Why Santos and Woodside are among our biggest holdings

Overview

In Forget Next Year’s Commodity Prices: Focus on 2075’s (1 September 2025), I demonstrated that nobody can reliably predict commodity prices over the next year – yet cautious analysis based upon sensible assumptions can plausibly infer them decades into the future. The CPI-adjusted stability of commodities’ very long-term prices supports the generally-superior returns of coal, gas and oil companies (for details, see Why we’ve never held tech – and have long owned energy, 2 March).

In this article, I apply this result to Australia’s two biggest (ranked by production, export volumes and market capitalisations) energy companies.

It emphasises a key fact: world-class (“Tier-1”) energy assets offer durable as well as significant returns. In 2021, Santos acquired plurality (currently 39.9%) ownership of one, and has commenced the early stages of the development of what may become another. Since the 1980s, Woodside Energy Group (hereafter “Woodside”) has developed and operated, and now owns, 50% of one Tier-1 asset; moreover, it’s constructing and by the end of this decade will operate and own 60% of another.

What’s increasingly being called the Third Gulf War doesn’t underpin our case. However, a crucial implication of the war may strengthen it.

Although Canberra’s acceptance is belated and grudging (and Chris Bowen continues to reject it), to most people it’s now obvious: national security presupposes energy security, and energy security necessitates hydrocarbons. The recent and sharply-upward volatility of the prices of crude oil and liquified natural gas (LNG) – which for that very reason could over the next year or more become strongly-downward volatility – are, for consumers and speculators, dramatic developments. According to the head of the International Energy Agency (23 March, reiterated on 22 April), “the world is facing the greatest global energy security threat in history.”

For investors, in sharp contrast, the threat is possibly transitory; if so, from a long-term perspective it’ll be relatively unimportant. What’s enduring and significant is what everybody, it seems, is overlooking: Santos and Woodside have become globally-significant and low-cost producers of LNG.

Their world-class (very large, high-quality, long-life and low-cost) resources and infrastructure, as well as LNG’s CPI-adjusted prices over the next several decades, offer reasonable prospects for healthy cashflows extending decades into the future (see also Dividends aren’t a bane – they’re a boon, 20 November 2023).

My analysis acknowledges what everybody knows and many emphasise: these two companies are “price takers,” that is, they’re unable to influence (at least on a global basis) the prices of the crude oil, gas, LNG, etc., which they produce. Yet it also reveals what few others apparently realise:

To a significant extent Santos and Woodside are “margin-makers.” By steadily reducing their “Breakeven” cost of production, as their shift towards large-scale and low-cost production of LNG has enabled them to do, they’ve boosted their “Netback” – and thus their profitability.

However, and as I detail, their attractive long-term prospects DON’T assure continuously attractive investment returns. The short-term “spot” prices of crude oil and LNG can fluctuate enormously. As a result, LNG’s medium-term contract price can vary greatly. So can STO’s and WDS’s long-term revenues and profits – and their shares’ returns.

An examination of their fortunes and returns over the past ca. 35 years provides no reason to assume that the next several decades will be smooth sailing. This volatility is the investor’s friend: fluctuations of STO’s and WDS’s returns will generate ample opportunities to acquire their shares at attractive prices.

Two Disclaimers

What follows is NOT a comprehensive analysis of Santos and Woodside. In particular, I’ve omitted all details of Leithner & Company’s valuations; instead, I highlight fundamentals which nobody else has emphasised (or even mentioned).

Accordingly, and secondly, what follows is NOT a recommendation to purchase the shares of either company at their current (that is, boosted by the Third Gulf War) prices. Leithner & Company has purchased STO’s and WDS’s shares over the years – and most recently in January of this year – at considerably lower prices.

Those prices offered compelling value; I don’t claim that recent ones do.

Anticipating Possible Objections

More than a year ago, speculators who mistakenly thought they’re investors doubted my assessment of CSL Ltd (see Why CSL will likely underperform term deposits, 10 March 2025). At the time it was regarded as a “growth” stock. These stocks are popular; therefore, socially it’s easy to buy them. Approval provides psychological safety; hence speculators generally ignore or reject any reasoned criticism of popular stocks. Equally, complacent punters are oblivious to evidence: over the past century, popular stocks have generally underperformed (see in particular Want to shrink your returns? Buy “growth” stocks! 23 March).

Similarly, I won’t be surprised – quite the contrary, I’ll be reassured – if speculators question and reject my assessment of Santos and Woodside.

That’s because these companies long been and today remain unpopular. Moreover, if a company’s disliked, it’s likely a value stock; and if it’s a value stock, the odds are that it’ll generate reasonable long-term returns. Investing in unloved companies is a reliable – but hardly a foolproof – method of long-term wealth creation (see in particular Why value investing usually outperforms, 29 April).

In The General Theory of Employment, Interest and Money (1936), John Maynard Keynes compared market speculation to a contest whose participants "win" by picking securities which they believe will be the most popular – NOT whose values, they conservatively estimate, greatly exceed their prices. Ninety years later, nothing much has changed.

