AUST�LIANTHEEnergy ReviewO I L – G A S – E L E C T R I C I T Y – R E N E W A B L E S

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1414 SPRUIKS TECH AHEAD OF IPO

RENEWABLES p9

RESILIENT BUSINESS

APPEA p10

ICHTHYS DELAYED AGAIN

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Image: Jemena.

NEWS p6

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Deloitte national oil and gas leader Bernadette Cullinane speaks about how companies, researchers, and policy makers can work

together to deliver the best outcomes amid Australia's energy evolution.

THE BIG ISSUES

FEATURE p15

Image: Snowy Hydro.

2 APRIL 2018

THE AUST�LIAN ENERGY REVIEWCONTENTS PUBLISHED BY

ABN 28 112 572 433

GENERAL MANAGERBrad Francisbrad@miningoilgas.com.au

MANAGING EDITORReuben Adamsreuben@miningoilgas.com.au

JOURNALISTSCameron Drummondcam@miningoilgas.com.au

Elizabeth Fabrielizabeth@miningoilgas.com.au

GRAPHIC DESIGNERCharlotte Lufinocharlotte@miningoilgas.com.au

SALES EXECUTIVESBeej Francis, Penny West

PRINTER

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CONTACT US

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E-mail the editor at editorial@miningoilgas.com.au

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The Australian Energy Review is a free publication to all mine sites and mining companies in Australia. Its value is $11 an issue. (Includes GST, postage and handling).The copyright is vested in the Proprietors of The Australian Energy Review; neither whole nor any part of this issue may be reproduced without permission. The views expressed in this publication are not necessarily those of Miningoilgas Pty Ltd and its staff, but are those of the respective author who accepts sole responsibility and liability for them.

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NEWS

Renewable Energy 9

FEATURES

Pluto Gas 12

APPEA 2018 10

news p6

renewable energy p9

GREEN LIT:

PROJECT ATLAS

INDUSTRY SPOTLIGHT

THE INTERVIEW

Heat Exchangers 14

Bernadette Cullinane 15

BIGBATTERIES

FUNDED

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Publications & Exhibitions Australia Pty Ltd

THE Northern Territory Government will soon make a decision on whether to lift a moratorium on hydraulic fracking, following the release of a 15-month independent inquiry that determined risks can be managed through effective regulation.

Hydraulic fracking — which is currently prohibited in Victoria and the subject of a moratorium in Tasmania, NSW and WA — has been an issue of contention in the NT for some time, with the last three Governments commissioning reviews and inquiries into the matter.

In September 2016, Northern Territory chief minister Michael Gunner introduced a moratorium on fracking and appointed the independent inquiry, led by NSW Land and Environment Court judge Justice Rachel Pepper. Justice Pepper said the report put forward 135 recommendations to mitigate identified risks if the Government lifts the moratorium.

“No industry is without risk, and any onshore shale gas industry is no exception, however, it is the panel’s opinion that if all of the recommendations are implemented, the identified risks associated with any onshore shale gas industry can be mitigated or reduced to an acceptable level, and in some cases, the risks can be eliminated,” Justice Pepper said.

“The decision whether or not to retain the ban on hydraulic fracturing in the Northern Territory is a political decision that rests with the Government alone.”

Justice Pepper said the inquiry’s scope was much broader than previous reports, and included 52 community forums, 151 public hearings, 31 community updates and 1257 written submissions.

Mr Gunner said the Government will now “carefully consider the report’s

recommendations and take as long as is needed to make the right decision” for the Territory.

“Once the final report has been carefully considered we will do what we have always promised Territorians - either ban fracking in the Northern Territory or allow it in highly regulated circumstances in tightly prescribed areas,” Mr Gunner said.

“We will not put at risk existing fishing, farming, tourism and cattle jobs for the possibility of jobs from fracking.”

Australian Petroleum Production & Exploration Association (APPEA) Northern Territory director Matthew Doman said the final report “debunked many of the myths spread by activists opposed to onshore gas development”.

“There is no reason the Territory cannot manage the safe, sustainable development of its considerable natural gas resources,” Mr Doman said.

“APPEA’s member companies stand ready to invest billions of dollars in new projects in the Territory if the industry is allowed to resume exploration activity.”

Jemena, was one of the companies ready to push forward new developments in the Territory. In a February submission to the Fracking Inquiry, Jemena executive general manager corporate development Antoon Boey said the company had already invested significantly in its Northern Gas Pipeline (NGP) under construction, but was prepared to “invest significantly more capital” in extending and expanding the NGP if onshore gas can be commercialised.

“The project is estimated to cost around $3-4 billion and could create around 4000 new jobs across Northern Australia,” Mr Boey said.

“Any delay to progressing the exploration of [the Territory’s] onshore gas resources increases the risk that the NT will be unable to capitalise on the need for new gas supply in the east coast market.”

ELIZABETH FABRI NORTHERN TERRITORY

Inquiry backs fracking

“The decision whether or not to retain the ban on hydraulic fracturing in

the Northern Territory is a political decision that

rests with the Government alone.”

Image: APPEA.

4 APRIL 2018

THE AUST�LIAN ENERGY REVIEWNEWS

AGL, formerly known as the Australian Gas Light Company, has been in existence for over 180 years, being founded in Sydney in 1837.

As the second company to be listed on the Sydney Stock Exchange, it is not only steeped in history, but is recognised as an organisation that readily adapts to customer and market changes.

Today, AGL Energy is involved in both the generation and retailing of electricity and gas for residential and commercial use.

AGL Energy’s Torrens Island Power Station (TIPS) is located on Torrens Island in South Australia, 18km from Adelaide’s CBD.

The ‘A’ station became operational in 1967, with the ‘B’ station completed in 1981.

The station burns natural gas in boilers to generate steam, which drives the eight turbines to generate electricity with a total nameplate capacity of 1280MW.

As the largest power station in South Australia, it is a critical asset, even more so in light of the power generation challenges encountered by the state in recent years.

The team at TIPS have always prided themselves on the depth of their generation and operations knowledge, keeping the station running at optimal performance at all times.

In striving to move to the next level, they decided to explore the possibility of implementing a process simulator, or Digital Twin, in 2013.

When evaluating their requirements, the team at TIPS took a number of factors into consideration. Not only did they want rigorous training for operators in all aspects of unit, common and local plant operations, they needed to ensure that failure and malfunction situations were addressed quickly and efficiently.

