the next access arrangement period will be linked to the Consumer Price Index (CPI) (which, for the purposes of the revenue model, AGLP has assumed to be 2.5 per cent) with an X factor.
AGLP has proposed a single pricing zone, claiming that this reflects a regional infrastructure development objective of ensuring that no local community will be at a price disadvantage to any other.  AGLP states that the proposed single zone reference tariff is intended to encourage sufficient demand in Forbes, Parkes, Narromine and Dubbo to justify the total investment.  AGLP contends that other tariff methodologies, such as distance-based or stand-alone, would result in a delivered price for gas that would be uncompetitive with alternative fuels.  AGLP states that without the combined volumes of the four centres, the pipeline would not be viable. 
AGLP states that prospective users of the CWP have agreed to the single pricing zone.  This is supported by submissions from Dubbo City Council (DCC) and the Mudgee Region Business Enterprise Centre (MRBEC).  
Tariffs are proposed by AGLP for each year and would not be revised during the proposed initial access arrangement period as a result of differences between projected and achieved performance.  This provides AGLP with an incentive for efficiency gains and increased volumes, as it will reap the total of any benefit.  No comment has been made by AGLP on how these gains may be shared with users. 
As discussed in the previous chapter, AGLP has used a CAPM approach to develop a nominal cost of equity.  This is then used to calculate a pre-tax real WACC through the use of various formulae.  The pre-tax real WACC so obtained is then applied to an initial asset base which AGLP states has been valued using the depreciated optimised replacement cost (DORC) approach
As a result of low forecast throughput during the early years of the CWP, coupled with low initial tariffs (which are intended to stimulate demand), revenue is not expected to recover all costs during the first phase (which extends over a significant number of years) of the lifetime of the CWP.  Any net under-recovery is termed ‘economic depreciation’ which is negative.  AGLP’s economic depreciation approach is intended to allow AGLP to subsequently recoup these under-recovered revenues and have the opportunity to earn a revenue stream that covers efficient costs over the life of the asset.  The methodology results in negative depreciation during the first phase, which has the effect of increasing the asset value for regulatory purposes.  The residual value at the end of the initial access arrangement period is greater than the initial capital base at the start of the period.  Similarly, the initial capital base is greater than the actual cost of the assets as a result of negative economic depreciation in the first period of operation.  This approach is considered reasonable for the CWP and is discussed further in the following section of this chapter. 
One point to note when considering AGLP’s methodology is that it has used the term ‘economic depreciation’ when ‘back-ended depreciation’ or ‘deferred depreciation’ may be a more appropriate description.  The Commission has adopted AGLP’s usage in its decision documents to avoid inconsistency with the terminology used in the proposed access arrangement, access arrangement information and most submissions.  The Commission expects that AGLP will adopt either of the preferred usages in its revised access arrangement and access arrangement information.
Under the price path methodology, notional depreciation over the access arrangement period is equal to the difference between the value of the initial capital base at the start of the period and the residual value at the end of the period (section 8.34(a) of the Code).
3.2	The initial capital base
3.2.1	Code requirements
Section 8.4 of the Code outlines how total revenue should be calculated under the cost of service, IRR or NPV methodologies.  For the NPV methodology as adopted by AGLP the Code states:
The initial value of the Covered Pipeline in the NPV calculation is to be given by the Capital Base at the commencement of the Access Arrangement Period and the assumed Residual Value at the end of the Access Arrangement Period should be calculated consistently with the principles in this section 8.
The methodology used to calculate the Cost of Service, an IRR or NPV should be in accordance with generally accepted industry practice.
The Code therefore requires the regulator to approve a value for an existing pipeline (an initial capital base) prior to the commencement of the access arrangement.  Under the NPV methodology, the residual value assumed in the initial access arrangement period is carried forward to the subsequent access arrangement period (adjusted for differences between actual and forecast new facilities investment and inflation and, where appropriate, redundant assets).  The valuation of the initial capital base is of central importance to the service provider, users and prospective users as it will determine expected future returns to the existing assets (in present value terms, evaluated using the regulated WACC). 
The applicable principles set out in chapter 8 of the Code for establishing the initial capital base for a pipeline differentiate between pipelines that came into existence before (sections 8.10 and 8.11) and after (sections 8.12 and 8.13) the commencement of the Code  (which in NSW was 14 August 1998).
The initial capital base – new pipelines
For new pipelines (that is, pipelines that came into existence after the commencement of the Code), the Code (section 8.12) requires, subject to section 8.13, that the value of the initial capital base is the actual capital cost of those assets at the time they first enter service.  A new pipeline does not need to pass the tests described in section 8.16. 
Section 8.13 allows for adjustment to be made to the actual capital cost if it is appropriate to account for new facilities investment (or the recoverable portion, whichever is relevant), depreciation and redundant capital incurred or identified if a sufficient period exists between the time the covered pipeline first enters service and the time the reference tariff is proposed.
The initial capital base – existing pipelines
For existing pipelines, the Code (sections 8.10(a) and (b) and 8.11) requires that normally the value of the initial capital base should not fall outside the range of depreciated actual cost (DAC) and depreciated optimised replacement cost (DORC).  In establishing the initial capital base, the Code also requires the Commission to consider: 
•	other well recognised asset valuation methodologies (section 8.10(c)) and the advantages and disadvantages of these methodologies (section 8.10(d));
•	international best practice and the impact on the international competitiveness of energy consuming industries (section 8.10(e));
•	the basis on which tariffs have been (or appear to have been) set in the past, the economic depreciation of the covered pipeline, and the historical returns to the service provider from the covered pipeline (section 8.10(f));
•	the reasonable expectations of persons under the regulatory regime that applied to the pipeline prior to the commencement of the Code (section 8.10(g));
•	the impact on the economically efficient utilisation of gas resources (section 8.10(h));
•	the comparability with the cost structure of new pipelines that may compete with the pipeline in question (for example, a pipeline that may by-pass some or all of the pipeline in question) (section 8.10(i));
•	the price paid for any asset recently purchased by the service provider and the circumstances of that purchase (section 8.10(j)); and
•	any other matters considered relevant (section 8.10(k)).
General principles
In addition, the Commission is guided by the objectives outlined in section 8.1 of:
(a)	providing the Service Provider with the opportunity to earn a stream of revenue that recovers the efficient costs of delivering the Reference Service over the expected life of the assets used in delivering that Service;
(b)	replicating the outcome of a competitive market;
(c)	ensuring the safe and reliable operation of the Pipeline;
(d)	not distorting investment decisions in Pipeline transportation systems or in upstream and downstream industries;
(e)	efficiency in the level and structure of the Reference Tariff; and
(f)	providing an incentive to the Service Provider to reduce costs and to develop the market for Reference and other Services.
3.2.2	AGLP’s proposal
AGLP has proposed that reference tariffs will be determined for the CWP based on a NPV methodology incorporating what AGLP defines as economic depreciation in order to allow it the opportunity to earn a stream of revenue that recovers the efficient costs of delivering the reference service over the expected life of the assets used in delivering that service.  This methodology impacts on the valuation of the initial capital base as a result of the time interval between the commencement of the pipeline operations (nominally) on 30 June 1998 and the establishment of the initial capital base on 30 June 1999. 
Figure 3.1 below illustrates how the regulatory asset base would grow under AGLP’s proposal during the first phase of the life of the CWP from an adjusted capital cost of $25.93 million (30 June 1998) to the initial capital base valuation of $29.49 million (30 June 1999), and subsequently to a residual value of $45.12 million (30 June 2004).  The same regulatory asset base profile would have resulted if the initial capital base had been established a year earlier.  Notionally, the value of the initial capital base is equal to the residual value at the end of the first year of the CWP’s operations.  
The methodology proposed by AGLP implicitly categorises the CWP as an existing pipeline.  AGLP has advised that the CWP was constructed and commissioned progressively.  Construction commenced late in 1997 and the sections from Marsden to Parkes and from Parkes to Dubbo respectively were commissioned on 29 April 1998 and 1 August 1998.  Gas first flowed through the Forbes and Parkes off-takes respectively on 1 and 2 May 1998, and through the Narromine and Dubbo off-takes respectively on 2 and 4 August 1998.  The Code commenced in NSW on 14 August 1998.

Figure 3.1:	AGLP’s proposed valuation of the capital base, 1998 to 2004 ($m)
Source:	Supplementary Access Arrangement Information, p. 6.
AGLP has not explicitly addressed whether the CWP should be valued as a new pipeline, or referred to the pertinent sections of the Code (section 8.12 and 8.13).  However, it is relevant that AGLP states that the reference tariffs for the years ending 30 June 1999, 2000 and 2001 were ‘committed to by AGLP and communicated to the market’ prior to lodgement of its proposed access arrangement to the Commission for approval.  AGLP states that ‘[t]his was necessary because at the time the CWP was commissioned the Code was not in place, and Prospective Users required tariff certainty prior to committing to using the CWP.’ 
AGLP states that it has used a DORC methodology to value the CWP, incorporating an adjustment for economic depreciation.  Table 3.1 summarises the process followed by AGLP to determine a proposed regulatory asset value of $29.49 million as at 30 June 1999.  
Table 3.1:	AGLP’s proposed valuation of the initial capital base of the CWP
	$ million (at 30 June 1999)(a)	
Asset type	RC(b)	ORC(c)	Adjusted ORC(d)	AGLP valuation(e)	
Transmission pipeline	29.76	26.98	24.98	28.54	
Compressor stations:					
   Rotating equipment	nil	nil	nil	nil	
   Station facilities	nil	nil	nil	nil	
Regulation and metering stations	0.17	0.17	0.17	0.17	
Odourisation stations	0.15	0.15	0.15	0.15	
SCADA and communications	0.63	0.63	0.63	0.63	
Total asset value	30.71	27.93	25.93	29.49	
Source:	Revised Access Arrangement Information, p. 8. 
Notes:	(a)	AGLP states that all cost information in the table is in 1999 dollars. 
(b)	Replacement cost  is the actual construction cost of the pipeline. 
(c)	The optimised configuration is a 168 mm (6”) pipeline from Marsden to Dubbo in free flow.
(d)	For regulatory purposes, AGLP has removed the Commonwealth Government grant of $2 million from the initial capital base. 
(e)	Economic depreciation has been applied. 

AGLP used the actual construction cost for the pipeline (including regulation and metering stations, odourisation stations and System Control and Data Acquisition (SCADA) and communications) of $30.71 million as the replacement cost (RC).  While this amount includes an allowance of $0.15 million for capitalised interest, AGLP has advised that the additional interest charged to the project would have been in the vicinity of $0.6 million if construction costs had been capitalised since the commencement of construction activities in September 1997.  
The pipeline consists of a 219 mm (eight inch) pipe from Marsden to Alectown and a 168 mm (six inch) pipe from Alectown to Dubbo.  This configuration has been built in anticipation of an extension of the pipeline to Tamworth.  An optimised pipeline for Marsden to Dubbo would be a 168 mm pipe for the entire length.  AGLP has removed $2.78 million from the asset base to give an optimised replacement cost (ORC) of $27.93 million for a 168 mm pipeline.
The ORC has then been reduced by $2 million to $25.93 million (adjusted ORC in Table 3.1) in order to reflect the funding received by AGLP under the Commonwealth Government’s Regional Development Program.  
Finally, AGLP states that it has applied economic depreciation to the adjusted ORC which increases that amount by $3.56 million to arrive at the proposed valuation of $29.49 million at 30 June 1999.  AGLP has used the definition:
Economic depreciation = revenue – operating costs – return on capital
Normally an adjustment to account for depreciation would be expected to result in a decreased valuation, reflecting the fact that part of the asset’s life has already been used.  However, under the AGLP proposal, the pipeline incurs negative economic depreciation during the earlier phase of its lifetime such that initial under-recovery of the cost of the service can later be offset by commensurate over-recovery.  Therefore, the adjustment proposed to account for depreciation in this case increases the valuation of the CWP.  
3.2.3	Submissions by interested parties
No comments were received on this issue. 
3.2.4	Commission’s considerations
Valuation of the CWP as a new pipeline
The Commission notes that the CWP does not fall within the definition of a ‘new pipeline’ for the purposes of section 8.12 of the Code.  However, the Commission considers that, consistent with the overall principles of the Code, it needs to give some weight to the guidance provided by section 8.12 when assessing the reasonableness of the proposed value of the CWP’s initial capital base.
Application of the provisions of section 8.12 would result in the initial capital base being valued at $30.71 million, the actual construction cost of the pipeline.  Adjustment to reflect funding by the Commonwealth Government of $2 million could be made either through a commensurate reduction in the initial capital base or through the cash flows.  The former option, which is simpler, and is consistent with AGLP’s proposal, would result in an initial capital base valuation of $28.71 million.  
Valuation of the CWP as an existing pipeline
The Code provides considerable guidance regarding the valuation of existing pipelines.  In particular, sections 8.10(a), (b) and (c) respectively require consideration of values arising from the DAC, DORC and ‘other well recognised’ asset valuation methodologies.  Section 8.11 states that the valuation should not normally fall outside the range between the DAC and DORC valuations.  The Commission has considered alternative methodologies as part of its assessment below of AGLP’s proposed four-stage process to establish the initial capital base of the CWP.  
AGLP’s methodology starts with the assumption that the replacement cost of the CWP is equal to $30.71 million, which it states is the actual construction cost.  The Commission is satisfied that this amount is the actual construction cost of the pipeline, and that it provides a reasonable basis for establishing the RC.  
Second, AGLP optimised the configuration of the pipeline to remove the cost of ‘oversizing’ installed capacity to allow for potential future gas flows to Tamworth.  AGLP re-costed the CWP as if it were comprised solely of 168 mm pipeline, reducing the valuation by $2.78 million.  The Commission has modelled the likely gas flows through the CWP (including with the proposed extension), and has concluded that the proposed optimised configuration is reasonable.  The Commission has also assessed the costing of the optimised configuration (an ORC of $27.93 million), which it considers to be reasonable.
Third, AGLP removed $2 million from the ORC valuation in recognition of the Commonwealth Government funding provided of that amount.  The Commission agrees that benefits provided by governments to facilitate infrastructure development should be passed on to the users of those assets, and that AGLP’s removal of the amount from the capital base is an appropriate adjustment.
The fourth stage of AGLP’s proposal is to increase the ORC valuation by an amount of $3.56 million to reflect negative economic depreciation which AGLP expects to be incurred.  AGLP refers to the resultant valuation of $29.49 million that it proposes for use as the initial capital base as a DORC valuation.  However, the AGLP approach to determining a regulated asset base differs significantly from the accepted DORC methodology, and is not consistent with the value that the Commission should consider pursuant to section 8.10(b) of the Code.  The Commission has referred to valuations resulting from the AGLP approach in this Final Decision as the regulatory value in order to differentiate it from the generally accepted DORC methodology.  
The Commission has confirmed that, based on assumptions applied in AGLP’s revenue model, (minus) $3.56 million would be a reasonable estimate of the appropriate adjustment for economic depreciation.  However, the magnitude of this adjustment is sensitive to assumptions applied in AGLP’s revenue model.  For example, higher early revenues or lower costs would reduce the amount of negative economic depreciation in this period.
The Commission has modelled cash flows under a range of plausible assumptions to derive alternative estimates of the value of economic depreciation.  In each case the outcome is negative over the initial access arrangement period.  For example, applying the WACC (of 7.75 per cent) adopted in the Victorian Final Decision would result instead in an economic depreciation adjustment of (minus) $2.95 million, and an asset valuation of $28.88 million at 30 June 1999.  Conversely, if expected throughput volumes were reduced by ten per cent in the initial access arrangement period, the magnitude of economic depreciation would increase to (minus) $3.00 million.
Section 3.4 of this Final Decision discusses the Commission’s views on the appropriateness of AGLP’s use of economic depreciation and concludes that, subject to a number of reservations, the proposal to apply a form of tariff levelising to eventually recoup under-recoveries accrued in the early period of the life of the CWP is consistent with Code principles.  
As noted above, Figure 3.1 illustrates how the regulatory value of the asset base would grow under the NPV price path methodology from the (optimised) actual cost of the CWP ($25.93 million at 30 June 1998) to the initial capital base valuation ($29.49 million at 30 June 1999), and subsequently to a residual value ($45.12 million at 30 June 2004).  Subject to the Commission’s acceptance of AGLP’s overall NPV approach, the fundamental regulatory asset valuation for the purpose of this access arrangement is that of 30 June 1998.  The Commission considers that the optimised valuation of the actual cost of the CWP proposed by AGLP is appropriate.  The amount would be approximately $2.8 million higher if a non-optimised valuation were used.
Initial valuation of the CWP based on DAC
Table 3.2 provides an indicative estimate prepared by the Commission of DAC as at 30 June 1999.  Straight line depreciation has been applied on the basis of the economic life of the assets as identified by AGLP, and on the simplifying assumption that all assets came into existence on 30 June 1998.  As would be expected for such a new asset with a long expected life, the DAC valuation of $30.27 million is a little less than the actual cost.  After making allowance for the Commonwealth Government’s $2 million contribution to the funding of the CWP, the DAC based valuation of the initial capital base would be $28.27 million at 30 June 1999.
Table 3.2:	Derivation of estimate of DAC valuation of the CWP
		$ million (at 30 June 1999)	
Asset type	Economic life (years)	Actual Cost	Depreciation	DAC	Adjusted DAC(a)	
Transmission pipeline	80	29.76	0.372	29.39	27.39	
Regulation and metering stations	50	0.17	0.003	0.17	0.17	
Odourisation stations	35	0.15	0.004	0.15	0.15	
SCADA and communications	10	0.63	0.063	0.57	0.57	
Total asset value		30.71	0.443	30.27	28.27	
Source:	ACCC.
Note:	(a)	The Commonwealth Government grant of $2 million has been removed for the purposes of considering the initial capital base.

Initial valuation of the CWP based on DORC
AGLP has provided the estimate shown in Table 3.3 of the CWP’s DORC as at 30 June 1999 of $25.55 million.  Straight line depreciation has been applied on the basis of the economic life and remaining economic life of the assets as identified by AGLP.  The derivation is essentially the same as that provided by AGLP in the CWP access arrangement under its proposed approach, with the exception that the adjusted ORC valuation is reduced by accumulated depreciation of $0.383 million (instead of being increased by economic depreciation of $3.56 million) to calculate the DORC valuation.
Table 3.3:	Derivation of estimate of DORC valuation of the CWP
	$ million (at 30 June 1999)(a)	
Asset type	RC(b)	ORC(c)	Adjusted ORC(d)	Accumulated Depreciation(e)	DORC	
Transmission pipeline	29.76	26.98	24.98	0.312	24.668	
Regulation and metering stations	0.17	0.17	0.17	0.003	0.167	
Odourisation stations	0.15	0.15	0.15	0.004	0.146	
SCADA and communications	0.63	0.63	0.63	0.063	0.567	
Total asset value	30.71	27.93	25.93	0.383	25.55	
Source:	AGLP, Additional General Information, 25 June 1999, p. 5.
Notes:	(a)	All cost information in the table is in 1999 dollars.
(b)	Replacement Cost is the actual construction cost of the pipeline.
(c)	The optimised configuration is a 168 mm (6”) pipeline from Marsden to Dubbo in free flow.
(d)	For regulatory purposes, AGLP has removed the Commonwealth Government grant of $2 million from the initial capital base.
(e)	Depreciation is calculated on a straight line basis assuming economic lives set out on page 10 of the Revised Access Arrangement Information.

Overall assessment of valuation of the initial capital base
Section 8.12 of the Code requires that the actual capital cost ($30.71 million, less the $2 million government contribution) would be the appropriate initial valuation for the CWP if it were a new pipeline.  While the Commission is guided by this, it is aware that it is not directly applicable to the CWP because the pipeline came into existence shortly before the Code commenced in NSW.
AGLP implicitly has proposed that the CWP be treated as an existing pipeline for the purpose of valuing the initial capital base.  The Commission considers that AGLP’s proposed valuation of the replacement cost is reasonable, and that the adjustments to reflect optimisation and Commonwealth funding are appropriate.
The Commission has carefully assessed AGLP’s proposed depreciation methodology and has concluded that it may provide an appropriate means to allow AGLP the opportunity to later recover early under-recoveries and so earn a reasonable return over the life of the CWP.  However, the Commission notes that the proposed methodology differs from the DORC approach as it is generally accepted, and that the resulting valuation differs from the DORC value that the Commission should consider for the purposes of section 8.10(b).  Further, the Commission notes that the valuation resulting from AGLP’s methodology is dependent on assumptions incorporated, and that use of a pre-tax real WACC of 7.8 per cent would generate a valuation of $28.48 million under this methodology. 
Table 3.4:	Summary of asset valuation estimates for the CWP
	$ million (at 30 June 1999)(a)	
	RC	DAC(b)	ORC	Adjusted ORC(c)	DORC(d)	AGLP approach(e)	
Total asset value	28.71	28.27	27.93	25.93	25.55	28.48	
Source:	AGLP and ACCC calculations.
Notes:	(a)	Amounts are in 1999 dollars. 
(b)	Accounting depreciation (straight line) has been applied. 
(c)	The Commonwealth grant of $2 million has been deducted.
(d)	Accounting depreciation (straight line) has been applied.
(e)	Adjusted to reflect revenue model amendments specified in this Final Decision. 

The Commission has taken into consideration the factors listed in section 8.10 of the Code, and notes in particular that:
•	$28.27 million and $25.55 million are respectively estimates of the DAC (section 8.10(a)) and DORC (section 8.10(b)) valuations which normally set the boundaries for the initial capital base for an existing pipeline (section 8.11);  
•	valuations based on other methodologies (or variations of methodologies) include $28.71 million actual costs or replacement cost (section 8.10(c));  
•	AGLP has proposed a regulatory value of $29.49 million, based on a NPV based methodology that applies economic depreciation to increase the ORC valuation during the earlier period of the life of the pipeline.  Under the NPV methodology, the capital base at the beginning of an access arrangement period is the value carried forward (adjusted as necessary) of the residual value at the end of the previous period.  Consistent with this approach, the initial capital base is set at the residual value at the end of the period preceding the establishment of the initial capital base (as illustrated in Figure 3.1);
•	amendments required in this Final Decision concerning the applicable WACC and inflation index would reduce the regulatory value to $28.48 million;
•	these estimates would be higher if construction costs incurred from the commencement of construction activities in September 1997 had been capitalised or (with the exception of AGLP’s regulatory value) if actual construction costs were indexed for consistency with 1999 dollars; 
•	as expected for an almost new pipeline, differences arising from alternative valuation methodologies are relatively small, and their comparative advantages and disadvantages are similar (section 8.10(d)); and
•	while assessment of performance compared with best practice (see chapter 5 of this Final Decision) is problematic, limited information provided by AGLP regarding comparative capital costs in Australia appears to indicate acceptable performance (section 8.10(e)). 
The Commission has decided to accept a valuation derived through AGLP’s methodology, adjusted to incorporate changes to costs and revenues as a result of amendments required in this Final Decision.  This valuation of $28.48 million does not materially differ from a DAC valuation or the actual capital cost, and is lower than if economic depreciation had been applied instead to a DAC starting base.  As noted above, this valuation is conceptually equivalent to the residual value at the end of the period preceding the establishment of the initial capital base, which is consistent with AGLP’s broader proposed methodology.
The Commission notes that the value of the initial capital base proposed by AGLP (once adjusted in line with changes required in this Final Decision which impact on the revenue requirement) of $28.48 million lies approximately $0.2 million outside the range of $25.55 million (DORC) to $28.27 million (DAC) specified by section 8.11 as usually being acceptable for an existing pipeline.  The Commission has considered the following additional factors in its assessment of the consistency of an asset valuation based on AGLP’s proposed methodology with the section 8 reference tariff principles:
•	the fundamental regulatory asset valuation for the purpose of this access arrangement is that of 30 June 1998, the nominal starting date of the CWP.  The 30 June 1999 valuation, although it establishes the value of the initial capital base, follows from the 30 June 1998 value and the assumptions under the overall NPV approach, and is in effect a residual value required to provide the determined return on assets;
•	AGLP has valued the asset base as at 30 June 1998 using ORC, which results in a valuation of approximately $2.8 million less than if a non-optimised valuation were used; 
•	adoption of the alternative approach to capitalisation of construction costs noted by AGLP would have resulted in a DAC valuation which does not significantly differ from the (adjusted) proposed AGLP regulatory value; and
•	the CWP would have been valued at its actual capital cost of $28.71 million as a new pipeline (pursuant to section 8.12 of the Code) if it had ‘ … come into existence after the commencement of the Code’.  
Two potential concerns are identified later in this Final Decision about the proposal: the implications of likely forecasting errors are addressed in section 3.7; and economic efficiency and equity issues relating to setting the tariff path over time are addressed in section 3.8.
An amendment is required so that the initial capital base will reflect changes to costs and revenues specified in this Final Decision.  In addition, as noted in section 2.4, the actual inflation outcome of 1.1 per cent for the year to 30 June 1999 must be incorporated in relevant calculations.
Amendment A3.1
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the value of the initial capital base must be adjusted to $28.48 million so that it reflects the impact of changes required in this Final Decision on AGLP’s costs and revenues and the actual inflation rate to the June quarter 1999.

