Australias major pipeline systems
The Transmission Pipeline Perspective
The following article is an edited version of the paper presented by Jim McDonald, President of the Australian Pipeline Industry Association and Managing Director of the Australian Pipeline Trust, to the South East Asia Australia Offshore Conference held in Darwin on June 17th to 18th 2002.
Among Australia's good fortunes are our vast reserves of natural gas; reserves which should be accessible to businesses and communities across the nation, and delivered via a sophisticated, innovative market that promotes real choice between gas supplies and alternative energy sources.
A national strategy promoting natural gas usage, encouraging market and industry innovation, and resulting in the construction of a transnational pipeline grid and the development of a robust market for gas, would be a great legacy for our nation.
problem in 2002 is that natural gas is running out of time; a number of
problems have converged to create a situation that requires urgent policy
attention. These problems are:
There are a number of steps that need to be taken. There is a need to return to the original vision of competition reform and to implement true wellhead competition. The regulatory architecture and regulatory governance arrangements also need revamping.
Several major users of natural gas have achieved fairly significant reductions in the delivered price of gas since deregulation occurred. However, those reductions have not resulted from falls in wellhead prices other than in Western Australia. In NSW, price reductions came at the expense of domestic consumers through the unwinding of a government inspired cross subsidy in existence prior to deregulation, and some rationalisation of tariff structures in distribution piping.
There is now every indication that well head prices will continue to rise, not fall. Deregulation of the gas industry has not delivered seriously competitive well head pricing, quite the contrary.
The presence of the Interconnect, the Eastern Gas Pipeline, the pipeline from Geelong to Portland, the imminent pipeline from Portland to Adelaide, and a fresh supply of natural gas from the Timor Sea or PNG provide the opportunity for true gas on gas competition. Ironically, if upstream competition eventuates it will be the pipeline companies, having risked their capital in long term investments, that created the catalyst. We fight regulators, wellhead prices rise to accept the rent shift, and rise again.
The presence of Timor Sea and/or PNG gas in the Australian marketplace as truly competitive gas supplies would create a much more effective market with true supply side competition. In that scenario, the Australian Bureau of Agriculture and Resource Economics' (ABARE) forecasts that the country's natural gas demand would grow at an average annual compund rate of 3.4% over the period to 2020, making the resource Australia's fastest growing energy source, may well be realised, and natural gas would be priced to enable it to produce competitive electricity. Further, that pricing would enable it to extend its reach and, as a fuel of choice, be selected by a great number of consumers who would not make that choice if it was delivered at the same cost as electricity to their home, business or factory.
The supply competition that was the missing element in 1990 at the commencement of competition reform remains unaddressed in 2002.
Some have argued that the threat of natural gas supply from the Timor Sea or PNG has accelerated certain developments within the marketplace. Examples include new onshore and offshore fields: Otway, Minerva, and the acceleration of Yolla and Patricia-Baleen fields; the expediting of coal seam development and exploration; Bass Strait seismic work; and Santos' deep well technology.
These 'developments' are seen by some to mitigate the need for a transnational pipeline, and hence the need for a new injection of natural gas supplies into the southeastern Australian markets.
Such an injection would, of course, adversely affect the price of competing fuels, the viability of alternative supplies of natural gas such as coal seam methane, and the price of gas from existing onshore fields.
The incumbent producers of Australian natural gas have little interest in the price stability that would result in the marketplace following the arrival of any large new gas supplies. Indeed, their interest lies in supply shortfall, as shortfall will lead to increased prices for remaining reserves.
We argue for abundance and increased opportunity for competitively priced natural gas delivered to as many homes and commercial premises as possible, as a genuine fuel of choice.
Others argue for scarcity and prices rising towards something now being identified as the 'world price for gas'.
For advocates of a transnational pipeline, calls for more gas into the southeastern Australian markets are not purely based on threats of supply shortfalls. Again, such statements oversimplify the market dynamics. Calls for additional supplies to the market become another self-fulfilling prophecy because, if optimistic views of market demand are taken as correct, and pipelines are built on this basis, and contracts are signed to justify a risk capacity, then pipeliners will have an incentive to ensure that demand projections for natural gas are achieved. When connected, pricing for natural gas at the well head will come under pressure, and once large quantities of gas flow through, the system will see a downward price pressure, and price stability.
