Although Australia has some of the most progressive fiscal regimes for offshore oil and gas, the country is being short-changed in LNG exports, which is on the verge of further expansion this year. Audrey Raj reports.
Shell’s Prelude hull float launch in South Korea in 2013.
Australia is a nation rich in energy resources, with about 95% of its petroleum production coming from its offshore sedimentary basins in the Western Australian and Northern Territory coast. Although prices of key commodities including liquefied natural gas (LNG) have fallen, new supply of LNG has successfully come onstream in the country with exports expected to quadruple over the new few years.
While the LNG boom is likely to deliver enormous export earnings, local reports suggest that Australia gets the lowest share of government revenue from its oil and gas production compared to other LNG producers like Qatar, Malaysia, Indonesia, and Nigeria.
The country’s petroleum resources rent tax (PRRT), for example, is a profit-based taxing system that applies to a bulk of offshore projects. A report by The Sydney Morning Herald showed that currently only 5% of 150 oil and gas ventures are paying any PRRT.
In fact, since 2013, revenue from the PRRT had halved to US$600 million (AU$800 million) and crude oil excise collections had also fallen by more than half. As a result, the government of Australian Prime Minister Malcolm Turnbull said it will review the PRRT and associated commonwealth royalties ahead of next year’s budget.
An initiative aimed at ensuring both local and international companies are paying the right amount of tax on their activities in Australia, the review will be led by former treasury official Michael Callaghan, with the support of the commonwealth treasury.
The tax review comes after the Australian National Audit Office (ANAO) published its finding indicating that the North West Shelf (NWS) joint venture, including Woodside, Shell and Chevron, may have underpaid millions of dollars in royalties. The NWS development is Australia’s first LNG project.
According to ANAO, revenue reported by producers from NWS petroleum sales between July 2014 and December 2015 was $14.7 billion (AU$19.7 billion). From which, $1.4 billion (AU$1.9 billion) in royalties was collected, with $450 million (AU$600 million) retained by the federal government and the remaining $975.1 million (AU$1.3 billion) paid to Western Australia.
More than $3.7 billion (AU$5 billion) worth of deductions were claimed against the petroleum revenues in the 18 months to December 2015 that were not legitimate. These deductions were claimed under broad categories of operating costs, cost of capital, and joint venture participating costs, to name a few.
Wood Mackenzie’s Saul Kavonic said the country has some of the most progressive fiscal regimes for its oil and gas, and is one of several countries worldwide with purely profits based fiscal systems for offshore oil and gas, alongside countries like the Netherlands, Norway, Denmark, and the UK. This means Australia’s tax take rises for more profitable projects, but falls when they are less profitable.
“We still expect over $20 billion (AU$26.6 billion) in LNG investment possible in Australia over the next decade,” the senior research analyst for upstream oil and gas told OE. “This investment could potentially be put at risk if any major fiscal changes were implemented without proper consideration of their impact on Australia’s relative competitive position amidst an increasingly competitive LNG market.”
Kavonic continues: “A comparison of fiscal take between Australia and other countries can be misleading, as each jurisdiction has different project costs, economics, and are at different stages in their productive lives. The recent wave of Australian LNG projects are forecast to deliver relatively low returns, well below the returns that Qatari projects have realized.
“So, the value pie in Australia is smaller to share between government and investors. Despite a number of projects that will struggle to pay back their capital cost, over $50 billion (AU$66.6 billion) in tax value is still forecast to be realized from the recent wave of Australian LNG projects over their lives,” Kavonic explains.
The Australian Petroleum Production & Exploration Association (APPEA) believes that the PRRT regime that the Labor Party introduced in the 1980s is a major reason why Australia has attracted more than $150 billion (AU$200 billion) worth of new investment in recent years.
APPEA chief executive Dr. Malcolm Roberts announced in November 2016 that a fact-based review of the PRRT by the treasury would show the profit based tax was working as intended. He said that the APPEA’s latest financial survey of its members shows that – despite the industry recording its first-ever net loss in 2014-15 – it paid more than $3.7 billion (AU$5 billion) worth of taxes during the same period.
