Hey everyone! This month we wanted to switch it up and try a new industry. This piece is written assuming no real prior knowledge of the oil and gas industry and thus we hope you can learn a lot about sector specific concepts. Having said that, there are particular risks with this investment that we think will preclude many from interest in investing. Nevertheless, we still think the analysis provides a lot of value and is well worth a thorough read as the oil industry intertwines with almost every industry and we go to lengths to simplify complexity. Of course, the facts could change with PetroChina specifically that may make it a more acceptable investment in the future (or you can disagree with our risk assessment). Nevertheless, we promise you will learn a lot and hope you enjoy leaning about a new sector with us!

Background History.

The seeds of PetroChina were planted in the early 1950s when a predecessor state-run organization, The Ministry of Petroleum, started exploring the Yumen region in northwest China in search of oil. While there was good reason to believe oil was in this area, after unexceptional results and drilling more dry holes than they cared to remember, they started to move more eastward. Eventually, they would happen upon what today is known as the Daqing oil fields, an area so prolific it surpassed most of the greatest middle east oil fields in production. While total production figures are spotty throughout its half a century plus history, we know that at the turn of the century this single oil field was producing almost as much oil annually as Exxon did globally. While they would continue to find more oil fields throughout China, Daqing, until fairly recently, remained by and far the most prodigious.

The Daqing Oil Field in China’s Northeast Heilongjiang province.

China would undergo much political transformation since the oil fields were first found, but they continued to operate throughout the period, ultimately ending up in the newly created CNPC in 1988. The CNPC, or China National Petroleum Corporation, was a state-owned company that took over most of the activities of the Ministry of Petroleum. In 1999, the CNPC created a joint stock company and transferred most of its E&P, refining, and marketing assets to what would be dubbed PetroChina.

PetroChina Org Chart.

Just a year later, PetroChina IPOed with H shares on Hong Kong Stock Exchange and an ADS on the NYSE, followed by a second H share offering in 2005 and an A share IPO on the Shanghai Stock Exchange. Despite several share offerings on three stock exchanges, they continue to retain >80% of the company. Today, PetroChina remains China’s dominant onshore petroleum company and generates in excess of ~$400bn in revenues. In contrast to most listed Chinese companies, they pay out a material portion of dividends on their ~$15bn in net profits, which amounted to ~$6bn last year. Before diving into PetroChina specifically, we will zoom out and go through the industry.


At a high level, energy companies are very straightforward: they extract a compound from the ground, process it, transport it, and then sell it. However, there is a dizzying array of complexity that foments when getting into the specifics. For starters, even though we refer to all oil that is pulled out of the earth as “crude oil”, the composition of crude oil varies significantly, which can increase the cost to pull it out, refine it, and even the final value of the end product. There are no fewer than 19 different end products that can be yielded from crude oil, whose raw ingredients differ in amount for different crude oils. This is important as different end products have different demand, which means certain end products can actually be loss making, subsidizing higher margin products (depending how to attribute the refining costs). The best-known end product, Gasoline, is actually just 45% of what crude oil is turned into. In this section we will attempt to improve your understanding of the oil & gas industry without overloading you.

There are four main parts of the industry: 1) Exploration and Production, 2) Refining, 3) Transportation, and 4) End customer distribution, which is often called marketing. You can see below PetroChina’s revenue mix by segment, however since they are a fully integrated oil company there are a lot of intra-company transactions that distort this.

First, we will talk about Exploration and Production (E&P), which is also known as “upstream” in the value chain.

Exploration and Production.

Exploration and Production deals with the discovery and extraction of “hydrocarbons”. Hydrocarbons are the organic molecules that release energy when it combusts (reacts with oxygen) and thus are a great source of energy. If we were to categorize hydrocarbons by the number of carbon atoms they contained (at atmospheric pressures), hydrocarbons with 1-4 carbon atoms are typically gases, whereas those in the 5-24 range are liquids and those with more than 25 carbon atoms are usually solid. The number of atoms in the molecule distinguishes whether it is considered “light” or “heavy”. This is why certain crude oils are referred to as “heavy”—the hydrocarbons in the crude oil tend to contain more atoms per molecule. As a practical means, since analyzing the molecular contents of each crude oil is untenable, oil companies will use density as a rough approximation for the molecular composition. The crude oils with larger hydrocarbons (more atoms per molecule) are denser than the crude oils with smaller hydrocarbons (less atoms per molecule). The most common metric of density is referred to as API (after the American Petroleum Institute) and can range from 0-100 with 100 being the lightest.

