August 2025 Electricity Market Review

As spring approached, the National Electricity Market (NEM) entered a steadier phase. Spot prices eased further, averaging $90/MWh in August, down 16% from July and nearly 40% below August 2024. Futures remained broadly flat, with NSW and Queensland edging higher into September, while Victoria and South Australia softened slightly. 

The fall in spot prices was most pronounced in South Australia, where averages halved from July’s volatility to $86.84/MWh. NSW and Victoria rose modestly (to $101.25/MWh and $93.19/MWh respectively), while Queensland dipped to $78.20/MWh, the lowest in the NEM. Compared with August 2024, all states recorded declines of 35–42%, highlighting how calmer winter conditions and stronger renewable output continue to anchor the market. 

But beneath this stability, structural headwinds remain — and they’re starting to shape the futures curve. 

Futures Flat, Mixed Spot — Outlook Tightens 

Despite the easing in spot markets, forward contracts signal continued caution. 

• NSW closed August at $118.02/MWh, edging higher from July.
• VIC futures settled at $77.92/MWh, softer than July but still 12% above August 2024. 
• QLD rose to $101.50/MWh, while SA was steady at $95.72/MWh. 

Notably, Victoria’s 2028 futures spiked to $78.27/MWh, reflecting concerns about Loy Yang A’s closure and delayed firming capacity. Queensland and NSW also saw slight upticks at the start of September, suggesting traders are beginning to price in summer demand risk. 

Structural Risks Remain Front and Centre 

While August delivered softer spot outcomes, AEMO’s August reporting makes clear that structural risks are tightening rather than easing. The calm surface of the market belies the weight of systemic issues that will shape futures pricing and reliability over the rest of the decade. 

Coal fragility and reliability risk

AEMO’s 2025 ESOO reiterated that ageing coal stations remain the single largest variable for NEM stability. August proved the point: unplanned outages at Vales Point and Eraring once again pulled firm capacity from NSW at short notice, highlighting how frequently baseload can falter.  

The ESOO’s analysis shows that without timely replacement, any further coal derating or early closure could see reliability standards breached within two years, underscoring why NSW futures remain above $118/MWh despite softer spot conditions.  

Transmission delays and renewable curtailment

The 2025 Electricity Network Options Report (ENOR) mapped out the scale of the bottleneck. Projects such as VNI-West and Marinus Link are now costed at double original estimates and face slippage into the late 2020s. AEMO’s modelling suggests that without these upgrades, large-scale solar in Victoria and South Australia could face curtailment rates of up to 65% by 2027. That prospect continues to weigh on investment confidence and was one reason futures softened in those states even as renewables hit record shares in August.  

Gas supply, pricing, and firming adequacy

August saw APA advance its Beetaloo pipeline plans, but these remain long-dated, and manufacturers are already warning of a “competitiveness crisis” under today’s high domestic prices. AEMO’s IASR assumptions reinforced that southern states remain tied to volatile LNG-linked pricing, particularly in Victoria and South Australia. Further, plans to blend hydrogen at Tallawarra B and Kurri Kurri have been deferred indefinitely, trimming expectations that cleaner fuels will ease gas reliance this decade.  

Emerging demand growth from data centres

AEMO’s Inputs and Assumptions Report (IASR) highlighted a new demand risk not on the radar even five years ago: data centres. Endeavour Energy has already flagged that in Western Sydney, connection requests alone could add 25% to its network size. Unlike offshore hyperscale centres in Norway or Iceland, these facilities must be built close to cities to minimise latency, embedding new, permanent load growth directly into the urban grid. The scale of these projects could rival the incremental demand growth once expected from electrification alone. 

Together, AEMO’s August releases paint a clear picture: short-term calm does not diminish long-term risk. Coal units are breaking down more often than planned, transmission projects are blowing out in cost and time, gas firming is both expensive and uncertain, and new demand from data centres is arriving faster than policymakers anticipated. These risks are now being priced into forward markets, which explains why the futures curve remains sticky even as spot prices softened in August.  

What This Means for Energy Buyers 

The message remains consistent: short-term relief does not equal long-term certainty. Spot prices are subdued, but futures curves are already signalling the risks ahead — from coal retirements and gas volatility to surging demand from data centres. 

If your electricity contract expires in the next 6–12 months, now remains a strategic window to review, negotiate, and lock in competitive pricing before structural pressures reassert themselves. 