In response to the Draft Decision AGLP advised that it would amend its valuation of the initial capital base to reflect the impact of changes on costs and revenues and the assumed inflation rate.  It did not undertake to incorporate the rate of return proposed in the Draft Decision.
3.3	New facilities investment and capital redundancy
3.3.1	Code requirements
Once the value of the initial capital base is established, the capital base for each subsequent period must be determined.  In this case, where a NPV methodology is used, the subsequent period’s capital base is determined as the value of the capital base at the end of the preceding period (the residual value) adjusted for differences between forecast and actual new facilities investment (capital expenditure) and redundant capital (section 8.9 of the Code).  The difference between forecast and actual inflation is also factored into the calculation. 
This leads to the issues of how capital expenditure and capital redundancies are treated under an access arrangement.  These issues are the subject of this section.  
New facilities investment
The Code (sections 8.15-8.16) allows for the capital base to be increased to recognise additional capital costs incurred in constructing new facilities for the purpose of providing services.  The amount of the increase is the actual capital cost provided that the investment is prudent in terms of efficiency, in accordance with accepted good industry practice and is designed to achieve the lowest sustainable cost of delivering services.  
Furthermore, if the incremental revenue is not expected to exceed the cost of the investment, the service provider (and/or users) must satisfy the relevant regulator that the new facility has system wide benefits (justifying higher tariffs for all users), or that the new facility is necessary to maintain the safety, integrity or contracted capacity of services.
Under sections 8.18 and 8.19 of the Code a service provider may also undertake new facilities investment if these criteria are not met.  To the extent that an investment does not meet the section 8.16 criteria or is speculative in character the augmentation of the capital base needs to be correspondingly reduced.  
Reference tariffs may be determined on the basis of forecast investment during the access arrangement period provided that such investment is reasonably expected to pass the requirements noted above when the investment is forecast to occur (section 8.20 of the Code).  However, the inclusion of forecasts does not imply that the criteria contained in section 8.16 of the Code have been satisfied.  The regulator may reserve its judgment until the time that the investment is undertaken or at the next review.  The Code (section 8.22) also notes that the reference tariff policy should specify how discrepancies between forecast and actual investment are to be reflected in the capital base at the commencement of the next regulatory period (so as to meet the objectives of section 8.1 of the Code).  The alternative is for the regulator to determine how the expenditure will be treated for the purpose of section 8.9 at the time a revision to the access arrangement is submitted to the regulator.  
Capital redundancy
Section 8.27 of the Code allows a reference tariff policy to include (and the regulator may require that it include) a mechanism that will remove redundant capital from the capital base.  Such an adjustment is to occur at the commencement of the next access arrangement period and is to:
•	ensure that assets which cease to contribute to the delivery of services are not reflected in the capital base; and 
•	share costs associated with a decline in sales volume between the service provider and users. 
Before approving such a mechanism, the regulator must consider the potential uncertainty and its effect on the service provider, users and prospective users.
Where redundant assets subsequently contribute to or enhance the provision of services, the Code (section 8.28) allows the assets to be added back to the capital base as if they were new facilities investment subject to the associated criteria noted earlier in this section.  
While the Code permits a reference tariff policy to include a mechanism to subtract redundant capital from the capital base, it also allows for other mechanisms that have the same effect on reference tariffs while not reducing the capital base (section 8.29 of the Code).  
3.3.2	AGLP’s proposal
New facilities investment
As permitted by section 8.18 of the Code, AGLP’s reference tariff policy states that ‘AGLP may undertake New Facilities Investment that does not satisfy the requirements of the Code for inclusion in the Capital Base’.  
In addition, an amount in respect of the balance after deducting the recoverable portion of the new facilities investment, that is, the speculative investment fund, may subsequently be added to the capital base.  This can occur if the type and volume of services provided, which use the increase in capacity attributable to the new facility, change such that any part of the speculative investment fund would then satisfy the requirements of section 8.16 of the Code (see section 8.19 of the Code).  
The CWP is a combination of an eight inch pipeline (Marsden to Alectown) and a six inch pipeline (Alectown to Dubbo).  This is ‘oversized’ for the load between Marsden and Dubbo but would enable cost effective haulage of gas to Tamworth.  AGLP has valued the oversized portion of the CWP at $2.78 million.  This amount will be placed in a speculative investment fund.  AGLP expects that this amount will be added to the capital base once the Central Ranges Pipeline (CRP) to Tamworth is built.  
In accordance with section 8.22 of the Code, the reference tariff policy states that 
… for the purposes of calculating the capital base at the commencement of the subsequent access arrangement period, where the actual cost of new facilities differs from the forecast new facilities investment on which the capital base was determined, the new facilities investment will be included at actual cost.  
AGLP did not made a commitment to any major capital expenditure during its proposed initial five year access arrangement period.  The only expected capital expenditure during this period concerns the replacement of minor pipeline components.  This ‘stay in business’ capital expenditure is estimated at $6 750 per year in real terms for the life of the pipeline.  For the period from 1 July 1998 to 30 June 2004 this totals to $0.04 million in nominal terms.  The expected capital expenditure over the ten years to 30 June 2010 ($0.91 million) is considerably higher due to the planned replacement of the SCADA system in 2007-2008 and the longer period.  The reference tariff policy states that upon calculating the capital base for the next access arrangement period, actual capital expenditure will be used rather than the forecast expenditure.  
Capital redundancy
The reference tariff policy makes no comment on the treatment of redundant assets.  
3.3.3	Commission’s considerations
AGLP’s access arrangement does not comment on determining the asset base in subsequent access arrangement periods.  While this is dealt with in the Code at section 8.9, the Commission considers that there is some merit in service providers acknowledging in an access arrangement the relevant sections of the Code and the intention of the service provider to implement the Code at the appropriate time.  In relation to the CWP access arrangement, the Commission considers that users and prospective users would benefit from clarification of how the capital base for the subsequent access arrangement period is to be determined.  
New facilities investment
The provisions in the access arrangement for adding new investments into the capital base follow the Code closely.  However, an amendment is required to aid in the interpretation of the access arrangement.  There is no need for additional comment on this aspect of capital base augmentation from the perspective of acceptability of the approach within the framework of the Code.  
Amendment A3.2
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, section 4.3 of the access arrangement (the reference tariff policy) must state that new facilities investment that does not satisfy the requirements of section 8.16 of the Code may be undertaken by AGLP and may be included in the capital base to the extent to which this investment satisfies section 8.16 of the Code.  

AGLP accepts this amendment although it questions the desirability of repeating the Code in an access arrangement.
AGLP’s decision to place $2.78 million in a speculative investment fund and subsequently add this amount to the capital base is consistent with the Code.  Details of the proposed addition, in whole or in part, to the CWP capital base will be assessed by the Commission when a firm proposal is placed before it.  
As permitted by section 8.20 of the Code, AGLP has determined tariffs on the basis of forecast capital expenditure.  While this methodology is accepted by the Commission in this instance, this does not imply that the Commission considers such expenditure to meet the requirement of section 8.16 of the Code (see section 8.21 of the Code).  An assessment on this matter will be made by the Commission at the time of the review of the access arrangement.  
As noted earlier, section 8.22 of the Code requires either the regulator or the reference tariff policy to deal with the differences between actual and forecast capital expenditure.  In this instance, AGLP has included a statement in the reference tariff policy on the treatment of actual and forecast capital expenditure in relation to determining the capital base in the subsequent access arrangement period.  The Commission considers that this statement meets the requirements of the Code.  
Capital redundancy
AGLP has not included in its reference tariff policy a mechanism that will remove redundant capital from the capital base at the start of the subsequent access arrangement period, as provided for by section 8.27 of the Code.  The Commission considers that such a mechanism is needed in order to ensure that users do not pay for assets that have ceased, or substantially ceased, to contribute to the delivery of services.  Accordingly, the Commission, pursuant to section 8.27 of the Code, requires that a mechanism dealing with redundant capital be included in the CWP reference tariff policy. 
Amendment A3.3
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the reference tariff policy must be amended to allow the Commission, at the commencement of the subsequent access arrangement period, to review, and if necessary to adjust, the asset base for wholly or partially redundant assets, within the meaning of section 8.27 of the Code.  

AGLP has undertaken to revise the access arrangement as required by this amendment.  It suggests that the inclusion of a policy raises uncertainty which should be reflected in the rate of return.  The Commission does not consider placing a redundant capital policy in the access arrangement, as allowed in the Code, materially increases uncertainty for AGLP.
3.4	Depreciation and inflation
3.4.1	Code requirements
Depreciation
AGLP has elected to use the NPV/price path methodology to determine total revenue.  As stated in section 8.34 of the Code, under the NPV methodology the notional depreciation is the difference between the capital base at the beginning of the access arrangement period and the residual value.  For a new facility, notional depreciation is the difference between the actual (or forecast) cost and the residual value.  The residual value should reflect notional depreciation which meets the following principles (contained in section 8.33 of the Code):
•	the change in reference tariffs over time is consistent with the efficient growth of the market for the services provided;
•	depreciation occurs over the economic life of the asset(s) with progressive adjustments where appropriate to reflect changes in expected economic lives; and
•	that an asset is depreciated only once and that total accumulated depreciation will not exceed the valuation of the asset when initially incorporated in the capital base.
Although there is no specific provision in the Code to allow for adjustments to the asset base based on ‘economic depreciation’, some flexibility is allowed in the method used to calculate revenue.  Section 8.5 permits any methodology to be used provided it can be expressed in terms of one of the methodologies described in section 8.4 of the Code.
General principles set out in section 8.1 of the Code include that the service provider should have the opportunity to earn a stream of revenue that recovers the efficient costs of delivering the reference services over the expected life of the assets used in delivering that service, and efficiency in the level and structure of the reference tariff.  Section 8.34(d) is also relevant:
8.34	If the IRR or NPV methodology is used, then the notional depreciation over the Access Arrangement Period for each asset or group of assets that form part of the Covered Pipeline is:
… to comply with section 8.33: 
(d)	the Reference Tariff should change over the Access Arrangement Period in a manner that is consistent with the efficient growth of the market for the Services provided by the Pipeline (and which may involve a substantial portion of the depreciation taking place towards the end of the Access Arrangement Period, particularly where the calculation of the Reference Tariffs has assumed significant market growth and the Pipeline has been sized accordingly).

3.4.2	AGLP’s proposal
Depreciation
Growth in pipeline utilisation for the CWP will be gradual and returns in the initial access arrangement period will not cover accounting expenses.  AGLP’s concept of economic depreciation provides a mechanism for under-recovery in the early years which is offset by over-recovery in latter years.  This results in a reference tariff that is consistent with efficient growth in the market as required by section 8.33(a) of the Code.  It also allows cost recovery over the efficient life of the asset in accordance with section 8.1(a) of the Code. 
AGLP define economic depreciation in the following manner: 
Economic depreciation = total revenue – operating costs – return on capital
Economic depreciation can be either positive or negative.  It is deducted from the capital base each year to reflect the extent that total revenue has covered costs.  As costs are not covered in the initial access arrangement period, depreciation will be negative.  This results in an increase in the capital base over the period.  The level of economic depreciation anticipated by AGLP each year (using its assumptions) is shown in Table 3.5 below.  
Table 3.5:	Proposed economic depreciation, 1999 to 2004
	$ million	
	1999	2000	2001	2002	2003	2004	
Economic depreciation	(3.54)	(3.51)	(3.39)	(3.17)	(2.81)	(2.70)	
Source:	Additional Access Arrangement Information, 12 February 1999, p. 2. 
AGLP has stated that:
… it will be some considerable time into the future before the CWP will generate sufficient revenue to cover both operating costs and the return on capital.  
The economic life is estimated to be 80 years for the pipeline, 50 years for the regulation and metering stations, 35 years for the odourising stations and ten years for SCADA.  
Inflation
The amounts of economic depreciation shown above in Table 3.5 are in nominal dollars.  However, these and other figures are based on financial modelling by AGLP that is initially expressed in real terms, using year ending 30 June 1999 dollars.  AGLP has applied its forecast inflation rate of 2.5 per cent per annum to convert amounts derived in real dollars to nominal dollars.  
AGLP has proposed use of the ‘Sydney Consumer Price Index published quarterly by the Australian Statistician’ to adjust tariffs until the next access arrangement period commences if the revisions commencement date is later than 30 June 2004. 
3.4.3	Commission’s considerations
Depreciation
The Commission’s May 1999 Draft Regulatory Principles proposes the use of the competition depreciation approach (CDA) to achieve economically efficient price paths over the life of regulated electricity transmission assets.  CDA is a form of regulatory depreciation that shares a number of characteristics with AGLP’s economic depreciation.  However, the CDA has been designed for application across regulated entities with prices to reflect forward looking long run costs.  The CDA aims to be more flexible and less prescriptive than the AGLP proposal which simply incorporates the residual under-recovery based on company forecasts.  Given that the regulatory value exceeds the ORC, the AGLP framework for the CWP does not necessarily produce efficient pricing.
The Commission has considered the appropriateness of deriving an asset valuation which incorporates AGLP’s economic depreciation in the proposed asset valuation methodology.  Under most conventional frameworks AGLP would set tariffs much higher during the first phase of the life of the CWP than is currently proposed.  This would compromise the rapid growth of the customer base, which would have the effect of raising the inherent risks for the project.  A possible result of this could be that the CWP might never have been built.  However, the projected volumes suggest that the users of the CWP will derive a consumer surplus from the existence of the pipeline.  This implies that the CWP is in the public interest.  The test of this will be whether the forecast long term volume growth is sustainable at the projected tariffs.  
The Commission is guided in particular by section 8.1(a) of the Code which provides the objective that the service provider should have the opportunity to earn a stream of revenue that recovers the efficient costs of delivering the reference services over the expected life of the assets used in delivering that service.  
However, the Commission is concerned that the implementation of the proposal must be consistent with the Code and accord with accepted industry practice.  In particular:
•	as economic depreciation is the residual left after subtracting forecast operating costs and return on capital from forecast total revenue, it will be susceptible to forecasting errors; and
•	there may be a tension between flexibility in setting the tariff path over time and consistency with principles of competition, economic efficiency and equity.  
Subject to these reservations which are addressed later in this chapter, the Commission is of the view that AGLP’s proposal to apply economic depreciation as a type of levelising mechanism to eventually recoup under-recoveries accrued in the early period of the life of the CWP is consistent with Code principles.  However, it must be noted that the proposed framework is only feasible because it is unlikely that alternative pipelines would be available to users and potential users of the CWP.  This allows tariffs to be sustained above long run costs during the period when the economic value of the asset for regulatory purposes exceeds the ORC.  
Inflation
The Commission understands that AGLP’s cost and revenue values were initially derived in real or constant dollars, then converted into nominal dollars using AGLP’s forecast of the Sydney All Groups Index of the CPI of 2.5 per cent per annum.  As a result of this methodology, the accuracy of AGLP’s financial projections, when expressed in nominal dollars, is dependent not only upon factors such as the level of demand and the price of the reference service, but also of the accuracy of the inflation rate forecast.  This is relevant, for example, in that AGLP proposes that the residual value be expressed in nominal terms.
An issue for the Commission is whether the Sydney All Groups Index of the CPI is the most appropriate measure.  The choice of index is also relevant to AGLP’s proposal, in the event that the revisions commencement date is later than 30 June 2004, to adjust tariffs until the next access arrangement period commences (refer section 3.8.4).  The related issue of the reasonableness of AGLP’s inflation forecast is considered in section 2.4.1.
The Commission acknowledges that a general price index needs to be chosen, but it should be one which reflects the difference between real rates of return and nominal rates of return as perceived by financial markets.  In this context the CPI may not be the ideal index.  First of all, its consumer costs orientation means that it is over sensitive to some consumer oriented costs such as specific goods taxes and prices of products and services which may have only marginal relevance to general financial conditions.  At the same time factors relevant to business oriented costs may be somewhat muted.  Second, the selection of a Sydney based index is unnecessarily narrow given the financial markets oriented requirement of the index.  Indeed an Australia-wide based CPI is less likely to be as susceptible to fluctuations of a spurious nature in this context.  Despite these issues the Commission acknowledges the advantage of using a well recognised index like the CPI.  Further support for the use of this index is the fact that it is also used as the basis for adjusting the value of treasury capital indexed bonds.  Accordingly, the Commission requires that the CWP access arrangement use the CPI (All Groups – weighted average of eight capital cities) in the calculation of tariffs.  AGLP accepts this amendment.
Amendment A3.4
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the inflation index referred to throughout the access arrangement must be the CPI (All Groups – weighted average of eight capital cities). 

Revenue model indexation
As noted earlier, the Commission considers it appropriate to limit the inflation risk borne by AGLP.  This risk could be substantial under an extended access arrangement period, and might induce AGLP to submit revisions prematurely.  It is for this reason that the Commission decided to introduce a CPI-X price path.  In addition, actual CPI outcomes must replace forecasts in the revenue model prior to the determination of the residual value at the end of the initial access arrangement period.
Amendment A3.5
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the access arrangement must include a mechanism to replace forecast inflation in the revenue model with actual CPI outcomes prior to the determination of the residual value at the end of the access arrangement period.

Impact of the NTS on inflation
As noted in section 1.6 of this Final Decision, the impact of the NTS on the CPI adjustment used in AGLP’s revenue model must be estimated and deducted from the CPI.  The CPI calculated by the Australian Bureau of Statistics will reflect the price changes due to the commencement of the NTS of a fixed basket of goods and services acquired by household consumers.  The Commonwealth Treasury has estimated the NTS component of the CPI as approximately 2.75 per cent for the year to the June quarter 2001. 
Use of an unadjusted CPI results in a double counting as an unadjusted CPI will reflect economy wide changes in cost structures for which AGLP is compensated via the cost pass through adjustment.  This means that under the NPV price path approach, AGLP’s projected cost under-recoveries will be over-stated if an unadjusted CPI is used.  Such an outcome would be inconsistent with the objective set out in section 8.1(a) of the Code that the service provider be provided the opportunity to earn a stream of revenue that recovers the efficient costs of delivering the reference service over the expected life of the assets used in delivering that service.  The Commission notes that tariffs that are higher than that required to cover efficient costs would not be in the interests of users and prospective users, a factor that it must consider pursuant to section 2.24(f) of the Code.
The Commission has considered adjusting the tariff for the year 2001-2002 to remove the estimated 2.75 per cent NTS component of the CPI.  This approach would be appropriate for access arrangements based on a cost of service model where tariffs are adjusted annually on the basis of a CPI-X formula.  However it would sit uneasily with AGLP’s NPV price path approach.  Such an adjustment would result in a benefit to users of the CWP in 2001-2002 at the expense of other users of the pipeline.
The Commission will instead adjust the level of negative depreciation accumulated in the revenue model to correct for this factor prior to determining the residual value of the capital base at the scheduled review of the access arrangement.  The Commission requires an amendment to the access arrangement to this effect.
Amendment A3.6
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the access arrangement must state that the projected level of economic depreciation will be adjusted prior to determining the residual value of the capital base at the end of the initial access arrangement period to correct for additional revenue collected during the initial access arrangement period due to the NTS component of the CPI.  

3.5	Non-capital costs
3.5.1	Code requirements
The Code (sections 8.36 and 8.37) allows for recovery of the operating, maintenance and other non-capital costs that would be incurred in providing the reference service by a prudent service provider acting efficiently and in accordance with good industry practice.  
Attachment A to the Code (summarised in Box 5.1 in this Final Decision) requires the disclosure of certain costs by the service provider in the access arrangement information, unless it would be unduly harmful to the legitimate business interests of the service provider, a user or a prospective user.  The costs to be disclosed include wages and salaries, rental equipment, gas used in operations, materials and supply and corporate overheads and marketing.  Some disaggregation by zones, services or categories of assets is also required where appropriate. 
3.5.2	AGLP’s proposal
Little historical information on operational costs is available for the CWP as it commenced operation only recently.  AGLP has estimated the costs that it expects to incur over the proposed access arrangement period assuming real costs are unchanged from 1999.  These costs are shown in Table 3.6 below in nominal terms for the years 2000 to 2004, calculated by applying AGLP’s assumed annual 2.5 per cent inflation factor.  
Table 3.6:	Proposed non-capital costs, 1999 to 2004
	Year ending 30 June ($’000)	
	1999	2000	2001	2002	2003	2004	
Operations and maintenance	450.0	461.3	472.8	484.6	496.7	509.1	
Administration	223.5	229.1	234.8	240.7	246.7	252.9	
Sales and marketing	50.0	51.3	52.5	53.8	55.2	56.6	
Total	723.5	741.7	760.1	779.1	798.6	818.6	
Source:	Revised Access Arrangement Information, p. 20. 
Operations and maintenance has been outsourced to EAPO which also carries out these activities for the MSP.  EAPO has advised AGLP that the key operations and maintenance costs are labour (29 per cent of total costs), outside services (27 per cent) and material and supply (six per cent).  AGLP considers the $450 000 payable to EAPO for operations and maintenance during the year to June 1999 is reasonable and less costly to users than if carried out by AGLP itself.  
Administration tasks are carried out by various sections of the AGL Group on behalf of AGLP.  AGL Group also carries out marketing activities for the CWP.  However, AGLP has advised that there are no formal agreements between itself and members of the AGL Group for these functions at present.  The cost to AGLP has been estimated as a proportion of the overall costs incurred by AGL Group in carrying out the administration and marketing activities.  Further information regarding these costs has been provided to the Commission on a confidential basis.  
3.5.3	Submissions by interested parties
BHPP submitted to the Commission that for services provided by AGL Group: 
AGLP should confirm that it has disclosed all related party transactions and provide details of the nature and quantity [of] services that have been purchased or sold and the counter party to these transactions.  
3.5.4	Commission’s considerations
As noted above, BHPP has raised concerns regarding related party transactions undertaken by AGLP in relation to the operation of the CWP.  AGLP has provided information to the Commission regarding the nature and quantity of the services that are to be undertaken by the AGL Group and EAPO on behalf of AGLP.  The Commission is satisfied that this information supports the costs estimated by AGLP and that the relationships between the entities are fully disclosed.  
Three industry accepted benchmarks for operations and maintenance costs are cost per pipeline length, cost per volume transmitted and cost per volume transmitted by distance.  Comparisons between the CWP and other transmission pipelines in Australia are shown in Table 3.7 below.  In terms of cost per 1 000km, the CWP compares favourably with the other pipelines.  However, in relation to cost per GJ and cost per GJ per 1 000 km, the CWP is considerably more expensive to operate than the other pipelines in the comparison.  
It must be noted that, while these measures of pipeline cost efficiency have been accepted in the industry, they do have obvious limitations.  The comparisons can be made but in doing so, other aspects of the pipelines such as compression, age, size and throughput should, in general, be noted.  For the CWP, the fact that it is a new pipeline may suggest that non-capital costs such as maintenance should be relatively low when compared to a pipeline that has been operating for some years.  In addition, it must be noted that the volume of gas through the CWP is quite small in the initial years of the pipeline’s life.  This will impact on cost per volume measures.  
Table 3.7 illustrates the impact of volumes on the comparison indicators.  In 1999, CWP’s non-capital costs per GJ are calculated as $2.62.  In 2004, the last year of the proposed initial access arrangement period, this falls to $0.58/GJ as a result of the increased volumes expected through the pipeline.  While the 2004 unit costs are much closer to those for the other pipelines, there remains a significant gap.  As volumes improve further in later years unit costs would fall further.  Nonetheless, the CWP’s performance would continue to suffer from diseconomies of scale. 
Table 3.7:	Comparison of transmission pipeline non-capital costs 
	$/1 000 km 
($ million)	$/GJ	$/GJ/1 000km	
AGLP – CWP (1999)(a)	2.8	2.62(d)	10.27(d)	
AGLP – CWP (stand-alone) (1999)(a)	4.7	4.38(e)	17.18(e)	
EAPL – MSP (2001)(b)	6.1	0.12	0.06	
Epic – Moomba-Adelaide Pipeline (1999)(c)	19.2	0.16	0.15	
TPA – Victorian transmission systems (1998)(a)	16.0	0.13	0.07	
Notes:	(a)	AGLP, Revised Access Arrangement Information, pp. 27-31.  ‘Stand-alone’ costs have been estimated by AGLP as the amount it would spend if it undertook these tasks directly instead of outsourcing them to EAPO and AGL Group.
(b)	EAPL, Proposed Access Arrangement Information, p. 65. 
(c)	Epic, Proposed Access Arrangement Information, attachments 1 and 4. 
(d)	For 2004 non-capital costs are $0.58/GJ and $2.27/GJ/1 000 km.
(e)	For 2004 non-capital costs are $0.96/GJ and $3.76/GJ/1 000 km.

