The East Coast Gas Market Explained

Transcription

1 The East Coast Gas Market Explained Analysis of the Gas Market Supply and Demand Dynamics APPEA JOURNAL PAPER Submitted: 8 December 2017 Accepted: 15 January 2018 Published: 28 May 2018 at Abstract The Australian East Coast Gas Market is experiencing arguably the most disruptive structural change since its inception with the completion of the 25.4mtpa Curtis Island Liquefied Natural Gas (LNG) facilities and the introduction of a fourth pillar to the market for domestic gas. However, this disruption was not in isolation and coincided with substitutional interactions with electricity market already dealing with transition. This report develops context for the natural gas market, establishes the four major avenues of markets and then investigates eight fundamental supply and demand dynamics that are influencing the market in an interconnected fashion. The report concludes that all participants of the gas market must address the multiple dynamic drivers including economic consideration, government policy and regulatory engagement to avoid disorderly market transition. By Joshua Stabler, Managing Director, Energy Edge

2 Contents Introduction to the Australian East Coast Gas Market... 3 Gas Avenues to Market... 5 Avenue 1: Domestic residential and commercial heating... 5 Avenue 2: Industrial and manufacturing... 6 Avenue 3: Gas Generation... 6 Avenue 4: Liquefied Natural Gas Exports... 6 Supply and Demand Dynamics... 7 Dynamic A: Curtis Island LNG Demand... 7 Dynamic B: Surat Gas Production Dynamic C: Cooper Gas Redirection Dynamic D: Decline in Victorian Gas Production Dynamic E: Environmental and Regulatory Barriers Dynamic F: Role of Gas Storage Dynamic G: Electricity Market Transition Dynamic H: Gas Generation Interactions Conclusions from the Supply and Demand Dynamics Bibliography Further Information Contact Details... 23

3 Introduction to the Australian East Coast Gas Market Natural gas is an important. As the cleanest burning fossil fuel (Energy Information Agency, 2017), natural gas has a vital role in the transition to a low carbon energy future. However, natural gas also has a distinct set of characteristics that has influenced its ability to be exploited as an energy resource. It is gaseous, transparent, odourless and flammable at standard atmospheric conditions, which is a dangerous combination (Energy Information Agency, 2017) requiring odorisation with its distinctive smell. It is also stored under pressure rather than atmospherically neutral commodities such as coal or iron which can be stockpiled. Natural gas is then traditionally transported from upstream production to end consumers via pipeline infrastructure in a continuous method and the pressure must be maintained between the minimum pressure requirements of customers and the maximum pressure of the physical pipeline infrastructure. Natural gas first became a substantial source of energy on the Australian east coast during the 1960 s with the development of three gas resources: Longford in the Gippsland Basin offshore Victoria, Moomba in the Cooper Basin in northern South Australia and Roma in the Surat Basin in Southern Queensland. These supply-side developments were matched with infrastructure to the capital cities via four pipelines: Moomba to Sydney (MSP); Moomba to Adelaide (MAPS); Roma to Brisbane (RBP) and Longford to Melbourne (LMP). By the 2000s, additional interconnected pipelines were added to include the new field developments at Otway Basin in western Victoria with connections to Adelaide and Melbourne via the South East Australia Gas Pipeline (SEA) and South West Pipeline (SWP) respectively. The Eastern Gas Pipeline (EGP) between Longford and Sydney and the South West Queensland Pipeline (SWQP) between Roma and Moomba were also established which meant this was the first time the whole east coast gas network had become interlinked between each of the capital cities. This new interconnectivity provided the market with the ability to trade and compete inter-regionally while also increasing the reliability of the network through increased diversity of supply. This market robustness was highlighted with the Moomba fire incident on 1 January 2004, when Sydney was supplied by Longford and Adelaide was supplied by Otway (Santos, 2017). [The infrastructure as it currently stands has been illustrated in Figure 1]. While the market has and will continue to evolve, each new stage of development be it new physical supply or pipeline infrastructure, state and federal government energy policy or expansion of retail market and attempts to develop financial markets was pursued based on the requirements that were immediately relevant for that period in the market s evolution. The requirements upon the gas markets in Australia in 2018 are remarkably different to those in 1968.