Crude oil can vary in API usually ranging from 10-50°, but most refiners are optimized to handle 30-39°, requiring crude oil blending or specialized refineries to handle heavy crude.

There are hundreds of different molecular combinations that hydrogen and carbon can take together (they can vary even if they have the same number of carbon and hydrogen atoms), but for our purposes it is only important to know that some of these molecules are easier to manipulate than others. Transforming hydrocarbons into different (more desired) molecules is what the refining process is. We will touch more on this in the refining section, but for now it is important to acknowledge the highest value crude oils are those that require the least refining. To simplify, a refiner will try to make as much of the highest value end product—which is usually gasoline—and using a crude oil that can yield the most gasoline with the least refining would be the most profitable crude oil. Gasoline is a mix of hydrocarbons with 5-12 carbon atoms and thus using a light crude oil as “feed stock” (raw input) tends to yield the most gasoline with the least refining. It is the higher ease of which light crude oil can be turned into gasoline that allows it to garner a slight premium in global oil markets (to oversimplify).

There are several other factors that dictate the quality of crude oil and impact it’s price, including sulfur content, acidity, viscosity, and contamination level of other non-desirable compounds (like metals, salts, and sentiment). The most valuable crudes are those with the lowest sulfur content, lowest acidity, least viscous, and minimal contamination of other substances. The amount of sulfur in crude oil is referred to as being “sweet” if the sulfur content is under 0.5% by weight or sour if over 1.5%. So, if a crude oil is sweet, it is more desirable (and garners a premium price) because it requires less treatment to remove the sulfur. TAN, the total acidity number, is a measure of how acidic the crude oil is. Acidity is problematic as it is corrosive to most machinery and thus requires additional refining. (A TAN number over 0.7 is considered highly acidic and most refiners prefer below 0.5). There are similar discounts or premiums factored into the price of a certain crude oil for the other variables mentioned.

Crude oil, which we haven’t defined yet, is simply an unrefined liquid of hydrocarbons (also called unrefined petroleum). If the hydrocarbons are in gaseous form, then it is called natural gas (which is a mix of mostly methane gas with some ethane, propane, butane, and some other non-hydrocarbon molecules). Ethane, propane, and butane can be stripped out of natural gas to create “natural gas liquids” (NGLs) or can also be found naturally (sometime alongside a small amount of natural gasoline). These NGLs are called such because it is easy to cool them into a liquid but are gases at room temperature. These different forms of hydrocarbons tend to be found near each other, so it is very common for an E&P company to be extracting crude oil and natural gas together.

The photo above shows a “sucker rod pump” extracting oil, while “flaring gas”. Flaring gas is when a producer ignites the methane gas that escapes the oil reservoir since that is better environmentally than letting it leak unlit into the atmosphere. Usually flaring is illegal (depending on country) unless it is unavoidable since regulators want the producer to capture the methane gas for use. This also shows how drilling for oil will often make you a gas producer as well.

For the past few years PetroChina produced around ~900mn barrels of crude oil annually. For context the world produces around ~33bn barrels of crude oil globally and the largest integrated oil companies like Royal Dutch Shell and Exxon produced around ~600mn and ~500mn annually, respectively. The only other mega producer in China is CNOOC, China National Offshore Oil Corporation, who produces around ~450mn barrels of crude annually. PetroChina not only produces twice as much as them, but their current crude oil reserves are larger at 6.2bn barrels vs CNOOC’s 4.1bn (However, CNOOC does have more natural gas reserves at 8.8tn cubic feet vs Petro’s 7.9tn).

CNOOC is China’s largest offshore producer and the 2nd largest oil and gas producer in China.

The reserve figures we just quoted though are worth diving into as there are a ton of assumptions that go into them. For starters there is term called Original Oil in Place (OOIP) which is the total amount of oil that is originally in a reservoir. However, the majority of oil actually cannot be recovered and remains in the earth. The “recovery factor” or “recovery efficiency” is the % of oil that can actually be extracted, Incredibly, that figure globally averages around 30-35%. A common misconception (that we were guilty of too) is thinking that oil exists in “pools” underground, and you simply have to suck it out. In reality, most oil is found within a rock matrix with varying porosity and permeability. Since the oil is surrounded by obstacles to get it out, pressure is a critical aspect of extracting the oil. Thankfully, often there is natural reservoir pressure (remember how gases are usually found with oil) sufficient for a driller to extract out oil easily. When an oil producer can simply use the reservoirs natural pressure to extract oil, it is referred to a “primary recover”.

Oil in commonly found in the pores of a “rock matrix”. In order to extract the oil out, producers rely on pressure to bring it to the wellhead.