Such failures and malfunctions would need investigating to identify root causes and prevent any repetition.

Another crucial aspect was the testing of control and logic modifications, or proposed alterations to plant operating regime (such as different burner patterns, lower minimum load, higher ramp rates, etc.) without having a detrimental impact on operations.

Being able to test process and equipment modification scenarios using live plant data, yet without affecting operations was a huge attraction to the TIPS team.

With all this in mind, and following a rigorous evaluation process, AGL selected Yokogawa’s Plant+ as the process simulator of choice.

Yokogawa Australia & New Zealand has been developing and implementing high fidelity dynamic simulators for the process industries for over 20 years.

With a dedicated design and development group based in Sydney, Yokogawa has provided leading edge operator training and process optimisation simulators to both domestic and overseas markets. These simulators have improved operational efficiency and safety in the Power Generation, Oil & Gas and Mining sectors.

With the decision made, AGL engineers moved quickly to implement, completing installation of their new Digital Twin in 2016.

Although one of the initial plans was just to train plant operators, they were conscious of not falling onto the trap many do in just using the simulator as an Operator Training Simulator (OTS).

Due to time or resource pressures, few process simulator owners take advantage of the full capabilities a Digital Twin can provide.

The team at TIPS however, had far greater plans, starting with investigations into effects on unit operations when running without a Boiler combustion air pre-heater.

Air heaters are an important component of unit operations from an efficiency perspective.

Yet they also require a great deal of maintenance to ensure they are working correctly, with unit efficiency significantly affected when not functioning correctly.

In periods of high demand, it is not possible to go offline to resolve issues with air heaters, as the financial implications of doing so would be significant.

Yet if an air heater failed during periods of high demand, or an air heater was not functioning at all, what would be the effect of running a unit without the heater?

This was a scenario that AGL, made a decision to test using their Digital Twin.

There was the very real possibility that one unit may have to run without the airheater during summer. To ascertain the impact on the unit, TIPS conducted testing on the Simulator to determine the effects on the process and also define the limitations for the Boiler and Turbine.

“Obviously the unit would not achieve full output, but we needed to establish where the point at which the unit could be run safely and economically. We knew we had a challenge on our hands with this air heater and were still going through the process of resolving it for the long term. However, we had the short-term challenge of ensuring the power station met consumer demands and this unit would be crucial in doing so. We therefore decided to test the effects on a unit of running without an air heater to see if this could assist in resolving this short term issue.”

Using one of the operational units to test this just wasn’t feasible; similarly firing up the affected unit without having a clear understanding of the implications was out of the question.

However, the process simulator is an ideal tool to try out the changes replicating operations to a high degree.

Knowing that they could run multiple scenarios of unit operations without an air heater and monitor the impact on operations was ideal.

The team looked at several ways to run the 200MW unit without an air heater, eventually deciding to run the unit at 100MW.

Then, the idea was to slowly remove the (model) mass and surface area of the air heater until only a 2-degree heat exchange transpired, which was seen as being the best outcome. Later removing this restriction, AGL could simulate less backpressure on the Forced Draft fans.

“The testing was completed in a limited timeframe but the results seemed to reflect what we expected. As the fans worked harder, fuel gas pressure was higher and at about 160MW the air and fuel became unstable so would require some tuning.”

Next, the unit was taken through all loads up to 160MW with a reduced ramp rate without any issues. Without restriction, several boiler purges were then performed successfully and once more the expected results were observed, with lower windbox pressures for given fan positions.

“Testing included closing in the stack damper slightly to see if it was an option to increase pressure to normal and this worked too. We also didn’t need to force any of the safety system parameters and the trip settings were not breached.”

Using their Digital Twin, TIPS confirmed their belief that running without an air heater would be possible.

Not an ideal scenario, but knowing they can operate the affected unit to meet consumer demand in the short term and even operate other units without air heaters for short periods provides options.

In the pressurised and high profile environment of power generation in South Australia, AGL‘s adoption of a Digital Twin has provided clear evidence that process performance can be optimised in response to plant constraints.

CASE STUDY

AGL uses Digital Twinto optimise power station

5APRIL 2018

THE AUST�LIAN ENERGY REVIEW NEWS

ENERGY imports to the United States have fallen to their lowest levels since 1982, according to data from the International Energy Agency (IEA).

Imports fell 7.3 quadrillion British thermal

units (qBtu) in 2017; a 35 per cent decrease from 2016.

Gross energy imports have been generally decreasing from a high of 34.7 qBtu in 2007; however, the larger factor leading to the reduction in the net energy trade balance has been increasing energy exports.

Gross energy exports rose to 18 qBtu in 2017; a 27 per cent increase from 2016 and

the highest annual US energy exports on record, driven largely by increases in exports of petroleum and natural gas.

In recent years, exports of crude oil have also contributed to the overall rise in energy exports after crude oil export restrictions were lifted at the end of 2015.

Following the removal of restrictions on exporting US crude oil in December 2015,

total volumes of crude oil exports and the number of destinations for those exports both increased.

The US exported crude oil to 27 countries in the first half of 2017 compared with 19 countries in the first half of 2016.

In energy content terms, the US now exports nearly as much energy in the form of crude oil (2.3q Btu) as coal (2.5 qBtu).

US energy imports plummet

Pacific buys Contract Power

POWER generator Pacific Energy has struck an agreement to acquire Contract Power for $90 million.

Contract is a remote power generation specialist with customers in the hard rock lithium sector including Pilbara Minerals, Galaxy Resources and Tawana Resources; and Pacific, through its subsidiary Kalgoorlie Power Systems, is WA’s largest power supplier to the gold sector.

The deal will give Pacific an additional 82 megawatts (MW) of installed power generation, taking its total capacity to 245MW

across 16 projects.

“The transaction with Contract Power gives Pacific Energy significantly more scale and reach, now with over 30 long-term power generation contracts for remote mines and townships and a weighted average remaining contract duration rising above four years across the entire portfolio,” Pacific managing director James Cullen said.

“This provides us with stronger and longer earnings visibility,” he said.

Contract Power founder Leon Hodges said that during the due diligence of the deal it became very clear that the two businesses were remarkably similar.

“I am looking forward to continuing to drive the business with our team and the support of

Pacific Energy’s resources … this is certainly a landmark transaction in our industry,” Mr Hodges said.