Leading Edge Energy helps you assess the full picture — spot trends, futures curves, policy risk, and global pressures — so you can act decisively in a shifting market. 

Futures – Average of Terms   

National Electricity Futures   

The average electricity futures price for 2026 across New South Wales, Victoria, Queensland, and South Australia closed August at $98.79/MWh, slightly higher than July’s $97.99/MWh. This 0.8% month-on-month rise contrasts with the sharp rally seen in July, instead pointing to a market that has steadied into spring. 

• NSW traded between $114.43 and $116.23/MWh, just under July’s $117.00 close. 
• Victoria averaged $75.91–77.00/MWh, easing from $78.00. 
• Queensland ranged between $95.32 and $96.67/MWh, down from $99.88. 
• South Australia was broadly steady at $94.93–95.27/MWh, compared with $95.10 in July. 

The modest national increase masks regional differences: NSW futures firmed slightly on persistent coal reliability concerns, while Victoria, Queensland, and South Australia softened or held flat. Collectively, this reflects a pullback from July’s hedging-driven volatility, with calmer spot outcomes, stronger renewable supply, and improved generator availability all contributing. 

Still, underlying risks remain unresolved, and traders continue to price in longer-term uncertainty: 

• Coal retirements: The looming 2025 closure of Eraring continues to hang over NSW markets, with traders wary of how quickly new firming capacity can replace lost baseload. Similar questions linger around the medium-term fate of Vales Point and Victoria’s brown coal stations. 

• Transmission delays: Key projects such as VNI West, Marinus Link, and Snowy 2.0 face cost blowouts and slippage. Each setback reduces confidence that new renewable zones can be connected in time to support expected retirements. 

• Firming build: While batteries are being announced at scale, actual delivery of long-duration storage and gas firming projects remains slow. The risk is a “firming gap” by the late 2020s, where renewables dominate the mix but dispatchable capacity lags behind. 

• Gas exposure: Victoria and South Australia, in particular, remain tied to LNG-indexed pricing through domestic contract linkages. Global gas market volatility — from Middle East tensions to Asian demand spikes — can still feed directly into Australian forward pricing, despite local renewables growth. 

• Policy uncertainty: Questions around the rollout of the Capacity Investment Scheme and the balance between federal and state schemes create additional layers of risk. Without clarity, traders are inclined to price in extra caution. 

At these levels, 2026 futures remain broadly aligned with August 2024, signalling a market that is calmer in the near term but still hedging against a more volatile, structurally constrained second half of the decade. 

Spot Market Price Changes    

Period	FY 2024	FY 2025	Movement
FY Price	$80/MWh	$107/MWh	⇧ 34% YoY
April	$85/MWh	$93/MWh	⇧ 9% YoY
May	$155/MWh	$97/MWh	⇩ 37% YoY
June	$159/MWh	$232/MWh	⇧ 46% YoY
July	$163/MWh	$109/MWh	⇩ 33.13% YoY
August	$149/MWh	$90/MWh	⇧ 39.6% YoY

In August 2025, the National Electricity Market (NEM) recorded an average spot price of $89.87/MWh, down 15.6% from July’s $106.54/MWh. This marks a return to sub-$100 pricing across all mainland states and reinforces the sharp cooling that began after June’s $232/MWh spike. 

At the state level, outcomes diverged: 

• NSW rose modestly to $101.25/MWh, up 4.4% from July, though still 42% below August 2024. 

• Victoria climbed 13.5% to $93.19/MWh, reflecting firming costs during lower wind intervals, but remained 35% cheaper year-on-year. 

• Queensland eased 4.8% to $78.20/MWh, delivering the lowest mainland outcome, nearly 40% below last year. 

• South Australia collapsed to $86.84/MWh, halving from July’s $164.95 as wind output strengthened and volatility subsided. 

On a year-to-date basis, NEM spot prices now average around $100/MWh, lower than FY25’s volatile start but still elevated relative to pre-2022 norms. While the August correction eases near-term pressure, year-on-year comparisons (down almost 40% nationally) highlight how extreme the 2024 baseline was. 

For forward procurement strategies, the key question is whether August represents a new stabilisation band around $90–100/MWh, or simply a calm interlude before the summer demand cycle tests system reliability again. 