Chapter 5 of this Final Decision discusses the use of key performance indicators (KPIs) and performance benchmarks in more detail.  It concludes that on the basis of the available information the operating, maintenance and other non-capital costs on the CWP are not unreasonable over the life of the pipeline.  The costs incurred by AGLP can be considered to reflect costs that would be incurred by a prudent service provider acting efficiently within the framework proposed by AGLP.  Nonetheless, the Commission is concerned that AGLP’s contracting out of non-capital expenditure activities to EAPO and other businesses within the AGL Group has the effect of reducing the transparency of these operations.
3.6	Forecast revenue 
3.6.1	Code requirements
Three alternative methodologies are set out in section 8.4 of the Code for determining total revenue.  They are: cost of service; IRR; and NPV.  In this access arrangement, the service provider has proposed to use the NPV methodology.  The NPV of total revenue is calculated on the basis of a forecast of all relevant costs for the pipeline with the rate of return being the relevant discount rate.  The NPV methodology in conjunction with a price path profile allows for forecast revenue in the initial access arrangement period to be less than that which is needed to fully recover costs in this period. 
3.6.2	AGLP’s proposal
Volumes
AGLP has provided forecast volumes for the CWP to the Commission.  These volumes are based on the expected demand requirements for industrial and commercial users as well as growth in the residential sector.  AGLP’s volume data to 2004 are shown in Table 3.8 below. 
Revenues
Forecast revenue is set at a level, over the life of the asset, which ALGP states allows it to earn a reasonable rate of return on assets employed in providing tariffed transmission services on the CWP.  In proposed initial access arrangement period, the tariffs would produce revenue from the forecast volumes which would under-recover costs.  Consequently, economic depreciation is initially negative which leads to an increase in the regulatory asset value.  It is proposed in the access arrangement that, as a fixed principle, the residual value at 30 June 2004 be $45.12 million (in dollars of that day).  Consequently, tariffs in future access arrangement periods, which would be based on this value, would recover costs that have not been recovered by tariffs in the initial access arrangement period.
AGLP does not provide a forecast of revenue in its access arrangement or access arrangement information.  However, forecast revenue can be easily calculated from the proposed tariffs and the forecast volumes provided.  The revenue associated with the proposed throughput charge for the reference service is shown in Table 3.8.  AGLP has not forecast revenue from any other source (either associated with the reference service, such as overrun or variance charges, or associated with negotiated services) as AGLP considers that this revenue is not material.  
Table 3.8:	Proposed forecast volumes and revenues, 1999 to 2004 
Year ending	Forecast volumes	Forecast revenue ($)	
30 June	(TJ/pa)	Real dollars(a)	Nominal dollars	
1999	276	491 280	491 280	
2000	498	961 990	986 040	
2001	720	1 487 115	1 562 400	
2002	942	2 073 135	2 232 540	
2003	1 164	2 720 679	3 003 120	
2004	1 255	3 083 679	3 488 900	
Source:	ACCC calculations from data in the Revised Access Arrangement Information, pp. 4 and 23.  
Note:	(a)	An inflation rate of 2.5 per cent is assumed by AGLP. 

The residual value of the asset is the asset valuation at the end of the initial access arrangement period.  For each year (year n) the value of the asset has been determined by AGLP using the following formula:
Asset valuen = asset valuen-1 + capital expendituren – economic depreciationn
As a result of the forecast revenue path which in turn determines the level of economic depreciation, AGLP has determined that the residual value of the asset for the initial access arrangement is $45.12 million in nominal terms at 30 June 2004.  This figure has been incorporated into AGLP’s proposed fixed principle.  
3.6.3	Submissions by interested parties
Forcenergy has submitted that in its view, ‘NSW gas demand should at least double between the year 2000 and the end of the review period’.  However, support for this claim was not provided to the Commission. 
3.6.4	Commission’s considerations
Volumes
It is difficult to validate forecast volumes for the CWP due to the limited operational history of the pipeline.  However, the Commission understands that in preparing to commence the building of the CWP AGLP undertook market inquiries to the extent possible to determine the forecast volumes.  
The Commission has considered the forecast volume information provided by AGLP and, following its own assessment, has incorporated the data into the model used to determine revenues and the rate of return without any change.  The Commission does not have any basis to alter the forecasts provided by AGLP nor determine whether they are unbiased estimates.  The Commission acknowledges that the forecasts may prove to be incorrect.  However, if substantially lower volumes were achieved AGLP would be able to seek revisions of the forecast volumes included in the access arrangement.  If actual volumes are greater than those forecast then AGLP is able to retain the additional revenues earned as a result.  This is the basis of AGLP’s incentive mechanism.  
Forecast volume data to 2010, the length of the initial access arrangement period, are included in Table 3.9 below. 
Revenues
AGLP has applied a NPV framework to determine total revenue as permitted by the Code.  For the initial access arrangement period, total revenue will under-recover costs.  The Commission finds this framework acceptable for the CWP and notes that AGLP has complied with the Code in relation to determining forecast revenue.  
However, AGLP has not quantified the forecast revenue in the access arrangement or access arrangement information.  Users and prospective users need to calculate AGLP’s forecast total revenue from the access arrangement information in order to form an opinion on compliance with the Code and the appropriateness of the level of revenues.  The Commission does not consider this satisfactory.  Not only should total revenue be calculated according to one of the methodologies identified by the Code but it should be specified in the revised access arrangement documents.  
As a result of the amendments specified for the WACC, inflation, tariffs and the length of the access arrangement period, the actual revenue path for the CWP will be different to that proposed by AGLP and noted in the above section.  The forecast revenues as a result of the Commission’s amendments are provided in Table 3.9 below.  
Table 3.9:	Forecast volumes and revenues, 2001 to 2010 
Year ending	Forecast volumes	Forecast revenue ($)	
30 June	(TJ/pa)	Real dollars(a)	Nominal dollars	
2001	720	1 562 400	1 562 400	
2002	942	2 170 887	2 232 540	
2003	1 164	2 680 966	2 835 407	
2004	1 255	2 888 910	3 142 102	
2005	1 320	3 036 800	3 396 757	
2006	1 360	3 127 038	3 597 026	
2007	1 400	3 217 172	3 805 807	
2008	1 439	3 304 906	4 020 625	
2009	1 479	3 394 833	4 247 320	
2010	1 520	3 486 951	4 486 467	
Source:	ACCC calculations.  
Note:	(a)	An inflation rate forecast of 2.84 per cent has been used. 

In addition, the expected residual value of the assets varies as a result of the amendments to the access arrangement.  The Commission has determined that the expected residual value in nominal terms at 30 June 2005 is $41 475 764 and at 30 June 2010 $51 754 801.  The equivalent amounts in real terms (1999 dollars) is $34 621 720 and $37 553 249 respectively. 
The Commission has noted in the Draft Regulatory Principles that financial indicator analysis can provide assistance in determining the impact of forecast revenue on the credit worthiness of a business.  The Commission, IPART and IPARC have previously carried out this type of analysis.  
While financial indicator analysis is useful for established businesses, it is not necessarily suitable for a new project such as the CWP.  In the case of the CWP, the calculation of financial indicators is affected by the capitalisation of unrecovered costs through AGLP’s economic depreciation that in turn impacts on cash flows and profits.  However, it must be noted that the regulatory framework, which allows this capitalisation, provides a benefit to AGLP that the financial indicators for the business over the initial developing years do not reflect.  When considered in isolation, financial indicators for the CWP over the initial access arrangement period do not provide meaningful results.  As the demand for gas through the CWP grows and the market is established, the performance of the CWP as measured by the financial indicators is much improved.  It should be noted, however, that the methodology of the CWP access arrangement is designed to allow AGLP to recover the efficient costs of delivering the reference service over the life of the pipeline.  It would be expected, therefore, that the performance of the CWP as measured by financial indicators would improve over time.  
3.7	Cost allocation and tariff setting
3.7.1	Code requirements
Section 8.38 of the Code requires that, to the maximum extent that is commercially and technically reasonable, reference tariffs should recover all costs directly attributable to the reference service and a fair and reasonable share of joint costs.  It also requires (section 8.42) that a particular user’s share of revenue to be recovered also follows these principles.  These requirements must be met, regardless of the methodology used to calculate total revenue.  
3.7.2	AGLP’s proposal
The proposed tariff for the CWP consists solely of a commodity charge based on actual throughput volumes.  Most other pipelines collect the majority of revenue on the basis of contracted amounts (through capacity reservation charges) with a smaller proportion of revenue collected through a commodity charge.  AGLP has not differentiated between classes of customers or implemented capacity and commodity elements to its tariff structure.  The single ‘one-part’ tariff proposed has the benefit, according to AGLP, of being simple and easy to understand and use.  AGLP considers this an important aspect of the tariff structure in light of the need to develop the market for natural gas.  It considers that the requirements of the Code are met by: 
•	recovering from users the costs incurred in providing the service; 
•	assisting in the development of the market; and 
•	not creating a barrier to the development of a competitive market for gas supply services. 
AGLP notes that capacity-based charges are expected to be introduced in the next access arrangement period.  
The CWP has not been separated into multiple pricing zones.  AGLP has stated that this reflects a regional infrastructure development objective of ensuring that no local community will be at a price disadvantage to any other.  In addition, AGLP considers that it would not be prudent to build a pipeline like the CWP without single zone pricing.  AGLP states that ‘[i]t is not technically and commercially reasonable to allocate costs to particular Users by any other means and maintain the long term viability of the pipeline’. 
AGLP states that the proposed single zone reference tariff is intended to encourage sufficient demand in Forbes, Parkes, Narromine and Dubbo to justify the total investment.  AGLP contends that other tariff methodologies, such as distance-based or stand-alone, would result in a delivered price for gas that would be uncompetitive with alternative fuels at the regional centres.  As a result, the pipeline would not have been extended to some of these centres.  AGLP states that without the combined volumes of the four centres, the pipeline would not be viable.  
AGLP has proposed that if, as anticipated, the pipeline is extended to Tamworth it would then decide whether to submit revisions to include the extension within the CWP access arrangement.  If included, it may form a second pricing zone.  AGLP intends that the tariff for the Marsden to Dubbo pricing zone (the subject of this access arrangement) would not increase during the initial access arrangement period from the structure or levels currently proposed.  
3.7.3	Submissions by interested parties
Forcenergy submits that ‘[t]he pipeline business is a fixed cost business and some, if not most, of those costs should be collected via a demand or capacity reservation charge.’  It does not accept AGLP’s claim that the basis for a throughput-based tariff is to assist in the development of the market.  Forcenergy suggests that AGLP has little or no capacity contracts for the CWP and has built the pipeline with little to no contractual underpinning.  It also suggests that tariffs should reflect the different costs associated with the other services it proposes should be offered by AGLP and that a comparison between the proposed tariff approach and other methodologies be made.  
As noted previously, Forcenergy has expressed concern about the volume forecasts used by AGLP in determining its tariffs and tariff methodology, suggesting that AGLP has not demonstrated that it has conducted a thorough market assessment for the CWP.  It considers that the tariff path does not reflect this growth in demand.  If the demand growth does not occur, Forcenergy suggests that AGLP should incur substantial penalties.  
Forcenergy also submits: 
We hope that the revenue collected on the CWP and the proposed CRP do not cross subsidise AGLN’s (sic) effort to grow the tariff markets in rural NSW.  
The Commission received submissions in support of the single pricing zone.  DCC supports the single pricing zone and further states that it does not expect users of the CRP to contribute to the cost of the CWP.  The Council states that it understands and supports the low initial tariff which rises steeply over the initial access arrangement period.  The MRBEC states that: 
It is imperative to the future development of both regions that we achieve a regional pricing structure and remain competitive in our endeavours to grow business and industry for the regions.  
3.7.4	Commission’s considerations
Major issues arising from AGLP’s chosen tariff methodology include cost allocation and the adoption of a single charge for users based on throughput, the single pricing zone, the impact of the proposed extension to Tamworth on tariffs and the forecast volumes.  These issues, in addition to the impact of the NTS, are addressed below.  
Cost allocation
In assessing this issue, the Commission must consider whether, as claimed, all AGLP’s costs are associated with the provision of the reference service or whether some costs are associated with other aspects of the company’s operations.  Almost all pipelines are used by more than one customer, as are facilities such as odourant stations.  Operations and maintenance costs are related to the running of the system and are thus joint costs.  This raises questions as to whether these costs have been shared appropriately between users. 
As noted above, AGLP has not established different tariff structures for different customers nor does it propose a commodity-capacity tariff structure or distance-based tariffs.  As a result, no cost allocation between users, distances, or between capacity and commodity is proposed.  All costs are allocated to all users of the CWP on the basis of their actual throughput volumes. 
The Commission accepted the proposed cost allocation method in its Draft Decision in light of the fact that the initial access arrangement period would be approximately five years.  However, it is now anticipated that as a result of the amendments in this Final Decision the initial access arrangement period will be approximately ten years.  
The Commission has reconsidered the appropriateness of the proposed cost allocation methodology.  In light of the need to develop the market for natural gas and that users and prospective users have not had the opportunity to consider any alternative methodologies the Commission is prepared to accept the proposed cost allocation methodology for the initial access arrangement period. 
One-part tariff
The Commission notes evidence that local communities support the proposed tariff structure.  It has also considered the arguments put forward by AGLP in support for the proposed single ‘one-part’ tariff.  
The proposed tariff structure is unusually simple.  Two-part tariffs are normally considered to have desirable characteristics such as pricing efficiency, cost reflectivity and providing the market with the correct pricing signals.  However, if, as suggested by AGLP, there is no chance of capacity constraints during the initial access arrangement period, there is little benefit to AGLP or users in including a capacity-based charge in the reference tariff.  AGLP has proposed that capacity-based charges will be introduced in the future when demand patterns for users will be sufficiently established and gas management procedures can be implemented. 
In light of this, the Commission accepted the proposed one-part tariff in its Draft Decision.  However, as the initial access arrangement period is to be approximately ten years the Commission has reconsidered the appropriateness of AGLP’s proposal.  The Commission has considered the local community support for a one-part tariff.  It also notes that any user wishing to use a service with a two-part tariff could apply to AGLP for a negotiated service.  The Commission expects that it would be in AGLP’s interest to provide such a service if this increases usage of the CWP.  In addition, if the market develops sufficiently then it will become important for both users and AGLP to improve the operational efficiency of the CWP.  Two-part tariffs can assist in the management of a pipeline and AGLP can, at any time, seek to revise the access arrangement to include services that have a two-part tariff.  However, it should be noted that under the current forecast volumes, capacity constraints on the CWP would not be expected in the period to 2010. 
Accordingly, the Commission will accept the proposed one-part tariff structure for the CWP initial access arrangement period.  However, this should not be interpreted as a general endorsement of one-part tariffs for transmission pipelines. 
Single pricing zone
AGLP has provided detailed information to the Commission on its modelling of distance-based and stand-alone pricing methodologies for the CWP to support its claim that under its assumptions these pricing methodologies would result in tariffs that would be uncompetitive with the alternative energy sources available to users.  
In adopting a distance-based pricing methodology the distance from Marsden to each of the four regional centres is factored into the determination of tariffs.  Under AGLP’s assumptions the tariff for Dubbo, which is at the end of the CWP, would be higher than the proposed tariff and the level considered competitive with alternative fuels.  As a result, it would not be prudent to build the CWP as far as Dubbo.  However, without Dubbo, some economies of scale for the project are lost since Dubbo represents approximately 59 per cent of the total annual volume through the CWP during the proposed initial access arrangement period.  While the pipeline would be approximately 210 km to Narromine (rather than the full 255 km to Dubbo), the reduced total volume could not support the pipeline at tariffs that would be competitive.  As a result, it would not be prudent to build the pipeline.  
The Commission has also considered distance-based pricing under different assumptions to those included in AGLP’s proposed access arrangement.  It has found that it is possible to derive tariffs for Forbes and Parkes, the two centres closest to Marsden, that are lower than that currently proposed in the access arrangement, and so would be lower than the estimated prices of alternative fuels.  However, tariffs for Narromine and Dubbo remain higher than the target level under all reasonable assumptions modelled by the Commission.  
A stand-alone pricing methodology derives tariffs for each location based on the appropriately sized pipeline to that location and the forecast demand.  There are no economies of scale available in this scenario.  The Commission has established that under a range of assumptions this methodology results in tariffs for each location that are significantly higher than the prices of the alternative fuels of coal and LPG.  The tariffs are also significantly higher than that proposed in the access arrangement.  The Commission agrees with AGLP that with such a pricing methodology it would not be economical for the CWP to be built to any of the locations now supplied by the CWP.  
The Commission’s sensitivity analysis indicates that should plausible changes in the assumptions used to develop the access arrangement occur, including the financial parameters and volumes, distance-based pricing is unlikely to become feasible during the initial access arrangement period.  Stand-alone pricing remains even less likely to be a feasible alternative to the single pricing zone proposed.  However, distance-based tariffs may be viable for the CWP if actual demand substantially exceeds forecasts.
The Commission has decided to accept the single pricing zone that AGLP has proposed for the CWP.  However, this does not indicate that the Commission will necessarily accept this type of pricing structure for other pipelines or for the CWP’s future access arrangement periods.  
Extension to Tamworth 
The Commission noted in its Draft Decision that it anticipated that the CWP would be extended to Tamworth (the CRP) prior to the scheduled review of the access arrangement, which was expected to commence in 2004.  AGLP proposed that the CRP would be included in the present access arrangement through the application of the extensions/expansions policy.  The Commission considered that the most appropriate time to assess the issues relating to the CRP, including cost allocation implications, would be once AGLP submitted revisions to include it in the CWP access arrangement.
Subsequent to the release of the Draft Decision AGLP advised the Commission that it proposed to revise the wording of its extensions/expansions policy such that AGLP would have the discretion to decide whether or not the CRP would be included in the present access arrangement.  The Commission has agreed to this change.  
As a result of the extended access arrangement period the impact of the CRP on the CWP may not be assessed by the Commission for a number of years after the CRP is commissioned.  For example, if AGLP elected not to include the CRP in the access arrangement, the Commission would not be able to assess its impact on the CWP until the first scheduled review. 
In the context of the incentives provided to AGLP by the extended access arrangement period and the uncertainty as to whether the CRP will be built, the Commission is satisfied that this outcome is appropriate.  
Volumes
The Commission notes that without historical information on the demand for natural gas it may be difficult to estimate the gas required by new users.  It is possible that, over time, actual demand may be quite different to that forecast.  The Commission is not well placed to assess the likelihood of this occurring.  However, AGLP is able to submit revisions to the access arrangement at any time during any access arrangement period.  The Commission expects that the accuracy of the demand forecasts for the CWP will be greatly improved at the time of the scheduled review of this access arrangement.  
All demand projections provided by AGLP in support of the CWP access arrangement have been based on demand on the existing Marsden to Dubbo leg.  No explicit allowance has been made in these forecasts, nor in the Commission’s tariff analysis, for the potential impact of additional volumes flowing on the leg from Dubbo to Tamworth.  At the time of the Draft Decision it was expected that there would be a relatively short period between the commissioning of the CRP and the first scheduled review and that the latter would be the most appropriate time to assess the extension.  However, under the arrangements now to be approved by the Commission it is likely that there would be an extended period between these points in time. 
No forecast volumes for the proposed CRP are available to the Commission at present.  In the event that the CRP is constructed during the initial access arrangement period, and AGLP elects to include it in the CWP access arrangement, the Commission would consider relevant forecasts in its assessment of the revisions.  If the CRP is not included in the access arrangement, the impact of increased throughput volumes would be considered when assessing tariffs for the second access arrangement period.  
Application of the NTS
As discussed in other sections of this Final Decision, the introduction of the NTS impacts on this access arrangement.  The Commission has assessed estimates provided by AGLP that indicate that the overall costs of the CWP will increase by 9.73 per cent as a result of the NTS.  This reflects the impact of the GST net of WST savings on operation and maintenance costs.  The Commission considers that these estimates are reasonable.  
The NTS pass through must be applied to the revenue model to determine the correct tariffs charged to users of the CWP.  An amendment to this effect is required to be made to the access arrangement. 
Amendment A3.7
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, AGLP must incorporate the NTS cost pass through of 9.73 per cent in the tariffs from 2000-2001 to 2009-2010.  