Mr Cullen said that subject to the settlement of the transaction, the estimated EBITDA for Contract in FY19 would be in the range of between $14m and $16m, and likely increase to between $17m and $19m the following financial year.

“In addition to a dependable and growing earnings profile, the transaction is also backed by strong underlying asset values, both installed on site and available to be installed in [the] future, and gives both companies access to an expanded asset base and therefore lower joint future capital expenditure and improved utilisation,” Mr Cullen said.

CAMERON DRUMMOND NORTH AMERICA

CAMERON DRUMMOND NATIONAL

The acquisition will take Pacific Energy’s total provided capacity up to 245MW.

Image: IEA.

US ENERGY EXPORTS 2017

Crude Oil 89%

Petroleum 11%

Natural Gas 36%

Coal 61%

THE Federal Government has handed out $24 million in funding to fast track the development of four gas projects, as part of its Gas Acceleration Program (GAP).

The funding will enable an additional 12.4 petajoules of gas to be supplied to the East Coast gas market by 30 June 2020, and an extra 27.6 petajoules over five years.

Each project received a $6 million grant towards their respective developments, including Armour Energy to put towards drilling three additional production wells at its Kincora gas plant in QLD; Westside Corporation to put towards the drilling of 10 additional single lateral wells at its Greater Meridian project in QLD; Beach Energy’s new Katnook Gas Processing Facility in South Australia; and Tri-Star Fairfields’ four new wells west of Rolleston, QLD.

Federal Resources minister Matt Canavan said the extra supply would help safeguard Australia’s future gas security.

“While Australian Government measures like the Australian Domestic Gas Security Mechanism and the Prime Minister’s agreement with LNG exporters in October 2017 have helped to address domestic gas supply in the short term, the only way to provide gas security into the future is by increasing the supply of gas through increased development,” Mr Canavan said.

“The GAP is fast tracking projects with the best prospects of bringing significant new gas volumes to target markets by mid-2020.”

ELIZABETH FABRIEAST COAST

Gas supply boost

6 APRIL 2018

THE AUST�LIAN ENERGY REVIEWNEWS

SENEX’S Project Atlas could deliver first gas to the domestic market as early as next year, now that a petroleum lease and preliminary environmental approvals have been secured.

The high-quality coal seam gas permit, southeast of Wandoan in the Surat Basin, was awarded to Senex in September 2017 following a competitive State Government tender.

The granting of the lease will enable Senex on-ground access to progress environmental studies and preliminary activities for the development of 100 wells and associated infrastructure.

Senex managing director Ian Davies said the company expected to secure remaining State and Federal Government approvals by mid-2019, and deliver first gas by late 2019.

“We are in detailed discussions with parties to provide gas processing infrastructure, have materially progressed financing discussions with prospective lenders, and look forward to engaging with domestic gas customers in the near term,” Mr Davies said.

“The direct award of a petroleum lease for Project Atlas is an innovative solution by the QLD Government to help address the shortage of new east coast gas supply.”

State Mines and Energy minister Dr Anthony Lynham said the Palaszczuk Government used existing legislative powers to ensure the gas would only be sold and used in Australia.

“Construction work can now begin on the wells and pipelines needed to pump up to 26 Petajoules per year of additional gas into the domestic market,” Dr Lynham said.

Queensland Resources Council (QRC) chief executive Ian Macfarlane said the granting of the license with a domestic-only condition

“was an example of the State’s leading regulatory framework”.

“Not only will it create 150 jobs but the pilot has been a success in best-practice regulation in action – fast, effective and focussed on outcomes," Mr Macfarlane said.

“Other State Governments and Territories need to get their heads out of the sand and back the science and their own industries.

“Only yesterday an inquiry recommended to the NT Government to lift its fracking moratorium and develop its onshore gas.”

IN BRIEF

Mereenie project moves ahead

CENTRAL Petroleum and its joint venture partner Macquarie Group will proceed with their Mereenie gas project after the ACCC approved joint marketing arrangements.

The development includes drilling of WM26 and an immediate $12 million upgrade of the processing plant, aimed at increasing capacity from 25 terajoules per day to 63TJ/day.

In late March, Central announced an Ensign rig was making its way to the site in preparation for the start of a three-well drilling program to commence in April.

The plant upgrade was also expected to be complete by December.

NORTHERN TERRITORY

McNamara named new AEC chief

THE Australian Energy Council (AEC) has announced the appointment of Sarah McNamara as its new chief executive with outgoing chief Matthew Warren to step down on 2 July 2018.

Ms McNamara joined the AEC as Corporate Affairs general manager in January 2016, and previously worked with energy provider AGL.

“Sarah has more than a decade’s experience working with policy and regulatory frameworks across the energy sector,” AEC chairman Jeff Dimery said.

“She has advised the highest levels of Government on energy policy and advocated for the industry at both the peak body level and through her previous role with AGL.

“Her appointment provides important continuity to the role having worked in the AEC Secretariat for the past two years.”

NATIONAL

Glenaras drilling begins

GALILEE Energy’s Easternwell Rig 101 in the eastern Galilee Basin has commenced drilling operations, with the Glenaras 10 well spudding on 23 March.

The milestone marks the beginning of the Glenaras gas project – multi-lateral pilot program.

A vertical test hole will test the various seams and identify the optimal coal target for the lateral wells and then be plugged back with three separate lateral wells to be drilled into the target coal seam.

Galilee said it would drill three lateral wells and conduct a production testing pilot with the potential to ultimately convert a large portion of the 5314 petajoules (PJ) of 3C resources to reserves, and deliver up to 73 PJ per annum into the under supplied east coast gas market.

QLD

Green light for Project Atlas

INPEX has announced further delays at its majority owned Ichthys project, with production slated to begin within the next few months.

On 26 March, INPEX said commissioning required for production start-up was now expected to be completed between April and May, with production and shipment of condensate liquefied natural gas (LNG) and liquefied petroleum gas (LPG) to begin thereafter.

First production was originally scheduled at the end of 2016, however was pushed back to the September 2017 quarter, and then the March quarter 2018, following a review of the project’s development schedule.

INPEX said it has already completed drilling the production wells required for start-up, and the necessary commissioning of the first train at the onshore gas liquefaction plant, Floating Production Storage and Offloading (FPSO) facility, and subsea production systems.