4 Curtis LNG Cooper SWQ P Surat RBP Brisban e MAP S MSP Adelaid e Sydney SEA Melbourn e VNI EGP Otway SWQ LM P Gippsland Figure 1 - East Coast Australia Gas Infrastructure Map as at 2017 (EnergyEdge, 2017)

5 Gas Avenues to Market Natural Gas on the Australian East Coast has four primary commercial avenues to market and exploitation (represented in Figure 2) which further includes context to electricity markets interactions. These market segments have developed based on the physical properties of gas and all require pipeline transportation to reach the market. 1. Domestic residential and commercial heating and energy source 2. Domestic industrial manufacturing as both energy and feedstock 3. Domestic gas generation through conversion of gas energy into electricity 4. International exports via Liquefied Natural Gas and seaborne shipping Figure 2 - Interactions between Australian Energy Markets showing Energy Flows and Circular Behaviour (EnergyEdge, 2017) Avenue 1: Domestic residential and commercial heating Natural gas is currently only utilised to heat residential and commercial areas unlike electricity (which as a substitutional energy source) which can be used to both heat and cool (i.e. air conditioners). Figure 3 highlights the behaviour due to the impact of Victoria s seasonal domestic gas consumption which demonstrates the strong winter peak shape. This contrasts with electricity peak that can occur in both hot and cold weather conditions (EnergyEdge, 2017). Figure 3 - Victorian Declared Wholesale Gas Market Consumption from Jan 2016 to Nov 2017 (EnergyEdge, 2017)

6 Victoria, which has the combination of cool weather and high population, has the highest ratio of homes with mains gas (91.4%), especially when compared to Queensland (19.6%) (Australian Bureau of Statistics, 2017). Both states have similar annual electricity consumption however, the Australian Energy Regulator (AER) State of the Energy Market 2017 (Australian Energy Regulator, 2017) states that Victorian residential and commercial consumption is approximately 115PJ p.a. whereas Queensland is less than 1PJ p.a. Avenue 2: Industrial and manufacturing Industrial and manufacturing sectors utilise natural gas as both a source of energy (via combustion) and chemical process feedstock (i.e. the chemical process converts the gas into a different product). In most cases, it is possible to spend capital to substitute the source of energy from gas to electricity. The utilisation of gas as a feedstock usually has less options for substitution as the manufacturing / chemical process has been defined based on natural gas as an input. For example, the Haber process is used by the Incitec Pivot fertiliser plant 1. According to the AEMO National Gas Forecasting Report, east coast industry accounted for 257PJ during 2017 compared with residential consumption of 190PJ. Avenue 3: Gas Generation Gas Generation incorporates the assets that convert gas supplies into electricity. These assets fit into two primary classes: open cycle gas turbines; and combined cycle and co-gen gas turbines. The important relationship with Gas Generation is that the assets create value between the marginal cost of production and the electricity sales revenues. At the theoretical unconstrained valuation, the asset would have maximum dispatch at times when marginal revenue exceeds marginal costs, although in reality, there are a number of operational, physical, technical and contractual limitations that affect the ability of an asset to be fully optimised. These limitations include start costs, ramp rates, gas supply rates, electricity and gas commodity pricing risk and uncertainty, pipeline pressure thresholds, contractual take or pay obligations and portfolio optimisation. Open Cycle Gas Turbines Open Cycle Gas Turbines (OCGTs) are single pass turbines with a low efficiency of between 25-35% which means that the power station consumes 10-14GJ of gas to produce 1 MWh of electricity. The primary benefits are the lower capital cost, low start-up costs and rapid ramp rates compared with other thermal generators. Combined Cycle and Co Gen Gas Turbines Combined Cycle Gas Turbines (CCGTs) utilise the waste heat from an OCGT and inject it through a steam turbine to gain additional energy production capacity albeit with additional capital investment. In Australia, the CCGT efficiencies range between 45-50% (Australian Energy Market Operator, 2017), although technical best practice is currently 60.75% (Siemens, 2017). Co Gen Gas Turbines utilise the exhaust heat for additional manufacturing processes rather than additional electricity production which results in a higher whole-ofprocess efficiency. Avenue 4: Liquefied Natural Gas Exports As noted earlier, natural gas is gaseous, transparent, odourless and flammable under normal atmospheric conditions (Energy Information Agency, 2017). These features allow the gas to 1 Industry have provided the following description of the manufacturing process for fertiliser development. The process is a steam methane reforming, in which natural gas is reacted with steam on a nickel catalyst to produce hydrogen gas. The Haber process then reacts the hydrogen gas with nitrogen gas from the atmosphere on an iron catalyst to produce ammonia, which is a fertilizer itself, or can be reacted with other compounds to produce other fertilizers such as urea or ammonium sulphate.