Buying “growth” stocks is socially easy, but purchasing value stocks is psychologically difficult. No matter: successful investors ignore noise (speculators’ illogical and empirically unjustifiable pessimism towards value stocks) and seek signal (rational assessments of unpopular companies’ prospects).

Background

Forget Next Year’s Commodity Prices: Focus on 2075’s (1 September 2025) produced three key results: 

1. in the short term (periods of 12 months or less), the prices of energy and mineral commodities which trade in liquid “spot” markets (which include coal, copper, crude oil, iron ore and LNG, but exclude lithium, “rare earths” and uranium) fluctuate tremendously;
2. over medium-term intervals (ca. five years), these prices occasionally boom and bust (as everybody surely knows, the Third Gulf War has caused the prices of crude oil and LNG to spike);
3. over very long terms (periods of 20 years and beyond), however, the CPI-adjusted prices of energy and mineral commodities change little.

I demonstrated that, generally speaking, nobody can predict next year’s commodity prices – but you can plausibly infer them decades into the future.

I also rebutted a predictable objection: “haven’t you heard about the energy transition? ‘Net Zero’ by 2050? Everybody knows that during the next quarter-century the demand for fossil fuels – and hence their prices – will collapse. Coal, crude oil, gas and LNG infrastructure are thus ‘stranded assets;’ therefore, their owners will suffer huge losses!”

It’s surprisingly often the case: “what everybody knows” is grossly mistaken.

Worldwide, as Figures 7-10 of Forget Next Year’s Commodity Prices: Focus on 2075’s (1 September 2025) demonstrated, no “energy transition” is occurring. Intermittent (and therefore costly) energy from sun and wind isn’t replacing hydrocarbons; it’s supplementing them. Thanks to relatively high growth of income and population in low-income countries, on a global basis hydrocarbons’ per capita consumption shows no sign of decelerating – never mind decreasing in absolute terms (see also “Net zero” isn’t a Megatrend: It’s a Mega-trap, 8 April 2024).

For investors, the implications are momentous.

On the one hand, energy and mining companies typically can’t influence (never mind control) the prices they receive for the commodities they produce. Additionally, the exploration for and production of energy and minerals is complex and capital-intensive, and these attributes entail various risks which can severely impact these companies’ operations, profitability and shareholder returns.

Accordingly, conclude the authors of Why Moats Matter: The Morningstar Approach to Stock Investing (John Wiley & Sons, 2014), “it’s not always easy for energy companies for energy companies to create long-term moats …” This word, whose application to valuation Warren Buffett has popularised, refers to a business’s ability to protect its profitability.

A castle’s (company’s), moat (depth and breadth of competitive advantage) defends those inside the fortress (profits) from outsiders (competitors).

Broad and deep moats in mining and energy are rare because mineral and energy commodities are basic products which are broadly interchangeable. That’s the definition of a commodity: one producer’s LNG is essentially indistinguishable from another’s. That’s less true, but still broadly applicable, to crude oil. As Buffett cautioned his son (who as a young man wished to become a farmer): “no one goes to the supermarket to buy Howie Buffett’s corn.”

One the one hand, energy and mining companies seldom control the prices they receive for the commodities they produce; as a result, they’re typically “price-takers.” On the other hand, they can become “margin makers” – that is, create durable competitive advantages – by acquiring or developing “Tier-1” assets and thereby becoming lowest-cost producers.

These assets are mineral and energy deposits which are exceptionally large (and can thereby supply a significant percentage of global demand), have exceptionally long lifespans (typically 50 years or more), rank among the world’s lowest-cost to operate – and thus offer the highest profit margins.

World-class deposits and associated infrastructure typically offer not just quantity, quality and longevity, but also durable and significant economic returns.

Santos, Woodside and LNG

Figure 1 disaggregates Santos’ revenue by major product since 2015 (Darwin LNG, which commenced production in 2006, was Santos’ first LNG project; until 2015, however, it didn’t distinguish LNG from its other sources of revenue). “Crude oil” includes distillates, that is, liquids produced by heating crude oil and condensing the resulting vapours during refining. Products produced from these liquids include diesel, kerosene, jet fuel and heating oils.

Figure 1: Percentages of Santos’ Revenue by Major Product, 2015-2025

Australian natural gas, which includes condensates, is consumed domestically. Condensates are liquids condensed from “wet” gas; they’re used as feedstocks for refineries, diluents for heavy crude oil (to enable its transport through pipelines), and to manufacture petrochemicals. Finally, Australian LNG is produced exclusively for export. Figure 2 disaggregates Woodside’s revenue since 2005 in a similar manner.

Over time, crude oil and gas for domestic consumption have comprised generally-lower percentages of STO’s and WDS’s revenues; conversely, LNG’s percentages have risen.

Since 2022, when Santos acquired Oil Search Ltd and thus its PNG LNG project, LNG has generated more than 60% of its revenue. In 2015, crude oil contributed ca. 20%, and gas for domestic consumption each provided ca. 40%. A decade later, these latter percentages have sagged to ca. 10% and 30% respectively.