“While the project’s activity schedule going forward may fluctuate depending on weather conditions at the worksites, preparation

activities and other factors, INPEX will continue to work toward the success of the Ichthys LNG Project with the understanding and cooperation of all its stakeholders, including the project’s joint venture partners, the local communities, the Australian Federal government and the governments of Western Australia and the Northern Territory,” INPEX said.

Once developed, the project will have an operational life of more than 40 years, producing and shipping about 8.9 million tonnes of LNG and 1.65 million tonnes of LPG a year, and 100,000 barrels of condensate per day at peak.

ELIZABETH FABRIQLD

ELIZABETH FABRINATIONAL

Ichthys delayed again

An aerial view of the Ichthys onshore gas liquefaction plant.

Senex expects to deliver first gas from Project Atlas by late 2019.

Image: INPEX.

Image: Senex.

http://www.blhgroupservices.com

ROYAL Dutch Shell has agreed to sell its New Zealand assets to Austrian oil and gas company OMV for $US578 million.

The sale, in line with the company’s strategy of divesting $US30 billion in assets by the end of 2018 to simplify its upstream portfolio, comprises eight Shell NZ entities, including the Maui, Pohokura and the Tank Farm operations, of which OMZ is already a co-owner.

Shell’s interest in the Great South

Basin venture, which includes a drilling commitment of about $US50 million, will also be sold in a separate transaction.

Shell Integrated Gas and New Energies director Maarten Wetselaar said the sale was another step towards reshaping and deepening Shell’s financial resilience and competitiveness.

“We are proud of having worked in New Zealand for more than 100 years,” Mr Wetselaar said.

“Our customers, our neighbours, the regulator and partners have been a critical part of this journey and integral to our successes, I wish them all well.”

Shell Companies in New Zealand chair Rob Jager said the business will continue to run as it is now, until the deal was complete.

“We have two high priorities over this transition period: to continue to run our assets in a safe and reliable manner and care for our people,” Mr Jager said.

The divestment follows a two year strategic review of Shell’s interest in New Zealand, and the sale of the 60-year-old Kapuni oil and gas field in April last year to its joint venture partner Todd Energy.

The company expected to finalise the sale of its New Zealand assets by Q4 this year.

CONOCO Phillips has reached a key milestone towards the development of its Barossa-Caldita project after receiving the tick of approval from the offshore petroleum regulator.

Barossa-Caldita, a joint venture between operator Conoco Phillips (37.5 per cent), Santos (25 per cent), and SK E&S (37.5 per cent), is flagged to supply backfill gas to Darwin LNG when Bayu Undan production ends in the early 2020s.

Approval from the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) will allow the Joint Venture to begin the next stage of planning, including the submission of activity-specific environment plans.

“Acceptance of the Offshore Project Proposal (OPP) gives us a level of regulatory comfort and the certainty we need to enter the Front End Engineering and Design (FEED) phase in the very near future,” Santos managing director and chief executive Kevin Gallagher said.

“This is one of the major regulatory

steps leading to offshore project development and petroleum production, and it reinforces Barossa’s position as the only gas supply source capable of meeting Darwin LNG’s timetable.”

The Woodside-led Sunrise project has also been a strong contender to supply gas to Darwin LNG but was set back by a decade-long border dispute between

Australia and Timor Leste.

The Barossa field, 300km north of Darwin, will comprise a permanently moored Floating Production Storage and Offloading (FPSO) facility, subsea production system, supporting in-field subsea infrastructure and subsea gas export pipeline.

Conoco Phillips said the expected liquefied natural gas (LNG) and condensate production rates were about 3.7 million tonnes per annum and 1.5 million barrels per year, respectively, over a 25-year operating life.

A Final Investment Decision was expected in 2019, with first gas to be delivered in 2023.

8 APRIL 2018

THE AUST�LIAN ENERGY REVIEWNEWS

Shells offloads NZ assetsMeg O’Neill joins Woodside

ELIZABETH FABRIINTERNATIONAL

ELIZABETH FABRI NORTHERN AUSTRALIA

EXXONMOBIL’S Meg O’Neill will replace Mike Utsler as Woodside chief operations officer in May this year following a brief handover period.

Woodside stated that Ms O’Neill brought a “wealth of operations experience” gained during a long stint at ExxonMobil working in Indonesia, Norway, Canada and the US.

Her most recent role was vice president–Africa in ExxonMobil’s Development Company.

Meg holds dual Bachelor Degrees in Ocean Engineering and Chemical Engineering, and a Master’s Degree in Ocean Systems Management from the Massachusetts Institute of Technology.

Woodside chief executive Peter Coleman said Mr Utsler had been an outstanding member of Woodside’s leadership team since 2013, delivering significant improvements across operational performance, HSEQ, and maintenance campaign delivery.

“Under Mike’s leadership our operations team has achieved world-leading results. We wish Mike all the best for the future,” he said.

Maui operation in New Zealand.

The Barossa project location.

REUBEN ADAMSNATIONAL

Image: Royal Dutch Shell.

Image: Conoco Phillips.

Barossa project wins approval

9APRIL 2018

THE AUST�LIAN ENERGY REVIEW NEWS

SILICON thermal energy storage systems are more compact than batteries and have the lowest levelised cost compared to any other form of storage, according to 1414 Degrees chairman Dr Kevin Moriarty.

1414 is preparing for an ASX listing on the back of its “ground-breaking” storage technology which it is progressing towards commercialisation.

The company stated in October last year that $8.4m in IPO funds had already been promised by cornerstone investors following $2.5m seed raise.

With the significant increase in the number of large-scale batteries and pumped hydro projects in Australia, there was a clear need for energy storage to help increase the efficiency and reliability of the grid, Mr Moriarty said.

Thermal energy storage systems are cost effective, can be located anywhere, are very compact, and have a very long life, he said.

They also provide solutions to a number of deficiencies in existing energy storage options.

“Pumped hydro is very useful for long-term storage, seasonal storage and so on, but you can’t put it anywhere; it’s got to be located somewhere where there’s mountains and plenty of water, and so on,” he said.

“So you’re quite limited in location. It’s also relatively expensive, and possibly environmentally challenging to set up.”

IN BRIEF

Northam Solar turns first sod

THE 10MW Northam Solar Farm project turned first sod in March, marking the start of development of WA’s next solar farm.

The project will be developed by Carnegie Clean Energy in partnership with Indigenous Business Australia and the Perth Noongar Foundation.