New South Wales    

Electricity Future Prices

New South Wales electricity futures for 2026 opened August at $116.92/MWh and closed at $118.02/MWh, a modest $1.10 increase that contrasts with July’s $4 decline and signals a slight firming in forward risk. 

Longer-dated contracts also edged higher: 

• 2027 futures closed at $115.10/MWh (up from $113.14) 
• 2028 futures at $115.57/MWh (up from $113.05) 

The upward shift across the curve suggests a gentle recalibration, likely reflecting firmer hedging activity as spring approaches, coupled with ongoing concern over coal reliability and transmission bottlenecks. This marks a reversal of July’s softness, when subdued winter demand and stable spot outcomes drove easing. 

At $118.02/MWh, 2026 futures are $2.47 above August 2024’s $115.55/MWh, pointing to a slightly tighter medium-term outlook despite recent gains in renewable supply and storage. 

Electricity Spot Prices    

Average electricity spot prices in New South Wales rose slightly from $96.95/MWh in July to $101.25/MWh in August — a 4.4% month-on-month increase. Prices were also 42% lower than in August 2024 ($174.45/MWh), underscoring how much volatility has eased year-on-year. 

The uptick reflects firmer evening demand and intermittent renewable dips, though prices remained anchored well below June’s extreme highs. Negative pricing persisted during sunny, windy intervals, reinforcing the growing influence of weather-driven variability in NSW price formation. 

Energy Generation Mix    

Coal remained the dominant source, generating 59.9% of electricity (4,394 GWh), down from 66.3% (4,470 GWh) in July. 

Renewables contributed 37.3% (2,749 GWh), up from 30.3% (2,042 GWh) the previous month. Wind supplied 10.2% (751 GWh), compared with 12.7% (858 GWh) in July. 

Rooftop Solar delivered 12.7% (929 GWh), up from 7.6% (513 GWh), while Utility-Scale Solar added 10.8% (790 GWh), compared with 7.1% (477 GWh). Hydro accounted for 3.6% (267 GWh), above July’s 2.7% (180 GWh). Bioenergy added a small 0.2% (13 GWh). 

Gas made up 2.3% (167 GWh), slightly above 2.9% (195 GWh) in July. Distillate remained negligible at 0.01% (0.009 GWh). 

Battery discharge was modest at 0.3% (20 GWh), broadly consistent with July’s 0.5% (30 GWh), though average costs rose sharply. 

Weighted average prices for each generation category in NSW for August 2025: 

• Renewables (Wind, Solar, Hydro, Bioenergy): $71.41/MWh (down from $73.65/MWh in July) 
• Coal: $138.27/MWh (up from $107.86/MWh) 
• Gas (including Distillate): $308.07/MWh (up from $162.04/MWh) 
• Battery (Discharging): $326.15/MWh (up from $148.49/MWh) 

Victoria    

Electricity Future Prices

Victoria electricity futures for 2026 opened August at $77.69/MWh and closed at $77.92/MWh, a negligible $0.23 increase that signals stability after July’s $4 decline. 

The curve, however, moved unevenly further out: 

• 2027 futures fell to $74.79/MWh (from $77.49), extending July’s softness. 
• 2028 futures rose sharply to $78.27/MWh (from $75.23), bucking the downward trend and lifting the long end of the curve. 

The divergence reflects shifting market sentiment: while near-term hedging eased with strong winter wind output and softer spot prices, the 2028 jump highlights structural risks — notably uncertainty around the retirement profile of Loy Yang A and potential delays in firming projects such as battery storage and transmission upgrades. Traders appear to be pricing in tighter reliability conditions later this decade, even as nearer-term outlooks remain calm. 

At $77.92/MWh, 2026 futures remain 12% higher than August 2024’s $69.68/MWh, underscoring the persistence of long-term reliability concerns as Victoria transitions away from brown coal. 

Electricity Spot Prices    

Average electricity spot prices in Victoria rose from $82.13/MWh in July to $93.19/MWh in August, a 13.5% month-on-month increase. Prices were still 35% lower year-on-year compared to $143.40/MWh in August 2024, highlighting how wholesale pressure has eased over the past year. 

The increase was driven by periods of lower wind output, which firmed prices despite continued strong solar and stable baseload supply. Evening peaks remained the main source of volatility, while negative prices persisted during sunny, low-demand periods, underlining the ongoing influence of variable renewables on Victoria’s price dynamics. 