After commencing LNG exports in 1989, it continued to rely heavily upon oil and liquids. Indeed, during the mid-to-late 1990s to the late-2000s, Woodside produced more crude oil and liquids than gas and LNG. As late as 2008, high-performing oil fields generated more revenue than its LNG business.

Figure 2: Percentages of Woodside’s Revenue by Major Product, 2005-2025

Woodside’s completion of its $12 billion Pluto LNG project in 2010, which complemented its North West Shelf project, commenced the shift of its output heavily towards LNG. From the GFC until 2021, LNG’s share of WDS’s revenue vaulted four-fold from 20% to 80%, and gas’ share dwindled almost to nothing. As a result of its purchase of BHP Petroleum, since 2021 LNG’s percentage has receded to just below 50% and oil’s has doubled to 40%; as a result, gas comprises little more than 10%.

Over the next 5-7 years, WDS aims to boost its output of LNG to ca. 40 million tonnes per annum (Mtpa). That’s double its rate of production in 2024. Similarly, by 2027 STO expects to increase its overall production by 25-30%.

As an important aside, I’m NOT saying – indeed, I strongly doubt – that these two companies have deliberately downgraded the production of gas for domestic consumption.

I certainly DO contend that state and federal governments have tacitly discouraged and, in some instances, overtly prohibited this production. Their policy isn’t merely an embarrassment: over the past few years it’s become obvious that it’s created a crisis.

Santos’ Narrabri project provides just one of several major examples. It was first proposed in 2011, and can supply one-half of NSW’s requirements for decades. Had it been expeditiously approved rather than consigned to years of bureaucratic purgatory and environmental lawfare, Santos’ output of gas for the domestic market would be much greater – and Australia’s supply would be much more plentiful.

State and federal government inertia and opposition, plus the contract and “spot” prices of LNG versus their costs of production and transport, have depressed the percentages of domestic gas – and boosted the percentages of LNG – in Figure 1 and Figure 2.

Santos’ and Woodside’s World-Class LNG Pillars

North West Shelf

Woodside’s North West Shelf (NWS) project, of which it’s the operator and 50% owner, is a Tier-1 asset. It’s one of Australia’s largest and most significant resource developments; it’s also its largest (capacity of 16.9 Mtpa) oil and gas project. During construction in the 1980s, it was the world’s largest engineering project; today, it’s the world’s third-largest LNG project.

Since it commenced output in the mid-1980s it’s been the cornerstone of Australia’s LNG industry. It’s received state and federal approvals to extend its operations until 2070. It’s also expandable: WDS’s Browse to NWS Project, whose proposed capacity is 11.4 Mtpa and which is in its early design phase, plans to pipe gas to the existing NWS infrastructure for processing.

Louisiana LNG

Woodside’s Louisiana LNG (LLNG) project is also world-class. It’s a fully-permitted development which, following WDS’s final investment decision in April 2025, has become a core component of its growth strategy. Located near Lake Charles, Louisiana, it accesses America’s (and one of the world’s) biggest and lowest-cost reservoirs of natural gas – which, at current rates of consumption and assuming no further discoveries, has an estimated lifespan of ca. 50-90 years.

LLNG has a permitted capacity of 27.6 Mtpa – almost twice the current capacity of NWS – and its foundation phase, to be completed by 2029, will produce 16.5 Mtpa (equal to NWS’s current output). By the mid-2030s it will be one of America’s and the world’s biggest. It underpins Woodside’s aim to become a global top-three producer of LNG (generating 5.0-7.5% of global supply) by the early-2030s.

PNG LNG

PNG LNG is a Tier-1 project, operated by ExxonMobil (Santos is its biggest (39.9%) owner), whose production capacity currently exceeds 8.6 Mtpa. That ranks it just outside the world’s top-ten. Its low production costs, high-quality gas supply and ability to double its capacity (to ca. 16 Mtpa with the addition of the P’nyang field) are its key characteristics – and make it the jewel in Santos’ crown.

Papua LNG (led by TotalEnergies), of which Santos owns 22.8%, complements, expands and leverages PNG LNG. Papua will utilise some of PNG’s pipelines and its plant to deliver ca. 5.4 Mtpa of LNG by as early as 2028 (but likely beyond 2030).

Beetaloo

According to estimates, the Beetaloo Basin in the Northern Territory contains more than 500 trillion cubic feet of prospective shale gas. That ranks it among the world’s largest emerging gas resources. Not all of it’s recoverable, but a significant portion is – and advances of technology will over time increase the recoverable proportion. It’s likely to contain enough gas to meet Australia’s current domestic demand for more than 200 years.

Santos is a major player in the Beetaloo – which, at its AGM on 16 April, it identified as “a Tier-1, long-life asset.” Its CEO, Kevin Gallagher, elaborated: it “is a potential game-changer for (STO) … If fully developed, Beetaloo would unlock the scale of opportunity for the NT that (NWS did) for WA 40 years ago, and will supply both domestic and LNG markets for decades.”