Overall assessment
As noted above, AGLP has proposed to implement a single one-part reference tariff for all users of the CWP.  The use of a single pricing zone will necessarily mean that some users will pay more, and some less, than they would have if multiple pricing zones had been proposed.  Improved cost reflectivity of tariffs could be achieved by implementing a different tariff structure that included, for example, a capacity charge, a distance-based component or differentiation between groups of users.  
Both sections 8.38 and 8.42 of the Code provide that there will be situations where the desired level of cost reflectivity may not be possible in designing a tariff structure.  In light of these sections of the Code, the Commission undertook an analysis of the tariff structure proposed by AGLP in addition to the alternatives of distance-based tariffs and stand-alone tariffs.  As noted previously, the Commission does not disagree with AGLP’s claim that neither distance-based nor stand-alone tariffs would be feasible for the CWP during the initial access arrangement period.  As a result, the allocation of costs and total revenue between users is not considered to be an issue as any reasonable alternative allocation method is not a commercial proposition for the CWP at present.  
Accordingly, the Commission accepts AGLP’s tariff proposal, and subsequent allocation of costs, for the initial access arrangement period.  The Commission considers that the requirements of the Code are met as far as commercially feasible in this case.  It does not propose to alter the cost allocation methodology employed (apart from the inclusion of the NTS cost pass through) although the initial access arrangement period is likely to extend to ten years.  Users and prospective users have not been provided with alternative methodologies to consider during this assessment process.  The Commission notes that AGLP is able to seek to revise its cost allocation methodology and reference services it offers at any time during the access arrangement period. 
The Commission’s decision to accept a single reference tariff applying to all users in a single pricing zone in this instance does not imply acceptance of the same, or similar, proposal for the CWP in future access arrangement periods or for other pipelines.  
Additional comments on the proposed tariffs in relation to the general principles of sections 8.1 and 8.2 of the Code can be found in section 3.9 of this Final Decision.  
3.8	Tariff path and incentive structure
3.8.1	Code requirements
Tariff path
The Code (section 8.3) provides discretion to service providers in how the reference tariffs may be varied during an access arrangement period.  For example, tariffs may change according to a price path approach where tariffs follow a path determined at the start of the period.  The alternative method specified in the Code is the cost of service approach.  Tariffs are set according to forecast costs and are adjusted throughout the access arrangement period in light of actual outcomes.  The Code also allows variations or combinations of these approaches to be used. 
Incentive structure
Section 8.44 of the Code also states that the reference tariff policy should, where the regulator considers appropriate, contain a mechanism to enable a service provider to retain some, or all, returns which exceed the expected level, particularly where these increased returns are due to the service provider’s efforts.  This incentive mechanism should encourage the service provider to increase sales volumes, minimise costs, develop new services, and undertake prudent investment (section 8.46).  It should also ensure that users gain from any increased efficiency, innovation and improved sales volumes.  Pursuant to section 8.45, the mechanism may include: 
•	specifying that tariffs are based on forecast not realised variables;
•	setting a target revenue and specifying how revenue in excess of this is to be shared between the service provider and users; and 
•	a rebate mechanism for rebatable services that does not provide a full rebate to users.  
Fixed principle
Sections 8.47 and 8.48 of the Code allow a reference tariff policy to include certain principles that remain fixed for a set period (referred to as the fixed period).  These fixed principles can not be changed without the agreement of the service provider and may include structural elements but not market variable elements.  
Section 10.8 of the Code defines a market variable element as:
… a factor that has a value assumed in the calculation of a Reference Tariff, where the value of that factor will vary with changing market conditions during the Access Arrangement Period or in future Access Arrangement Periods, and includes the sales or forecast sales of Services, any index used to estimate the general price level, real interest rates, Non Capital Cost and any costs in the nature of capital costs.
While a fixed period may be for all or part of the duration of an access arrangement, the regulator is required to consider the interests of the service provider, users and prospective users in determining the period. 
Sections 8.9(e) and (f) specify the methodology to calculate the capital base for the next access arrangement period.  The residual value at the end of the first access arrangement period is adjusted to allow for any difference between actual and forecast new facilities investment, actual and forecast inflation and redundant capital.  Once these adjustments are made, the residual value becomes the capital base for the commencement of the next access arrangement period.  
3.8.2	AGLP’s proposal
Tariff path
The tariffs for the proposed initial access arrangement period have been specified in nominal terms in the proposed access arrangement.  The tariffs increase by approximately $0.20/GJ each year starting at $1.78/GJ for the year ending 30 June 1999.  These prices, coupled with the forecast volumes, are insufficient to recover total forecast costs over the proposed initial access arrangement period.  AGLP considers that the low initial tariffs it has proposed are needed to encourage prospective users to switch from existing fuels to natural gas.  
AGLP has proposed that, in the event that the revisions commencement date is later than 30 June 2004, the reference tariff between that date and the revisions commencement date would be determined through CPI adjustment of AGLP’s proposed reference tariff for the year to 30 June 2004 of $2.78/GJ.  
AGLP has indicated that tariffs after the proposed initial access arrangement period will be calculated through a CPI-X mechanism.  The value of the annual escalation factor X that satisfies the NPV methodology and results from the initial proposed tariffs, WACC and other elements incorporated into AGLP’s model is minus 1.36 per cent (that is, the implicit long term price path would be given by the relationship CPI+1.36 per cent).  This indicates that real tariffs would be expected to increase significantly over the remaining life of the CWP. 
Incentive structure
Under AGLP’s proposed NPV based price path approach, the tariff path would not be varied during the initial access arrangement period as a result of differences between forecast and achieved outcomes.  AGLP states that this will provide an incentive to it to improve on its forecasts as any benefits would be retained during the current access arrangement period.  AGLP does not propose any sharing of benefits with users in the initial access arrangement period.  AGLP also claims that the level of reference tariffs provides an incentive to develop the market.  
Fixed principle
Under AGLP’s NPV methodology the increase in the regulatory value of the CWP over the initial access arrangement period is designed to allow later recoupment of the under-recovery of costs that arise from the low initial volumes and tariffs.  The forecast residual value of $45.12 million at the end of the proposed initial access arrangement period, which would be (after adjustments) carried over to the subsequent period, reflects the level of under-recovery AGLP proposes to subsequently recoup.  
AGLP has proposed the following as a fixed principle:
Reference Tariffs for this Pipeline will be determined on the basis of Net Present Value methodology incorporating economic depreciation with a residual value as at 30 June 2004 of $45.12m (in dollars of that day).
The $45.12 million in the proposed fixed principle has been derived by AGLP as a function of a number of variables, including the market variable elements of forecast sales of services, inflation, capital costs and non-capital costs.  AGLP has not specified the duration of the fixed period associated with the fixed principle. 
3.8.3	Submissions by interested parties
No submissions on this issue were received. 
3.8.4	Commission’s considerations
Tariff path
The Commission has considered a range of alternative tariff paths that would be consistent with the reduced real revenue requirement for the CWP resulting from the amendments specified regarding the WACC.  The Commission is aware that there can be tension between flexibility in setting the tariff path over time and consistency with the principles of competition, economic efficiency and equity.  For example, if the reduction in revenue was implement through AGLP’s pre-set tariffs and a CPI-X mechanism, the tariffs would rise substantially, then decrease in real terms over the life of the asset.  This might raise efficiency and equity issues.
In view of the overall regulated revenue stream available over the life of the asset, the sharp rise in real tariffs proposed over the first five years may be excessive.  In particular, the increasing tariffs may discourage prospective users adopting natural gas as a fuel and would reduce the overall total usage of the assets over their life.  This would be the opposite result to that sought by AGLP. 
Efficiency and equity considerations generally support a tariff path with a levelised real tariff over time, or one that declines slightly to reflect declining costs relative to output.  The Commission’s modelling of tariffs indicates that such a tariff structure is achievable for the CWP. 
AGLP has stated that the tariffs for the CWP for years ending 30 June 1999, 2000 and 2001 are already in place and have been communicated to the market by AGLP.  As the access arrangement will commence after 30 June 2000 only the last of these tariffs is a reference tariff under the terms of the Code and subject to the current approval process.  The Commission accepts the proposed tariff for the year ending 30 June 2001 and has incorporated it into the modified revenue model.  In addition, the Commission does not consider it necessary or appropriate to vary the proposed reference tariff for the year ending 30 June 2002.  The tariffs for the years ending 30 June 2001 and 30 June 2002 will be $2.17/GJ and $2.37/GJ respectively.  
For the remaining years of the initial access arrangement period (that is, from the year ending 30 June 2003) real tariffs will be derived from the tariff for the previous year adjusted by the X factor determined by the Commission.  This has the benefit of reducing the peak in the tariff path that would otherwise occur as a result of the Commission’s amendments regarding the WACC and inflation.  
Real tariffs will fall slightly with an X of 0.06 per cent.  Tariffs will be adjusted each 1 July on the basis of the increase recorded in CPI-All Groups, weighted average of eight capital cities series in the four quarters to the March of that year and reduced by the X factor.  AGLP must notify the Commission of its proposed tariff at least 30 business days prior to the intended commencement of the tariff.  The Commission will assess the proposed tariff to determine if it complies with the CPI-X formula.  The Commission will notify AGLP of its decision regarding compliance within 20 business days of receiving AGLP’s submission.  If the Commission does not notify AGLP of its decision within the 20 business days, the Commission will be taken to have approved the tariff with effect from the 21st business day after lodgement. In calculating the tariff (t) for a particular year (n) with a CPI-X adjustment, the Commission prefers the formula: 
tn = tn-1 (1 + (CPIn-CPIn-1)/CPIn-1).(1 - X)
The difference in the results from the preferred formula and the often-used alternative, is minor if the inflation rate is low.  However, with higher inflation rates, the formulae produce quite different results.  The Commission considers that the regulatory framework should use the more accurate formula and has incorporated the formula into its calculations.  
When AGLP lodged its proposed access arrangement it was assumed that the access arrangement would commence on, or soon after, 1 July 1999 and that the revisions commencement date would be on, or soon after, 1 July 2004.  Consistent with that expectation, AGLP proposed reference tariffs for the years up to 30 June 2004 followed by CPI adjustment of its proposed final tariff, if necessary, for the period until the revisions commencement date.  As a consequence of adopting the CPI-X approach from 1 July 2002, AGLP must delete its proposed reference tariffs for 2003 and 2004 from the access arrangement and remove the reference to CPI adjustment of AGLP’s proposed reference tariff for the year to 30 June 2004.  
While the current approval process only covers reference tariffs for the initial access arrangement period, the Commission notes that, based on the underlying assumptions, the resulting tariff path over the life of the asset would be consistent with the reference tariff principles established in section 8 of the Code.  
The access arrangement must be amended to reflect the Commission’s analysis in regard to the tariff path and the yearly application of the CPI-X adjustment.  The provisions regarding the determination of tariffs in circumstances where there is an extended assessment period of revisions to the access arrangement must also be revised
Amendment A3.8
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the pre-NTS reference tariffs must be specified in terms of a price path commencing with $2.17/GJ and $2.37/GJ for the years ending 30 June 2001 and 2002 respectively, with the tariffs for the remainder of the initial access arrangement period determined each year in accordance with CPI-X as defined in the Final Decision and where X has the value of 0.06 per cent.  This tariff path is consistent with the parameters specified in Amendment A2.2.  
The access arrangement must be amended to state that AGLP will notify the Commission of its proposed tariff for the forthcoming year at least 30 business days prior to the intended commencement of the tariff.  The Commission must determine if the proposed tariff complies with the CPI-X formula within 20 business days.  If the Commission does not notify AGLP of its decision within 20 business days the Commission will be taken to have approved the proposed tariff with effect from the 21st business day after lodgement with the Commission.  The tariff may not be varied unless the Commission either approves the proposed tariff or does not notify AGLP within 20 working days of its decision.
Section 3 of the access arrangement must be amended to remove the reference to CPI adjustment of AGLP’s proposed reference tariff for the year to 30 June 2004 of $2.78/GJ.  In the event that there is a gap between the reference tariff years specified in the access arrangement and the revisions commencement date, the interim reference tariff will be determined by adjusting the final year’s reference tariff in accordance with CPI-X.  

As noted in its Draft Decision, the Commission considers it appropriate to reduce AGLP’s inflation risk.  This is done by approving pre-determined tariffs for the first two years of the access arrangement period and implementing a CPI-X tariff adjustment mechanism for tariffs in the later years of the initial access arrangement period.  The following table sets out the tariffs for the years to 30 June 2003.  It also shows the tariffs for later years that would be expected under current forecasts.  
Table 3.10:	Tariffs, 1999 to 2010
	$/GJ	
Year	Real tariffs(a)	Nominal tariffs	Nominal tariffs 	
(ending 30 June)	Pre-NTS	NTS	
1999	1.78	1.78	1.78	
2000	1.90	1.98	1.98	
2001(b)	2.03	2.17	2.38	
2002	2.15	2.37	2.60	
2003(c)	2.15	2.44	2.67	
2004	2.15	2.50	2.75	
2005	2.15	2.57	2.82	
2006	2.15	2.64	2.90	
2007	2.15	2.72	2.98	
2008	2.14	2.79	3.07	
2009	2.14	2.87	3.15	
2010	2.14	2.95	3.24	
Source:	AGLP proposed revenue model and ACCC calculations. 
Notes:	(a)	For the year ending 30 June 1999. 
(b)	First year of the initial access arrangement period. 
(c)	First year of CPI-X mechanism.  Tariffs shown for 2003 to 2010 are indicative only as they have been estimated using the current inflation forecast of 2.84 %.  Actual tariffs will differ as they will be set annually using CPI outcomes.
Further discussion and analysis on the level of tariffs is contained in the following section (section 3.9) of this Final Decision. 
Incentive structure
The fixing of tariffs for the initial access arrangement period effectively implements an average price cap for AGLP.  An average price cap provides an incentive to reduce costs and increase volumes.  In the case of the CWP, AGL Group and EAPO directly incur the operational costs.  AGLP pays for work carried out by AGL Group as that work arises.  In contrast, AGLP has an agreement with EAPO in which EAPO carries out operations and maintenance for a set charge.  As a consequence, AGLP has control over the administration and marketing costs throughout the access arrangement period and has an incentive to reduce these costs.  Similarly, EAPO has an incentive to reduce operations and maintenance costs.  It would be expected that AGLP will share in the benefits of reduced operations and maintenance costs at the point of renegotiating its agreement with EAPO.  
Reductions in capital expenditure in comparison to that forecast will be retained by AGLP for the remaining duration of the access arrangement period.  Thus, AGLP has an incentive to reduce capital costs during the access arrangement period by seeking the most cost efficient method of enhancing the system as required.  The Commission considers that this incentive is appropriate.  It should be noted that in determining the capital base for the subsequent access arrangement period, the Commission is required to allow for the differences between actual and forecast capital expenditure under section 8.9 of the Code.  
AGLP and EAPO have incentives to reduce costs and, for AGLP, to increase volumes during the initial access arrangement period.  This incentive structure is permitted by the Code.  The proposed access arrangement does not discuss benefit sharing, implying that any increased profitability in this access arrangement period is not shared with users until the next access arrangement period.  This sharing could be achieved by lower forecast costs leading to reduced tariffs over the next period.  However, it must be noted that the revenue stream is already insufficient for AGLP to fully recover its costs during the initial access arrangement period.  
AGLP has expressed concern that the current wording of the incentive mechanism in the access arrangement may be incompatible with the proposed ten year access arrangement period.  The Commission has considered this and agrees that the wording of the reference tariff policy should be revised to reflect the ten year access arrangement period and the benefits it provides to AGLP.  It agrees that the revised wording proposed by AGLP should be incorporated into the access arrangement.  Accordingly, an amendment to the reference tariff policy in the access arrangement is required.  
Amendment A3.9
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the reference tariff policy must be revised to remove the second clause in section 4.6 relating to the incentive mechanism. 
In addition, the reference tariff policy must state that the prospect of retaining improved returns over the initial access arrangement period provides AGLP with an incentive to increase sales and minimise the cost of providing the reference service.  
It must also state that in determining reference tariffs for the subsequent access arrangement period AGLP will ensure that users and prospective users will benefit from the increased efficiencies achieved by AGLP during the initial access arrangement period. 

With these amendments to the reference tariff policy made, the Commission considers that the incentive mechanisms proposed by AGLP will be appropriate and comply with the Code. 
Fixed principle
The fixed principle proposed sets the residual value of the pipeline at $45.12 million (in dollars of the day) at the end of the proposed access arrangement period (30 June 2004).  AGLP has derived this figure from the NPV revenue model given the assumptions and forecasts expressed in the access arrangement and access arrangement information.  The residual value would then be adjusted to take into account any redundancy of assets that may occur in the access arrangement period and any actual capital expenditure that differs from that forecast.  The Commission notes that the amount of capital expenditure forecast for the CWP is quite small for the initial access arrangement period. 
By including the residual value for the initial access arrangement period in the access arrangement as a fixed principle, AGLP has sought to ensure that the Commission will accept the NPV methodology used including economic depreciation.  The Commission’s overall assessment and acceptance of the proposed NPV approach based on economic depreciation was discussed earlier in this chapter (section 3.1).  The Commission has decided to accept the proposed NPV price path approach.  It meets the objective specified in section 8.1(a) of the Code of allowing the service provider the opportunity to earn a stream of revenue to recover the efficient costs of the pipeline over the expected life of the assets.  It also provides AGLP with an incentive to better its forecasts as it will be able to retain the whole benefit during the extended initial access arrangement period.  
The Commission notes that the residual value of $45.12 million in the proposed fixed principle was derived as a function of a number of market variable elements (including forecast sales of services, the CPI, capital costs and non-capital costs).  The Commission considers that this proposal is inconsistent with the requirement of section 8.48 of the Code that a market variable element cannot be a fixed principle.  While the Commission accepts the NPV price path methodology adopted by AGLP for the CWP, it cannot accept this proposed fixed principle as part of the CWP access arrangement.  Accordingly, the Commission requires that the fixed principle be removed from the access arrangement.  
In addition, the Commission notes that AGLP’s reference tariff policy does not include a fixed period in relation to the proposed fixed principle.  The Commission is of the view that all fixed principles included in an access arrangement must also specify a fixed period to comply with section 8.47 of the Code. 
Amendment A3.10
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, AGLP must remove the fixed principle from the access arrangement.  

AGLP has indicated that it accepts this amendment and will remove the current fixed principle from the access arrangement. 
The Commission notes the objectives of the fixed principle as argued by AGLP.  It also notes the Code requirement that a service provider be able to earn a revenue stream that, over time, covers the efficient costs of operating a pipeline.  Under the NPV model used by AGLP and adjusted for other amendments specified by the Commission the residual value of the initial capital base is calculated to be $41 475 764 in nominal terms at 30 June 2005 or $51 754 801 at 30 June 2010 on the basis of current forecasts, including inflation.  It must be noted, however, that according to section 8.9 of the Code the capital base must be adjusted at the commencement of the next period for differences between actual and forecast capital expenditure and any redundant assets.  In addition, as discussed in section 3.4 of this Final Decision, the projected amount of accumulated economic depreciation must be adjusted as a result of additional revenue collected due to the NTS component of the CPI.  Given the underlying real framework proposed, it is considered appropriate that the capital base be adjusted for the actual change in CPI over the period to enable it to be expressed in dollars of the day.  This procedure will remove a degree of inflation associated risk for AGLP.
Productivity savings 
The forecast of constant non-capital costs (in real terms) for all years in the initial access arrangement period indicates that there are no expected productivity improvements.  It is then a question of whether the costs are at an appropriate level at the beginning of the access arrangement period.  The Commission has considered this and does not believe the level of costs included in the revenue model for the CWP are unreasonable.  
The proportion in which productivity benefits are shared between users and AGLP in the subsequent access arrangement period will be determined by the Commission at the review of the access arrangement.  
The Commission expects that gains resulting from productivity savings in the first access arrangement period will be fully or partially passed on to users in the second access arrangement period by way of lower forecasts of costs feeding into the tariff calculations for the second access arrangement period. 
Factors contributing to out-performance 
It is possible that AGLP will, in the first access arrangement period, achieve returns greater than those implied by the WACC used in calculating the target revenue.  These ‘excess’ returns may occur for a number of reasons including: volumes achieved being greater than forecast; costs being less than forecast; and capital expenditure being less than forecast.  In some instances the reason for the excess return will be due to the efforts of AGLP.  In other situations, the benefit will result from a windfall gain by AGLP.  However, the extended access arrangement period of ten years has been provided to AGLP to increase the opportunity to benefit from excess revenues and earn a rate of return greater than that set by the Commission in this Final Decision.  This has been developed to compensate AGLP for the perceived specific risk relating to the CWP.  
The Commission’s analysis indicates that the ten year access arrangement period provides AGLP with a noticeably higher rate of return.  However, the proposed access arrangement allows the Commission full discretion as to how these excess returns are to be shared between AGLP and its customers, from the beginning of the subsequent access arrangement period.  
The Commission considers that it is appropriate that redundant assets be removed from the capital base as part of the process of determining the capital base at the commencement of the subsequent access arrangement period as specified in section 8.9 of the Code.  An appropriate amendment has been specified in section 3.3 of this Final Decision. 
Overall assessment
The Commission considers that AGLP has satisfied the Code in relation to establishing a price path for tariffs (which it has modified) and an incentive mechanism to encourage efficiency gains. 
The tariff path determined by the Commission gives AGLP incentives to decrease some non-capital costs, increase market demand and reduce capital expenditure.  One factor in constructing the appropriate incentives for AGLP is the extent to which AGLP will be allowed to keep returns in excess of those implied by the WACC.  The Commission considers that the retaining of returns greater than those forecast during the first access arrangement period by AGLP provides an appropriate incentive as envisaged by the Code.  This incentive is substantially increased with the proposed ten year access arrangement period.  The Commission considers that the question of continuing to retain benefits into the subsequent access arrangement period is most appropriately dealt with at that time. 
3.9	Assessment of reference tariffs and reference tariff policy
3.9.1	Code requirements
Section 3.5 of the Code requires the access arrangement to include a policy describing the principles that are to be used to determine a reference tariff (a reference tariff policy).  This reference tariff policy must, in the regulator’s opinion, comply with the reference tariff principles set out in section 8 of the Code.
Section 8 of the Code establishes the principles that must be followed in the establishment of reference tariffs.  The reference tariff policy and all reference tariffs should be designed to achieve a number of objectives which are set out in section 8.1 of the Code:
(a)	providing the Service Provider with the opportunity to earn a stream of revenue that recovers the efficient costs of delivering the Reference Service over the expected life of the assets used in delivering that Service;
(b)	replicating the outcome of a competitive market;
(c)	ensuring the safe and reliable operation of the Pipeline;
(d)	not distorting investment decisions in Pipeline transportation systems or in upstream and downstream industries;
(e)	efficiency in the level and structure of the Reference Tariff; and
(f)	providing an incentive to the Service Provider to reduce costs and to develop the market for Reference and other Services.
To the extent that there may be conflict between the application of these objectives, the Commission has the responsibility to determine how they may be best reconciled.  In addition, section 8.2 of the Code specifies a number of matters on which the Commission must be satisfied before it can approve a reference tariff, including:
(a)	the revenue to be generated from the sales (or forecast sales) of all Services over the Access Arrangement Period (the Total Revenue) should be established consistently with the principles and according to one of the methodologies contained in this section 8;
(b)	to the extent that the Covered Pipeline is used to provide a number of Services, that portion of Total Revenue that a Reference Tariff is designed to recover (which may be based upon forecasts) is calculated consistently with the principles contained in this section 8;
(c)	a Reference Tariff (which may be based upon forecasts) is designed so that the portion of Total Revenue to be recovered from a Reference Service (referred to in paragraph (b)) is recovered from the Users of that Reference Service consistently with the principles contained in this section 8;
(d)	Incentive Mechanisms are incorporated into the Reference Tariff Policy wherever the Relevant Regulator considers appropriate and such Incentive Mechanisms are consistent with the principles contained in this section 8; and
(e)	any forecasts required in setting the Reference Tariff represent best estimates arrived at on a reasonable basis.
These factors are mandatory requirements for the Commission.  In addition, the Code specifies principles and requirements for each of these factors.  These principles and factors are a mixture of mandatory requirements for the Commission and principles which provide the Commission with different levels of discretion.  Furthermore, the Code provides the Commission with a limited ability to approve principles (fixed principles) in an access arrangement that will limit its actions at future reviews.  However, these fixed principles are only permissible if they meet certain requirements outlined in section 8.48 of the Code.
Nevertheless, within these parameters, the reference tariff principles are designed to provide sufficient flexibility so that reference tariff policies can be designed to meet the specific needs of each pipeline system.  The overarching requirement is that, when reference tariffs are determined and reviewed, they should be based on the efficient cost (or anticipated efficient cost) of providing the reference services. 
The principles also require that, where appropriate, reference tariffs be designed to provide the service provider with the ability to earn greater profits (or less profits) than anticipated between reviews if it outperforms (or under performs) against the benchmarks that were adopted in setting the reference tariffs.  The intention is that, to the extent possible, service providers be given a market-based incentive to improve efficiency and to promote efficient growth of the gas market.  The Code refers to this type of approach as an incentive mechanism. 
Reference tariffs are to be set on the basis that sales of all services provided by the covered pipeline deliver (or are forecast to deliver) a certain amount of revenue (total revenue) over the period for which the reference tariffs remain in effect (the reference tariff period).
3.9.2	AGLP’s proposal
Section 4 of the access arrangement is the reference tariff policy for the CWP.  This outlines the basis on which tariffs have been structured and states that AGLP may undertake new facilities investment that does not meet the requirements of section 8.16 of the Code.  The reference tariff policy also sets out incentive mechanisms for AGLP and a fixed principle. 
Section 3 of the access arrangement specifies the reference tariffs (and other charges) for the CWP.  This is supported by the reference tariff policy itself in addition to other material provided to the Commission by AGLP. 
3.9.3	Submissions by interested parties
Submissions to the Commission have not commented on AGLP’s compliance with sections 3.5, 8.1 or 8.2 of the Code specifically.  However, some submissions have been received regarding reference tariffs and these have been discussed in the relevant sections of this Final Decision.  It should be noted that the submissions received in relation to reference tariffs have focused on the proposal for a single pricing zone.  
3.9.4	Commission’s considerations 
The Commission considers that AGLP has complied with section 3.5 of the Code in providing a reference tariff policy in the access arrangement.  As noted above, each of the aspects of the reference tariff and reference tariff policy have been assessed in the relevant sections of this Final Decision.  The following discussion draws together the Commission’s conclusions within the framework of sections 8.1 and 8.2 of the Code. 
Section 8.1 objectives
Recovery of efficient costs associated with the provision of reference services (8.1(a))
The Commission assessed the level of capital costs in section 3.2 of this Final Decision.  It concluded that they are reasonable.  The Commission has also assessed the non-capital costs of providing services on the CWP, which are largely contracted out to AGL Group and EAPO, and concluded that they are reasonable (see section 3.5 of this Final Decision).  
The Commission has considered total CWP costs and whether they relate to the provision of the reference service specified in the access.  The Commission has concluded that the costs of providing the reference service are appropriate and reflect the efficient provision of that service.  
AGLP expects to under-recover these costs because of low revenues in the initial access arrangement period.  The regulatory framework provides for the under-recovery through the use of economic depreciation which augments the capital base to ensure that AGLP has the opportunity for its revenue stream to recover all costs in the long run.  That is, any shortfall of cost of service recovery in revenues is reflected in capital gains of the regulated asset base.  The Commission considers that this arrangement meets this requirement of the Code.  
Replicating the outcome of a competitive market (8.1(b)) 
Setting the regulated rate of return on CAPM benchmarks means the returns achieved are expected to be similar to those achieved by a firm facing similar commercial risks operating in a competitive environment.  The return will be based on only those assets necessary to deliver the services required.  The reference tariffs allow AGLP to achieve a return in excess of a normal return from increased efficiencies and growth in sales which can also occur in a competitive market.  However, over time, as in a competitive market, it is expected that this benefit will be passed onto customers.  
Pricing reflective of efficient costs is also a feature of competitive markets and, as previously noted, care has been taken to ensure that tariffs are reflective of efficient costs.  However, this does not lead to competitive pricing for this pipeline over the entire 80 year period.  The regulated asset base of the CWP will be greater than an ORC valuation from the commencement of the access arrangement as a result of employing an NPV methodology and economic depreciation.  As a result, tariffs will, at times, be greater than could be achieved in a competitive market.  However, this is considered to be a time path issue rather than a genuine competition issue.  Accordingly, the Commission concludes that section 8.1(b) of the Code is met. 
Ensuring the safe and reliable operation of the pipeline (8.1(c))
The reference tariffs are based on cost forecasts as being necessary for the safe and reliable operation of the pipeline.  Each review of the access arrangement provides an opportunity for AGLP to increase its revenue if the safety and reliability of the pipeline demands it.  AGLP may submit early revisions if appropriate.  Other factors that will tend to preserve the integrity of the system include the contractual arrangements between AGLP and its users and the need by the APT to satisfy commercial markets that its assets are well maintained and operated efficiently. 
Not distorting investment decisions (8.1(d))
Efficient investment decisions upstream and downstream will be facilitated by transmission pricing based on an allocation of costs to users which approximates long run costs of service provision.  Inter-temporal investment distortions are minimised by the levelising process which presents stable prices over the access arrangement period (see section 3.8 of this Final Decision). 
The level of the WACC determined by the Commission is considered unlikely to encourage over investment because of the redundancy provisions to be incorporated into the access arrangement.  Under different circumstances, the Commission considers the risk of inefficient investment by another pipeliner seeking to bypass a pipeline is minimised by the upper limit, the DORC valuation, placed on assets by the Code which would tend to create pricing which makes such ventures commercially unviable.  In the case of the CWP, the asset valuation actually increases to above DORC over the initial years of the project before it reduces to zero at the end of the pipelines life.  This suggests that bypass of the CWP may be feasible.  However, it must be noted that the low initial tariffs resulting in the under-recovery of costs for some years would reduce the commercial feasibility of bypassing the CWP. 
It should be noted that in respect to investments relating to the transmission pipeline, the Code allows for AGLP to impose surcharges to make up for any revenue above that collected through tariffs which is necessary to justify any new investment decision.  This means that expansions will only be undertaken when the user can justify the surcharge in terms of the benefits to its own business or when AGLP can justify a surcharge on the basis of benefits to the overall system.  
To the extent that new markets may emerge, the additional volumes will, as a result of the regulatory framework, lead to lower tariffs for all users sharing the same infrastructure in future access arrangement periods.  The Commission is satisfied that the reference tariffs will not distort pipeline investment decisions or investment decisions in related markets.  
Efficiency in the level and structure of the reference tariff(s) (8.1(e))
The efficiency of the structure of the reference tariff has already been noted above.  The Commission is aware that some prospective users may argue that the tariff structure is inefficient in that it does not make any specific provision for gas from alternative sources (that is, other than via the MSP).  If gas from Narrabri as suggested by Forcenergy, for example, were to become available during this access arrangement period users would be able to settle for a negotiated service with AGLP.  The Commission considers this the most appropriate method for dealing with this possibility in light of the progress in developing the Narrabri gas field to date.  The Commission will assess the need for AGLP to accommodate alternatively sourced gas in its tariff structure and levels, as well as other services as sought by users and prospective users, at the first scheduled review of the access arrangement. 
In implementing amendments specified in this Final Decision, the Commission has specified a tariff path that avoids any unnecessary price peak and that results in real prices that fall slowly over time.  The Commission considers that this tariff path reflects an efficient level and structure of reference tariffs for the CWP (see sections 3.7 and 3.8 of this Final Decision). 
Incentives to reduce costs and expand the market (8.1(f)) 
As noted previously in this chapter, the Commission considers that the specified tariffs give AGLP an incentive to increase sales volumes and minimise costs.  AGLP reaps the benefits of such developments in the initial access arrangement period, which is now approximately ten years.  However, the benefits of increased efficiency, innovation and volume of sales will also flow to users in subsequent access arrangement periods following the Commission’s reviews of the access arrangement.
The Commission is satisfied that, with the specified changes to the proposed access arrangement, the reference tariffs are generally designed to achieve the objectives stated in section 8.1 of the Code.
Section 8.2 factors
Total revenue is established consistently with the principles and according to one of the methodologies contained in section 8 of the Code (8.2(a)) 
The Code states that the methodology to be used to calculate total revenue should be the cost of service, IRR or NPV methodology.  AGLP has used an NPV framework.  The Commission has assessed the proposal and the revenue model provided by AGLP and considers that the forecast total revenue for the proposed access arrangement is based on a NPV framework that complies with the principles specified in section 8 of the Code (see section 3.6 of this Final Decision). 
The proportion of total revenue that any one reference tariff is designed to recover is calculated consistent with the principles of section 8 of the Code (8.2(b)) 
The Commission is satisfied that the allocation of operating, maintenance and other non-capital costs to the single reference service is appropriate for the initial access arrangement period as no material additional revenue is expected to accrue from negotiated services during this period.  It notes that the access arrangement is anticipated to be revised in the future to include a different tariff structure to that for the initial access arrangement period.  This will require AGLP to allocate costs according to any new tariff structure.  Revisions to the access arrangement to alter the tariff structure and cost allocation can be proposed by AGLP at any time during the ten year initial access arrangement period or at the time of the scheduled review.
The proportion of total revenue recovered from users of a service is calculated consistent with the principles of section 8 of the Code (8.2(c))
AGLP has a single service for all users.  The Commission assessed the information used by AGLP to determine and allocate costs of providing the service.  Given the tariff structure for the initial access arrangement period, the Commission considers that tariffs recover revenue in compliance with the objectives of the Code (see section 3.7 of this Final Decision).  
Incentive mechanisms that are incorporated are consistent with the principles of section 8 of the Code (8.2(d))
Incentive mechanisms are incorporated into the access arrangement by specifying that tariffs are calculated on the basis of forecasts.  The above normal returns earnt are kept by AGLP for the duration of the ten year access arrangement period.  This provides AGLP with the opportunity to capture higher revenues and returns for an extended period.  At the conclusion of the period, users will be able to benefit from any gains achieved by AGLP if the Commission considers it appropriate to adjust costs to reflect the levels actually achieved by AGLP rather than those presently forecast.  The Commission considers that the incentive mechanisms in this access arrangement are consistent with the Code. 
Forecasts used are best estimates determined on a reasonable basis (8.2(e)) 
The Commission considers the forecast costs are reasonable.  It also accepts the forecast volume figures used by AGLP in the revenue model.  However, the Commission is aware that the forecast volume data is always subject to some uncertainty.  After considering the greenfield project nature of the CWP the Commission has accepted the forecast demand schedule proposed by AGLP.  This schedule provides AGLP with an incentive to improve its performance, a feature that the Commission considers important for this access arrangement particularly in light of the concerns regarding the specific risk relating to the CWP.  The Commission is satisfied that the forecast volumes comply with the Code.  