On the other hand, if additional gas supply is deemed unnecessary and transnational pipelines are not built, there will be upward pressure on gas prices. In this scenario the long term interests of consumers the heart of the reform agenda of the 1990s will not be met.
Today, an extensive pipeline network exists, spurred by private capital. Notable features of Australia's pipeline network include the connection of Victoria and New South Wales through the Interconnect and the Eastern Gas Pipeline. Two interfaces now exist in Queensland between the Surat and Cooper Basin fields, extensive mining operations at Mt Isa have access to natural gas, and the reach of gas has been extended to Gladstone and nearby cities. New South Wales in the 1990s saw gas extended to the central west region with a pipeline to Dubbo. Gas fired power is in its infancy, but alive and well in South Australia, Victoria, Queensland and the Northern Territory.
Tasmania is about to receive supplies of natural gas for the first time, and the Otway Basin is being developed. Adelaide is about to be connected to the Victorian system, and plans are on the table to connect Esperance, Albany and Telfer in Western Australia. More gas is planned for the Mt Newman mining operations and a pipeline to Gove in the Northern Territory, to replace existing high-sulphur fuel oil, is also planned.
A new vision is needed to support the systems' evolution into a national grid, and Australian politics has not seen a visionary focussed on Australia's energy future. We need a new champion in the government in 2002. We need a visionary with a 50-year horizon.
The Northern Territory government and its new Chief Minister, Clare Martin, are fighting to bring natural gas to shore in Darwin. The Chief Minister is lobbying the Federal Government to provide incentives to pipe the gas into the domestic market.
The question over the future of natural gas in Australia is one of political will. It is also a question that cannot be ignored and left for future governments.
The transmission industry needs to know that private sector construction of pipeline infrastructure is valued and supported by government, and that natural gas has an important part to play in the future of this country. We need a champion of our industry in government.
The market for natural gas needs price determination according to the competitive forces of supply and demand (but it needs more supply), and a return on investment proportionate to the risks taken.
Regulatory intervention must be balanced and occur only when market failure takes place. With proper direction, the market will evolve to deliver a range of innovative services and best practice supply, creating new sources of value for consumers, and the nation.
As an industry we look forward to the outcomes of the CoAG Energy Market Review in which we have every right to expect to see the development of a national energy strategy with natural gas ascribed a clear and increased role in Australia's energy future. In the meantime, the industry makes an undertaking to the Northern Territory and Queensland governments that we are doing everything possible to ensure that Timor gas is piped onshore and that PNG natural gas also reaches the Australian marketplace. One, if not both, of these pipelines must be supported to ensure that South Eastern Australian markets access secure, cost effective supplies of natural gas.
The full text of Jim McDonald's presentation is available at www.apia.net.au.
Australian pipeliner, Epic Energy, has repeated earlier calls by stakeholders in the natural gas industry to work together to develop a long term strategic focus to managing the country's energy future.
At Adelaide's APPEA Conference in April, Epic Energy Chief Executive Officer, Sue Ortenstone, said a long term focus needed to be adopted to ensure the appropriate levels of investment in infrastructure were being made to meet projected future energy demands.
"Infrastructure such as gas transmission pipelines and power generation plants do not just happen overnight - they generally take around three to five years in development", Ortenstone said. "This takes careful planning and some level of investment risk."
"As we have witnessed from the Californian energy crisis, it takes a long time to recover if the appropriate infrastructure systems aren't in place when they are required", she said.
Ms Ortenstone said the current regulatory environment is impacting on all segments of the gas chain, including the producers. "A lack of infrastructure investment means less options for producers to move gas to market, which impacts on market diversification, reduces competition and increases operational risk", she said.
While Epic Energy is committed to developing its plans for future growth in Australia, Ortenstone stressed it would continue to lobby for regulatory reform at both Federal and State levels and for a full review of the national energy policy.