The partnership will provide contracting opportunities to a number of Aboriginal businesses, as well as the opportunity for ongoing Noongar employment during both the construction and operation phases of the project, which is expected to generate enough power for 3000 households over the next 25 years.

“This project is particularly exciting because of the opportunities it will provide to local Aboriginal people and businesses as a result of the joint venture,” WA energy minister Ben Wyatt said.

WA

Virtual power plant gets backing

SIMPLY Energy will build a $23 million second virtual power plant in Adelaide that will deliver Tesla Powerwall 2 home batteries to up to 1200 households.

The virtual power plant, partially funded by the Federal Government, will be up and running by the end of 2019, and create 6 megawatts (MW) of residential storage, and a further 2MW of demand response capacity across 10 commercial businesses.

The project follows AGL’s $5 million virtual power plant in Adelaide across 1000 homes and businesses.

SOUTH AUSTRALIA

Short-term forecasting trials

THE Australian Renewable Energy Agency (ARENA) and Australian Energy Market Operator (AEMO) are seeking expressions of interests from utility-scale wind and solar projects to participate in short-term forecasting trials.

As part of the trials companies will submit their own five-minute ahead forecasts to the AEMO to combine local measurements with AEMO modelling to improve overall accuracy.

“As more variable renewables enter the market, we need to improve the accuracy of our short-term forecasts so we can anticipate what will happen as a cloud passes over a solar farm or if the winds change,” ARENA chief executive Ivor Frischknecht said.

NATIONAL

1414 spruiks tech ahead of IPO

THE Victorian Government and the Australian Renewable Energy Agency (ARENA) have poured $50 million into two new large-scale battery projects for the State.

The projects include a 25MW/50MWh Tesla battery to be integrated at the existing 60MW Gannawarra Solar Farm, and a 30MW/30MWh Fluence system to connect directly to a vital grid intersection at a substation at Warrenheip.

The Tesla battery will be owned by Edify Energy and its partner Wirsol, while the Fluence battery will be built by a consortia led by Spotless Sustainability Services and owned by AusNet.

Together, the projects will generate 55MW of energy and 80MWh of storage to provide backup power, grid-stabilisation, and reduce energy bills for Victorians.

They will also help ease constraints on Western Victorian transmission lines, which currently limit the output of existing wind and solar farms.

“Storage has been the missing piece of the energy jigsaw for a long time,” Federal Energy minister Josh Frydenberg said.

“These two large-scale, grid-connected batteries in Victoria are yet another investment that will help deliver more affordable and reliable energy for Australian households and businesses as we transition to a lower emissions future.”

Construction had already begun at both projects, which were expected to be operational by next summer.

“We said we would deliver this for Victoria, and that’s exactly what we’ve done,” Victorian Energy minister Lily D’Ambrosio said.

“We are continuing to modernise our electricity grid, strengthen our energy security and deliver real action on climate change.”

Both batteries will be operated by EnergyAustralia under long-term offtake agreements. Edify Energy chief executive John Cole said the company is proud to have designed and delivered the first combined utility scale solar and storage facility in Victoria.

“Without a doubt as the cost of battery storage falls, we see solar and storage becoming a ‘category killer’ in the energy sector and accelerating Australia’s transition to a clean energy future,” Mr Cole said.

REUBEN ADAMSNATIONAL

ELIZABETH FABRIVICTORIA

Large-scale batteries funded

A Tesla Powerpack will be integrated at the 50MW Gannawarra solar farm in Victoria.

1414 Degrees executive chairman Dr Kevin Moriarty.

Image: Edify Energy.

Image: 1414 Degrees.

Thermal energy storage systems are cost effective, can be located anywhere,

are very compact, and have a very long life.

10 SPECIAL FEATURESAPPEA

APRIL 2018THE AUST�LIAN ENERGY REVIEW

Q. Following the 2017 conference in Perth, what feedback did you get from

the industry?

APPEA delegates never hesitate to give us feedback! Delegates are always seeking insights into how the global market is changing – the opportunities and risks ahead. Our international speakers bring a different perspective to these issues.

Delegates are acutely aware that technology as well as markets are changing rapidly, so there is strong interest in practical stories of innovation and business transformation.

The industry is not quarantined from the changes occurring in society. The Diversity and Inclusion plenary generated a lot of healthy discussion in 2017 and is very much a theme for this year’s conference.

APPEA strives to deliver a broad program which appeals to everyone in the industry.

Q. Can you describe this year’s theme ‘Resilient Business: Success in

the New Energy Market’?

Every APPEA conference is built around a broad theme which captures the issues of the day while also posing some big, strategic questions. Resilience is a simple word but it captures a host of challenges.

The last three years have tested the capacity of every business in the industry to adjust to tough market conditions.

Successful companies have done more than just cut costs and rationalise assets. Business strategies have changed as has business methods. The enthusiasm for industry collaboration is just one example. And where better to share these insights than the APPEA Conference?

Looking at the energy market, we have the bizarre situation that the need for more gas has never been more obvious or more pressing – for Australia and our global customers – but the political conversation is dominated by other agendas. APPEA is warning that government intervention in markets is

jeopardising essential investment and adding unnecessary costs and risks.

Q. How will this year’s conference and exhibition differ from previous

years?

APPEA is known for its world-class keynote speakers, the high-quality technical and business program and the showcase of the industry, the APPEA Exhibition. These elements are stronger than ever in our 2018 program, with some twists.

The Product Presentation Theatre is an arena on the Exhibition floor, where exhibitors will present their products and services. The theatre is a great opportunity for our exhibiting companies and to our delegates who will see first-hand, in a professional setting, the latest technologies.

In partnership with EY, APPEA will host the EY Collaboration Centre on the exhibition floor. The centre will be open to delegates to come together at breaks in the program to debate their industry issues. It’s an ideal way for groups who wish to discuss a particular topic to meet in one spot and not get lost in the crowds. A full calendar of topics will be issued two weeks out from the event.

We are very excited to launch the APPEA Conference Youth Program at Adelaide. This initiative will see high school students experience a day at the conference. Their program will include meeting industry leaders, learning about career opportunities in the industry, and seeing the latest in technologies.

Promoting the industry to students is essential to ensure we continue to attract talented people.

Q. Who are the keynote speakers and what will be some of their biggest

discussion points?