7 be pressurised and eventually liquefied if cooled to -162 o C which reduces the volume of the gas to 1/600 th of the size (Energy Information Agency, 2017). The primary benefit of the Liquefied Natural Gas (LNG) process is that the gas can be transported to regions where pressurised pipeline is not technically or economically feasible (i.e. overseas or long distances) (Energy Information Agency, 2017). The process for this converting to LNG was first commercialised in 1917 with the first seaborne trade between Algeria and United Kingdom in 1964 (California Energy Department, 2017). Australia commenced LNG exports from the North West Shelf LNG facility (near Karratha, WA) to Japan and South Korea in 1991 (California Energy Department, 2017). Table 1 provides a listing of the key dates for the six-year journey of the Curtis Island LNG facilities between first Final Investment Decision (FID) of QCLNG in October 2010 and final First LNG of APLNG train 2 in October Table 1 - Curtis Island LNG Facilities Key Dates (EnergyEdge, 2017) LNG Facility Operator Nameplate FID Train 1 First LNG Train 2 First LNG QCLNG Shell 8.6mtpa 30-Oct Dec Jul-2015 APLNG Origin 9.0mtpa 04-Jul Jan Oct-2016 GLNG Santos 7.8mtpa 13-Jan Sep May-2016 Supply and Demand Dynamics The supply and demand dynamics of the East Coast of Australia have been extremely complex to dissect due to the multifaceted interactions between the several macro market fundamental changes. These include: a) The speed, quantum and location of the new consumption of the three Curtis Island LNG facilities (Curtis Island LNG Demand) b) The expansion of the local Surat production in advance, during and subsequent to the Curtis Island demand growth and the interaction of oil price with the drilling programs (Surat Gas Production) c) The changing interaction of the Cooper basin production with the domestic market due to the nature of the physical contractual obligations with related party LNG participants (Cooper Gas Redirection) d) The continuous decline of the legacy production facilities connected to off-shore Victorian gas production (Decline in Victorian Gas Production) e) The environmental and regulatory barriers to entry for on-shore developments in Victoria and New South Wales (Environmental and Regulatory Barriers) f) The interaction between gas storage facilities and the ongoing market dynamics (Role of Gas Storage) g) The changing electricity market generation structure with increasing renewable penetration and the implications of exits by coal fired power station as they reach end of life (Electricity Market Transition) h) The implications of these fundamental gas supply and demand drivers on the role of gas generation (Gas Generation Interactions) Dynamic A: Curtis Island LNG Demand The following analysis on the Curtis LNG facilities located within the Gladstone Port focuses on two major influences on the domestic market; the volumes of gas in terms of sheer quantum and interaction; and the LNG netback price calculations based on the Japanese Crude Cocktail (JCC)-trained outcomes.

8 Expansion of LNG Volumes Figure 4 - East Coast Gas Consumption from Jan 2009 to Nov 2017 (Domestic, GPG and LNG Exports) (EnergyEdge, 2017) The three LNG facilities at Curtis Island are: 8.6mtpa Queensland Curtis LNG (QCLNG: 73.75% Shell, 25% CNOOC, 1.25% Tokyo Gas) 9.0mtpa Australia Pacific LNG (APLNG: 37.5% Origin, 37.5% Conoco Phillips, 25% Sinopec) 7.8mtpa Gladstone LNG (GLNG: 30% Santos, 27.5% Total, 27.5% Petronas, 15% Kogas) Figure 5 - LNG Throughput compared to 115% Nameplate Capacity from Jan 2017 to Nov 2017 (EnergyEdge, 2017) The combined nameplate of the three LNG facilities is 25.4mtpa which equates to a domestic consumption of 3,866TJ/d. However, the assets have shown the capability of up to 15% overload capacity (29.2mtpa). The comparison of throughput to the full 115% capacity has been highlighted in Figure 5.