Pipeliner Epic Energy remains in limbo over the pricing of gas transported through its Dampier to Bunbury Natural Gas Pipeline (DBNGP) after the full court of the Supreme Court reserved judgement as to whether a draft decision by WA's independent gas Regulator should be quashed.
Epic's troubles stem from ambiguities in the tariff pricing arrangements from when it purchased the pipeline from the Western Australian state government in 1998. Epic argues its purchase price of $2.407BB was based on tariffs of $1/GJ to Perth and $1.08/GJ south of Perth and maintains that although these figures were not made explicit in a written legal contract, a legal understanding, known as a regulatory compact, existed between the two parties.
When the independent regulator, Dr Ken Michael, took his position in February 1999, he revalued the pipeline and recommended operating tariffs vastly lower than those Epic said existed in the regulatory compact. The regulator's decision was based on a complicated but common economic model that considers elements including the initial capital base value of the pipeline, which is usually between the depreciated actual cost (DAC) and the depreciated optimised replacement cost (DORC). In his draft decision, issued in June 2001, the value of the pipeline was outlined as somewhere between $1BB (DAC) and $1.2BB (DORC), with transportation tariffs of 75c/GJ to Perth and 85c/GJ to the south of Perth.
The independent regulator, and his supporting office, OffGAR (the Office of the Gas Access Regulator), originated as a result of an inter-governmental agreement signed in 1997. The agreement was signed by each of Australia's states and territories in a bid to regulate Australia's pipelines in a particular way so as to encourage fair competition in the pipeline industry.
OffGAR requires pipeline owners to submit an access arrangement as an offer or contract to any party wishing to make use of the pipeline. As the only pipeline of its type in WA, OffGAR considered the DBNGP had a natural monopoly and, as such, fair and reasonable access to the infrastructure had to be made available.
OffGAR Executive Director, Peter Kolf, said that there is an obligation on parties to not just use the infrastructure for their own use, but to allow third parties to use it and to have access arrangements in place for these third parties.
Although the legislation was not enacted until a year after Epic purchased the pipeline, the intergovernment arrangement had been active from 1997 and Kolf said all bidders knew the legislation to introduce a regulator was on its way.
An official publication issued at the time of the pipeline sale, the Information Memorandum, contained information on the proposed regulation and, Kolf said, outlined that future regulation of the pipeline would be subject to national legislation and indicated what the likely regulatory value of the pipeline would be.
"At that stage there was uncertainty [as to the exact regulation arrangements] and that was acknowledged in the outset that the sale of the pipeline was done in uncertain times. Bidders were asked to exercise their commercial judgement", Kolf said. He added that potential buyers knew how regulation had been applied in other countries such as England and the USA.
Kolf said the formal position of the regulator in the draft decision was that they are unable to verify the existence of the regulatory compact or any similar understanding. "Submissions to the regulator by Colin Barnett and present government have indicated there was no understanding", he said.
The regulator has requested access to all sale information and is now looking at the bids. There will be a complete and comprehensive assessment to investigate what happened during the sale", Kolf said.
Epic claimed victory in the first round of the legal challenge over the proposed new transmission tariff regime when the Supreme Court ruled the company had an arguable case against the fegulator's draft decision. Epic argued that the regulator erred at law in his draft decision by failing to balance the various interests he is required to, including the service provider and potential users.
Epic also believes that since it paid in the vicinity of $2.5BB for the pipeline, that figure should be the regulatory value.
The case has been heard and Epic Energy's Chief Executive Officer, Sue Ortenstone, said the company had presented a well constructed argument and remained confident the Supreme Court would identify with its issues on the interpretation of the principles of the Access Code.
Epic remains hopeful of an announcement from the Supreme Court in the next few months. Meanwhile, submissions continue to roll in from companies supporting Epic's position. Thiess, Chevron and Deutsche Asset Management (Australia) Limited are amongst more than 100 companies that have stepped forward.
A spokesperson for Epic said the letters were mostly from the interest of future development as, if the regulator's position is allowed to stand, future customers to the pipeline would have to pay considerably higher tariffs than existing customers to finance an expansion of the pipeline, which is operating at its full capacity. An expansion of the pipeline would not be financially viable at the tariffs proposed by the regulator.