Energy Generation Mix    

Coal remained the dominant source, generating 56.2% of electricity (2,768 GWh), slightly lower than 57.4% (3,024 GWh) in July. 

Renewables contributed 40.0% (1,964 GWh), up from 39.0% (2,054 GWh) the previous month. Wind was again the largest contributor, supplying 24.1% (1,189 GWh) compared with 28.8% (1,516 GWh) in July. Rooftop Solar delivered 8.4% (413 GWh), up from 5.2% (274 GWh), while Utility-Scale Solar added 3.6% (175 GWh) versus 2.3% (121 GWh). Hydro accounted for 3.8% (187 GWh), higher than 2.7% (143 GWh) in July. 

Gas made up 2.8% (139 GWh), close to 2.7% (144 GWh) in July. 

Battery discharge was modest at 1.1% (55 GWh), compared with 0.9% (46 GWh) the previous month. 

Weighted Average Prices – Victoria, August 2025 

• Renewables (Wind, Solar, Hydro): $64.68/MWh (up from $60.22/MWh in July) 
• Coal: $102.25/MWh (up from $90.87/MWh) 
• Gas: $216.28/MWh (up from $186.69/MWh) 
• Battery (Discharging): $190.72/MWh (up from $180.75/MWh) 

Queensland    

Energy Generation Mix    

Queensland electricity futures for 2026 opened August at $99.90/MWh and closed at $101.50/MWh, a $1.60 increase that reverses July’s $3.99 decline and points to firmer forward risk. 

Longer-dated contracts also strengthened: 

• 2027 futures closed at $96.92/MWh (up from $94.93) 
• 2028 futures at $92.97/MWh (up from $91.15) 

The uniform rise across the curve suggests a mild recalibration, likely tied to expectations of stronger summer demand, elevated gas pricing, and uncertainty around coal fleet reliability. This contrasts with July’s easing, when mild winter conditions and stable spot markets encouraged softer hedging. 

At $101.50/MWh, 2026 futures are 3.4% higher than August 2024’s $96.24/MWh, highlighting a steady but cautious outlook as Queensland balances strong coal baseload with emerging renewable and storage investments. 

Electricity Spot Prices    

Average electricity spot prices in Queensland eased slightly from $82.13/MWh in July to $78.20/MWh in August, a 4.8% month-on-month decline. Prices were also 40% lower year-on-year, down from $130.10/MWh in August 2024, reflecting stable supply conditions and subdued volatility. 

Daytime oversupply from rooftop solar continued to drive negative pricing intervals, while firm coal baseload and moderate demand kept evening peaks contained. August marked a continuation of Queensland’s balanced market conditions — ample generation, limited volatility, and consistently lower prices — though structural risks around the ageing coal fleet and exposure to volatile gas markets remain. 

Energy Generation Mix    

Coal remained the dominant source, generating 61.7% of electricity (3,575 GWh), slightly down from 63.0% (3,646 GWh) in July. 

Renewables contributed 30.0% (1,733 GWh), broadly steady with 30.3% (1,752 GWh) the previous month. 

 Rooftop Solar was the largest renewable, delivering 13.0% (753 GWh) versus 11.1% (642 GWh) in July. Utility-Scale Solar supplied 8.2% (477 GWh), almost unchanged from 8.3% (479 GWh), while wind accounted for 6.5% (376 GWh), below 8.0% (462 GWh). Hydro generated 2.2% (127 GWh), close to 2.4% (138 GWh) in July. Bioenergy added 0.6% (34 GWh). 

Gas made up 7.2% (411 GWh), slightly above 6.1% (353 GWh) in July. Output included 6.2% (358 GWh) from CCGT, 0.6% (32 GWh) from OCGT, and 0.4% (21 GWh) from waste coal mine gas. Distillate remained negligible at 0.007% (0.4 GWh). 

Battery discharge was minimal at 0.7% (39 GWh), similar to 0.6% (33 GWh) in July. 