After the pressure in the reservoir is no longer adequate to pull the oil out, they will move to “Secondary Recovery Methods”, which involve injecting more reservoir pressure either with gasses or water. There after they can move to “Enhanced Recovery Methods”, which include creating more fractures within the rock matrix to make it easier for the pressure to reach the oil or adding other liquid solutions to make the oil less viscous and thus easier to be pushed out.  (On a side note, preserving natural reservoir pressures is critical to achieve the maximum recovery of oil and why a lot of the “lassie fair” drilling that occurred in the early days of the oil industry was extremely wasteful. Essentially it was a tragedy of the commons issue: drillers would put multiple wells, sometimes just a few yards from each other, in order to get the most oil out for themselves as quick as possible, despite each drill lowering the overall reservoir pressure and reducing the ultimate recoverability rate).  With secondary and enhanced recover methods, the recoverability factor can reach over 60-70%, which is considered excellent.

Water injection well near an oil field.

Now with some appreciation for how hard it is to extract oil; we can better imagine how difficult it is to accurately measure the amount of oil underground and how much is recoverable. There are three categories of reserves: 1) Proven, 2) Probable, and 3) Possible. The SPE (Society of Petroleum Engineers) created these broad categories, which the SEC later adopted in 2009. Now companies report proven reserves and may at their discretion also disclose probable and possible reserves. Here is the distinction:

1. Proven. Also known as P90 or “1P” reserves. These are reserves that are estimated with a probability over 90% to be recoverable under current technological capabilities while being economic. The SEC requires that a company use the average market price for the last 12 months when calculating economic viability of reserves, which means if prices plummet reserves can vanish. Similarly, if prices increase, reserves increase as they become economically viable.

In 2016, PetroChina provided the below disclosure after prices plunged from ~$100 a barrel in 2014 to averaging <$40 in 2016. In this disclosure they show how a change in price from $37 to $70 would allow them to book another 2.4bn in BOE reserves (BOE is barrel of oil equivalent—it is calculated by assuming 6,000 cubic feet of natural gas equals one barrel of oil and adding that amount to their crude oil reserves). This is an incredible number of reserves that become available from a price swing, worth over $170bn at the $70 price. 

2016 disclosure shows reserve accounting sensitivity to price swings.

Below we can back into the incremental cost of the supply, showing how the cost curve of extraction increases in order to get a higher recover rate of the reservoir. We see that the incremental cost of the 2.4bn barrels is $40.30 versus $19.41 for their actual 2016 reserve base. This also implies that at an even higher oil price there would be even more oil available for them to produce as enhanced recovery methods become more economically feasible. Especially at high oil prices, it is always crucial to remember that reserves exist only in the context of a specific price. Presumably in the future, new lower cost extraction methods will make “harder to get oil” more economically tenable, and thus increasing the reserves.

In addition to economic considerations, in order to count reserves as proven, the company must show geological and engineering data that show recovery is reasonably certain (>90% probability). This is not an exact science and revisions are very common. The reserves may change for four reasons: 1) technical revisions of estimates, 2) discoveries & extensions, 3) improved recovery, 4) acquisitions and disposals. “Technical revisions of estimates” are estimate revisions because of inaccurate assumptions. Since proven reserves are supposed to have a probability of >90%, you can judge the honesty of management based on how many downward adjustments there are in this item—theoretically downward adjustments should be rarer than upward adjustments owing to the required conservatism. The next item, discoveries & extensions, are fairly self-explanatory—E&P companies will find new sources of oil or existing reservoirs will prove deeper than they originally realized. The third factor, improved recovery, deals with technological changes that allow for better resource extraction. Lastly, acquisitions & disposals, is simply selling or buying land with reserves. The exhibit below shows the itemization of PetroChina’s 2021 reserve changes.

One final detail of proven reserves is that they can be further split up into two groups: Developed vs undeveloped proven reserves. Developed reserves are those that already have the majority of capital expenditures outlaid in order to extract the reserves. Developed reserves can be produced with relatively minimal incremental capex through existing wells, but also tend to be considered less susceptible to downward revisions as the company is already producing on them and thus has a lower probability of running into issues. Undeveloped reserves are those that require material capex in order to extract the resources. Similarly, these reserves are also held to the >90% probability test, but despite the same probability test, reserves in this category vanishing are more likely (but so is an upside revision).  

PetroChina oil and gas fields. The Daqing region is circled in red.

2. Probable. These are oil reserves that are thought to have an >50% probability of being recovered. They can also be referred to as 2P or P50 reserves. By definition this category would also include all proven reserves.