9 At full capacity, the three LNG assets consume 4,445TJ/d, which is 67% more than the 99 th percentile peak of the remainder of the East Coast gas consumption (2,660TJ/d 2 ). The high East Coast usage is isolated to the coldest day of the winter as opposed to a daily capacity all year around. At the time of writing, the peak export rate has reached 23.7mtpa (compared to the 115% capacity limit of 29.2mtpa) 3. Since the commencement of the final LNG train (APLNG 2 which reached First LNG in October 2016), the LNG facilities have each seen wide ranges of variability (between 0% and 115% of nameplate) in consumption, however, the variability is most managed within the boundaries of the Curtis Island facilities. This has been graphically represented via a wide ranged histogram of capacity factor percentages for each of the LNG facilities (Orange, Red and Blue) compared to the more concentrated aggregated outcome (Grey Area). The drivers for this behaviour is due to a combination of location of physically available capacity of equivalent size; prearranged bilateral contractual arrangements between the facility operators; and limited to the flexibility of the upstream CSG production facilities. Figure 6 - Histrogram of Daily Capacity Factors for Curtis Island Individual and Aggregate from Jan 2017 (EnergyEdge, 2017) Netback Price Calculations The second component of the LNG analysis focuses on the LNG Netback Price Calculations which are calculated prices based on reported Japanese Crude Cocktail (Quandl, 2017) headline price outcomes but aligned these with the live rather than delayed Brent oil prices. This means that the analysis is a generalisation of the public market rather than an assessment of any individual participant s private contractual arrangements. 2 99% Percentile of aggregated domestic residential, industrial and commercial and gas generation (Energy Edge Gas Market Analysis Tool). 3 December 2017

10 Figure 7 - LNG Netback Price Calculation (EnergyEdge, 2017) Further to the Netback Calculation, a range has been developed to allow for the inclusion or exclusion of long run costs with regards to the access to the international gas markets. This also creates a range with an upper boundary (international price parity excluding long run costs) and lower boundary (international price parity inclusive of all long run costs), which theoretically represents economically rational LNG participant behaviour (i.e. willing to buy at lower bound and willing to sell at upper bound). The resultant Figure 7 provides a comparison between Energy Edge s assumption-based assessments of LNG netback prices compared to the domestic gas market outcomes (30-day rolling average domestic market for visualisation clarity). Of interest from Figure 7 is the large proportion of time that the regional domestic market outcomes remain within the range of the Netback Price Calculation, especially the regionally adjacent Queensland market. This indicates that there is rational buying and selling from the LNG participants into the domestic market allowing for the ability for the participant to discretionally change their consumption. The primary periods of excursion outside the range are winter 2016 (see Gas Storage below), summer 2016/17 (see Spark Spread below) and autumn 2017 (see Regulatory below). Dynamic B: Surat Gas Production Surat Gas Growth With LNG s quantum increase in demand for exports, there was a reciprocal shift up in the supply side to match. This was primarily facilitated by the same three participants, although not necessarily equally aligned to consumption. The imbalance between participants has been contractually arranged with some third-party commitments from traditional domestic supplies (i.e. Santos Horizon contract from Cooper Basin) (Santos, 2017). In the Surat Basin, the development and growth has been remarkable. Between 2015 and 2016, the average year-on-year growth was 1,465TJ/d and from 2016 to 2017YTD also saw an understated growth of 480TJ/d which has been highlighted in Figure 8.

11 Figure 8 - Surat Basin Production - Year on Year Comparison to 2017 (EnergyEdge, 2017) Surat Production Growth vs LNG Demand Growth Further to the comparison against the LNG demand growth, Figure 9 provides a comparison between the new Surat Production compared to a 2013 baseline (i.e. pre-lng production development) against the LNG consumption. This figure provides some visual context to the ramp gas phase during late 2014 when new supply was active in advance of the LNG facilities commissioning schedule. The next phase shows the relative alignment of new LNG and new production during However, 2016 shows a widening of the imbalance (i.e. more demand than new production) which was sourced from interregional supplies and reduced local consumption. For 2017 to date, the dynamic has become more balanced although at the time of writing, LNG exports were beginning to increasingly access interregional suppliers as Brent has rallied (Figure 7). Figure 9 - Surat Basin Production Increase from 2013 c.f. LNG Exports 2013 to 2017 (EnergyEdge, 2017)