There are too many to list everyone, but names such as Peter Coleman and Shaun Gregory (Woodside), Nigel Hearne (Chevron), Zoe Yujnovich (Shell), Kevin Gallagher (Santos), Peter Bennett (Clough), Larry Marshall

(CSIRO), Diane Smith-Gander, Tom Quinn (Broadspectrum) and Matthew Kay (Beach) will provide delegates with industry perspectives on subjects ranging from the Global Energy Outlook and Diversity and Inclusion, to Technology and the Supply Chain dynamics.

APPEA has also secured speakers outside the immediate industry to provide unique perspectives and to provoke debate.

Amy Mayers Jaffe is one such speaker who is direct from Washington DC. Its Amy’s first visit to Australia so I anticipate we will hear some new views in her address ‘Competing options for energy transformation: Implications for Australia’.

Q. Why did APPEA choose to hold the conference in Adelaide this year?

South Australia is an important part of our industry. The South Australian government has also been a great advocate for natural gas as well for renewables.

With the new investment flowing into the Cooper Basin, the vast potential of the Great Australian Bight and the lift in onshore exploration, South Australia has exciting stories to tell.

Q. What are your predictions for the energy industry through 2018 and

2019?

I am looking forward to a steady improvement in market conditions, with our LNG exports surging and earning better prices.

Exploration remains a real concern, with activity very subdued and governments doing little to help. One of the great ‘known unknowns’ is how much more demand we may see in the national electricity market for gas-fired generation, given the increasing penetration of renewables and the closure of Hazelwood.

Q. How do APPEA’s networking opportunities differ to other industry

conferences?

As the APPEA Conference is only open to paid delegates and exhibitors and invited guests (it’s not open to the general public), everyone at the event is a potential quality contact.

APPEA prides itself on creating the ideal environment for four days of industry networking - and making new contacts at APPEA 2018 is guaranteed!

We gather the entire supply chain, regulators, stakeholders and community groups to come together to discuss and network.

Each day there are multiple opportunities to meet with your target market and industry sector or to take advantage of the ‘one stop shop’ and mix with new contacts.

The Exhibition floor, refreshment and lunch breaks, the official members and authors lunch, the happy hours, the EY Collaboration Centre with their ‘Hot Topics Program’ – all opportunities to mix with quality industry and stakeholder representatives.

Q. How were registrations going?

The exhibition is close to sold out with more than 100 exhibitors preparing for their showcase at APPEA – so we are well on track for another great turnout.

We are certainly looking for over 2000 attendees to come and see APPEA 2018 and all it has to offer!

Q. What are the key benefits for delegates that attend APPEA?

There is no other event which brings together all the industry’s movers and shakers for a deep dive, over three days, into the issues which will drive the market.

We are excited to be liaising closely with our exhibitors for APPEA 2018, so delegates can be treated to the latest innovation in the industry.

Signs are that there will be some really exciting technology launched and showcased at the event. The conference is the essential event to meet colleagues, do deals and learn.

The annual Australian Petroleum Production and Exploration Association (APPEA) conference and exhibition returns to Adelaide next month, bringing together oil and gas professionals, industry leaders, analysts and policymakers from across Australia and the world. Elizabeth Fabri spoke with APPEA chief executive Malcolm Roberts about what

delegates can expect from this year’s conference, running from 14-17 May.

Image: APPEA.

BUSINESSRESILIENT

11APRIL 2018

THE AUST�LIAN ENERGY REVIEW APPEA

CONFERENCE HIGHLIGHTS

Monday 14 May

• The Petroleum Exploration Society of Australia (PESA) Deal Day | Held at Adelaide Convention Centre, Deal Day is an annual showcase for acreage and farm-in opportunities in Australia and the neighbouring region in a presented papers format. Registrations are at www.pesa.com.au.

• Site Tour: ‘Innovation and Excellence’ | This pre-conference event tours three facilities in Adelaide including; Australia’s first Innovation District at Tonsley, the Onshore Petroleum Centre of Excellence (OPCE) and the South Australia Drill Core Reference Library followed by afternoon tea.

• Welcome Reception: ‘You had me at Merlot…’ | The first official social function of APPEA 2018.

Tuesday 15 May

• Resilient business - the success in the new energy market | The first plenary session will include comment from Government, Santos chief executive Kevin Gallagher, and APPEA and Shell Australia chairman Zoe Yujnovich.

• Energy transformation - the future is now | Speakers from Woodside, CSIRO, Chevron and ConocoPhillips will provide perspectives on the changing global energy system.

Wednesday 16 May

• Diversity and inclusion - what is beyond the tick box? | This session considers what diversity and inclusion really means for the industry.

• Conference dinner - Experience the Iconic | Delegates can book tickets to dine at the historic Adelaide Oval.

Thursday 17 May

• Technology and Innovation - the keys to a resilient business | Industry experts consider a hands-on approach to the use of technology to enable it to thrive.

• A Resilient supply chain - what does success look like in the new energy market? | Major producers, contractors, small businesses and start-ups discuss how to secure business in a new market.

12 APRIL 2018

THE AUST�LIAN ENERGY REVIEWPLUTO GAS

THE Pluto LNG project is a joint venture between Woodside, the operator, which has a 90 per cent interest, and offtake partners Tokyo Gas (five per cent) and Kansai Electric (five per cent).

It took just seven years from the discovery of the Pluto gas field in 2005 to complete the offshore and onshore infrastructure and begin production from its first LNG train.

A 5.1 million tonnes per annum (mtpa) processing facility is fed from the Pluto and Xena gas fields, which are estimated to contain a combined 5 trillion cubic feet (Tcf) of dry gas.

During 2017, Woodside and its partners had been engaging with third-party resource owners in the region about the potential to process gas through Pluto infrastructure as part of expansion plans laid out in early February last year.

Initial studies for a small-to-medium scale 0.7mtpa to 3.3mtpa second LNG train and connecting the plant to the North West Shelf (NWS) LNG complex were concluded, broadening Woodside’s expansion options.

Dubbed the “Burrup Hub”, the Pluto-NWS Interconnector is intended to unlock incremental value for both Pluto LNG and the North West Shelf project, of which Woodside owns a 25 per cent stake.

The company said subject to joint venture, regulatory and other approvals, developing a pipeline connection between the two plants would accelerate Pluto area gas reserves, and leverage existing Pluto offshore capacity and emerging production from the NWS.