How Santos and Woodside Have Become World-Class E&Ps

They’ve become world-class explorers and producers (E&Ps) by concentrating upon the acquisition, development and operation of Tier-1 LNG assets and infrastructure. LNG’s capital requirements are huge, and the requirements of Tier-1 projects, given their size, are even bigger.

Hence they don’t just produce large quantities of LNG: they also erect significant barriers to others’ entry. Moreover, Tier-1 assets enable their owners to produce at ever lower cost – and thus at ever lower “Breakeven” prices.

LNG projects are enormously capital intensive. They require billions of dollars (a rough rule of thumb is at least $US2 billion per Mtpa of output) of upfront investment. Moreover, given their technical complexity and large size, as well as regulatory intricacies and environmental hurdles, they now require ca. five years – and often much longer – to construct.

Long-term (20 or more years) Sale and Purchase Agreements (SPAs) ensure LNG projects’ economic viability. Without SPAs, lenders won’t advance the billions of dollars which the construction of LNG projects requires. New entrants must also secure access to ancillary infrastructure such as pipelines, downstream storage and ports. These often require complex and lengthy negotiations. In practice, even projects which have obtained SPAs can’t proceed without this access.

Securing SPAs and access to third-party infrastructure ensures a project’s access to major markets; failure to secure them usually scuttles its ability to obtain finance – and thus to proceed to construction.

According to some analysts (but few producers), before the outbreak of the Third Gulf War on 28 February the global LNG market (what had largely been distinct Asian and European markets became a global one in the wake of Russia’s invasion of Ukraine in 2022) faced a significant glut. Supply, these analysts believed, would outpace demand through the early-2030s—and therefore depress new SPAs’ prices and impose further risk upon market entrants.

Given the recent and significant damage to major LNG infrastructure in Qatar, which ranks among the world’s biggest exporters (along with Australia and the U.S.) and which will certainly require months and perhaps several years to repair, the risk of glut has likely – and perhaps greatly – receded.

Whatever the future holds, one crucial fact will remain: Tier-1 producers of LNG will consistently secure the cheapest financing, generate the lowest-cost producers and deliver the highest returns to their shareholders.

Margin-Makers as Well as Price-Takers

It’s well-known: E&Ps are “price takers,” that is, they’re unable to influence the global prices of crude oil and LNG. What’s virtually unknown is that a few – including STO and WDS – have to a significant degree also become “margin-makers.”

By transitioning towards Tier 1 LNG projects, whose large size and resultant economies of scale reduce costs per unit of output, Santos and Woodside can – given relatively constant (adjusted for CPI) long-term LNG prices – increase their profitability, that is, profit per unit of output.

To see this, I’ll explain and quantify three concepts. By my definitions, Average Realised Price = Netback + Breakeven. This identity allocates a company’s total revenue among (1) the recovery of cash costs and (2) the generation of cash profit. Netback tells you how much cash an E&P keeps per unit of output; Breakeven tells you how much cash it expends in order to produce each unit.

Average Realised Price

An energy company’s average realised price (ARP) measures the revenue which it receives during a given period per standardised unit of output. The oil and gas industry’s standard, barrel of oil equivalent (boe), expresses as a single number a company’s total output per year of various types of energy such as coal, crude oil, gas, LNG and various condensates and distillates.

In order to calculate a company’s ARP, we require what we lack – internal data of the quantity and price of each commodity sold each day. STO and WDS currently release ARP figures in their quarterly production reports, but since the 1990s they haven’t done so on continuous and comparable bases. To estimate ARP, I’ve used information which they’ve published in their annual and quarterly reports. My estimate is: ARP = total annual revenue ÷ output (expressed as boe).

On these bases, for each year since each company has expressed its total output in terms of boe, I’ve recorded or estimated Santos’ and Woodside’s ARPs; I then converted them into $US (in 1996 both companies reported in $A; by 2024, they reported in $US) and adjusted them for CPI; Figure 3 plots the results.

Figure 3: Average Realised Price per boe, CPI-Adjusted $US, 1996-2025

Albeit cyclically, each company’s CPI-adjusted ARP has risen over time. Additionally, WDS’s has almost always exceeded STO’s: since 1996 Woodside’s has averaged $64.45 and Santos’ $52.54. (The disparity was particularly marked in 2022, when the global price of LNG soared in response to Russia’s invasion of Ukraine.)

WDS’s higher ARP reflects three factors. Firstly, since 1996 it’s exported most of its output; until 2015, in contrast, all of Santos’ output supplied the domestic market. Secondly, until ca. 2018 the global price of LNG was significantly higher than the price of gas in Australia. Finally, Woodside sells a larger proportion than Santos of LNG in the “spot” market – that is, at the usually higher current market price for immediate delivery.