“The continued payment of taxes at a time when the industry is under severe pressure debunks critics’ suggestions that the industry is not somehow paying its way. Much of the debate about PRRT has been characterized by grossly misleading information, distortion and a willingness to ignore the facts,” Roberts said in November.
“For almost 30 years, the commonwealth has used the PRRT as a super profits tax,” Roberts said. “The tax encourages investment by only taxing projects when upfront costs have been recovered and profits exceed a modest benchmark rate. Australia’s oil and gas industry is at a crossroads. Exploration has collapsed.”
Chevron’s Wheatstone project near completion. Photo from Chevron.
As other countries, Australia too understands that openness to foreign investment is critical to unlocking its natural resource wealth which is 80% underexplored. Most of its oil resources are condensate and liquefied petroleum gas (LPG) associated with giant offshore gas fields in the Browse, Carnarvon and Bonaparte basins.
Oil reserves, however, are modest as the story in Australia is really LNG, David Campbell, senior trade and investment commissioner of the Australian Trade and Investment Commission said at the 2016 Offshore South East Asia Conference and Exhibition (OSEA) in Singapore.
“Around 92% of Australian conventional gas resources are located in the Carnarvon, Browse and Bonaparte basins off the coast of Western Australia and the Northern Territory. There are also resources along the offshore basins along our southern margin as well as onshore basins, and the potential for additional commercial discoveries is significant. With unconventional gas we have significant resources in coastal basins around Queensland and New South Wales,” he said.
New LNG market
David Campbell speaking at OSEA. Photo from OSEA.
Australia is home to several LNG projects such as Pluto LNG, Gorgon LNG, Darwin LNG, Gladstone LNG, Asia Pacific LNG and Queensland Curtis LNG. In October 2015, the country’s LNG exports climbed to a record of $1.3 billion (AU$1.75 billion) – the best performance in 22 months, data from Adelaide-based energy advisory firm Energy Quest showed.
The Asia Pacific region will be the driving force behind LNG demand growth, which is also a rapidly growing market for Australian exports. To maintain its competitive edge, the Australian government is expanding oil and gas market opportunities through free-trade agreements with China, Japan, and Korea. These countries combined, purchase more than two thirds of Australian resources in energy exports, worth about $87.7 billion (AU$117 billion) in 2014-15.
“But it’s not only about China, it’s also India,” Campbell told OSEA, adding that there are reasons to expect why the Australians will play an important role in meeting the growing gas demand there.
“India’s LNG demand is expected to double by the end of the decade while it seeks to provide electricity to its population. We are geographically close to the four east coast LNG regasification terminals that are currently under construction in India. At the moment, over 85% of their gas comes from Qatar,” he said.
Year of the mega project
Three large Australian LNG projects that extract gas from fields off the north coast of Western Australia are expected to come online this year. Currently, at various stages of development it includes Shell’s Prelude floating LNG (FLNG) facility, Chevron’s Wheatstone LNG project, and Inpex’s Ichthys LNG development.
The Chevron-operated (64.14%) Wheatstone project, west of Onslow in Western Australia is expected to achieve first LNG in mid-2017. Wheatstone features a huge offshore gas-processing platform, with a topside weight of about 37,000-tonne. It also includes two LNG trains with a combined capacity of 8.9 MTPA and a gas plant. It comprises the WA-17-R and WA-253-P gas fields in the NWS, in water depths of 70-200m.
Chevron’s partners in the project include Kuwait Foreign Petroleum Exploration Co. (13.4%), Woodside Petroleum (13%), Kyushu Electric Power Co. (1.46%), and PE Wheatstone (8%).
Since discovering a giant gas and condensate field in the Browse basin offshore Western Australia, Inpex has been developing Ichthys LNG, which involves a central processing facility and a floating production, storage and offloading vessel.