12 Dynamic C: Cooper Gas Redirection The Cooper Basin, located in northern South Australia and dominated by the Cooper Basin Joint Venture (Santos ~66%, Beach ~34%) with the 450TJ/d Moomba Gas Plant (Australian Energy Market Operator, 2017). Originally developed as the sole supply of gas to Adelaide and Sydney in 1960s and although both capital cities introduced diversification of gas supplies from Victoria by the early 2000s, the region remains an important cornerstone of the east coast gas supply. Of interest has been the evolution of the role of Cooper Basin over the past six years, especially in light of the Cooper s support of the Queensland and Southern Gas Markets. Figure 10 - Flows into Queensland Gas Market (EnergyEdge, 2017) The deliveries from the Cooper Basin toward the Queensland Gas Market (i.e. via the South West Gas Pipeline or SWQP) since 2012 has been highlighted in Figure 10. It can be noted that SWQP was consistently delivering from Queensland toward Cooper until early 2016 when the pipeline reversed rapidly toward consistent and solid ( TJ/d) deliveries into Queensland until mid Between May and September 2017, the pipeline was regularly delivering 100TJ/d to Cooper with a recent reversion at the time of writing 4. Figure 11 - Flows into Southern Gas Market (EnergyEdge, 2017) 4 December 2017

13 On the other side of the Cooper Basin equation (refer Figure 11), deliveries toward the Southern Gas Market (i.e. via Moomba to Adelaide Pipeline (MAPS) and Moomba to Sydney Pipelines (MSP)) followed the seasonal shape of the domestic retail market until early 2017 when deliveries were almost zero except over the May to September 2017 period which aligned with the 100TJ/d deliveries from Queensland to Cooper (Figure 10 above). The causality of this change in behaviour has been in the growth of the Curtis Island LNG facilities and the contractual arrangements (namely the Horizon Gas Contract) between Moomba Gas Plant s operator, Santos and the related Gladstone LNG facilities. The ramp up of the GLNG train 1 and APLNG train 2 during December 2016 and January 2016 was the primary causality of the change in significant behaviour noted in Figure 10 and Figure 11 above. Dynamic D: Decline in Victorian Gas Production Otway Decline Rates Figure 12 - Otway Gas Production from Jan 2009 to Nov 2017 (EnergyEdge, 2017) The conventional extraction of gas production facilities in offshore Victoria have a dynamic and decaying field capacity limit which is easily observed over a long horizon. Figure 12 shows the long term daily production of Beach Energy s recently acquired Otway Gas Facility. On a dayto-day basis, the shape of the field decline is masked but over a long-time horizon, the field degradation and integration of new production are clear. This physical field limit is technical response to decaying field pressure (Mikael Höök, 2013) and has been noted across many of the gas production facilities (EnergyEdge, 2017), but the fact that Otway has a significantly higher infrastructure limit compared to the field limit makes the relationship more easily observable. Gippsland Forecast Limitations Located on the South Eastern corner of Australia, the Gippsland Basin and Southern Gas Market is dominated by the 1000TJ/d Longford Gas Plant owned by the Gippsland Joint Venture (46% ExxonMobil, 46% BHP, Mitsui 8%). The facility was first developed in 1965 (ExxonMobil, 2017) and has since been critical to the energy security of Victoria and eventually via pipeline connections, Tasmania and New South Wales. This is highlighted by the fact that the Longford Gas Plant alone has supplied 69% of the gas requirements of Victoria, New South Wales and Tasmania since the beginning of 2016 (EnergyEdge, 2017).