Woodside’s LNG portfolio comprises a mix of short-, medium- and long-term contracts. Contracts provide certainty: buyers agree to purchase a given quantity over a given interval. Yet this certainty comes at a cost: the contracted price is generally a discount to “spot.” Hence WDS also sells a significant portion of its output in the spot market in order to capture fluctuating prices. Over the past several years, it’s sold up to one-third of its annual output of LNG in this manner.

Santos, in contrast, has sold 80%-90% of its LNG under long- and medium-term contracts, and just ca. 10-20% in “spot” markets (at its AGM on 16 April, it stated that 83% of its output over the next five years has been contracted).

“Netback”

“Netback” quantifies the profit per boe which a company earns after deducting all cash costs (as opposed to non-cash costs such as depreciation). As it often is with ARP, so it is with Netback: lacking precise (internal) data, I’ve used publicly-available figures to estimate it. My formula is: Netback = EBITDA ÷ output (expressed as boe). Figure 4 plots STO’s and WDS’s Netback since 1996.

Figure 4: STO’s and WDS’s Netback per boe, CPI-Adjusted $US, 1996-2025

Over the past quarter-century, WDS’s Netback has been higher than STO’s: since 1996, WDS’s has averaged $US44.32; since 1998, STO’s has averaged $US20.82. Before 2015, this disparity partly reflected the fact that STO mostly sold in domestic markets (and thus received relatively low ARPs); from 2015 until 2021 (in the latter year STO purchased Oil Search Ltd, and thus a large stake of its very large and very low-cost PNG LNG project), it’s reflected STO’s higher costs.

STO’s higher costs, in turn, partly reflected large overruns on major projects, particularly Gladstone LNG, and huge write-downs of assets (including GLNG) in response to the collapse (by ca. 75%) of LNG’s price in 2015-2020. Given these and other factors, each company’s Netback mostly rose from 1996 to 2014, fell from 2015 to 2020 and has rebounded since 2020.

The collapse of STO’s Netback in 2014-2017 is particularly marked. So too is the declining difference between the two companies’ Netbacks, which in 2025 – for the first time since the early-2000s – virtually disappeared.

“Breakeven”

Finally, “Breakeven” quantifies the point at which total revenues per boe equal cash costs per boe: above it, production generates cash; below it, output consumes cash. My formula is: Breakeven = (total revenue – EBITDA) ÷ output (expressed as boe).

Each company’s Breakeven (Figure 5) mostly rose from 1996 to 2014, and from 2010 to 2015 STO’s soared. Since then, apart from upward spikes in 2020-2021, they’ve mostly fallen. The sharp fall of STO’s, from almost $50 per barrel in 2015 to less than $20 in 2024 and 2025, which is a consequence of its strict cost-cutting and the takeover of Oil Search and addition of PNG LNG to its portfolio, is particularly marked.

As a result, ands for the first time since 2011, STO’s Breakeven is now (2025) slightly below WDS’s.

Figure 5: STO’s and WDS’s Breakeven per boe, CPI-Adjusted $US, 1996-2025

Relationships among ARP, Netback and Breakeven

Relationships among these three variables underscore the vital importance of costs – and cost control – as bases of cash generation. ARP × quantity of output = revenue. Netback helps to determine the minimum price the company requires in order to cover its cash costs; Breakeven helps to determine the sales volume required to achieve profitability. Figure 6 plots STO’s ARP, Netback and Breakeven since the 1998; Figure 7 plots Woodside’s since 1996.

Figure 6: STO’s ARP, Netback and Breakeven per boe, CPI-Adjusted $US, 1998-2025

For both companies, ARP’s best-fitting line is linear: average received prices have risen over time, and at a compound annual growth rate (CAGR) of 3.8% per year since 1998 (Santos) and 2.1% per year since 1996 (Woodside). However, Breakeven’s best-fitting lines are curvilinear; moreover, they crested in ca. 2016. Since then, Santos’ has fallen at a compound rate of 8.0% per year, and Woodside’s has risen marginally (0.6% per year).

Figure 7: WDS’s ARP, Netback and Breakeven per boe, CPI-Adjusted $US, 1996-2025

The higher is ARP, other things (such as Breakeven) being equal, the higher is Netback; and the lower is Breakeven, other things (such as ARP) being equal, the higher is Netback. Accordingly, and crucially, if Breakeven falls more than ARP then Netback can rise. And if ARP rises and Breakeven falls, as is likely occurring presently, then Netback leaps.

STO’s and WDS’s versus ExxonMobil’s Breakeven

If Santos and Woodside really are world-class E&Ps, then they’ll compare to E&Ps whose world-class status is undisputed. As a “downstream” refiner of petroleum and producer of petrochemicals, as well as an “upstream” producer of crude oil, LNG and natural gas, etc., ExxonMobil’s Tier-1 assets aren’t exclusively – or even predominantly – LNG projects. Its biggest LNG project (a JV with Qatar Energy whose capacity exceeds 18 Mtpa and whose operations commence later this year) is Golden Pass LNG in Texas. PNG LNG is its second-biggest, and it’s also a member of the Papua LNG JV consortium.