Epic argues the higher rate would provide all customers with the security of knowing how much they would be charged for the life of the pipeline.
Epic Energy's General Manager of Corporate Services, David Williams commented, "The regulator's draft decision, if allowed to be implemented without change, obviously has serious consequences for Epic Energy's financial viability. However, it also has far reaching implications for future industrial development in Western Australia particularly on investment in the growth of the gas industry."
US energy giant and a 33% shareholder in Epic Energy, El Paso, has said it will reconsider its investment strategy in Australia if the draft decision on the pipeline becomes final. El Paso Corporation's Chief Executive Officer, Eastern Pipelines Division, Jay Holm, said that Western Australia's reputation as a place to invest in infrastructure would be seriously questioned if the DBNGP draft decision was made final.
"Australia offers significant opportunities in terms of gas reserves and market growth, but current regulatory decisions have put Australia in a high risk category", Holm said. "An investor cannot commit risk capital when a regulator can 'change the rules' after the investment has been made."
Holm called on the Western Australian Government to stand up and support their sales process, or risk losing future infrastructure investment dollars.
Kolf said the issue is clearly a problem and OffGAR is working closely with Epic to devise a sensible solution.
Gas Pipeline project location map.
Construction of Origin Energy's underground pipeline between South Australia and Victoria will commence in October 2002, following completion of the project's construction and financing arrangements, but rival pipeliners continue to work on their projects in a move that is likely to see South Australian gas consumers with a range of alternative gas suppliers.
The South East Australia (SEA) Gas pipeline, developed by a partnership of Origin Energy and International Power, is due to deliver first gas in October 2003 and expected to be in commercial operation by January 2004.
The partnership of Duke Energy International and GasNet Australia remains in competition with its Southern Gas Pipeline (SGP), which it plans to have online by late 2003.
Spokesperson for Duke, Michelle Barry, said there had never been any question development would stop at a single pipeline and said Duke was continuing work on its Southern Gas Pipeline project. "Land acquisition, easement, engineering: all the necessary components for a gas pipeline are continuing", Barry said.
Barry said the SGP partnership had received a lot of interest from clients who were interested in an alternative gas supplier. Presently South Australia relies solely on gas from the Santos owned and operated pipeline from Moomba.
International Power's Corporate Affairs Manager, Jim Kouts, said it was important competition remained in the gas market because commercial clients wanted more than one choice when determining who would supply their gas needs.
Gas supply company, TXU, has been linked to the SGP through media reports that the company plans to purchase Duke Energy's intellectual property related to the pipeline. At the time of going to press, TXU would only confirm that the SGP is an option the company is considering as a means of transporting its gas needs, and that no formal agreement had been entered into with Duke.
The SGP and SEA Gas pipelines differ in diameter, length and annual capacity. The SGP will be a 16 inch pipeline with an annual capacity of approximately 62 PJ per annum without intermediate compression, assuming a fairly flat hourly load profile, such as for a power station. With compressors added in the future the capacity could be almost doubled.
The 14 inch SEA Gas option has been planned to primarily run through cleared or developed agricultural land, avoiding parks, conservation reserves, remnant forests and woodlands. Origin said that where possible, other easements including telecommunication and electricity easements, will be followed to minimise disruption to the landscape.
Kouts said the smaller diameter of the SEA Gas pipeline had been determined by market demand and engineering requirements of the pipeline. The need to make an economic return had also been a consideration.
Another primary difference between the two pipelines is the supply to regional centres. The SGP is routed to pass near regional centres in southwest Victoria and southeast South Australia, such as Portland, Mount Gambier and Naracoorte, whereas the SEA Gas pipeline would require lateral pipelines to service these areas.
Project Director of the Southern Gas Pipeline, Allan Tapley, said the SGP route would avoid the need for expensive lateral pipelines which were often difficult to justify. "It's better to go close to the source of demand rather than relying on lateral pipelines which may never get built", he said.
Kouts said the SEA Gas project had never led the public to believe it would undertake regional development. He said the company's involved would not pursue regional development unless it was commercially viable.