14 At the time of writing 5, Longford had recently completed the Kipper expansion. According to production figures reported to AEMO (Australian Energy Market Operator, 2017) and ACCC (Australian Competition and Consumer Commission, 2017), the asset will reduce in production to levels for the 2018 calendar year, which is a 25% (or 222TJ/d) reduction on annualised production rates. This annualised number provides limited information on the shape of the production from Longford which has a visibly different seasonal shape to Surat Basin production rates in Figure 8. Furthermore, the decline rates noted above are not as clearly discernible for Longford Gas Plan (Figure 12) as they were for Otway. This means they don t exist rather, the limitations appear to have been isolated to the production level, not the field level. As a result, there is a shadow limit on the facility, but not one that a third party can see. Figure 13 - Longford Production - Year on Year Comparison from 2010 to 2017 (EnergyEdge, 2017) Dynamic E: Environmental and Regulatory Barriers At the time of writing, the environment and regulatory barriers to entry for new production in onshore New South Wales and Victoria (Victoria Premier, 2017) remain in place. Rod Sims, Chairman of ACCC, has stated succinctly that: It is easy to accept that some projects will fail on environmental grounds; it is, however, difficult to accept they all do. (Sims, 2017) This is a clear representation of the issue where new production has been incorporated into the forecast and anticipated supply and demand dynamics in advance of a period of time, but the barriers have limited the ability for the market to exploit those conditions into reality. While not passing judgment on the introduction of those environment and regulatory barriers, there has been a clear mismatch between the anticipated upstream solutions and their ability to be converted into reality. Adding to the regulatory barriers is the Federal government s intervention on the LNG participants with the Australian Domestic Gas Security Mechanism (ADGSM) (Australian Department of Industry, Innovation and Science, 2017), which introduces a barrier for LNG participants to actively purchase from the domestic market. This has been recently noted with the domestic deviation below the LNG netback price range (see Figure 7 above). 5 December 2017

15 Dynamic F: Role of Gas Storage While Australia does not have the working capacity of gas storage that the United States (approximately 5,000PJ) has (Energy Information Agency, 2017), gas storage on the East Coast remains critical infrastructure with each of the primary gas storage facilities holding different roles, responsibilities and intrinsic value. One of the more seasonally critical gas storage facilities is the Iona Gas Storage Facility located in western Victoria with up to 26PJ of working storage and up to 300TJ/d of withdrawals and injections (Australian Energy Market Operator, 2017). The asset has a high utilisation each winter, historically filling up in lower domestic demand periods of between spring and autumn before withdrawing heavily during winter to meet the seasonal shape of Victorian retail gas market. Figure 14 - Iona Gas Storage Year on Year comparison 2013 to 2017 (EnergyEdge, 2017) Iona Gas Storage has been subjected to two significantly different winters in 2016 and During 2016, the facility was at a historical low leading into winter before rapid extraction of gas saw a historical minimum storage level of 7.5PJ by mid-july During the period between 23 June and 15 July, the average gas price in the Victoria and South Australian Gas Markets was $16-$17/GJ, with a peak in Victoria of $43.55/GJ on 13 July These high prices were partially driven by the limited extraction capacity of the Iona Gas facilities at low pressures. In comparison, winter 2017 was significantly more subdued for the southern markets (ranging between $8.80-$9.80/GJ) with the facility storage level remaining robust for most of the winter despite equivalent levels leading into May for both years. However, due to reduced facility withdrawal during June 2017 and refilling during August, the Iona Gas Storage facility had recovered to a historical maximum storage level for October 2017, exceeding the conditions during the ramp gas 6 period prior to the commencement of LNG facilities during late Ramp Gas was a common industry term used to describe the excess gas supplies in the lead up to the first LNG facility in late 2014.