Then, in February, Woodside

surprised the market with a massive $2.5 billion capital raising for a revamped LNG expansion initiative which included the acquisition of ExxonMobil’s 50 per cent share of the undeveloped 7.3Tcf Scarborough gas field for $US744 million – giving the company a 75 per cent stake in the project.

The funds will also be used towards the Pluto facility expansion, Pluto-NWS Interconnector and first-stage development of the SNE discovery off the coast of Senegal.

Woodside chief executive Peter Coleman pegged the cost of the Scarborough project, involving the offshore development, pipeline and second Pluto LNG train, at up to $US9.7bn, with a potential cost of $US7.9bn for Woodside.

“At Pluto, we have done thorough groundwork on options for expanding production, which we are now able to use in our development planning for Scarborough, taking account of our increased equity and the certainty this delivers,” Mr Coleman said.

Woodside has set a 2020 final investment decision (FID) date on development.

Domestic Gas

Woodside commenced studies this year to increase domestic gas supply to WA under an obligation penned with the State Government to feed a portion of total LNG production to the domestic market, five years after first gas flow from Pluto.

Under the reservation policy, 15 per cent of LNG production from certain gas fields has to be offered to WA customers.

Companies are obliged to reserve and market the gas, however not required to sell if it is not commercially viable.

Woodside’s five year grace period expired in May last year, and according to the WA Department of Jobs, Tourism, Science and Innovation, the company is required to commit 110 TJ/d at Pluto’s current export capacity.

Woodside however, said that domestic supply shortages were not an immediate concern for WA.

“For now the market has significant excess of supply and capacity,” a Woodside spokesperson said.

“Woodside is proposing Pluto projects that could address this by creating new demand, for example trucked LNG, and will also study options that could supply more, as and when viable demand emerges.”

While no domestic supply – nor Government intervention to force its policy – had yet surfaced, the oil and gas producer said it was progressing studies for the installation of a compressor at Pluto that would be capable of delivering LNG into the Dampier-Bunbury Natural Gas Pipeline at rates of between 10 terajoules (TJ) and 25 TJ per day.

Preparations were also underway for the first delivery of trucked LNG with the construction of a truck-loading facility at Pluto to distribute gas to mining and marine industries throughout the Pilbara region.

Potential applications for the gas include remote power generation and heavy transport fuel.

Primary approvals were progressing for construction, and the company anticipated both projects would be able to start supplying WA’s domestic market in the second half of 2018.

Operations

Woodside said a focus on “operational excellence” had driven an improvement in Pluto’s plant capacity, resulting in record daily, weekly and monthly production rates during 2017.

The company said the results were achieved following the completion of high-rate production trials in Q2 2017.

Pluto produced 41.1 million barrels of oil equivalent (MMboe) at a unit production cost of $3.9/boe, achieving 100 per cent reliability during Q4 and averaging 94 per cent reliability across the 12 month period.

The facility delivered 66 LNG cargoes, of which 44 were sold under foundation contracts, 14 under mid-term contracts and eight on the spot market.

Woodside chief executive Peter Coleman said the fourth quarter was underscored by a strong operational performance at Pluto and first shipment from Wheatstone.

“Pluto LNG delivered excellent production on the back of outstanding facility reliability and higher operating rates,” Mr Coleman said.

This year, Woodside said the facility would target maintaining higher rates through ongoing process improvements using 4D seismic data collection.

The data would also be used to consider the optimal offshore gas supply sequence for Pluto LNG through to end of field life.

No major maintenance or turnaround campaigns had been scheduled for 2018, however preparations were underway for a scheduled major turnaround in 2019 prior to Woodside making an FID for Scarborough and the Pluto developments.

The Pluto LNG project is at the centre of Woodside’s development plans as the oil and gas producer looks to commit to its Scarborough

project and increase domestic gas supply to the WA market.

Image: Woodside.

OPPORTUNITYDEVELOPING

CAMERON DRUMMOND

13APRIL 2018

THE AUST�LIAN ENERGY REVIEW PLUTO GAS

Home away from home

SEARIPPLE Karratha is a workforce accommodation village that has been a critical enabler to major resources projects in the WA Pilbara.

Originally a caravan park, Searipple was purchased by modular builder Fleetwood in the late 1980s, developed into a construction camp, and more recently into a modular accommodation village.

Over the years, the village has housed thousands of workers who have been contracted to work at WA’s resources and construction projects.

“We are proud to have been able to provide an accommodation solution that supported the development of resources and construction projects in the Pilbara,” Fleetwood Village Operations executive general manager Dominic Letts said.

The property, which spans 15 hectares, is comprised of more than 1300 rooms, with a key focus on providing guests with good food and good rest.

“Our guest is the centre of everything we do,” Mr Letts said.

“FIFO is tough and we aim to do what we can to make life easier for our guests.

“That’s why we continue to innovate. “One example of this is the Glyde

technology we have created, which has removed the burden of guests to check in and check out, allowing them to go straight to their room on arrival and use our smartphone app to access their room for the duration of their stay.

“When it’s time to go home they simply close the door and Glyde checks them out.”

The village also has a large selection of facilities to make guests feel at home, including Gunners Grill & Wok, Tates Restaurant, Denisons Takeaway, and Gillys – a fully licensed social hub and beer garden.

Then, there’s Searipple’s array of recreational facilities that offer an outlet

after a hard day’s work or travel.“Guest wellbeing is very important for

us so we have dedicated a full time staff member to it,” Mr Letts said.

“This person’s main aim is to ensure that you feel at home while staying with us.

“They can design a personal training program for you, facilitate your involvement in nightly sporting actives or take you on our hosted weekend excursions.”

Searipple’s facilities include two gyms, two pools, grass playing field that is perfect for touch footy or backyard cricket and a basketball/tennis court.

More information on Searipple can be found by visiting www.searipple.com.au.

WA

Searipple offers comfortable ensuite accommodation set within attractive grounds.

14 APRIL 2018

THE AUST�LIAN ENERGY REVIEWHEAT EXCHANGERS

15APRIL 2018

THE AUST�LIAN ENERGY REVIEW15THE INTERVIEW

Q. Australia will soon take the crown as the largest LNG exporter

in the world. How can exporters and domestic consumers come to a resolution over the east coast gas

crisis?