Figure 8 plots ExxonMobil’s, Santos’ and Woodside’s CPI-adjusted Breakeven prices, expressed as $US-denominated barrels of oil equivalents, since 2015. Crucially, over the past decade each company’s Breakeven has plunged.

ExxonMobil’s has decreased from $56 to $21; that’s a total decrease of 62% and a CAGR of -8.3% per year. Santos’ has fallen from $50 to $19; that’s a total decrease of 63% and a CAGR of -9.4% per year. Woodside’s has decreased from $27 to $21; that’s a total decrease of 25% and a CAGR of -2.6% per year.

Figure 8: Breakeven Prices, CPI-Adjusted $US boe, 2015-2025

ExxonMobil’s has decreased most, Santos’ less and Woodside’s least. In 2015, ExxonMobil’s was highest, Santos’ occupied the middle ground and Woodside’s was lowest. Since 2023, their Breakevens have been indistinguishable.

Today, each company’s Breakeven is ca. $US20 per barrel of oil equivalent. At ARPs above ca. $20, they generate cash; above $80, they gush it. Given today’s Breakeven, the higher is the ARP the higher is the Netback; relatively fixed costs mean that higher prices fall straight to their bottom lines.

Implications

Speculators obsess about what’s unpredictable: commodity prices’ present and possible fluctuations over the next 12 months. Investors, in contrast, plausibly infer decades into the future. Speculators grossly overestimate the importance of recent changes and fluctuations – and ignore the critical importance of long-term developments.

Speculators’ short-term obsession amplifies the volatility of energy E&Ps’ shares – and thereby enable investors to buy low and sell high.

Short-Term Crisis but Long-Term Blip?

Investors consider energy prices in long-term CPI-adjusted contexts. Figure 9 plots the price ($US per million metric BTUs) of LNG in Asia and the EU since January 1992. It demonstrates two key points. Firstly, until the outbreak of the Russo-Ukrainian War in February 2022 the price of LNG was lower in the EU than in Asia. That was primarily because LNG imported into Europe before the war (primarily from Qatar) competed with cheaper gas transported via pipeline from Russia.

Figure 9: Price of LNG, CPI-Adjusted $US per Million Metric BTUs, January 1992-March 2026

Since the start of the Russo-Ukraine War, the quantity of Russian gas shipped to Europe has shriveled – and created greatly increased demand and resultant higher prices for LNG from Australia, the Middle East and the U.S.

Secondly, Figure 9 demonstrates that recent prices – ca. $25 during March 2026 – aren’t unduly dear by some past standards. Between August 2011 and March 2014, for example, prices in Asia averaged $25.10 and rose as high as $27.74. During this interval, high prices resulted from a “perfect storm” of factors which induced a massive shortfall of supply relative to demand.

In particular, the Fukushima nuclear incident in March 2011 Fukushima nuclear disaster in Japan, in whose wake Japan’s government closed that country’s nuclear reactors, triggered a surge in demand for LNG amidst constrained global supply. This period was also marked by high oil prices, to which many contracts were indexed, further elevating LNG’s price.

Above all, today’s price – so far – remains far lower than those which emerged following the outbreak of the Russo-Ukrainian War. Even before the war, they were already elevated. Between September 2021 and December 2022, prices in the EU averaged $39.89 and rose as high as $77.06.

Long-Term Stability

Another key point emerges from Figure 10: the longer is the interval, the lower is the volatility (expressed as standard deviations) of LNG’s price. (For the sake of legibility, I’ve truncated Figure 10’s vertical axis; on a 12-month basis during several months in 2022, LNG’s 12-month price skyrocketed almost 500%.)

Figure 10: Price of LNG, CPI-Adjusted CAGRs over Five Intervals January 1992-March 2026

Table 1 summarises Figure 10’s implications. The longer is the interval, (1) the more the CPI-adjusted price settles into a range ca. 2-3% above CPI’s rate of increase, (2) the more fluctuation of prices collapses – and (3) the smaller is the probability (established from Monte Carlo experiments with 10,000 iterations) that LNG’s CPI-adjusted price falls.

Over 20-year intervals, the probability is less than one chance in five that LNG’s CPI-adjusted price decreases; over 30-year intervals, the probability is less than 1-in-20.

Table 1: LNG’s “Spot” Price in Asia, CPI-Adjusted Change of Price and Volatility, Five Intervals

The price of “spot” LNG in Asia rose from $8.97 (CPI-adjusted) in January 1992 to $10.76 in February 2026. That’s a CAGR of 0.5% per year over this interval of 409 months (34 years and 1 month). In March 2026, however, the price vaulted to $25.15; that’s a CAGR of 3.0% per year over this 410-month interval from January 1992.

Obviously but importantly, this entire interval comprises just a single observation. The 12-month, five-year, …, and 30-year intervals, in contrast, contain scores and hundreds of observations (denoted by “N” in Table 1). Averaged over these many observations, and comparing the corresponding cells in the two halves of the table, the spike doesn’t affect these intervals’ average CAGRs or their standard deviations.