16 Dynamic G: Electricity Market Transition Transition away from Coal and toward Renewables Between 2006 and 2017, 4,600MW 7 of coal fired generation exited the market with only the 750MW Kogan Creek entering the market in response. During that same period, 2,980MW 8 of gas generation was committed across every region of the east coast. In comparison and at the time of writing, there was a reported 3,810MW of new renewable project under construction, i.e. developed, financed and due to be online within the next two years. While it would be disingenuous to state that all replacement capacity is like-for-like, it is still going to have an incredible impact on the shape and design of future electricity markets. This has of particular interest for gas, as most new variable renewable generation is characterised by its highly correlated energy source (e.g. windy days in South Australia are windy for the entire coastline and the same for sunny days). Gas generation continues to hold a strong market position as a discretional supplier of electricity with an acceptably moderate environmental footprint due to strong dispatch capability and abundancy of potential domestic gas resources. Dynamic H: Gas Generation Interactions Calculation of Spark Spread Spark Spread is defined as the difference between the price received by a generator for electricity produced and the cost of the natural gas needed to produce that electricity. (Energy Information Agency, 2017). In the case of East Coast Australia, it is the difference between the half-hourly electricity spot market revenue at the local regional reference node and the daily gas costs based on the closest publicly referenced gas market (STTM or DWGM) compared to using a consistent unit of measure (i.e. $/MWh allowing for the heat rate of the gas turbine). Spark Spread is used as a comparison index for the inflection point where economically rational gas generators are motivated during times of high spark spread to commit their assets to dispatch and motivated during negative spark spread to de-commit or limit dispatch. While there are non-trivial complications to this simple strategy such as start costs for gas generators, plant availability, physical ramp rates, gas contract liquidity, gas take or pay contracts and electricity price forecasting accuracy, there are still strong relationships between spark spreads and dispatched generation (EnergyEdge, 2017). OCGT Spark Spread compared to Gas Generation Output The following two scatterplot graphics shows similar behaviour between the spark spread (horizontal axis) and the dispatch of OCGT Gas Generators (vertical axis) for both Queensland (Figure 15) and South Australia (Figure 16) regions. These figures highlight the strong rational behaviour to increase dispatch during periods of high electricity outcomes compared to gas costs and both regions have active and/or independent gas generation assets. A simple linear regression has been overlayed to highlight the relationship. However, the perfect (physically, technically and realistically unachievable) result would see zero dispatch at negative spark spreads and full dispatch at positive spark spreads. 7 Hazelwood (1400MW), Wallerawang (1000MW), Munmorah (660MW), Northern (500MW), Swanbank B (500), Playford B (240MW), Collinsville (160MW), Redbank (150MW) (Australian Energy Market Operator, 2017) 8 Braemar 1 (450MW), Braemar 2 (450MW), Tallawarra (450MW), Darling Downs (660MW), Condamine (140MW), Colongra (660MW), Uranquinty (640MW), Tamar Valley (240MW), Quarantine (150MW) (Australian Energy Market Operator, 2017)

17 Figure 15 Queensland OCGT Spark Spread vs OCGT Gas Generation Jun-Aug 2017 (EnergyEdge, 2017) Figure 16 South Australia OCGT Spark Spread vs OCGT Gas Generation Jun-Aug 2017 (EnergyEdge, 2017) Comparing Spark Spread Outcomes The following four figures show the 2017 daily mean electricity outcomes (Blue lines) and calculated gas costs for OCGTs (Pink) and CCGTs (Green) in a common unit ($/MWh) allowing for the different efficiencies of the assets to provide a graphical illustration of the market relationships. Queensland Outcomes Queensland s relationship (Figure 17) between Electricity and OCGTs remains strong throughout January and February 2017 saw extreme electricity outcomes averaging $217/MWh for the two months. It is also noted for most of analysis period, there was a substantial difference between the electricity revenue outcomes (blue) and the CCGT costs (green).

18 Figure 17 - Queensland Electricity Outcomes vs OCGT/CCGT Gas Prices (2017) (EnergyEdge, 2017) New South Wales Outcomes New South Wales (Figure 18) has seen variable market outcomes with periods aligning with OCGT, CCGT and some periods of disconnected results. Figure 18 - New South Wales Electricity Outcomes vs OCGT/CCGT Gas Prices (2017) (EnergyEdge, 2017) Victoria Outcomes Victoria (Figure 19) saw a substantial alignment in the relationship between electricity and gas with the exit of Hazelwood at the end of March 2017 (EnergyEdge, 2017) with visually aligned results since April. Note that there are no CCGTs within Victoria which has been primarily driven by the historical overhang of baseload brown coal assets (Australian Energy Market Operator, 2017).

19 Figure 19 - Victoria Electricity Outcomes vs OCGT Gas Prices (2017) (EnergyEdge, 2017) South Australia Outcomes South Australia (Figure 20) saw significant variability during 2017 in the daily electricity and gas price. This is strongly aligned with the high penetration of wind generation in the region which creates large swings between oversupply and undersupply resulting in daily disconnects to the gas market, although a clear relationship between electricity and gas price exists. Figure 20 - South Australia Electricity Outcomes vs OCGT/CCGT Gas Prices (2017) (EnergyEdge, 2017)