4.	Non-tariff elements
Section 3 of the Code establishes the minimum contents of an access arrangement, which include the following non-tariff mandatory elements:
•	a services policy that must contain at least one service that is likely to be sought by a significant part of the market;
•	terms and conditions on which the service provider will supply each reference service;
•	a capacity management policy to state whether the covered pipeline is a contract carriage or market carriage pipeline;
•	in the case of a contract carriage pipeline, a trading policy which refers to the trading of capacity;
•	a queuing policy which defines the priority that users and prospective users have to negotiate capacity where there is insufficient capacity on the pipeline;
•	an extensions/expansions policy which determines whether an extension or expansion of a covered pipeline is or is not to be treated as part of the covered pipeline for the purposes of the Code; and
•	a date by which revisions to the access arrangement must be submitted and a date on which the revisions are intended to commence.
An access arrangement must also contain a reference tariff policy and at least one reference tariff.  AGLP’s tariff related proposals for the CWP are assessed for compliance with the Code in chapters 2 and 3 of this Final Decision.
In this chapter the mandatory non-tariff elements for the CWP are assessed for conformance with the Code.  The Code requirements are outlined for each mandatory element followed by a summary of the service provider’s proposal, the issues raised in submissions, and the Commission’s considerations.  The Commission’s assessment includes, where relevant, amendments that the Commission requires be made in order for the access arrangement to be approved.  All amendments are replicated in the Executive Summary of this Final Decision. 
4.1	Services policy
4.1.1	Code requirements
Sections 3.1 and 3.2 of the Code require an access arrangement to include a services policy which must include a description of one or more services that the service provider will make available to users and prospective users.  The policy must contain one or more services which are likely to be sought by a significant part of the market, and any service or services that in the relevant regulator’s opinion should be included in the services policy.
To the extent that is practicable and reasonable, a service provider should also make available only those elements of a service required by users and prospective users and apply a separate tariff for each element if this is requested.
4.1.2	AGLP’s proposal
AGLP’s service policy consists of a single reference service — the transportation service.  Gas is transported from the receipt point to any delivery points on the pipeline with tariffs charged on the basis of throughput ($ per GJ of throughput).  AGLP also offers negotiated services which are services negotiated to meet the needs of a user that differ from those in the reference service.  
In order to encourage maximum usage of the pipeline in the initial phase of its operation, the transportation service has a reference tariff based solely on throughput (without an adjustment for load factor that is customarily adopted in transmission pipelines to encourage load management).  Payment is based on actual throughput without the usual obligation to pay for a minimum quantity in each contract year whether or not that quantity is taken.  There are no charges for authorised overruns until contracted capacity reaches 85 per cent of pipeline capacity.
AGLP states that the proposed simple tariff structure for the single service offered is intended to encourage gas usage.  Users would have the certainty of knowing that they only pay for the quantity of gas delivered.  Inexperienced gas users, in particular, would benefit from not having to be concerned about load management issues which would usually be expected to affect gas transportation costs.
AGLP advises that it anticipates that by the time of the first scheduled review of the access arrangement, which it proposed to occur 4½ years after the commencement of the access arrangement, the pattern of usage of the pipeline will be sufficiently known to establish a service with capacity and throughput charges.  AGLP stated its intention to offer such a service as a reference service from the start of the second access arrangement period. 
Key factors relating to the proposed transportation service include:
•	AGLP will receive gas at the receipt points, transport it through the pipeline and deliver it at the delivery points;
•	users must establish a level of gas transportation required which fairly reflects their needs, including their maximum hourly quantity (MHQ) for each delivery point, the maximum daily quantity (MDQ) and the annual contract quantity (ACQ);
•	AGLP’s maximum obligation to deliver gas to a user is the agreed MHQ, MDQ and ACQ;
•	in the event that a user’s withdrawals at a delivery point exceed the MHQ in any hour or the MDQ on any day, an overrun (either authorised or unauthorised) will occur.  There will be no charges for overruns until contracted capacity reaches 85 per cent of pipeline capacity; 
•	a daily variance of ten per cent is permissible.  If variance greater than this occurs for more than four days in a month or more than 24 days during a contract year then a daily variance charge will be incurred for each day over the relevant limit; 
•	users are responsible for balancing input and withdrawals over three month periods.  If an imbalance exists at the end of a three month period the user is charged an imbalance charge; and
•	the term of the service is generally one year but may be longer if the user so elects. 
The proposed access arrangement outlines the procedures that would be followed for a prospective user to gain access to a service, including the minimum level of detail to be provided in a request, and time periods within which AGLP will respond.  
4.1.3	Submissions by interested parties
Some parties raised concerns in their submissions about the adequacy of the services policy being offered for the CWP.  
Forcenergy, the operator of a Petroleum Exploration Licence for the Gunnedah Basin in NSW, submitted that a backhaul service is needed in the CWP access arrangement.  As a potential competing supplier of gas, Forcenergy stated its view that numerous services are likely to be requested by new or existing users over the forthcoming five years.  These services include interruptible, partial forward haul and parking.  Forcenergy submitted that it would be inefficient to omit these services from the access arrangement at this time.
The NSW Department of Energy (DOE) has also noted the potential for Forcenergy to provide a new source of gas supply in NSW in competition with the Cooper Basin and Bass Strait suppliers.  DOE submitted that appropriate provisions are required to allow backhaul, in order to facilitate inter-basin gas competition and to ensure free and fair trade in gas. 
In contrast, DCC, MRBEC and ODEC support AGLP’s proposed reference service.  While they do not specifically refer to the proposal that there be only one reference service with the tariff based solely on throughput, each expresses support for a single zone reference service.  For example, MRBEC stated:
A regional price was the objective of all stakeholders [of the Central Ranges Natural Gas Working Group] to ensure that no town would be disadvantaged in attracting large energy users.
All tariff users wanted to have the same price across the region, as in other regions.
Without the regional pricing system, the price of gas at the end of the system becomes too expensive and therefore the project “implodes” and becomes uneconomic and in the case of the Central Ranges, will not be built.  As the Central West pipeline has now been constructed the price to other users would need to be increased if the load cannot be obtained.  This would result in even higher energy costs and a loss of competition in the energy market.  
In response to the Commission’s Draft Decision, ODEC reiterated that:
… all players in the Orana/Central West strongly supported the “postage stamp” rate for natural gas to ensure the pipeline’s extension and the Councils and Communities in the Central Rages project have adopted a similar stance.
The importance of a competitive alternate fuel for industry within the various regions is essential for continued economic development and suppliers such as AGL Pipelines need to be encouraged.  The suggestion in the report [the Draft Decision] that tariffs be distance based could have a negative affect on the existing pipeline and the extension to Tamworth. 
4.1.4	Commission’s considerations
The Commission notes evidence that local communities support the proposed reference service and tariff structure, and AGLP’s view that a simple tariff structure is likely to be attractive to gas users, particularly to inexperienced ones.  The Commission considers that a significant number of users and potential users is likely to seek the single pricing zone service (identified as the transportation service in the access arrangement) being offered.  Accordingly, the services policy complies with section 3.2(a)(i) of the Code. 
The Commission has the power to require that a services policy include any service or services that the Commission considers should be included (section 3.2(a)(ii) of the Code).  Forcenergy and DOE contend that the present access arrangement should allow for other services that may be sought by users or prospective users in the future, in particular backhaul.  
As noted earlier, AGLP expects to provide a more complex suite of services once usage patterns are established and users are more experienced.  AGLP nominated the expected 2004 commencement of the subsequent access arrangement period as the appropriate time to introduce these services.  The Commission noted in its Draft Decision that additional services of the type nominated by Forcenergy and DOE could be made available during the initial access arrangement period as negotiated services.  Accordingly, the Commission did not propose to require additional services to be specified as reference services for the initial access arrangement period.  
The Code also requires, to the extent practicable and reasonable, that a user be able to obtain only the elements of a service that it requires.  AGLP has suggested that the majority of users will seek the transportation service as described in the access arrangement.  Any variation of this service is able to be negotiated between the parties.  While no interested parties have as yet expressed a view that unbundling of the transportation service be required, this position may change over time.  With greater experience in the use of natural gas, users may wish to explore alternative gas supply arrangements.  
The Commission has considered whether AGLP’s proposed initial single reference service is compatible with an extended initial access arrangement period.  In particular, the Commission has considered issues related to the efficiency of a one-part throughput tariff and the likelihood of demand by users and prospective users for additional services.
The expected additional efficiency of a two part tariff based on throughput and capacity is derived from the use of capacity charges to manage demand in order to utilise effectively scarce pipeline capacity.  Capacity charges are of particular importance as a demand management tool when pipelines face tight capacity constraints.  However, in the absence of constraints the introduction of a capacity charge may introduce inefficiencies.  This is because individual customers are likely to incur costs as they seek to tailor their demand patterns to minimise transmission costs while the choice of tariff structure would be expected to be revenue neutral overall.  There may also be some shifting of costs between customers.
As more complex tariffs have received little attention during the current consultative process the Commission does not consider it appropriate to specify additional or different reference services for inclusion in the access arrangement either at its commencement or at a later date.  
AGLP has advised that it proposes to alter its services policy to make it clear that a two part tariff could be made available as a negotiated service.  In practice, the Commission considers it unlikely that many customers would seek this option.  Rather, the Commission expects that AGLP would introduce a two part tariff as revisions to the access arrangement if it considers that a constraint is imminent.  AGLP also proposes to state in its services policy that arbitration under section 6 of the Code is available to users and prospective users in regard to disputes relating to negotiated services.  
After consideration of the issues raised by interested parties and the need and suitability for alternative services and the unbundling of services, the Commission has formed the view that the proposed services policy is appropriate for this initial access arrangement period and meets the requirements of the Code.  In addition, it agrees that AGLP may amend its services policy as foreshadowed.
4.2	Terms and conditions 
4.2.1	Code requirements
Section 3.6 of the Code requires an access arrangement to include the terms and conditions on which a service provider will supply each reference service.  Based on the relevant regulator’s assessment, these terms and condition must be reasonable. 
4.2.2	AGLP’s proposal
AGLP states that it will provide its reference service (identified as the transportation service) on the terms and conditions set out in its standard service agreement for the reference service from time to time.  The key terms and conditions are set out in schedule 2 to the access arrangement. 
Schedule 2 is divided into three parts:
•	general -  topics include: relationship between AGLP and user; obligation to transport gas; gas pressure; nominations; MHQ, MDQ and ACQ; daily variance; system use gas and linepack; metering; allocation; accounts and payments; force majeure; liabilities and indemnities; interruptions and curtailments; option to extend; title to and responsibility for gas; metering and records; gas quality; part periods; and overruns;
•	calculation of imbalance; and
•	connection of metering facilities to the pipeline.
AGLP states that it will not discriminate between prospective users in the provision of services on the basis of: 
•	past transactions or relationships with AGLP; 
•	the identity of the prospective user;
•	the fact that the prospective user is a related party of AGLP; or
•	the source of the gas proposed to be transported, subject only to the gas meeting the specifications. 
Gas quality specifications
AGLP’s gas quality specifications for the CWP are set out in schedule 3 of the access arrangement.  The specifications include heating value, Wobbe Index, sulphur content and receipt point temperature and reflect the specifications for the MSP.  
Section 5 of the revised access arrangement information provides details relating to the technical specifications of the pipeline.  
AGLP has nominated the pressure at which gas will be delivered to users as between 4 000 kPa and 6 000 kPa.  This range of acceptable pressures is based on the pressures used in the MSP.  
Overruns, variances and imbalances 
AGLP states that overruns are a method used by a pipeliner to ensure that on any day the pipeline can deliver users their MDQ.  Overruns occur when either MHQ or MDQ is exceeded, that is, when gas delivered is greater than that nominated by the user.  An overrun can be authorised (where AGLP has agreed to a user’s request for additional gas at a particular delivery point) or unauthorised.  
Users of the CWP face an overrun charge when the contracted capacity of the CWP is at least 85 per cent of the pipeline capacity.  AGLP propose an authorised overrun charge of 20 per cent of the reference tariff.  The unauthorised overrun charge is to be 100 per cent of the reference tariff.  
In the event that the CWP contracted capacity is greater than 85 per cent of the pipeline capacity AGLP will limit the availability of authorised overruns to users.  A user will not be entitled to an authorised overrun if that user has already exceeded MDQ for four days of the month or 105 per cent of MDQ on more than 12 days in the year. 
Variances are used to ensure that users can be supplied with their nominated quantities.  With users nominating their requirements for a particular day in advance AGLP is able to schedule deliveries by the operation of looped sections and compressors as required.  
AGLP allows daily variances (where the delivered or received quantity exceeds the nominated quantity by more than ten per cent) to occur on four days within a month (or 24 days in a year) before a user is required to pay a daily variance charge.  By charging an additional 120 per cent of the reference tariff for the daily variance quantity AGLP claims that users are provided with an incentive to correctly nominate their gas needs.  
AGLP acknowledges that it is impossible for a user to balance receipts and deliveries on any one day and, consequently, has established an inventory system.  A user’s imbalance is calculated each month.  If an imbalance exists a user is expected to rectify it during the next month.  If at the end of three months a user remains out of balance then the quantity attracts an imbalance charge of 250 per cent of the reference tariff.  
Apportionment
AGLP sets out its requirements for apportionment (referred to by AGLP as ‘allocation’) in clauses 21 and 22 of schedule 2 of the access arrangement. 
21.	Where gas is delivered to a Delivery Point for more than one User, those Users must establish allocation methodologies, and notification processes reasonably acceptable to AGLP and must provide sufficient information to AGLP to enable it to reconcile between Users the quantities of gas received and delivered.  If no such methodologies or processes are established, AGLP will be entitled to adopt a reasonable methodology such as a pro-rating based on Nominations. 
22.	Where a Receipt Point is used by more than one User, those Users must establish allocation methodologies reasonably acceptable to AGLP, and must provide sufficient information to AGLP to enable it to reconcile between Users the quantities of gas received and delivered.  If no such methodologies are established, AGLP will be entitled to adopt a reasonable methodology such as a pro-rating based on Nominations. 
4.2.3	Submissions by interested parties
Gas quality specifications
Esso contends that the proposed gas specifications are unduly tight, and may raise a barrier to inter-basin competition.  In particular, Esso notes that the minimum allowed value proposed for the Wobbe Index (a measure of heating value) applicable to gas shipped on the CWP is higher than the minimum allowable under regulations pursuant to the Victorian Gas Industry Act.  Esso is concerned that Bass Strait gas, which meets standards applicable in Victoria, may not be accepted for transportation on the CWP.  Esso contends that there are no valid reasons for the higher specifications.
The DOE has also suggested that the Wobbe Index range proposed by AGLP is too narrow.  It questions the need for a transmission pipeliner to use the Wobbe Index when in Victoria the Wobbe Index is only specified for distribution systems.  The DOE states that, if AGLP is to specify a Wobbe Index in the CWP access arrangement as proposed, the index should be broad enough to allow gas from the Bass Strait and the Narrabri field to be transported on the CWP.  
Apportionment
The DOE submits that the CWP access arrangement should address the issue of apportionment, noting that this issue has been identified by the Gas Reform Implementation Group (GRIG) as potentially a significant impediment to retail competition as it may deny new entrants access to gas.  DOE advised that the GRIG was considering the option of amending the Code to require a service provider to include an apportionment policy in an access arrangement but that a decision had not been made.  
Other terms and conditions
No comments were received by interested parties regarding any other terms and conditions of access to the CWP. 
4.2.4	Commission’s considerations
The Commission notes, while schedule 2 of the access arrangement includes key terms and conditions, the proposed access arrangement does not include the standard service agreement which sets out the terms and conditions on which AGLP will provide the reference service.  AGLP has stated that the standard service agreement cannot be finalised until the terms and conditions applicable to the CWP for the initial access arrangement period have been settled following the Commission’s approval of the access arrangement.  
The Commission is aware that AGLP cannot at this stage be confident that its standard service agreement is consistent with the terms and conditions which the Commission will approve as part of the access arrangement.  The Commission expects that users may be primarily guided as to the terms and conditions on which they will gain access to the CWP by the content of the standard service agreement.  Consequently, the Commission requires an amendment to the CWP access arrangement to make it clear that, in the event that any apparent inconsistency arises, schedule 2 of the access arrangement prevails over the standard service agreement.
Amendment A4.1
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, AGLP must clearly specify that schedule 2 of the access arrangement prevails over the standard service agreement.  