In that sense, Table 1 also quantifies the relative unimportance – from investors’ point of view – of the upward spike of “spot” LNG prices in March 2026.

Anticipating Some Cautions and Additional Objections

Given their Tier-1 (very large, high-quality, long-life and low-cost) deposits and projects, as well as the rough predictability over the next several decades of LNG’s CPI-adjusted prices, STO and WDS offer reasonable prospects for cashflows extending years and even decades into the future.

However, these promising very long-term prospects WON’T underpin continuously attractive investment returns.

In the short and medium terms, the prices of crude oil (which, with lags, help to determine the long-term contract prices of LNG) and “spot” LNG fluctuate enormously. So too, as a result, in the short and medium terms, do STO’s and WDS’s revenues and profits – and the prices of their shares.

An examination of STO’s and WDS’s fortunes over the past ca. 35 years provides no reason to assume that the next 35 years will be smooth sailing. The fluctuations of their returns will, however, generate ample opportunities for investors to buy low and sell high.

Figure 11 plots three investments of $1, adjusted for CPI and incorporating dividends, from January 1992 to March 2026:

• The investment in the All Ordinaries Index grew to $8.95; that’s a compound annual growth rate (CAGR) of 6.6% per year;
• The investment of $1 in Santos grew to $2.84; that’s a CAGR of 2.7% per year;
• The investment in Woodside grew to $10.03; that’s a CAGR of 7.0% per year.

Over these 34.25 years, Woodside has outperformed the Index and the Index has greatly outperformed Santos.

Figure 11: Investments of $1, CPI-Adjusted and Including Dividends, January 1992-March 2026

Until June 2008, however, STO and WDS greatly outperformed the Index:

• The investment in the Index grew to $3.84; that was a CAGR of 8.4% per year;
• The investment in Santos rose to $7.86 (CAGR of 12.4% per year);
• The investment in Woodside zoomed to $15.62 (CAGR of 17.6% per year).

The global commodity boom, driven in particular by insatiable demand from China, caused the prices of “spot” crude oil (which help to set the prices of LNG in long-term contracts) and LNG to soar. In addition, the reaction to STO’s announcement of its intended transition into LNG production was euphoric: firstly, it commissioned the Bayu-Undan LNG project in the Timor Sea and thereby proved its ability to operate in international LNG markets; secondly, it announced the development of the Gladstone LNG (GLNG) project in Queensland.

In Woodside’s case, significant growth of output and particularly its emergence as a major supplier at a time of vaulting commodity prices caused its shares to skyrocket. In particular, the commissioning of NWS Train 5 (a “train” is essentially a giant refrigerator which converts natural gas into LNG) and the acquisition of additional stakes in NWS oil assets (such as from Shell in 2008) greatly increased its output.

These huge CAGRs didn’t last. A dramatic and unexpected plunge in global oil prices (in nominal terms – that is, unadjusted for CPI – Brent crude crashed from $111.80 in June 2014 to $30.70 in June 2016), and consequently of LNG prices, began in mid-2014. The “shale revolution” in the U.S., combined with OPEC’s decision to maintain production levels rather than cut output to support prices, created a massive glut. Weakening global demand exacerbated it.

This plunge of crude oil’s price coincided with the peak capex phase for STO’s GLNG project. Its capex peaked just as low energy prices slashed its prospective revenues. This combination caused market participants to lose confidence in STO’s ability to finance its expansion.

In December 2014, Standard & Poor’s downgraded Santos’ credit rating and warned of further downgrades if oil prices stayed low or if GLNG experienced cost overruns. The construction of GLNG’s first train concluded in 2015; the second train finished in 2016. By then, it’d experienced cost overruns of ca. $2.5 billion. Given lower than expected oil prices and higher than expected construction costs, over the next several years Santos took ca. $2.5 billion of non-cash impairment charges against its value.

As a result, from June 2008 to January 2016, the investment in the Index grew 12% (CAGR of 1.5% per year); Santos’ collapsed 86% (CAGR of -23.0% per year); and Woodside halved (CAGR of -10.1% per year).

The past 10 years, however, tell a very different story (Figure 12):

• the investment of $1 in the Index grew to $1.96 (CAGR of 6.8%;
• the investment in Santos grew to $2.58 (CAGR of 9.7%);
• Woodside rose to $1.43 (CAGR of 3.5%).

Figure 12: Investments of $1, CPI-Adjusted and Including Dividends, January 2016-March 2026

Figure 13 plots these three investments’ CPI-adjusted, medium-term total returns since January 1997. In general, they’ve been volatile; specifically, they’ve fluctuated cyclically. Santos’ has varied between a minimum of -26% per year and a maximum of 31% per year, and has averaged 3.1%. Woodside’s has varied between -11% and 40%, and has averaged 7.2%. Finally, the Index’s has varied between -6.7% and 19.2%, and has averaged 6.5%.