20 Conclusions from the Supply and Demand Dynamics This report has been developed to promote discussion around the drivers of the East Coast gas market including the four structural avenues to market and the interactions of the key supply and demand dynamics. Further to that context, it is important to remember that the current gas market is not new, it has been inherited. It was not pre-planned or designed for our current conditions, it is the result of evolution of the infrastructure and industry. Participants (be it producers, retailers, generators, end users or government agencies) have responded progressively over the last 50 years to the economic, political drivers and conditions at the time to develop new strategy, new policy and new markets. As such, the gas market is now responding to possibly the largest influence ever on the East Coast energy market in the development and operation of the Curtis Island LNG facilities during 2015 and LNG exports have dramatically rearranged the landscape in terms of both gas volumes and price. On the volume side, the sheer volume of gas consumed by LNG facilities has seen the Surat upstream production increase by 330% in the three years to November This is an understated and incredible achievement given this new development is larger than the rest of the entire east coast gas market combined which took fifty years to develop. The physical nature of the gas contract market has also resulted in volumes being reallocated away from traditional domestic facilities (namely Cooper) toward LNG which has further concentrated the suppliers in the southern gas market. Furthermore, the southern gas markets have not been immune from its own market dynamics shifts; the natural decay in gas supplies, Hazelwood/Northern coal plant exit causing impacts via gas to electricity substitution, and environmental and regulatory barriers to entry have all made their mark. On the price front, the connection to the international LNG markets has created an economic upper and lower price bound (i.e. bid to buy and offer to sell range of the LNG facilities) for the Queensland domestic markets and progressive filtration across the southern gas markets. As the international price range remains higher than the historical domestic equilibrium, there has been rational economic substitution away from discretional gas generation and into contracted LNG exports during periods of negative spark spread. As the LNG exports volume exceed the entire domestic gas market, the relativity small substitutional decommitment by gas generator has had limited visible impact on the domestic gas market. However, as the LNG producers are able to provide short term gas supplies back to the domestic market during period of high short-term gas outcomes, the electricity markets across the East Coast has shown heavy pattern alignment with domestic markets, which are driven and bound by the range of the LNG international economic outcomes. This have been further compounded by the dispatch behaviour of the competitive electricity market which is able to shadow price the marginal cost of gas generators in most regions. However, at the time of writing 9, it was becoming evident that the domestic gas market outcomes were starting to trend below the lower resistance bound of the LNG netback price outcomes across all domestic gas market for one of the first consistent periods since 2015 when only two of the six LNG trains were online. This divergence in the relationship was fundamentally driven by the combination of a rallying Brent international oil prices which drove the LNG contract netback prices rapidly higher (as noted in Figure 7), the onset of warmer spring weather which resulted in lower domestic market gas and electricity consumption and only a small responsive uplift in the LNG exports for the same period. However, the Australian federal government s keen and investigative (via ACCC) interest in the behaviour of the 9 December 2017

21 wholesale gas markets which has also likely limited the full implication of economic scarcity on the gas prices. It has been the intent of this report to highlight the complex interactions of natural gas across its multiple avenues to market. There must be focus and commitment by participants to understand and manage the outlined economic drivers of supply and demand dynamics along the Australian East Coast. This commitment must be aligned with government policy and regulatory direction, to create the structure and framework necessary for the gas market to evolve and be a critical player in meeting the challenges that comes with following either an orderly or disorderly path to an enviable transition to a more carbon-constrained energy market. Bibliography Australian Bureau of Statistics. (2017, November 15). Environmental Issues: Energy Use and Conservation. Retrieved from ABS: ease1mar% Australian Competition and Consumer Commission. (2017, November 15). Gas inquiry September 2017 interim report. Retrieved from ACCC: Australian Department of Industry, Innovation and Science. (2017, November 15). The Australian Domestic Gas Security Mechanism. Retrieved from Department of Industry, Innovation and Science: Pages/Australian-Domestic-Gas-Security-Mechanism.aspx Australian Energy Market Operator. (2017, November 15). Gas Reports. Retrieved from Natural Gas Bulletin Board: Australian Energy Market Operator. (2017, November 15). Gas Statement of Opportunities. Retrieved from AEMO: Australian Energy Regulator. (2017, November 15). State of the Energy Market Retrieved from AER: California Energy Department. (2017, November 15). LNG Significant Events. Retrieved from California Energy Department: e. (n.d.). Energy Information Agency. (2017, November 15). An introduction to spark spreads. Retrieved from Energy Information Agency:

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