AGLP has indicated that it will revise the access arrangement to this effect although it considers that the access arrangement already establishes this priority.  
The Commission notes that the services policy and queuing policy of the access arrangement both require users and prospective users to meet AGLP’s prudential requirements prior to the user requesting a service or assigning a request on a queue.  The prudential requirements that AGLP requires users and prospective users to meet are not specified in the access arrangement.  The Commission considers that it is important for users and prospective users to be aware of all the conditions of use of the CWP including any prudential requirements prior to commencing a contract.  The reasonableness of the terms and conditions of access cannot be assessed by the Commission or interested parties in the absence of AGLP’s prudential requirements.  
Accordingly, the Commission requires an amendment to the CWP access arrangement for AGLP to set out the prudential requirements that it will apply to users and prospective users in the access arrangement.  AGLP has stated that it intends to comply with this amendment.  
Amendment A4.2
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, AGLP must include in the access arrangement the prudential requirements relevant for users and prospective users.  

Section 2.3 of the proposed access arrangement states that AGLP will not discriminate between users on a number of grounds, including on the basis of past transactions or relationships with AGLP (section 2.3(a)).  The Commission noted in its Draft Decision that this provision is unnecessarily narrow as it only proscribes discrimination relating to relationships with AGLP, which at that time was part of the much broader AGL Group.  Accordingly, the Commission proposed an amendment to the CWP access arrangement for AGLP to extend the proscription of discrimination set out in section 2.3 of the proposed access arrangement to cover relationships with the AGL Group.  AGLP has accepted this amendment.  
The Commission understands that AGLP and the CWP are now owned by the APT. Accordingly, the Commission considers that the proscription should cover relationships with either AGLP or the APT.
Amendment A4.3
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, the words ‘or the Australian Pipeline Trust’ must be inserted after ‘AGLP’ in sections 2.3(a) and (c) of the access arrangement.

Gas quality specifications
The Commission notes Esso’s concerns about the gas quality specifications proposed for the CWP.  It also notes that the same gas quality specifications are identified for the MSP transmission pipeline and for the NSW and ACT gas distribution networks.  EAPL states that all gas entering its pipeline system will be required to comply with certain quality specifications, and lists what it describes as typical requirements, which it notes correspond closely to the current specification for gas received into the MSP at Moomba.  While EAPL acknowledges that gas from other sources may have alternative or additional parameter limits, it must, in any case, be compatible with gas already being transported through the pipeline system to ensure that the quality of gas delivered meets required specifications. 
The Commission understands that this issue has been debated extensively within the Australian natural gas industry, and that support for the higher Wobbe Index minimum is largely based on possible safety concerns arising if older domestic appliances currently operating on Cooper Basin gas were to be fed gas with a lower heating value.  While the Commission has not formed an opinion on the validity of these overall concerns, they appear unlikely to be relevant for the CWP in isolation.  
The Commission notes that IPART addressed a similar issue in relation to gas marketed in Wagga Wagga in its Final Decision on the access arrangement proposed by Great Southern Energy Gas Networks Pty Ltd.  IPART required the insertion of a trigger mechanism to:
… enable the Tribunal to reopen the Access Arrangement if GSN fails, within a reasonable time, to seek an amendment to adopt new gas specifications following recommendations by the Gas Quality Specification Working Group.  A working group has been formed by the Australian Gas Association (AGA), the Australian Petroleum Production and Exploration Association, and the Australian Pipeline Industry. 
More recently, IPART proposed an amendment to the AGLGN access arrangement that would have the effect of requiring the gas specifications to be consistent with any law that is made by the NSW Government.  
The Commission is concerned that overly tight gas quality specifications may hinder the potential for inter-basin gas competition in NSW.  However, it notes that changing the gas specification for the CWP in isolation would have little, if any, practical effect.  In order for gas to reach customers in the Central West, it also must be acceptable on the MSP and the distribution network.  The Commission is also aware that its role and expertise is as an economic rather than technical regulator, and that it has not conducted a full technical review of this issue. 
The AGA’s Gas Specification Working Group has reached an agreement on a proposed common specification for NSW and Victoria.  The Commission requires that AGLP’s access arrangement be amended to ensure that any new specification recommended by the Gas Specification Working Group and approved by the relevant jurisdictions is reflected in the access arrangement for the CWP.  The Commission recognises that implementation of the revised specification will be subject to obligations under existing service agreements.  AGLP has stated that it accepts this amendment.  
Amendment A4.4
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, AGLP must amend the access arrangement to state that AGLP will, if recommendations by the AGA Gas Specification Working Group to adopt more flexible gas specifications in south-eastern Australia are approved, substitute that specification for the specification currently set out in schedule 3 of the access arrangement, subject to obligations under existing service agreements.  

Apportionment
The Commission has considered DOE’s concerns about the potential for inadequate apportionment processes to impact on competition and also the proposal for the Code to be changed such that an explicit apportionment policy would be specified as a mandatory element of an access arrangement.  
The Commission notes that AGLP’s access arrangement requires users to establish apportionment or allocation methodologies where gas is delivered to a delivery point for more than one user, and that the methodologies and notification processes must be reasonably acceptable to AGLP.  If no such methodologies or processes are established, AGLP will be entitled to adopt a reasonable methodology.
Whether AGLP’s proposals would be consistent with a mooted Code requirement for an apportionment policy would depend on the specification of such a policy in the Code.  For example, the Code might require a more prescriptive policy for apportionment than that set out in AGLP’s terms and conditions.  However, the Code does not currently require an apportionment policy, and such considerations may be considered speculative. 
No comments were received on the reasonableness of AGLP’s proposals concerning apportionment methodologies.  The Commission does not require AGLP to alter its allocation methodology.
4.3	Capacity management policy 
4.3.1	Code requirements
Section 3.7 of the Code requires an access arrangement to include a statement that the covered pipeline is either a contract carriage pipeline or a market carriage pipeline. 
4.3.2	AGLP’s proposal
AGLP has provided a statement that, for the purposes of section 3.7 of the Code, the CWP is a contract carriage pipeline. 
4.3.3	Submissions by interested parties
No comments were received on this issue.
4.3.4	Commission’s considerations
As the access arrangement includes a statement that the CWP is a contract carriage pipeline, it satisfies the requirements of section 3.7 of the Code.
4.4	Trading policy
4.4.1	Code requirements
If a pipeline is a contract carriage pipeline, the access arrangement must include a trading policy which explains the rights of a user to trade its right to obtain a service to another person.  The trading policy must, amongst other things, allow a user to transfer capacity:
•	without the service provider’s consent, if the obligations and terms under the contract between the user and the service provider remain unaltered by the transfer; and
•	with the service provider’s consent, in any other case.  Consent may be withheld only on reasonable commercial or technical grounds and the trading policy must specify conditions under which consent will be granted and any conditions attaching to that consent.  
4.4.2	AGLP’s proposal
According to section 5 of AGLP’s access arrangement users can trade rights in three circumstances.  These are: 
•	a user may make a ‘bare transfer’ without the consent of AGLP if, prior to utilising it, the transferee notifies AGLP of the portion and nature of contracted capacity subject to the bare transfer. 
•	a transfer or assignment of all or part of a user’s contracted capacity may occur by a way other than a bare transfer with the prior consent of AGLP.  AGLP’s consent will only be withheld on reasonable commercial or technical grounds, and may be given subject to reasonable commercial or technical conditions. 
•	a user may only change the receipt point and/or delivery point specified in a service agreement with the prior consent of AGLP.  AGLP’s consent will only be withheld on reasonable commercial or technical grounds, and may be given subject to reasonable commercial or technical conditions.
4.4.3	Submissions by interested parties
No submissions were received on this issue. 
4.4.4	Commission’s considerations
The Commission notes that the access arrangement for the CWP requires a trading policy to meet the minimum requirements of the Code, as the pipeline is a contract carriage pipeline.  The Commission considers that the trading policy in the access arrangement closely follows, and consequently accords with, sections 3.9 to 3.11 of the Code.  No amendments to the proposed trading policy are required. 
4.5	Queuing policy 
4.5.1	Code requirements
Sections 3.12 to 3.15 set out the Code’s requirements for a queuing policy.  An access arrangement must include a queuing policy for determining the priority given to users and prospective users for obtaining access to a covered pipeline and for seeking dispute resolution (under section 6 of the Code).  
A queuing policy must be set out in sufficient detail to enable users and prospective users to understand in advance how it will operate.  It must also, to the extent reasonably possible, accommodate the legitimate business interests of the service provider and of users and prospective users and generate economically efficient outcomes. 
4.5.2	AGLP’s proposal
Where there is insufficient capacity to satisfy a user’s request to obtain a service from AGLP a queue will be formed.  A queue will include all relevant requests which cannot be satisfied.  The date of a request is the date that it is received by AGLP.  A request for a reference service will have priority over a request for a negotiated service.
At the time a request is placed in a new or existing queue, AGLP will advise the prospective user of:
•	its position on the queue;
•	the aggregate capacity of requests which are ahead of it on the queue; 
•	AGLP’s estimate of when capacity may become available; and 
•	the size of any surcharge that may apply to developable capacity.
AGLP will update these details when the relative position of a request or the timing of available developed capacity changes.  
Once on a queue, a prospective user may reduce but not increase the capacity sought in its request.  An assignment of a request can be made to a bona fide purchaser of the prospective user’s business or assets.  A request for service may lapse and be removed from the queue if: 
•	the prospective user does not respond to AGLP’s request for confirmation of the request within the specified 14 days; 
•	the prospective user notifies AGLP that it does not want to proceed with the request; or
•	the entity to whom the prospective user assigns its request does not meet AGLP’s prudential requirements.  
A request will not lapse in the event that there is a dispute.  The request will retain its priority until the dispute is resolved in accordance with section 6 of the Code. 
When capacity can be made available which meets the requirements of any request in a queue, that capacity will be progressively offered to each prospective user in the queue in order of priority.  AGLP will advise each of those prospective users of its plans to make capacity available, and the terms and conditions on which the capacity will be available.  A prospective user will have 30 days after an offer is made to enter into a service agreement, failing which the request will lapse or lose priority to those entering into such a service agreement. 
4.5.3	Submissions by interested parties
No submissions were received on this issue. 
4.5.4	Commission’s considerations
The purpose of a queuing policy is to allocate spare capacity where there is insufficient capacity to satisfy the needs of all users and potential users who have requested capacity.  The Commission notes that no comments have been raised by interested parties about the proposed queuing policy for the CWP.  This may reflect a view that, based on AGLP’s volume projections (which reach a peak load of 5.884 TJ/day in 2004, approximately half the maximum uncompressed daily delivery capacity of 10.1 TJ/day) there would be little likelihood of a queue forming within the initial access arrangement period.  
AGLP’s volume projections also indicate that maximum capacity would be unlikely to be reached within an initial access arrangement period ending in 2010 as proposed in section 4.7.4.
The Commission considers that the proposed queuing policy satisfies the minimum requirements of the Code.  The policy may need to be further developed once demand grows and the possibility of a queue forming becomes more immediate.  However, at present, no amendments to the CWP queuing policy are required. 
4.6	Extensions and expansions policy
4.6.1	Code requirements
The Code requires an access arrangement to have an extensions/expansions policy (section 3.16).  The policy is to set out the methodology to assess whether any extension to, or expansion of, the capacity of the system will be treated as part of the covered pipeline.  A service provider is also required to specify the impact on reference tariffs of including an extension or expansion with the covered pipeline.  In addition, an extensions/expansions policy must outline under what conditions the service provider will fund new facilities and provide a description of those new facilities.  
4.6.2	AGLP’s proposal
AGLP initially proposed that, in the event that the pipeline is extended to Tamworth, the extension (known as the CRP) would form part of the pipeline for the purposes of the access arrangement, and that it would submit proposed revisions under section 2 of the Code for the purpose of including the CRP in the CWP access arrangement.  An extension to Tamworth would not affect reference tariffs for existing delivery points between Marsden and Dubbo.  
AGLP subsequently advised the Commission that it wished to revise its initial proposal such that it would have the discretion to determine whether it would lodge revisions to the access arrangement in the event that it built the CRP.  AGLPs state that CWP tariffs will not be affected in the initial access arrangement period if the CRP is built. 
AGLP’s proposed access arrangement states that no other geographical extension to the pipeline will form part of the pipeline for the purposes of this access arrangement.  However, AGLP has subsequently proposed to the Commission that this policy would be modified in its revised access arrangement such that, if an extension (other than the CRP) is undertaken, AGLP will decide (after consultation with the Commission) whether to include the extension with the CWP access arrangement.  
Any expansion to the capacity of the pipeline would form part of the pipeline, and such capacity would be offered at the reference tariff.  
4.6.3	Submissions by interested parties
DCC, in its submission, stated:
Dubbo City Council is certainly supportive of the proposed single zone for Forbes, Parkes, Narromine and Dubbo and would not, in all fairness, then expect users between Dubbo and Tamworth to be expected to contribute to costs in this zone.  
Following the release of the Draft Decision, Narromine Shire Council suggested that a cross subsidy scheme be implemented to assist in the future extension of the whole Central West gas pipeline system.  In particular, the Council suggested that a portion of revenues from the CWP be set aside for the development of network extensions to locations such as Trangie and the Warren Shire.  It was submitted that such a scheme would assist and minimise the risk of regional development, and that the proposal had been adopted by the ‘C’ Division Shires (Bogan, Coonabarabran, Coonamble, Coolah, Gilgandra, Gunnedah, Narrabri, Narromine, Walgett, Warren and Wellington).  
In addition, a number of parties expressed concern that the Commission’s decisions regarding the CWP might deter AGLP from building the proposed extension from Dubbo to Tamworth.  It was suggested that the Commission should closely consider issues related to potential extensions to the CWP when determining the appropriate rate of return (see section 1.5.1 of this Final Decision for further discussion).
4.6.4	Commission’s considerations
In its Draft Decision the Commission proposed to accept AGLP’s proposal that the CRP would be included in the CWP access arrangement and that costs and benefits arising from the CRP would not be reflected in the tariffs between Marsden and Dubbo during the initial access arrangement period.  The combined costs and revenues of the CWP and the CRP were expected to be fully evaluated as part of the first review of the access arrangement which was scheduled to commence in 2004.  
The Commission has now reconsidered its position, in light of AGLP’s revised proposal, and has decided that the access arrangement should be altered to allow AGLP the discretion to decide whether to include the CRP in the CWP access arrangement.  Accordingly, an amendment to the extensions/expansions policy of the access arrangement is required.  
Amendment A4.5
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, section 7.1 must be revised to state that should AGLP proceed with the Central Ranges Pipeline it will decide, after consultation with the Commission, whether to include the Central Ranges Pipeline in the access arrangement through the extensions/expansions policy. 

While the Commission notes the unlikelihood in the short term of the transmission pipeline being extended beyond Tamworth, it was concerned that the policy as originally proposed might unnecessarily act to preclude such an extension from inclusion in the access arrangement.  The Commission welcomes the revised policy proposed by AGLP which it expects will be incorporated in AGLP’s revised access arrangement.  The Commission considers AGLP’s revised proposal that it will decide, after consultation with the Commission, whether these potential extensions to the CWP will be included in the access arrangement is reasonable.
The Commission considers it reasonable that any capacity expansion to the CWP will form part of the pipeline and will not result in an increase to the existing reference tariff.  
At present there is no mechanism in the access arrangement to provide for notification to the Commission of any expansions, or extensions, to the CWP that come into service.  The Commission considers, as a general principle, that it should be alerted to the commissioning of extensions and expansions to aid in its role as transmission access regulator.  Accordingly, the Commission requires an amendment to the CWP access arrangement. 
Amendment A4.6
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, AGLP must specify in the access arrangement that it will notify the Commission of the commencement of services provided through expansions and extensions to the Central West Pipeline.  

AGLP has stated that it accepts this amendment and will revise the access arrangement accordingly.  
The Commission, as noted earlier in this Final Decision, appreciates the concern of regional representatives in regard to the economic development of their areas, and of the need to balance the interests of the service provider, users and prospective users, including the need to provide incentives to efficient investment while allowing services to be delivered at appropriate prices.  
The Commission has considered suggestions that it should explicitly look beyond the proposed access arrangement and consider issues related to other potential regional infrastructure development, in particular when determining the appropriate rate of return (see section 1.5.1 of this Final Decision).  
As discussed above, Narromine Shire Council has proposed that a levy on transmission of gas on the CWP be used to help fund future expansions to the associated distribution system.  It must be noted that there is legal and regulatory separation of the CWP (a transmission pipeline) from the associated distribution systems servicing the regional centres.  As such, the Commission’s role is to regulate the transmission pipeline while IPART regulates the distribution systems operated in NSW by AGLGN.  This includes the distribution systems in the Central West region.  Future extensions and expansions of the distribution systems must be carried out in accordance with the extension/expansions policy of AGLGN as approved by IPART.  There is no scope for revenue earned on the transmission pipeline to be used to help fund distribution expansions.  
In addition, with AGL’s transfer of the CWP to the APT, which it only partly owns, there is no longer common ownership of the CWP and the associated distribution network.  Regardless of the regulatory system, it would appear inappropriate for the APT to transfer part of its revenues to AGLGN.  The Commission will not require a levy on the transmission of gas on the CWP.
4.7	Review and expiry of the access arrangement 
4.7.1	Code requirements
Section 3.17 of the Code requires an access arrangement to include a date upon which the service provider must submit to the regulator a revised access arrangement (revisions submission date) and a date upon which the revisions are intended to commence (revisions commencement date).  
The regulator’s assessment of the appropriateness of the two dates set under section 3.17 must include reference to the objectives contained in section 8.1 of the Code.  The regulator may require an amendment to the proposed access arrangement to include earlier or later dates and may also define a specific major event as a trigger which compels the service provider to submit revisions prior to the revisions submission date.
An access arrangement period accepted by the regulator may be of any duration.  However, if the period is greater than five years, the regulator must consider whether mechanisms should be included in the access arrangement to address the potential risk that forecasts, on which terms of the proposed access arrangement are based, subsequently prove to be incorrect (section 3.18 of the Code).  The Code provides the following examples of mechanisms for guidance: triggers for early submission of revisions based on the service provider’s profitability or the value of services reserved in contracts, or changes to the type or mix of services provided (section 3.18(a)); and the return of some or all revenue or profits in excess of a certain amount to users (section 3.18(b)).
Finally, it should be noted that the revisions commencement date is not a fixed date but is subject to variation by the regulator at the time at which it approves the revisions pursuant to section 2.48 of the Code.  This section states that: 
Subject to the Gas Pipelines Access Law, revisions to an Access Arrangement come into effect on the date specified by the Relevant Regulator in its decision to approve the revisions (which date must not be earlier than either a date 14 days after the day the decision was made or ... the Revisions Commencement Date).  
4.7.2	AGLP’s proposal
AGLP proposes to submit revisions to the access arrangement four years and six months after the commencement of this access arrangement, and that the revisions would commence either six months later, or on the date that the Commission’s approval takes effect, whichever is later.  Thus, the length of the initial access arrangement period would be five years or longer.  
4.7.3	Submissions by interested parties
Forcenergy contends that NSW gas demand could more than double between the year 2000 and the proposed end of the review period, and that a five year review period is not in the best interests of the general public.  Forcenergy considers that the Australian gas industry is going through a period of unprecedented change and it would not be appropriate in such a climate to set an access arrangement period as long as five years.  
Forcenergy has stated that it prefers incentive rate making over a strictly cost based approach, but is concerned about the difficulties involved in establishing a ‘baseline’ on which performance based rate making can be implemented. 
The establishment of tomorrows baseline from which to build incentives has become problematic even in America where there are many years of cost-recovery data, as prescribed by traditional rate of return cost of service principles applicable to regulated public utility firms.  To suggest that we have established a credible baseline in NSW for AGLP from which to enter into a five year performance based rate making formula is nonsense.  
Forcenergy considers it ‘totally unacceptable’ that AGLP has proposed no sharing of over recoveries or under recoveries with users, and contends that, if the Commission does accept a five year price path, there should a considerable sharing of benefits.  Forcenergy contends that operating costs are under AGLP’s control, but not demand growth and throughput volumes. 
It is our view that the upside for AGLP far exceeds the downside on a risk adjusted basis.  An elaborate performance based formula with the sharing of most of the benefits with facility users realised outside of an earnings ceiling for each year must exist.  Otherwise, material changes in variables such as throughput must trigger a new access arrangement.
The Commission’s Draft Decision proposed an amendment to include a trigger mechanism in the CWP access arrangement.  The trigger mechanism was to be based on AGLP exceeding its forecast volumes and revenues and required that on reaching a trigger event AGLP would be required to submit revisions to the access arrangement to the Commission.  
In response to this amendment (Proposed Amendment A3.6) AGLP stated that while it understands the purpose of the amendment, it considers: 
(i)	the required amendment does not provide for a symmetrical method of addressing errors in forecasting …
(ii)	the inclusion of this requirement is contrary to the spirit of incentive regulation being designed to remove during the term of the access arrangement the benefit of increased throughput …
(iii)	 in requiring the lodging of revisions to the access arrangement, the Commission is requiring that a new access arrangement approval process be undertaken if such revisions are lodged.  
AGLP subsequently proposed to replace the trigger mechanism in Proposed Amendment A3.6 with a revenue sharing mechanism.
4.7.4	Commission’s considerations
AGLP’s proposal for the revisions submission date is consistent with section 3.17 of the Code in that it includes a date upon which the service provider must submit revisions to the access arrangement and a date upon which those revisions are intended to commence.  
The Commission notes that the effect of AGLP’s proposal would be an initial access arrangement period of five years duration, and potentially longer if the Commission’s approval of revisions were to take effect later than six months after the revisions submissions date.  As noted earlier, the Commission has considered a more extended initial access arrangement period which would be up to five years longer than this, taking into consideration the objectives of section 8.1 pursuant to sections 3.18 and 3.19 of the Code. 
The Commission understands that these provisions of the Code are intended to safeguard against forecasting errors impacting on the terms and conditions of access over lengthy periods.  It has considered the principles underpinning sections 3.17 and 3.18 and the potential trigger mechanisms.  It has also noted Forcenergy’s position that insufficient information existed to support a duration as long as five years without implementation of a performance based revenue sharing mechanism.
Chapter 3 of this Final Decision noted that AGLP’s proposed NPV price path approach was likely to be susceptible to forecasting errors as it is dependent on an economic depreciation methodology which incorporates a number of forecasts, including throughput volumes.  Sections 3.17 and 3.18 of the Code can provide a mechanism to require AGLP to submit revisions where forecasting errors (or other specified events) are likely to result in detriment to users which may be inconsistent with the principles set out in section 8 of the Code.
The likely consequences of any forecasting errors by AGLP will depend on both the extent and the direction of the inaccuracies.  If throughput achieved only varies to a moderate extent from forecasts, the underpinning revenue and rate of return assumptions would remain appropriate.  
However, the forecasts on which the terms of the access arrangement were based and approved may prove substantially incorrect.  In this instance, continuation for the full course of the period may result in revenues being achieved by AGLP, and costs incurred by users, that are inconsistent with the ex-ante rate of return determined in chapter 2 of this Final Decision.
A service provider may choose to submit revisions in advance of the revisions submission date if forecasting errors prove to be substantially to its disadvantage.  However, it would be unlikely to voluntarily submit revisions early if forecasting errors proved to be to its advantage.  Accordingly, the Code provides that mechanisms may be included in an access arrangement in order to help protect users from incorrect forecasts and other ‘events’. 
Accordingly, the Draft Decision incorporated an amendment to require the access arrangement to include triggers for a review of the access arrangement.  The purpose of the amendment was to provide users with some benefit from AGLP’s potential out-performance while still providing an incentive for AGLP to outperform. 
An alternative to establishing a trigger to review the access arrangement is a mechanism which would require AGLP to return some or all revenue or profits in excess of a certain amount to users.  Forcenergy has suggested such a formula.  AGLP has also suggested a revenue sharing mechanism in response to the Draft Decision.  This approach has the ability to provide users with the benefits from ‘excess’ revenues quickly and avoids an assessment process of revisions to the access arrangement under section 2 of the Code.  
However, as noted in chapter 2, AGLP and other interested parties have raised concerns that the level of the return proposed by the Commission in the Draft Decision is not sufficient for the CWP, in particular, that the specific risk associated with the CWP has not been fully incorporated into the regulatory framework.  While it has been suggested that the Commission simply increase the level of the WACC for the CWP, the Commission is of the view that the integrity of the CAPM/WACC framework should remain intact.  The CAPM parameters outlined in chapter 2 of this Final Decision have been assessed and determined to be appropriate for the CWP and consistent with the well established CAPM theory. 
Accordingly, the Commission has sought an alternative approach that is able to accommodate the specific situation of the CWP.  The Commission has decided that the most appropriate approach would be to extend the initial access arrangement period from the proposed five years to ten years.  The Commission has considered the requirements of section 3.18 of the Code and has determined that no trigger or revenue sharing mechanism will be required.
The Code requires the Commission to have regard to the objectives in section 8.1 of the Code in determining the appropriate length of the access arrangement period.  Section 8.1 sets out general reference tariff principles.  In particular, the Commission considers that a ten year access arrangement period: 
•	provides a greater opportunity to recover a stream of revenue that covers efficient costs, particularly when determination of the duration of the access arrangement period is asymmetric in nature (section 8.1(a)); 
•	will not distort investment decisions (section 8.1(d)); and 
•	provides a significant incentive to AGLP to develop the natural gas market in the Central West and (potentially) the Central Ranges regions (section 8.1(f)). 
The extended access arrangement period provides AGLP with the opportunity to retain all ‘excess’ revenues obtained during that period.  The extent that AGLP is able to capture these returns is dependent on the probability that AGLP is able to outperform its forecasts and the extent of the out-performance.  
The Commission noted concerns in its Draft Decision about the likely accuracy of the forecasts provided by AGLP as part of its access arrangement which have been developed without the benefit of any substantial operational history.  It expects that observed performance will depart to some extent from these projections.  To the extent that a differential does occur, the present forecasts may be considered to be inaccurate.  However, if the forecast information presented to the Commission is unbiased the probability of the forecasts being above or below the actual performance will be equal.  
Similarly, the likelihood that AGLP can either underperform or outperform its forecasts would be equal.  To outperform and retain the resulting returns until the end of the ten year access arrangement period should provide AGLP with a substantial increase in the actual rate of return for the business.  To underperform and carry the result for the remainder of the period could be a significant burden to the business.  However, under section 2.28 of the Code, AGLP has the right to seek revisions to the access arrangement at any time during an access arrangement period.  In contrast, the Commission cannot initiate an early review.
Consequently, AGLP is able to seek to revise the access arrangement if it underperforms its projections.  If volumes are not up to the level forecast higher tariffs may be appropriate in order to achieve the rate of return set in this Final Decision.  However, if demand at that stage is forecast to continue for some time at lower levels than originally projected, increased tariffs might be expected to dampen demand further.  Alternatively, AGLP may seek  to revise the access arrangement to adjust forecast volumes in line with revised expectations.  A downward shift of the demand schedule would increase the level of under-recovered revenues.  AGLP could potentially capitalise a greater amount of under-recovered revenues for future recoupment should demand improve.  Accordingly, the Commission considers that it would be in the interests of AGLP to submit revisions to the forecast demand schedule under these conditions.  
The Commission has concluded that a ten year initial access arrangement period is appropriate for the CWP.  A potential duration of this length, combined with the asymmetry in the power to submit early revisions, results in the potential outcomes faced by AGLP being skewed in its favour.  This arrangement is intended to provide AGLP with the opportunity to earn greater returns than suggested by the ex-ante rate of return determined in chapter 2.  As discussed in that chapter, the extended period addresses the perceived specific risk associated with the CWP.  AGLP has agreed to an initial access arrangement period of approximately ten years.  Accordingly, an amendment to the access arrangement to this effect is required.
Amendment A4.7
In order for AGLP’s access arrangement for the Central West Pipeline to be approved, section 9.2 of the access arrangement must be amended such that the revisions submission date is 9 years and 6 months after the commencement of the access arrangement. 