Weighted Average Prices – Queensland, August 2025 

• Renewables (Wind, Solar, Hydro, Bioenergy): $47.70/MWh (up from $44.20/MWh in July) 
• Coal: $88.59/MWh (down from $91.01/MWh) 
• Gas (including Distillate): $126.29/MWh (down from $129.51/MWh) 
• Battery (Discharging): $165.88/MWh (down slightly from $167.37/MWh) 

South Australia    

Electricity Futures Prices    

South Australia electricity futures for 2026 opened August at $95.48/MWh and closed at $95.72/MWh, a marginal $0.24 increase that mirrors July’s stability and underscores ongoing market caution. 

Longer-dated contracts moved unevenly: 

• 2027 futures slipped to $94.08/MWh (from $94.51) 
• 2028 futures rose to $96.00/MWh (from $94.80) 

The mixed curve reflects SA’s unique risk profile. Near-term stability suggests confidence in renewable output and interconnector support, while the 2028 uptick highlights persistent structural concerns — particularly around firming adequacy, weather-driven volatility, and transmission bottlenecks as renewable penetration deepens. 

At $95.72/MWh, 2026 futures remain 7.9% lower than August 2024’s $103.88/MWh, pointing to improved short-term confidence but leaving longer-term caution intact. 

Electricity Spot Prices    

Average electricity spot prices in South Australia plunged from $164.95/MWh in July to $86.84/MWh in August, a 47% month-on-month fall. Prices were also 42% lower year-on-year, down from $149.52/MWh in August 2024, marking a sharp correction from mid-winter volatility. 

The decline was driven by stronger wind output and higher rooftop solar generation, which suppressed prices through much of the month. Negative pricing was common during sunny, breezy periods, while volatility eased significantly compared with July. Evening peak spikes still occurred during wind lulls, but overall SA shifted from being one of July’s most volatile markets to one of August’s most subdued. 

Energy Generation Mix    

Renewables again dominated South Australia’s mix, generating 72.4% of electricity (1,015 GWh), higher than 68.9% (957 GWh) in July. Wind remained the largest contributor, supplying 51.2% (717 GWh) compared with 53.6% (745 GWh) the previous month. Rooftop Solar delivered 15.7% (221 GWh), up from 11.1% (153 GWh), while Utility-Scale Solar added 5.5% (77 GWh) versus 4.2% (58 GWh) in July. 

Gas provided 25.5% (355 GWh), below 28.4% (394 GWh) the month before. Output was split between CCGT at 12.8% (179 GWh), steam at 5.4% (75 GWh), OCGT at 4.2% (58 GWh), and reciprocating engines at 3.1% (43 GWh). Distillate remained negligible at 0.02% (0.2 GWh). 

Battery discharge accounted for 2.1% (30 GWh), slightly lower than 2.5% (35 GWh) in July, though prices eased. 

Weighted Average Prices – South Australia, August 2025 

• Renewables (Wind, Solar): $57.36/MWh (down from $59.19/MWh in July) 
• Gas (including Distillate): $165.43/MWh (down from $401.98/MWh) 
• Battery (Discharging): $162.36/MWh (down from $293.88/MWh) 

As August closed the financial year on a more stable note, a deeper swirl of strategic and structural shifts continued to shape the NEM—spot prices may have steadied, but under the surface, the energy transition is as complex as ever. 

Grid Bottlenecks, Coal Fragility, and Data Centre Loads Dominate AEMO’s 2025 Insights 

August saw a flurry of fresh analysis from the Australian Energy Market Operator (AEMO), offering critical signals for policymakers, investors, and large energy users about the decade ahead. 

The headline release was the 2025 Electricity Statement of Opportunities (ESOO), AEMO’s ten-year reliability outlook. The report struck a cautiously optimistic tone: projected investment in new generation and storage has improved the forecast compared with last year, but the outlook hinges entirely on timely delivery. Any delays in battery, gas, or transmission projects could see reliability standards slip, particularly around the 2025 closure of Eraring and subsequent brown coal retirements in Victoria. 

Complementing the ESOO, AEMO also published the 2025 Electricity Network Options Report (ENOR). This technical document feeds into the next Integrated System Plan (ISP) and highlights where augmentation and upgrades will be most urgently needed. Transmission remains the system’s weak link. Projects like VNI West, Marinus Link, and QNI continue to define the pace at which renewables can connect to the grid, with escalating costs and slippage now the primary risks to market confidence. 

Underlying these reports is AEMO’s Inputs, Assumptions and Scenarios Report (IASR), released with regulatory oversight from the AER. The IASR sets the modelling frameworks for the ISP, testing everything from demand growth and technology costs to global fuel prices. This year’s version sharpened its focus on new structural demand, particularly from data centres, and on the higher-for-longer trajectory for gas costs. 