3. Possible. These are oil reserve estimates that are thought to have >10% probability of being recovered. This category can also be called 3P or P10 reserves. You may think of these reserves as being the most optimistic scenario of what could be produced.

PetroChina oil field.

PetroChina’s oil production comes from several fields with one eclipsing the rest: the Daqing oil field. In 1999 they had 6,034bn barrels of crude oil reserves attributed to just the Daqing oil field, however two decades later that has dwindled to just 960bn or ~15% of its previous size. By summing up the total production of the Daqing oil field over its lifetime, we can see roughly how accurate their estimates have been. From 1999 to 2021 the Daqing oil field produced 6,539bn barrels of crude oil, or about 110% of their 1999 reserve estimate. If the remaining 960bn in Daqing reserves is an accurate estimate they will have extracted ~125% of their original 1999 estimate. This shows management was pretty fair with their original estimate.

Total oil produced in Daqing plus 2021 remaining reserves estimates is 7.5tn versus 1999 estimate of 6tn.

Validity of reserve estimates aside, a bigger point here is that their largest oil field, which was responsible for over half of oil production at one point, has been starting to dry up. While it still produces ~200mn barrels annually, at this rate of production the oil field will be fully depleted in 4.4 years versus 14.9 years in 1999.

As you can see below, it is not just the Daqing Oil field that has this issue—across all of their field’s production is exceeding the rate at which they find new reserves.  Below we graph their crude oil production against total reserves. As you can see reserves are about 40% lower than a decade ago. Generally speaking, it is desirable to see that reserves are being replenished as quickly as production. Of course, when you have an oil field as prodigious as Daqing, it is hard to just replace those reserves.

A common ratio to gauge reserve replenishment is the reserve to production ratio, which is simply total reserves divided by annual production. As you can see below, the ratio held roughly steady until 2009 and has since been failing rapidly. This is despite 2021 production levels being similar to 2009. At a reserve to production ratio of 5.7x means that without new field discoveries or extensions, PetroChina will run out of oil reserves by 2028. However, we view this as highly unlikely as in the past 3 years they increased reserves an average of ~450mn barrels of crude oil with new discoveries and extensions. This is in addition to another ~100mn of average annual reserve increases on improved recoveries. These two factors would yield ~550mn of crude oil additions, which if we assume steady production of ~900mn a year would mean that in ~17 years PetroChina will fully deplete their resources (~350mn annual net depletion of reserves).

Natural gas production (currently ~37% of total E&P revenues) has been more than matched by reserve growth. In 2000 they had an estimated ~32,500 bcf  (billion cubic feet) of natural gas proven developed and undeveloped reserves, which by 2022 almost doubled to ~75,000 bcf. This is despite natural gas production being up almost 8-fold to ~4,400 bcf annually from ~500 bcf in 2000. The increase in reserves has been mostly driven by new discoveries and extensions that have far outstripped their production, despite production significantly ramping up. Their reserve to production ratio on natural gas is ~17x today and over the past two decades they have consistently found new reserves in excess of their production. Of course, this will not be true forever. But having not observed an inflection like we saw with crude, it will be harder to estimate when they will deplete their natural gas. We will go through a few different ways of thinking through lifetime production and “terminal value” later as it is an important factor in valuing PetroChina.

Daqing Oil Field

Below we see total revenues and segment profit for their E&P segment. In 2021 they generated RMB 688bn in revenues, which is equivalent to ~$110bn. Their profits of RMB 68bn or ~$10bn are contingent on transfer pricing accounting as they “sell” what they produce to themselves. In theory, calculating the price should be straight forward as there are many widely traded crude oil products that create price transparency. However, in reality there is a slight discrepancy between the stated average purchase price and where other crude’s trade at (like WTI or Brent). In 2016 for instance their average selling price or crude was $37.99 versus WTI which averaged around $44. Generally speaking though, it is close and is explained by different oil quality and pricing contracts at a given price for a particular day.

There is less clarity on the cost structure within the E&P segment though. There are three main costs concerned with an E&P operation: 1) their lifting cost or production costs, and 2) their finding or exploratory costs, and 3) their development costs. The first item is always an expense and the third item is almost always capitalized, whereas the middle item can be both depending on the circumstances. The first item, lifting costs, are defined as follows:

For the last year their lifting costs were $12.30 (per BOE), still within their $11-$13 range of the last 7 years. As the oil gets harder to pull (or push rather) out of the ground, it is typical to see lifting costs increase, especially since their premier oil field has been slowing in production (which implies the “easy oil” that came up on natural pressure is dissipating). We would have to go back 15 years to see that lifting costs used to be ~half of their current rate, but they still are pretty low in absolute. Part of these steady costs though can also be the byproduct of technological improvements and a greater mix of natural gas in that figure over time.