5.	Information provision and performance indicators
5.1	Information provision
5.1.1	Code requirements
In conjunction with its proposed access arrangement, a service provider is required to submit access arrangement information.  This must contain sufficient information to enable users and prospective users, in the opinion of the regulator, to understand the derivation of the elements in the proposed access arrangement and to form an opinion as to compliance of the access arrangement with the provisions of the Code (section 2.6).  
Pursuant to section 2.7 of the Code, the access arrangement information provided may include any relevant information, but must at least contain the categories of information described in Attachment A to the Code, which is summarised in Box 5.1 below. 
Box 5.1:	Summary of Attachment A information
The information specified in Attachment A of the Code is divided into six categories:
Category 1: access and pricing principles
Tariff determination methodology; cost allocation approach; and incentive structures.
Category 2: capital costs
Asset values and valuation methodology; depreciation and asset life; committed capital works and planned capital investment (including justification for); rates of return for equity and debt; and debt/equity ratio assumed.
Category 3: operations and maintenance costs
Fixed versus variable; cost of services by others; cost allocation between, for example, pricing zones, and cost categories.
Category 4: overheads and marketing costs
Costs at corporate level; regulated versus unregulated; cost allocation between, for example, pricing zones, and categories of assets.
Category 5: system capacity and volume assumptions
Description of system capabilities; map of piping system; average and peak demand; existing and expected future volumes; system load profiles and customer numbers.
Category 6: key performance indicators
Indicators used to justify ‘reasonably incurred’ costs.
Under section 2.8 of the Code, information included in the access arrangement information may be categorised or aggregated to the extent necessary to ensure that disclosure of the information is not, in the opinion of the relevant regulator, unduly harmful to the legitimate business interests of the service provider, a user or prospective user.
If the regulator is not satisfied that the access arrangement information meets the requirements of the Code, it may, of its own volition, require the service provider to make changes to the access arrangement information.  Likewise, if requested to do so by any person, the relevant regulator must review the adequacy of the access arrangement information.  However, the relevant regulator must not require access arrangement information to be released which, in the regulator’s opinion, could be unduly harmful to the legitimate business interests of the service provider or a user or prospective user (section 2.9).
If the relevant regulator requires the service provider to change the access arrangement information, it must specify the reasons for its decision and allow the service provider a reasonable time to make the changes and resubmit the access arrangement information.
This chapter relates specifically to access arrangement information, which is provided for the use of users and prospective users.  However, it is important to note that the regulator also has much wider information gathering powers under the GPAL.  If the regulator has reason to believe that a person has information or a document that may assist the regulator in the performance of any of the regulator’s prescribed duties under the GPAL, the regulator may require that person to provide the information or a copy of the document to it.  Section 2.8 of the Code states that nothing in that section limits the regulator’s power under GPAL to obtain information, including information in an uncategorised or unaggregated form.  Both the Code and the GPAL place limitations on the discretion of the regulator to disclose information received that has been identified to be of a ‘confidential or commercially sensitive nature’. 
5.1.2	AGLP’s proposal
AGLP submitted access arrangement information in conjunction with the access arrangement on 31 December 1998.  
In response to a request by the Commission pursuant to section 2.9(a) of the Code, AGLP submitted revised access arrangement information on 8 February 1999, and a further amended version on 12 February 1999.  AGLP submitted supplementary access arrangement information on 25 June 1999 in response to concerns about the adequacy of the access arrangement information.  
The Commission has provided copies of these documents available to the Code Registrar (pursuant to section 7.9(a)(ii) of the code and made them available to interested parties (including from the Commission’s website).  Details have been included, where appropriate, in its Issues Paper, Draft Decision and this Final Decision.
5.1.3	Submissions by interested parties
Forcenergy and BHPP raised concerns about the adequacy of access arrangement information provided by AGLP.  Forcenergy contended that ‘information disclosure is a chronic problem with AGLP’.  Forcenergy did not provide support for this comment.
On 25 March 1999 BHPP lodged a formal request under section 2.9(b) of the Code that the Commission consider whether in its view the access arrangement information met the requirements of the Code.  As part of this request, BHPP raised a number of specific comments and concerns, including:  
Category 4: Information Regarding Overheads and Marketing Costs
- Total service provider costs at corporate level.
AGLP has not complied. AGLP should provide total costs at an AGL Group level, the proportion allocated to AGLP and the basis of that allocation. The split of Administrative & General and Marketing costs between the regulated and unregulated activities of AGL should receive specific attention. 
… BHP submits that the information provided by AGLP in their AA, AAI and RAAI does not enable a user to form an opinion as to compliance with the Code and to understand the derivation of the elements of the Access Arrangements. We believe the following information should be supplied:
1.	A single zonal tariff is proposed, and a rationale for this has been put forward, together with volume forecasts for each city gate.  A break out of the incremental costs (capital, operating) of servicing each of these city gates is requested to assist in assessment of the inefficiencies of a single zonal pricing model.
2.	The calculation to derive DORC from ORC should be detailed, together with the calculations for the proposed ‘fixed principle’ amount.
3.	Further information should be provided to substantiate the proposed write-up of value of the pipeline after 5 years operation.  The volume forecasts show growth to be plateauing at a level that could not support the initial capital value, far less a written-up value. In a competitive market, that would be a signal for an asset write-down to a supportable level.  Clearly, in putting forward the write-up proposal, AGLP must be relying on information which has not yet been disclosed, and this information should be provided.
4.	The Code requires that prices are set on the basis of efficient costs (clause 8.37). A significant proportion of the claimed costs are for services purchased within the AGL group. AGLP should confirm that it has disclosed all related party transactions and provide details of the nature and quantity [of] services that have been purchased or sold and the counter party to these transactions. The costs should be separated by service.
Sufficient information should be provided to enable an audit to be conducted to ensure these transactions are on an arms-length, open market basis.
Once sufficient information has been provided by AGLP, users and prospective users will be able to make an informed assessment as to whether the proposed AA complies with the Code.  
Following the release of the Draft Decision, BHPP stated that it remained concerned about the provision of information regarding related party transactions.  In particular, it suggested that the confidential information provided to the Commission regarding AGL Group costs (for operations and maintenance expenditure) be disclosed.  BHPP submits that any concern the Commission holds regarding contracting out and its effect on reducing the transparency of the pipeline’s operations could be addressed by disclosing the AGL Group costs.  
5.1.4	Commission’s considerations
Following receipt of AGLP’s access arrangement and access arrangement information on 31 December 1998, the Commission assessed the access arrangement information for compliance with the requirements of sections 2.6 and 2.7 of the Code.  Pursuant to section 2.9(a) of the Code, the Commission determined that the access arrangement information did not satisfy those requirements, and decided to require AGLP to make changes accordingly.  On 29 January 1999 the Commission requested that AGLP provide additional access arrangement information relating to Categories 2 to 6 of Attachment A to the Code.
The Commission gave the following reasons for requiring changes to the access arrangement information: 
(i)	the Commission is of the opinion that the access arrangement information would not enable users and prospective users to understand the derivation of the elements of the proposed access arrangement or to form an opinion as to the compliance of the access arrangement with the provisions of the Code, as required pursuant to section 2.6; and
(ii)	the access arrangement information does not include all the categories of information described in Attachment A of the Code, as required pursuant to section 2.7. 
AGLP submitted revised access arrangement information on 8 February 1999, and a further amended version on 12 February 1999.  The Commission considered this information pursuant to section 2.9(a) and, following BHPP’s request, section 2.9(b).  In response to the Commission’s continued concerns about the adequacy of the access arrangement information, AGLP voluntarily submitted supplementary access arrangement information on 25 June 1999.  
BHPP’s request under section 2.9(b) of the Code required the Commission to consider whether the combined set of access arrangement information was adequate and the requirements of sections 2.6 and 2.7 had been satisfied, and whether to require the service provider to make changes to the access arrangement information.
The Commission assessed the information provided by AGLP in its entirety and concluded that the original access arrangement information, together with all the additional information submitted, satisfied the requirements of the Code with respect to the proposed access arrangement as it stood at that time.  No further section 2.9(b) request has been made in regard to the CWP access arrangement information. 
The Commission has considered whether to release cost information relating to AGL Group activities carried out on behalf of AGLP.  The Commission has assessed the information provided to it on a confidential basis and is satisfied the level of costs is appropriate.  The Commission is also of the opinion that further disclosure is not warranted in this instance.  
Changes to AGLP’s proposed access arrangement specified in this Final Decision will result in a need for further revisions to the access arrangement information.  The Commission will assess the revised access arrangement information before making a decision on whether it will approve the revised access arrangement.
5.2	Key performance indicators
5.2.1	Code requirements
The Code identifies the need for KPIs to be disclosed by service providers to interested parties.  Category 6 of Attachment A of the Code lists the following relevant items:
•	industry KPIs used by the service provider to justify ‘reasonably incurred’ costs; and
•	service provider’s KPIs for each pricing zone, service or category of asset.
In addition, section 8.6 of the Code allows the regulator to ‘have regard to any financial and operational performance indicators it considers relevant in order to determine the level of costs within the range of feasible outcomes under section 8.4 that is most consistent with the objectives contained in section 8.1.’  The regulator must then identify the indicators and provide an explanation of how they have been taken into account (section 8.7 of the Code).
5.2.2	AGLP’s proposal
AGLP identifies a number of limitations on the usefulness of publicly available information relating to the performance of the Australian natural gas transmission industry.  AGLP notes that much of the information that is in the public domain relates to publicly owned pipelines prior to their privatisation, and that private companies have declined to release performance indicators on the basis of commercial sensitivity and restrictions on disclosure.  AGLP also notes the heterogeneity of transmission pipelines (due to differences in factors such as diameter, length, geography and topography of location, and operational characteristics) which can make comparisons difficult.  In particular, AGLP suggests it may be necessary and difficult to adjust for these differences in order to make comparisons meaningful.
Nonetheless, AGLP recognises the need for the regulator to benchmark performance and has provided a number of measures which it considers will contribute to the development of meaningful industry performance measures over time.  
Capital efficiency
AGLP notes the relative importance of capital related expenses which it states represent 80-90 per cent of annual accounting costs, and has provided a comparison of pipeline capital costs, shown below in Table 5.1.
Table 5.1:	Comparison of pipeline capital costs 
Pipeline	Operator	When 
Constructed	Length
(km)	Diameter
(mm)(a)	Unit Cost
$/mm/km	
Mereenie to Alice Springs	NT Gas	1985	270	200	730	
Young to Lithgow	EAPL	1987	212	150	1115	
Carnarvon Lateral	Epic Energy	1988	171	150	719	
Whyalla Lateral	Epic Energy	1989	  71	200	1212	
Gladstone to Rockhampton	Duke Energy	1991	  96	200	957	
Junee to Griffith	EAPL	1993	170	150	805	
Marsden to Dubbo	AGLP	1998	130(b)	200(b)	620(d)	
			125(c)	150(c)		
Source:	Revised Access Arrangement Information, p. 28.  The data were sourced from a paper ‘Australian Transmission Pipeline Costs’ by Philip Venton of Venton and Associates, presented at the 1998 APIA Convention.
Notes:	(a)	Outside diameter used in analysis.
	(b)	Marsden to Alectown.
	(c)	Alectown to Dubbo. 
	(d)	Applicable for Marsden to Dubbo. 

AGLP states that the comparison lists those Australian pipelines not dissimilar to the CWP in length and diameter and expresses the capital cost on a $/mm/km basis which it describes as an industry accepted measure of pipeline installation cost efficiency.  ALGP states that throughput related measures (such as $/GJ or $/GJ/km) provide poor measures of efficiency as they do not take into account differences due to factors such as the level of utilisation and load factor of a pipeline, or economies of scale for different sized pipelines.  It contends that the derived unit cost figures suggest that capital applied to the construction of the CWP has been utilised efficiently.  
Operating costs
AGLP’s total operating costs for the year ending 30 June 1999 are estimated to be $723 500.  Based on AGL Group’s ‘ … experience as a major owner and operator of transmission pipelines in Australia’, AGLP estimates that operation of the CWP on a stand-alone basis would require approximately ten employees and the use of various facilities and services which would result in an annual budget in excess of $1.2 million. 
AGLP also provided some analysis based on comparisons with:
•	estimated operating costs ($/1 000 km) of other Australian pipelines;
•	estimated operating costs ($US/1 000 km) of US pipelines; and
•	estimated operating costs ($ million) of the Victorian transmission system operated by TPA (now owned by GPU GasNet), after various adjustments.
While AGLP acknowledges that allowances have to be made for factors such as pipeline size and the use of compression, it concludes that the comparisons indicate that total operating costs for the CWP are efficient.
5.2.3	Submissions by interested parties 
No comments were received from interested parties regarding KPIs.  As noted in chapter 3 of this Final Decision, BHPP agrees with the Commission that financial indicators are of little value in relation to the CWP at present.  
5.2.4	Commission’s considerations
The Commission noted in its Victorian Final Decision the challenges in identifying KPIs and benchmarks especially in a newly deregulated commercial environment such as the Victorian natural gas industry.  At that stage the Commission stated its intention to work closely with the Victorian service providers to establish appropriate KPIs but that, in the short to medium term, it would have regard to financial performance indicators pursuant to section 8.6 of the Victorian Code.  The Commission also considered the use of benchmarks such as load factor and energy delivered per employee (which are set out by the Steering Committee on National Performance Monitoring of Government Trading Enterprises) as a basis for developing non-financial indicators for TPA.  
Similar difficulties apply in identifying KPIs and benchmarks for a new pipeline such as the CWP where only the installation capital cost is known.  All other parameters that might feed into performance indicators are at this stage estimates.  
In particular, the degree of accuracy of the throughput projections that underpin revenue forecasts will not be known for some time.  The impact of the throughput projections on performance measures is highlighted in section 3.5 of this Final Decision.  Based on AGLP’s projections, non-capital costs per GJ for the CWP have been estimated to fall from $2.62 in 1998-1999 to $0.58/GJ in 2003-2004.  As projected costs are escalated by the forecast inflation rate over time, the significant drop solely reflects the growth in gas volumes that is anticipated by AGLP.  
In addition, arrangements whereby AGLP has contracted operational activities out to EAPO and to companies in the AGL Group raise particular difficulties when considering use of some of the benchmarks mentioned above.  As AGLP has no employees, ‘per employee’ measures are not directly available.  Further, to the extent that these contracted entities are primarily engaged in activities unrelated to the CWP, there may be factors such as economies of scale and of scope that blur comparisons with pipelines that would on face value appear to be reasonably comparable with the CWP (for example, stand-alone pipelines of similar diameter and length).
The Commission also recognises the limitations of KPI information noted by AGLP.  Nonetheless, it welcomes AGLP’s contribution to the available body of benchmarking information, and notes that, based on the information provided by AGLP regarding capital costs and operating costs that the CWP’s performance over the long term appears to be reasonable in these areas given the framework proposed by AGLP.  
In assessing the proposed access arrangement, the Commission has not considered financial performance indicators in terms of section 8.6 of the Code.  The CWP is a newly established pipeline without significant foundation contracts, and is projected to under-recover revenues during the initial access arrangement period.  AGLP’s access arrangement methodology is designed to allow it the opportunity to recoup these revenues later in the life of the CWP and so recover the efficient costs of delivering the reference service over the total effective life of the assets.  As most financial performance indicators derived from projected performance are very sensitive to the throughput projections, they would provide results over the initial access arrangement period which are of little meaning and ‘unsatisfactory’ when considered in isolation.  Considered solely over periods late in the life of the CWP, these financial performance indicators would indicate ‘superior’ performance.
Further discussion on the Commission’s views regarding the use of financial indicator analysis is included in its May 1999 Draft Regulatory Principles.

6.	Final decision
Pursuant to section 2.16(b) of the Code, the Commission has decided to not approve AGLP’s access arrangement for the Central West Pipeline in its present form.  This Final Decision states the amendments (or nature of amendments, as appropriate) which would have to be made in order for the Commission to approve the proposed access arrangement.  A revised access arrangement must be submitted to the Commission on or before 31 July 2000.

Appendix A:	Submissions from interested parties
The following parties made submissions in relation to the access arrangement:
Pre Draft Decision
BHP Petroleum Pty Ltd, 25 March 1999
Dubbo City Council, 4 March 1999 
Esso Australia Ltd, 4 March 1999 
Forcenergy Australia Pty Ltd, 19 March 1999
Mudgee Region Business Enterprise Centre Inc., 5 March 1999 
NSW Department of Energy, 24 March 1999 
Post Draft Decision
Australian Gas Light Company, 19 October 1999 (2 submissions)
Australian Pipeline Industry Association and Australian Gas Association, 15 October 1999
BHP Petroleum Pty Ltd, 25 October 1999 and 20 April 2000
Central Economic Zone Inc, (received) 21 October 1999
Central Ranges Natural Gas Working Group, 25 October 1999
Institute of Public Affairs, 3 February 2000
Interstate Energy, 15 October 1999
Tony Kelly MLC, 17 November 1999
Mudgee Region Business Enterprise Centre Inc., 19 October 1999 
Mudgee Shire Council, 28 October 1999
Narromine Shire Council, 27 September 1999 and 8 October 1999
Orana Development and Employment Council, 5 October 1999 and 26 October 1999
Parry Shire Council, 29 October 1999
Harry Woods MP, 23 November 1999

Appendix B:	Pre-tax and post-tax WACCs in a NPV regulatory framework
In a NPV framework access prices are set according to a rule which recovers expected costs in NPV terms over the life of the asset.  The advantage of the approach is that revenues do not have to recover the expected cost of service in every period as required in some other approaches.  It is particularly useful for new infrastructure assets like the CWP where the initial level of business is insufficient to recover estimated costs at tariffs that are sustainable in the market place.  In this situation shortfalls in revenue are compensated for, in NPV terms, by over-recovery of costs in later years.  
The discount rate for assessing whether the revenues cover costs in NPV terms is the WACC.  The WACC in question must be relevant to the cash flows being assessed.  AGLP proposed the use of a pre-tax real WACC based on pre-tax real cash flows.  Of course, other rate of return measures can be used to give equivalent outcomes.  In the case of the NPV proposal, the profile of tariffs over time is determined by the CPI outcomes and the X factor which together determine the CPI-X adjustments.  Hence, it does not matter which cash flows are focused on provided the appropriate rate of return (WACC) is applied.  All equivalent rate of return measures will give identical outcomes.  
The Commission has strong reservations over the derivation of the pre-tax real WACC based on a formula approach as used by AGLP.  Instead, the Commission favours a post-tax WACC approach which utilises the post-tax rate of return directly from CAPM benchmarking without the need for a conversion formula.  Compensation for tax liabilities of the service provider (net of the value of imputed credits) is determined on the basis of cash flow assessments.  
If a pre-tax real WACC is used the Commission considers that it should be based on cash flow analysis to ensure consistency with the CAPM benchmark post-tax returns.  In the NPV framework as proposed, this only requires the Commission to focus on the post-tax nominal cost of equity cash flows.  As noted already, the pre-tax and post-tax frameworks converge to give the same outcome.  Thus, the use of a pre-tax real WACC or a post-tax nominal WACC is a matter of reporting the outcome. 
The convergence of outcomes is not very surprising given that the tariff profile is determined by a CPI-X mechanism and cash flows that give the desired nominal post-tax cost of equity (from the CAPM) are precisely those that give the equivalent pre-tax real WACC.  In the analysis the post-tax nominal cost of equity is the internal rate of return associated with net cash flows to equity holders and the pre-tax WACC is the internal rate of return for cash flows associated with the assets as a whole.  
The analysis is somewhat cumbersome to illustrate for the CWP over its 80 year life.  The Commission is also mindful that AGLP views elements of the 80 year model as confidential and commercially sensitive.  Accordingly, the Commission has constructed an example for a single 20 year life asset based on a similar framework to aid interested parties’ understanding of a NPV framework.  
Assumptions of an illustrative NPV model showing pre-tax and post-tax cash flows
General		
cost of pipeline	$20 million	
life of pipeline	20 years	
tax life of asset	10 years, straight line depreciation	
initial tariffs	$2.40/GJ (year 1), $2.60/GJ (year 2), $2.80/GJ (year 3)	
	from year 4 tariff adjusted by a CPI-X mechanism using CPIt/(CPIt-1)(1-X)	
expected volumes	250TJ/year, increasing by 250TJ each year (years 1-4)	
	from year 5 volumes increase by 10% per year to year 9 then level off 	
inflation	2.84% pa 	

CAPM		
nominal risk free rate	6.38%	
equity beta	1.50	
market risk premium	6.0%	
nominal cost of debt	7.58%	
debt as a percentage of asset value	60%	
utilisation of imputation credits	50%	
post-tax nominal cost of equity	15.36%	

Cash flows shown in Table B.1 are the end result of the spreadsheet calculations.  These calculations are performed using the spreadsheet solver facility.  That is, the X factor is adjusted so that the post-tax nominal cost of equity (as measured by the internal rate of return) equates to the 15.36 per cent that has been calculated from the CAPM.  
Points to note
1.	In this example, the cash flows reveal that the post-tax cost of equity (including the value of utilised imputation credits) of 15.36 per cent is equivalent to a pre-tax real WACC of 8.09 per cent.  This contrasts with a pre-tax real WACC of between 8.7 and 8.9 per cent which would have been obtained using the conversion formulae typically proposed by service providers.  This difference illustrates the magnitude of the error implied in relying on the formula approach and reinforces the Commissions view that the conversion formulae are unreliable.
2.	The pre-tax nominal cost of equity is 16.02 per cent, while the post-tax nominal cost of equity (excluding the value of imputation credits) is 15.36 per cent.  This indicates an effective tax rate of 8.0 per cent.  
3.	It is only by year eight that revenues ($4 692) exceed the cost of service (the return on capital and operation and maintenance costs) and a positive contribution can be attributed to economic depreciation ($414).  The shortfalls in revenue for years one to seven are reflected in negative economic depreciation which had added to the value of the asset base up until year eight.  
4.	The X is adjusted so that the value of the asset is depreciated to zero by the end of its economic life.  In this example X was calculated to be 0.10 per cent.  Hence, the tariffs will fall in real terms but will be observed to rise in nominal terms if inflation outcomes average above 0.10 per cent per year. 
5.	Table B.2 illustrates the assessment of the pre-payments of tax.  The calculations summarised in Table B.2 show that the value to the business at the end of the first access arrangement period (of ten years) of tax pre-payments is $1 763.  Following the earlier discussion in section 2.4.11, this needs to be accounted for when considering the next access arrangement period.  Within the context of a continuing pre-tax framework it provides the starting point for further accumulation of net tax pre-payments.  Or more generally, it indicates the amount the initial asset base should be reduced by relative to the regulatory asset base (RAB) from the pre-tax framework for the second access arrangement period. 
In the present access arrangement, AGLP has sought that the residual value of the asset base applying economic depreciation should reflect the value of the regulatory asset base going into the second access arrangement period.  However, this value does not incorporate the temporary return of capital represented by the pre-payments of tax and to this extent overstates the true economic depreciated residual value.  To better reflect the intended compensation to AGLP the Commission considers that the residual value of the asset should be reduced by the amount equal to the assessed value of the accumulated pre-payments of tax as at the end of the first access arrangement period.  The example in Table B.2 gives a modified residual value of $25 937 (that is, the pre-tax residual of $27 700 less net pre-payments inclusive of the return of $1 763) to be used as the starting regulatory asset value going into the next access arrangement period.
As expected, this is precisely the residual value that is obtained using a post-tax underlying framework within a NPV approach based on the same regulatory assumptions. 