There are several proposed ‘solutions’ to the east coast gas crisis. Each one has costs and benefits. Rather than be exposed to of export markets, domestic gas customers are starting to be more proactive in securing supply. There needs to be a better way of transporting gas domestically from regions of relatively abundant supply to the other side of the country. We might see more examples of relatively low capital intensity floating storage gasification units being built in areas of high demand. New gas pipelines, processing centres and storage infrastructure will help to reduce shortage scenarios and hopefully reduce the likelihood of adverse supply events and price shocks. With gas trading becoming a lot more sophisticated, we might also see Australian gas producers procure cheaper gas overseas and then resell to the domestic market. On the supply-side, the Federal Government is doing various things to encourage greater offshore exploration which may help alleviate things in the longer term. There’s no single magic bullet unfortunately; it needs all parties to come together.

Q. How effective do you think the Government’s National Energy

Guarantee will be in easing problems faced by the market?

While the Federal Government’s new energy policy, the National Energy Guarantee (NEG), purports to address some of the big challenges facing Australia’s energy sector, we await the details. The basic goals of the NEG – affordable, reliable, competitive and secure energy – are commendable, but there’s currently a lot of uncertainty in the market about the execution. There’s a lot of concern about the NEG effectively ‘gold-plating’ the energy system just as a few years ago with the Australian electricity network. Manufacturers, households and industry are worried the NEG will lead to higher energy costs and less competition. The challenge will be getting the various States and Territories on-board; both South

Australia and ACT have opposed the plan. NEG will be back on the table at the next Council of Australian Governments (COAG) meeting in April.

Q. On the back of last month’s AOG conference, can you share some of the insights you gained while meeting with

industry peers?

This year’s AOG 2018 was much more optimistic and forward looking than in recent years. There is a feeling the industry is turning the corner. Conference attendance and the number of exhibitors were up, there were new topics on the agenda and there was an international buzz generated by the large international delegations from Norway, Scotland and Belgium. AOG has always been a conference that brings together operators, the supply chain and services companies. This year however, there were more innovators, start-ups and entrepreneurs in attendance. These companies demonstrated a plethora of new technologies like automation, artificial intelligence, drones and virtual reality. Many of these small-medium sized businesses had the opportunity to interact with the operators to learn how to break into their large target customers at the first-ever NERA SME ConnectER program, which was a great success. Industry collaboration was on the agenda everywhere. Safer Together, the initiative for safety collaboration, was launched for WA and Northern Territory companies. WA Premier Mark McGowan announced the launch of the LNG Jobs Taskforce and Chevron managing director Nigel Hearne discussed how the industry will collaborate on maintenance planning for turnarounds and shutdowns.

Q. Recent stats from the ABS confirm a slump in offshore petroleum exploration. Is this a big issue for the

industry?

Exploration is the lifeblood for any finite resources sector and Australia will be at a competitive disadvantage if it underinvests in exploration, particularly given reports of reserve shortfalls and expectations of strong Asian demand. There’s a need for baseline production growth

and even in the world of US shale, interest in offshore exploration is picking up again. The economics are more supportive than 12-18 months ago. The higher oil price is making the marginal, riskier offshore exploration projects more attractive for companies and they have the cash-flows to fund these types of programs. Also there’s increased political will; State governments are more supportive – the Victorian Government recently released offshore gas acreage as part of its broader gas program, aimed at getting a much clearer picture of resources in the state. We may see an area like the Bass Strait transform from being an oil focus to mostly a gas operation.

Q. How is the oil and gas sector responding to the new energy economy

and what challenges does this bring?

The sector is repositioning to capture benefits of the new energy economy which includes renewables, low carbon energy and battery storage. Many oil and gas companies are transforming their business models to future-proof themselves given the high level of uncertainty over the future energy mix. Many are expanding their portfolios to include solar and wind assets and are becoming energy solution providers. The European headquartered supermajors including Shell, Statoil, BP, ENI and Total are on the front foot when it comes to new energy investment while the North American oil majors are still leaning on the traditional oil and gas model. In Australia, the two latest entrants to the large-scale solar sector are joint ventures with global oil and gas majors – another indicator pointing to the emergence of upstream energy companies into the local renewables market. The lines between oil and gas and energy/electricity are becoming increasingly blurred. There seems to be increased scope for collaboration and cross-industry learning in the emerging new energy sector. Italian oil major ENI recently formed a solar joint-venture with Carnegie Clean Energy, a local renewable energy player. We are likely to see more examples of this in the year ahead. Companies are reshaping their operating models to become ‘energy solutions providers’…active across the energy value chain. This is a definite break from the past when the oil and gas companies were more involved in the manufacturing equipment

side of the market. Strategies and mindsets are changing.

Q. What opportunities are you seeing in the decommissioning space?

Australia has more than 100 offshore platforms and subsea structures (Wood Mackenzie, 2017), in some of the most pristine and unique marine environments on the planet. Decommissioning these assets will be complex, challenging and costly. The current cost of decommissioning of Australia’s oil and gas infrastructure is estimated at more than $US21 billion over the next 50 years (Wood Mackenzie, 2016).The best way to address the challenges of decommissioning is by sharing the burden. Operators, State and Federal governments, the supply chain, regulators, financiers, environmentalists, researchers and others all need to work together in collaborative and innovative ways to reduce the cost and risk of decommissioning and deliver the best outcomes for Australia.With so many offshore decommissioning projects on the near to medium-term horizon, Australia has the potential to become a leader in end of life-cycle asset management, building on the experience in the construction, operations and maintenance of major capital projects. As an industry we need to plan for this eventuality now or skillsets and techniques may need to be imported.

Q. What does the workforce of the future look like in the oil and gas

space?

The sector is increasingly a world of drones, IoT, analytics, robotics, AI and machine learning as companies seek to achieve a step change in productivity levels, gain much greater understanding of their operations and take performance to the next level. It’s entirely possible we will soon see a fully automated offshore oil and gas platform with robots performing all the field operations and a highly skilled human taskforce pulling all the strings onshore. With digital extending its reach, data scientists, computer technicians and software engineers will become the employees of the future, leveraging the power of technology to uncover new reserves, exploit new oil and gas basins and harness the potential of alternative energy.

As confidence returns to the oil and gas sector, there are still big issues weighing on industry as a new energy economy encompassing renewables, low carbon energy and battery storage emerges. Deloitte national oil and

gas leader Bernadette Cullinane spoke with Elizabeth Fabri about the changing energy landscape.

BERNADETTECULLINANE

DELOITTE OIL AND GAS LEADER