Finally, AEMO issued its Enhanced Locational Information (ELI) Report, a new data tool that maps system strength, constraint risk, and VRE opportunity across the NEM. For developers and investors, ELI offers granular intelligence on where projects face the least friction. 

Taken together, these reports reinforce a simple but urgent message: Australia’s transition is technically feasible, but confidence depends on execution. Delays in firming, transmission, or coal retirements will remain the decisive variables shaping futures pricing and reliability over the next five years. 

Data Centers: Emerging Load Frontier 

Renewable energy is booming—but so too is load: network operators report a wave of data centre connection applications, especially in Western Sydney.  

If all proposals eventuate, networks could expand by 25%, underscoring a new structural demand vector closer to load centres. Forward curves are beginning to reflect this “urban grid pressure.”  

Coal Could Stay On Longer Despite Retirement Plans 

Renewables rollout delays and transmission bottlenecks are prompting discussions about extending the lives of legacy plants.  

AGL and other generators are exploring keeping units at Yallourn, Eraring—and even Bayswater—operational beyond planned closures to avoid tight margins

Record Penalties Signal Regulatory Tightening 

Australian energy retailers are under the microscope: the AER has dished out $53 million in fines in 2024–25, a massive rise from the prior year.  

Retail compliance failures ranged from life-support disconnections to overcharging vulnerable customers, spotlighting enforcement and trust risk in the sector. 

Rooftop Solar Reshaping the NEM’s Daily Pulse 

Rooftop PV now contributes 14.7% of NEM’s generation—surpassing utility-scale solar (9.3%)—thanks to a 13% rise in installed capacity to 23 GW.  

This non-dispatchable but growing source continues to flatten demand curves and reinforce negative pricing risk on high-sun days. 

Renewables Surge Hits a Record High Share 

August 30 saw a new peak for utility-scale solar & wind, hitting 47.2% of NEM generation in a single snapshot.  

Still, without faster grid upgrades, the system remains at risk of VRE spillage or congestion. 

Hydrogen Delay Dampens Transition Expectations 

EnergyAustralia’s hydrogen blending plans at Tallawarra B have been deferred until at least 2027, while Snowy Hydro’s Kurri Kurri project—initially billed as stepping up to 100% green hydrogen—now lacks a clear timeline and faces a $75 million budget shortfall.  

Analysts are questioning early assumptions around the pace of decarbonising firming fuel. 

Industrial Gas Demand Pressures Pricing 

Mid-tier industrial consumers, like steel and aluminium makers, are sounding alarms over the high cost and tight supply of gas.  

They’re calling for policy reforms such as price caps below $10/GJ to prevent plant closures and preserve critical manufacturing capability. 

LNG Supply Surge Could Ease Export Pressure 

Goldman Sachs forecasts a 42% drop in global LNG prices by 2027 due to a major supply injection from the U.S. and Qatar.  

That shift could begin easing domestic gas supply pressure—especially important for southern states reliant on gas peakers—but the timeframe doesn’t align with near-term market concerns. 

Actionable Advice  

For buyers with contracts expiring within the next 6–12 months, August presents one of the last opportunities to engage fixed-rate markets before winter volatility returns.  

Reassess procurement dates, assess how reliability risk affects your demand exposure, and consider layering pricing across timeframes cascaded by capacity vs. energy risk.  

Identifying which structural risk factors — coal, gas, transmission, curtailment — matter most to your operations will help shape negotiation strategies and lock-in decisions.  

Explainer:  Why we focus on Wholesale Futures Prices

Wholesale Futures Price: This reflects what the market expects wholesale electricity spot rates to be in future periods. The offers that commercial and industrial (C&I) customers receive via Leading Edge Energy are closely correlated to wholesale prices on the ASX Energy futures market; this is why we focus on these prices in our commentary.

Spot Price: This represents how much the spot market is charging for electricity currently based on demand and supply. Spot prices go up when demand is high and supply is tight. You can view live Spot Prices here. 

You can learn more about the difference between wholesale electricity futures and spot prices in our blog section.

Disclaimer: The information in this communication is for general information purposes only. It is not intended as financial or investment advice and should not be interpreted or relied upon as such.

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