Table B.1:	Illustrative model - NPV cash flows ($ 000)
Period			IRR (%)	0	1	2	3	4	5	6	7	8	9	10	11	12	13	14	15	16	17	18	19	20	
Consumer Price Index (assumed) 				1.000 	1.028 	1.058 	1.088 	1.119 	1.150 	1.183 	1.217 	1.251 	1.287 	1.323 	1.361 	1.399 	1.439 	1.480 	1.522 	1.565 	1.610 	1.655 	1.702 	1.751 	
																									
REVENUE CALCULATION																									
Gas volume throughput (TJ pa)					250	500	750	1,000	1,100	1,210	1,331	1,464	1,611	1,611	1,611	1,611	1,611	1,611	1,611	1,611	1,611	1,611	1,611	1,611	
Tariff ($ per GJ throughput) 					2.400	2.600	2.800	2.877	2.955	3.036	3.119	3.205	3.293	3.383	3.475	3.570	3.668	3.768	3.872	3.978	4.086	4.198	4.313	4.431	
Revenue (tariff x volume) 					600	1,300	2,100	2,877	3,251	3,674	4,152	4,692	5,303	5,448	5,597	5,750	5,907	6,069	6,235	6,406	6,581	6,761	6,947	7,137	
																									
TAXABLE INCOME AND TAX CALCULATION																									
Revenue (nominal) 					600	1,300	2,100	2,877	3,251	3,674	4,152	4,692	5,303	5,448	5,597	5,750	5,907	6,069	6,235	6,406	6,581	6,761	6,947	7,137	
	less O&M costs 					(1,000)	(1,028)	(1,058)	(1,088)	(1,119)	(1,150)	(1,183)	(1,217)	(1,251)	(1,287)	(1,323)	(1,361)	(1,399)	(1,439)	(1,480)	(1,522)	(1,565)	(1,610)	(1,655)	(1,702)	
	less interest paid 					(909)	(1,025)	(1,122)	(1,194)	(1,241)	(1,277)	(1,298)	(1,302)	(1,283)	(1,236)	(1,179)	(1,111)	(1,030)	(935)	(850)	(751)	(638)	(508)	(359)	(191)	
	less tax depreciation 					(2,000)	(2,000)	(2,000)	(2,000)	(2,000)	(2,000)	(2,000)	(2,000)	(2,000)	(2,000)	-	-	-	-	-	-	-	-	-	-	
Taxable profit (loss) 					(3,309)	(2,753)	(2,080)	(1,405)	(1,108)	(753)	(329)	173	768	925	3,094	3,278	3,478	3,695	3,905	4,133	4,378	4,644	4,932	5,243	
Accumulated tax loss 					(3,309)	(6,062)	(8,142)	(9,547)	(10,656)	(11,409)	(11,738)	(11,565)	(10,797)	(9,872)	(6,777)	(3,499)	(21)	-	-	-	-	-	-	-	
Tax payable at corporate 
rate of 30% 					-	-	-	-	-	-	-	-	-	-	-	-	-	1,102	1,172	1,240	1,314	1,393	1,480	1,573	
Asset value (start of period) 					20,000	22,538	24,676	26,272	27,292	28,077	28,555	28,639	28,225	27,191											
Pre-tax revenue premium 0.433%					87	98	107	114	118	122	124	124	122	118											
																									
CASH FLOW TO ASSETS																								
Revenue (nominal)				600	1,300	2,100	2,877	3,251	3,674	4,152	4,692	5,303	5,448	5,597	5,750	5,907	6,069	6,235	6,406	6,581	6,761	6,947	7,137	
	less O&M costs				(1,000)	(1,028)	(1,058)	(1,088)	(1,119)	(1,150)	(1,183)	(1,217)	(1,251)	(1,287)	(1,323)	(1,361)	(1,399)	(1,439)	(1,480)	(1,522)	(1,565)	(1,610)	(1,655)	(1,702)	
	less capital expenditure			(20,000)	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	
Pre-tax nominal cash flow to assets		11.10 (a)	(20,000)	(400)	272	1,042	1,789	2,132	2,524	2,969	3,476	4,052	4,161	4,274	4,389	4,508	4,630	4,755	4,884	5,016	5,152	5,291	5,434	
	less estimated tax payment				-	-	-	-	-	-	-	-	-	-	-	-	-	(1,102)	(1,172)	(1,240)	(1,314)	(1,393)	(1,480)	(1,573)	
Post-tax nominal cash flow to assets		10.24	(20,000)	(400)	272	1,042	1,789	2,132	2,524	2,969	3,476	4,052	4,161	4,274	4,389	4,508	3,528	3,584	3,644	3,703	3,759	3,812	3,861	

Table B.1:	Illustrative model - NPV cash flows ($ 000) (cont.)
Period		IRR (%)	0	1	2	3	4	5	6	7	8	9	10	11	12	13	14	15	16	17	18	19	20	
																								
CASH FLOW TO DEBT																								
Interest paid				909	1,025	1,122	1,194	1,241	1,277	1,298	1,302	1,283	1,236	1,179	1,111	1,030	935	850	751	638	508	359	191	
	less increase in debt			(12,000)	(1,523)	(1,283)	(957)	(612)	(471)	(287)	(50)	248	620	752	900	1,066	1,251	1,128	1,303	1,498	1,716	1,957	2,224	2,519	
Net cash flow to debt		7.58 (b)	(12,000)	(614)	(258)	164	583	770	990	1,248	1,550	1,904	1,989	2,080	2,177	2,282	2,063	2,152	2,250	2,354	2,465	2,583	2,710	
																								
CASH FLOW TO EQUITY (cash flow to assets less cash flow to debt)																								
Net cash flow to equity 
(pre tax)		16.02 (c)	(8,000)	214	530	878	1,206	1,363	1,534	1,721	1,925	2,148	2,172	2,194	2,212	2,227	2,567	2,603	2,634	2,662	2,687	2,708	2,724	
	less tax payable				-	-	-	-	-	-	-	-	-	-	-	-	-	(1,102)	(1,172)	(1,240)	(1,314)	(1,393)	(1,480)	(1,573)	
Net cash flow to equity (post tax, w/o imputation credits)		14.61	(8,000)	214	530	878	1,206	1,363	1,534	1,721	1,925	2,148	2,172	2,194	2,212	2,227	1,465	1,431	1,394	1,349	1,294	1,228	1,151	
	plus value of imputation credits				-	-	-	-	-	-	-	-	-	-	-	-	-	551	586	620	657	697	740	
Net cash flow to equity 
(post tax)		15.36 (d)	(8,000)	214	530	878	1,206	1,363	1,534	1,721	1,925	2,148	2,172	2,194	2,212	2,227	2,016	2,017	2,014	2,006	1,991	1,968	1,938	
Regulatory asset value 
(at end of period)		20,000	22,538	24,676	26,272	27,292	28,077	28,555	28,639	28,225	27,191	25,937	24,436	22,660	20,574	18,695	16,524	14,026	11,166	7,905	4,199	0	
Economic depreciation			-	(2,538)	(2,138)	(1,596)	(1,020)	(785)	(478)	(84)	414	1,034	1,254	1,501	1,777	2,086	1,879	2,171	2,497	2,860	3,261	3,706	4,199	
Pre-tax real cash flow to assets		8.09 (e)	(20,000)	(389)	257	958	1,599	1,854	2,133	2,440	2,778	3,149	3,145	3,141	3,137	3,132	3,128	3,124	3,120	3,116	3,112	3,108	3,104	
Notes:	(a) Forecast pre-tax nominal WACC	(c) Forecast pre-tax nominal cost of equity		(e) Forecast pre-tax real WACC
(b) Forecast nominal cost of debt		(d) Forecast post-tax nominal cost of equity

Table B.2:	Illustrative model - Assessment of tax payments, the values of pre-payments and the residual value of the asset base ($ 000)
Period			0	1	2	3	4	5	6	7	8	9	10	11	12	13	14	15	16	17	18	19	20	
Revenue				600	1300	2100	2877	3251	3674	4152	4692	5303	5448	5597	5750	5907	6069	6235	6406	6581	6761	6947	7137	
Less: Tax related expenses																								
	tax depreciation				-2000	-2000	-2000	-2000	-2000	-2000	-2000	-2000	-2000	-2000	0	0	0	0	0	0	0	0	0	0	
	interest paid				-909	-1025	-1122	-1194	-1241	-1277	-1298	-1302	-1283	-1236	-1179	-1111	-1030	-935	-850	-751	-638	-508	-359	-191	
	O&M				-1000	-1028	-1058	-1088	-1119	-1150	-1183	-1217	-1251	-1287	-1323	-1361	-1399	-1439	-1480	-1522	-1565	-1610	-1655	-1702	
																								
Taxable income				-3309	-2753	-2080	-1405	-1108	-753	-329	173	768	925	3094	3278	3478	3695	3905	4133	4378	4644	4932	5243	
Tax loss carried forward				0	-3309	-6062	-8142	-9547	-10656	-11409	-11738	-11565	-10797	-9872	-6777	-3499	-21	0	0	0	0	0	0	
Assessable income				-3309	-6062	-8142	-9547	-10656	-11409	-11738	-11565	-10797	-9872	-6777	-3499	-21	3673	3905	4133	4378	4644	4932	5243	
Tax liability				0	0	0	0	0	0	0	0	0	0	0	0	0	1102	1172	1240	1314	1393	1480	1573	
																								
Regulatory Asset Value 				20000	22621	24861	26579	27741	28689	29351	29641	29457	28677	27700	26502	25055	23329	21289	18898	16113	12886	9165	4891	
Pre-payment of tax				83	93	103	110	115	118	121	122	122	118	114	109	103	96	88	78	67	53	38	20	
Cumulative pre-payment of tax				83	176	279	388	503	621	742	865	986	1105	1219	1329	1432	1528	1616	1694	1761	1814	1852	1872	
Cumulative pre-payments less tax payable augmented by ROR (1)				83	185	307	450	612	796	1002	1232	1485	1763	2065	2396	2755	2595	2374	2086	1719	1260	692	0	
RAB (pre-tax) (2)				20000	22621	24861	26579	27741	28689	29351	29641	29457	28677	27700	26502	25055	23329	21289	18898	16113	12886	9165	4891	
RAB (post-tax) (3)				20000	22538	24676	26272	27292	28077	28555	28639	28225	27191	25937	24436	22660	20574	18695	16524	14026	11166	7905	4199	
	difference (2) - (3) = (4)				0	83	185	307	450	612	796	1002	1232	1485	1763	2065	2396	2755	2595	2374	2086	1719	1260	692	
(1) - (4)					0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	

Appendix C:	Post-tax issues
Implications for pre-tax regulatory frameworks 
The regulatory framework proposed by AGLP for the CWP access arrangement is based on a pre-tax real rate of return.  Because the rate of return is pre-tax, it implicitly provides for an allowance in revenues to cover expected tax liabilities over the life of the asset.  As discussed in the Victorian Final Decision and the Commission’s Draft Regulatory Principles, the application of such a rate of return concept in the regulatory framework creates a number of problems.  
The first is how to convert from the post-tax nominal cost of equity benchmark provided by CAPM to an equivalent pre-tax real WACC.  The formula based method has been shown to be significantly in error.  However, a consistent pre-tax real WACC can be estimated by modelling expected cash flows and taxes over the life of the assets as was done in the case of this Final Decision and other earlier Commission decisions. 
The second problem is related to uncertainties in making long-run forecasts of future tax liabilities, which vary with actual inflation outcomes and changes in the tax regime.  The recent review of the tax system by the Ralph Committee has highlighted this uncertainty.  During the course of assessing the Victorian access arrangements a range of financial experts at a forum convened to discuss WACC issues unanimously agreed that this uncertainty could be avoided.  It was suggested that this uncertainty could be overcome by assessing revenue requirements on a post-tax basis and augmenting the revenues obtained by making reasonable estimates of likely tax liabilities for the regulatory period (of five years in that instance) rather than over the lifetime of the assets.  The focus on short-term forecasts significantly reduces uncertainty over likely tax liabilities and whether they are adequately compensated for in the revenues that are expected to be received by the service provider.
A third problem with a pre-tax regulatory framework has become known as the S-bend problem.  It arises because in the pre-tax approach the rate of return provides for a fixed proportion of the return on capital to provide compensation in the revenue stream for current and future tax liabilities.  However, because of a range of tax concessions such as accelerated depreciation there is generally very little tax payable early in the life of an asset, and tax liabilities increase significantly later in the life of the asset after such concessions have been fully utilised.  When graphed (see Figure C.1(b)) the profile of tax liabilities takes on the appearance of a flattened S shaped curve.  
Theoretically, this is less of a problem since the pre-tax return is intended to assume an effective tax rate over the life of the asset just sufficient to compensate the service provider for the net taxes that it has to pay.  The regulatory problem is a practical one as well as a political one.  The uncertainty over the long term tax forecasts already mentioned is one issue.  The second relates to the adequacy of cash flows to enable the service provider to sustain a level of investment adequate to maintain its level of service later in the life of the assets when tax liabilities greatly exceed the provision for them within, the then, current regulatory revenue.  The service provider has been, in principle, already compensated for those tax liabilities in earlier cash flows so it is inappropriate to ask users to pay extra to meet the cash flow needs of the service provider.  Nevertheless, there would be significant pressure for the regulator to concede to such a measure.  Thus, the post-tax approach suggested by the experts provides a ready solution since taxes are assessed on an ‘as you go basis’ and the service provider does not suffer tax liability uncertainty or potential shortfall.
A methodology based on post-tax returns and assessment of near term tax liabilities using cash flow analysis readily overcomes most of these regulatory difficulties linked to a pre-tax real framework.  Accordingly, it is the Commission’s preferred regulatory approach.  
What is the effective tax rate?
The difference between pre-tax and post-tax rates of return is defined by the effective tax rate (Te).  It is sensitive to a number of factors which include the corporate tax rate and the range of available tax concessions which serve to lessen tax liabilities or defer them to a later period.  Although the tax rate on assessed tax income is always at the corporate tax rate (T), in any year the income for tax purposes can be quite different from net revenues available to the business.  The timing aspect and the fact that taxes are assessed on the basis of nominal income means that the prevailing inflation rate also has a significant impact on the effective tax rate.  The effect that deferral of tax has on the timing of cash flows does not generally cause administrative difficulties for a corporate entity that is well accustomed to uneven cash flows.  Nevertheless, such deferrals of tax costs can have significant value for a business and its shareholders.  As such they affect the rate of post-tax return earned by the company and its owners.  By examining the prospective pre-tax cash flows it is a simple matter to calculate the expected pre-tax internal rate of return for those cash flows over the life of the asset.  Similarly, an examination of prospective cash flows net of tax reveals the expected post-tax internal rate of return.  It is this expected post-tax rate of return that the regulator seeks to provide to a service provider through the regulatory framework approved as part of an access arrangement.
The regulatory framework may be based on the pre-tax rate of return or post-tax rate of return but there is a strict requirement that if a pre-tax rate is used it must be fully consistent with the required post-tax rate.  It is the correct relationship between the two which defines the effective tax rate (Te).  
return(post-tax) = return(pre-tax) (1-Te)
It is important to distinguish the returns to equity capital from borrowed funding since only the business entity incurs a tax liability.  Hence the above relationship is only appropriate to the equity term within a WACC formula.  In the case of the return to equity holders, the focus of CAPM, the necessary return to equity holders is complicated by the value which needs to be attributed to imputation credits.  Thus the relation between the pre-tax cost of equity (rte) and post-tax cost of equity (re) is defined by: 
re = rte [ (1-Te) +  Te ]
In this formulation gamma () is defined as the rate of utilisation of imputation credits attached to dividends and available to shareholders by virtue of taxes paid by the service provider.  Their value in the hands of shareholders is equal to [re  Te].  
Transitional issues
While the Commission in the Draft Regulatory Principles has identified the post-tax cash flow based framework as the preferred regulatory approach there are a number of access arrangements in place and proposed which rely on a pre-tax framework.  This creates a potential difficulty in moving to a post-tax framework at a later stage.  The main difficulty arises from that component of revenues determined in a pre-tax framework which represent pre-payment of expected future tax liabilities.  These cannot be ignored since they represent a significant return (although temporary) of capital to the service provider.  After switching to a post-tax regime tax liabilities are allowed for in revenues on a progressive basis.  It would be inequitable to expect users to pay a second time for tax liabilities of the service provider.
The pre-payment of tax in a pre-tax framework is readily illustrated by reference to the stylised S-bend diagrams below in Figure C.1.  
Figure C.1(b) shows the average rate of tax payable relative to net economic income available to the service provider over time.  Usually, the initial average rate of tax is zero because of available tax concessions (particularly the tax debt shield provided by interest on borrowing in combination with accelerated depreciation).  But as such concessions are used up the assessed taxable income increases and tax becomes payable.  In the later life of the assets the average tax payable is likely to exceed the corporate tax rate since some economic costs (for example, depreciation) have been anticipated and deducted for tax purposes in previous years.  Figure C.1(b) also illustrates the relative magnitude of the corporate tax rate T and the effective tax rate (Te) that is looking forward from a point in time when assets are new.  It also shows how the effective tax rate increases based on an assessment looking forward from a time part-way through the assets’ lives and from a time in the later part of the assets lives when it can exceed the corporate tax rate T.
The achieved annual post-tax return on equity is illustrated in Figure C.1(c) with the lifetime post-tax cost of equity (re) relevant to the CAPM benchmark shown as a horizontal line.  Also shown are estimates of the expected return (on equity as reflected in the regulatory accounts) looking from part-way through the assets’ lives and again at a later period.  The reducing prospective return is a symptom of the S-bend phenomena.  
Figure C.1(d) indicates the market value of the business relative to its regulatory value.  Initially, the ratio is unity since the discounted value of the future revenues net of expenses of the business should equal the initial cost of the assets if a commercial rate of return is expected.  The market value subsequently falls away relative to the regulatory asset value since in later periods a portion of the revenues designed to compensate for future tax liabilities has already been received.  Hence, looking forward, the revenues will be inadequate to provide for tax liabilities as well as providing the expected commercial return on the regulatory asset base from that point on.  This deviation of the implicit market value of the business from its regulatory asset value sits uneasily in a regulatory framework and is another aspect of the S-bend problem.  
Figure C.1:	The impact of tax liabilities over time under a pre-tax regulatory framework and the S-bend issue

While the S-bend feature of the pre-tax real framework can be readily appreciated it is implicit in the regulatory compact that the service provider should understand that it receives pre-compensation for future tax liabilities.  Thus, it should not seek additional compensation at a later date when it considers its current prospective return to be inadequate due to its tax burden.  If all parties understand this, concern in respect of the S-bend problem should not emerge.  The pre-compensation for future taxes that needs to be taken into account when moving to a post-tax regime can be acknowledged (to the extent that there remains an amount of tax pre-compensation which has not yet been utilised).  The compensation for future tax liabilities in revenues needs to be reduced so that, by the end of the life of the asset, the compensation for tax liabilities allowed for in the revenue stream has exactly offset (in present value terms) the estimated impost of taxes.  
To assume that political pressure to increase the WACC to accommodate a service provider’s tax burden would not occur maybe somewhat optimistic.  Where there are mature existing assets service providers have vigorously argued that the assets should be notionally depreciated for tax purposes.  That is, available tax concessions should not be taken into account when determining the pre-tax rate of return which will achieve the desired post-tax return.  Ignoring these concessions leads to a higher pre-tax WACC estimate.  Such a stance displays a misunderstanding of what the pre-tax WACC actually is, namely a WACC that gives a post-tax return over the life of the asset and needs to be consistent with the effective tax rate over the life of the asset.  However, such a stance is reasonable if the service provider has not received pre-compensation for future tax liabilities in earlier revenues.  This is essentially an empirical question.  However, to the extent that past revenues were based on a cost recovery methodology which included a benchmark rate return on capital, akin to a pre-tax rate of return, there seems little justification for ignoring pre-payment for tax where a service provider is entering a formal regulatory framework where a pre-tax framework is being considered.  The situation can be resolved in one of two ways. 
The first solution is that the earlier pre-payments of tax can be assessed and treated as a return of capital (in the same way as a depreciation allowance).  This involves a reduction in the initial regulatory asset value by an amount corresponding to the net prepayment of tax liabilities.  This change in asset valuation is analogous to the difference in the market value of the business and the regulatory asset value as illustrated in Figure C.1(d) above.  This approach may be used whether the new regulatory framework is going to be post-tax or pre-tax.  By recognising the pre-payments of tax as a temporary return of capital the new framework can be adopted without the historical tax baggage.  This approach is essentially the well accepted ‘normalisation’ procedure adopted by US regulators.
The second solution will apply only when the new proposed framework uses a pre-tax rate of return.  It involves an assessment of what the pre-tax rate of return would be assuming that the existing assets were all new, that is valued at optimised replacement cost (ORC) and eligible for all existing tax concessions.  It is this pre-tax-rate-of-return which delivers the commercial rate of return over the life of the assets.  If a pre-tax WACC is assessed on the basis of the existing tax status of the assets then the service provider is being overcompensated and essentially receives a windfall gain equal to the net pre-payment of taxes it has already received.
An additional benefit of tracking the pre-payments of tax and estimated liabilities is that uncertainty over the future tax regime and other factors that impact on actual tax liabilities disappear.  This is because the revenue for tax compensation and past and expected tax liabilities can be assessed on a continuing basis so that there is no net over or under compensation over the long term.  Acceptance of the approach means that fairly substantial errors in tax forecasts can be accommodated and rectified at a later date.  This provides a good reason for adopting the first of the two options described above regardless of the proposed changes to the future regulatory framework.