The SEA Gas partners have secured funding for their pipeline in the form of a $338 MM loan package from ABN AMRO Australia, Australia and New Zealand Banking Group, RBS (Australia) Pty Ltd and The Toronto-Dominion Bank. The finance facility comprises a $214 MM non-recourse loan and a $124 MM equity bridge loan which will fund the initial construction costs and a staged expansion prior to 2007. The non-recourse loan will convert to a three year bullet facility at commencement of commercial operations in early 2004. The funding has allowed an immediate start to the construction phase of the project.
SEA Gas will initially source its natural gas from two offshore Victorian gas fields - Minerva, located about 10 km offshore from the south west Victorian coast at Port Campbell, and Yolla, about 100 km offshore from Western Port, further east along the Victorian coast.
Both the SEA Gas and SGP projects anticipate transporting gas from the Otway Basin, with expedited development of the Thylacine and Geographe fields particular targets.
SEA Gas has awarded the major pipeline engineering, procurement and construction contract to a joint venture of AJ Lucas Joint Ventures and Spie Capag Australia Pty Ltd. A contract for the first compressor station has also been awarded to HPS Technology Pty Ltd.
"South Australia is almost totally dependent on gas supplied from the Cooper Basin. The link to Victoria will ensure we have access to more gas and will offer more versatility for industries, which rely on gas supplies. Importantly, the extra gas supplies will also reduce the risk of blackouts in South Australia", SA Premier, Mike Rann said.
ExxonMobil's plans to pipe Papua New Guinea gas to Queensland were dealt a blow when the Queensland government chose to meet the state's energy needs through a proposed coal seam methane development, to be led by Enertrade.
The $500 MM Enertrade proposal involves the construction of a 391 km long, 250 mm diameter pipeline from the Moranbah coal seam methane field in the Bowen Basin to the Yabulu Power Station near Townsville. The Moranbah field is owned and will be developed by CH4, which is an operation of the Macquarie Bank's private equity investment arm.
The project will also include conversion of the existing open cycle peaking Yabulu Power Station to a 220 MW combined cycle, base-load, gas-fired power station.
By selecting Enertrade as its preferred developer, the Queensland government stripped the PNG pipeline project of one of the potential customers of its 6 Tcf of gas resources from PNG's southern highlands. Oil Search's Group Secretary, Michael Sullivan, commented that Oil Search was disappointed with the decision, while President of Esso Highlands and Chairman of the PNG Gas Project Owners Group, Bill Threlfall, said, "Our attention continues to focus on marketing activities in Queensland and southeastern Australia and we look forward to initiating front end engineering and design, once we receive commitment to the project from additional gas customers."
But the blow was not fatal to the project, with the participants bouncing back to sign a gas agreement with the PNG government the following day. The agreement outlined elements including the PNG government's intent to take between 15% and 30% equity in the project's infrastructure, the necessary legal framework to develop the resources, and fiscal stability for the project.
The PNG project participants have so far confirmed one customer, Australian Gas Light, which has signed up for between 40 and 50 PJ of gas a year for 20 years, beginning in 2006. The lack of formal agreements has led to speculation the project could fold completely if more customers aren't signed in the near future.
Threlfall said the project participants were in active negotiations with potential customers. "If successful, these sales will provide the volumes required for the project to proceed", he said.
ExxonMobil is operator of the PNG Gas Project. Other participants include Oil Search, ChevronTexaco, Japan PNG Petroleum and MRDC, which is a PNG company representing the interests of land owners.
The award of the contract to Enertrade also dealt a blow to Origin Energy, which had been on the Queensland government's shortlist following its proposal to supply gas from its coal bed methane fields.
Origin considers the decision a vote of confidence in Queensland's coal seam gas industry as a viable long-term energy supplier. The company's Managing Director, Grant King, commented that the government's approach was consistent with Origin's strategic direction of developing resources as close as possible to end-use markets.
King said Origin would continue to seek other opportunities to commercialise its coal seam gas. "The gas that had been quarantined for delivery to the Townsville project in the case of a successful bid by Origin will now become available for southeastern Australian gas markets in general", King said.