Figure 13: CPI-Adjusted Total Five-Year Returns, Three Investments, January 1997-March 2026

Figure 13 illustrates Warren Buffett’s cautions about equity ownership.

“If you’re going to do dumb things (such as sell) because a stock goes down,” he told CNBC in 2017, “you shouldn’t own (it) at all.” “Some people,” he added a year later, “should not own stocks at all because they just get too upset with price fluctuations.”

If you’ve researched carefully and your valuation is conservative, Buffett concluded, you should be “prepared, when you buy a stock, to have it go down 50% – or more – and be comfortable with it.”

Conclusions

Leithner & Company purchases shares of major companies in essential industries when our conservative estimates of their values exceed their current market prices. Leading explorers for and producers of crude oil and LNG amply qualify as essential. Indeed, they’re exemplars of indispensability. Energy is the master resource: the production of all commodities, goods and services presupposes its availability; without energy, no good is produced and no service is performed.

Hydrocarbons have long been, today are and will long remain irreplaceable pillars of the global economy. The world’s population is slowly but steadily becoming more prosperous; hence it requires ever more – not less – energy. In particular, it’s demanding more coal, crude oil, natural gas and LNG.

They presently comprise 80% of the world’s consumption of energy (and, by the federal government’s own estimate, 90% of Australia’s). That’s despite the expenditure over the past couple of decades of trillions of dollars on intermittent (which is ubiquitously but falsely called “renewable”) energy, and is barely lower than the corresponding percentage (ca. 85%) in 1975.

Globally, the “transition to net zero” simply isn’t happening. At best, it’s unfolding at a snail’s pace: at its current rate, reaching something close to “net zero” will take 400 years! (see in particular “Net zero” isn’t a Megatrend: It’s a Mega-trap, 8 April 2024).

It’s becoming clear to ever more people: this expenditure of tens of trillions of dollars globally hasn’t merely been a monumental waste: it’s imposed enormous costs upon those countries (Australia, alas, is one) whose governments have stupidly chased absurd fads (among a Mount Everest of evidence, see “Labor’s Missing $1 Trillion,” The Australian, 15 May).

Hydrocarbons remain as indispensable as they’ve been since the 18^th century: today they power virtually all of the world’s transport, generate the vast majority of its electricity and provide all of the feedstock for vital industries such as fertilisers, petrochemicals, plastics and much more.

Without plentiful hydrocarbons, hundreds of millions of people would starve and the standard of living of billions of people would plummet.

In the wake of the Third Gulf War, it’s become obvious – even Anthony Albanese (but not, alas, Chris Bowen) has very grudgingly accepted it – that the security of hydrocarbons’ supply is a necessary condition of national security.

Before the war, the tide was already turning. In the latest (November 2025) edition of its World Energy Outlook – which, it’s worth emphasising, was published months before the start of the war – the International Energy Agency reversed its longstanding predictions of “peak oil and gas.”

IEA now admits that it’s much more likely that global demand for hydrocarbons will increase over the decades to come. This growing demand will derive primarily from low-income (which are mostly high-population) countries.

Since the war, according to The Wall Street Journal (“The Global Energy Order Is Breaking Down,” 29 April), the departure of the United Arab Emirates from OPEC and “other moves are accelerating a shift from an oil market structured around economic efficiency toward one shaped by politics and conflict … The Iran war is scrambling the longstanding foundations of the oil market, ushering in a more fragmented and potentially more volatile energy world. The free flow of petroleum across oceans is out. Resource nationalism is in.”

The same point applies to LNG.

“What’s very clear is that this has driven home a point to Canada and other countries around the world of how much we are at a hinge moment, how much the system we all took for granted around free trade, around the free flow of energy, has been ruptured,” Tim Hodgson, Canada’s minister of energy and natural resources, told The Wall Street Journal (“The Global Energy Order Is Breaking Down,” 29 April).

Australia is one of those other countries.

Santos and Woodside are well-placed to help meet this shift of demand – as well as rising global demand. They own and operate Tier-1 LNG infrastructure, and over the past decade they’ve become world-class producers and exporters. Accordingly, the Breakeven prices of their overall output, which includes gas for domestic consumption and crude oil, have fallen steadily and are now close (on CPI-adjusted bases) to all-time lows. In particular, over the past several years their productivity has matched ExxonMobil’s.

These developments, other things equal, will tend to boost their bottom lines. Meanwhile, it’s reasonable to infer that in the decades to come their top lines will expand. In particular, the longer is the investor’s time horizon the smaller is the probability that LNG’s CPI-adjusted price will decrease.

Despite drawbacks such as capital intensity, risk of cost overruns during construction and operation, etc., low-cost and globally-significant producers of minerals and energy possess a key advantage which very few other companies do (and virtually no other sector does): essential products whose CPI-adjusted prices can plausibly be inferred decades into the future.

For these and other reasons, at multiple junctures over recent years and also in January, Leithner & Company purchased the shares of globally-significant owners of Tier-1 energy assets such as Santos and Woodside. As a result, they’re a pillar of our portfolio.

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