Scheduled for startup in September 2017, the project is expected to produce 8.9 MTPA of LNG and 1.6 MTPA of LPG, along with up to approximately 100,000 b/d of condensate at its peak.
Inpex operates Ichthys with 62.2% interest. Its partners are Total (30%), CPC Corp., Taiwan (2.625%), Tokyo Gas (1.575%), Osaka Gas (1.2%), Kansai Electric Power (1.2%), Chubu Electric (0.735%) and Toho Gas (0.42%).
Shell’s Prelude FLNG is one of the largest offshore floating facilities ever built. It has around 260,000-tonne of steel in the facility alone, around five times the amount of steel used to build the iconic Sydney Harbour Bridge.
The FLNG unit is designed to withstand a category five cyclone while moored above the Prelude and Concerto gas fields in the Browse basin, for the next 25 years. Once operational in late 2017, Prelude will produce at least 5.3 MTPA of liquids: 3.6 MTPA of LNG, 1.3 MTPA of condensate and 0.4 MPTA of LPG. Shell serves as operator. Its partners include Inpex (17.5%), KOGAS (10%) and OPIC (5%).
Activity is picking up down under. But, it’ll be at a slow pace, says the Energy Industries Council’s (EIC’s) Neil Golding.
During the early part of this decade, following significant gas discoveries in the 2000s, several projects geared up for development with significant front-end engineering and design (FEED) contracts awarded on Woodside’s Browse gas discovery, Shell’s Crux gas condensate field and Hess’ Equus gas field.
Significant engineering, procurement and construction (EPC) activity also took place with multi-billion dollar contracts signed for the development of the Inpex’s Ichthys and Chevron’s Wheatstone projects.
While contracts continue to be awarded, there has been a significant drop off in activity since 2013.
Why is this? The continued increase in contracting costs from 2013-2014 for offshore developments saw operators put on hold both oil and gas developments. The huge gas projects that were already under construction, relating to liquefied natural gas (LNG) developments, meant that additional gas developments were not needed and would have only added to the current supply glut. All these factors brought into question the commercial viability of future developments.
We saw some positive activity in 2016, and contracts continued to be awarded. In the Greater Enfield oil development, Technip, OneSubsea and Aibel all won significant contracts. It must be noted though that projects continued to be put on hold, which in turn delayed the award of EPC contracts, the most notable of which was the Equus gas field, where Hess decided in November 2016 to postpone the floating production system project.
Prospects for 2017
The expectation is that projects will move forward, albeit at a slower rate than the early part of the decade, with contracts being awarded during 2017.
The Caldita-Barossa gas field being developed by ConocoPhillips is one development where activity is expected to ramp up. The field is in water depths of 320m, off the Northern Territory, with approximately 3.5Tcf of reserves. Currently, construction for a floating production, storage and offloading vessel is planned to separate gas, condensate and water, and remove the bulk of the carbon dioxide. The project includes a subsea production system and umbilicals, risers and flowlines, and a 260km, 26in gas export pipeline to the Darwin LNG plant. FEED and EPC tenders are expected in 1H 2017.
The Santos-operated Sole gas field offshore Victoria, in the Gippsland Basin, could also see activity. A binding sales gas agreement has been signed and the final investment decision is expected imminently, with EPC work likely to start in 2017.
The sizeable Crux, Scarborough, Tassie Shoal and Equus discoveries will all require major investment to be brought into production. New finds continue to be made and it must be mentioned that Australia still has some very exciting frontier regions that have seen little exploration, and which could contain significant reserves. Australia is a market full of opportunities for the supply chain in both the short- and long-term.
Neil Golding has over 16 years’ experience of working in the oil and gas industry in various roles and currently heads up the Oil and Gas and Product Development teams at the EIC. The teams’ main objective is to support the UK supply chain in identifying business opportunities in the global oil and gas market. Golding is joint product owner of the EIC project database EICDataStream which tracks over 8000 global energy projects throughout their development lifecycle.