From PetroChina promotional material.

The finding costs or exploration costs are incurred in identifying areas that are thought to have recoverable resources and include the cost of drilling exploratory wells that confirm the existing of oil. These costs are usually expensed until some oil is proven at which point further efforts can be capitalized. PetroChina spends about RMB ~10bn or $1.5bn annually on exploration costs, which are not capitalized. There is an unspecified amount that is included in capex as well.

Development costs, which are the costs incurred to build the facilities to ready the resources for extracting and storing are usually capitalized and depleted over the lifetime of the well. Total capex for the E&P segment for the past couple years, which is principally development costs, has been around RMB ~180bn or ~$27bn annually.  PetroChina drilled almost 1,500 exploratory wells in 2021 versus ~11,500 development wells, which helps show why their development costs are much higher than exploratory. (As a side note, It is hard to think about what a “normalized” level of maintenance capex is because success in finding oil and natural gas is somewhat independent of their efforts or spend. At some point the easy oil simply no longer exists and it becomes increasingly expensive and difficult to find incremental supply. The ambiguity of when the resources will ultimately run out makes it hard to conceptualize their reinvestment needs. In short, any return you see bears little indication of future returns. We will pick back up on this in the valuation section).

Unfortunately, there is some ambiguity as to PetroChina’s itemized segment P&L for the E&P segment. They give us information on a group level, but not company level. The issue is the group includes all affiliates, but not certain JVs and we cannot parse out easily what to actually attribute to PetroChina. On a group basis we know that their production costs are about 25% of total revenues, exploration costs are 5%, and depreciation, depletion & amortization (DD&A) is 30%. The DD&A is where the capitalized development costs run through the P&L. Other than production taxes these are theoretically all of the main components of expenses. However, when we try to reconcile the group’s costs base with the company’s, they are off by ~20% (we saw that others had similar issues reconciling as well). Nevertheless, whatever these excess “other costs” are, they tend to be fairly steady overtime and we can still run the math on the value of production in our DCF later on. We will come back to another discussion on the E&P segment from a business perspective later on, but first we will go through the rest of the segments starting with Natural Gas & Pipeline.

A PetroChina pipeline.

Natural Gas & Pipeline.

The next step after the crude oil and natural gas is extracted is to transport it so it can be refined into a consumable product. This is usually done through either pipeline, ship tanker, railcar tanker, or truck tanker. Despite “barrel of oil” remaining a conventional measurement metric, oil is seldom actually shipped in barrels as pipelines and tanks are far more efficient. For natural gas, if there is no pipeline nearby, it can be condensed 600x to become liquefied (liquid natural gas) and shipped in a tank. Shipping costs will vary by method and distance but usually at most it is ~10% the price of a barrel of oil and typically less than that (of course if oil prices get abnormally low like in April 2020 that rule of thumb won’t apply).

PetroChina has extensive infrastructure to support the transportation of their crude oil production, including 2,590km of pipeline to accommodate the Daqing oil fields alone. They have also built railway facilities and can contract railcar tankers to move other crude oils or refined products. Most of their pipes connect directly to their refineries and they also have a vast pipeline network to move refined products, including natural gas in particular.

Natural gas still needs to be purified before being used by an end consumer, so pipelines will take the gas directly to a treatment plant which will separate out carbon dioxide, hydrogen sulfide and other undesirables, as well as certain higher value gases like propane and butane, which can be easily liquified and sold as NGLs.  After processing, another pipeline network will take the processed natural gas (the consumer product that is mostly methane gas) to the end consumer, which can be a municipal utility, power plant, fertilizer & chemical company, or industrial manufacturer. In total PetroChina has 17,329km of natural gas pipelines, 7,340km of crude oil pipelines, and 1,407km of refined oil product pipelines. A pipeline network as large as this is very hard to replicate and usually configured to a particular oil field and refinery footprint with long-term contractual service agreements that minimize the risk of service disruption. Essentially this means there is virtually no other player that can be competitive on each of these particular routes as they would need to build a pipeline to be the lowest cost operator but would never do that without guaranteed volumes which they would not be able to get. This is why pipelines are often thought of as the highest quality businesses in the oil the value chain; they are analogous to the metaphorical toll bridge.

PetroChina recently reorganized its pipeline business and put the majority of the assets in “PipeChina” in exchange for a 29.9% interest in PipeChina and cash consideration of RMB 97bn (~$15bn). They retained most of their pipelines that connect their refineries to their oil fields. Prior to the reorganization they had 53,291km of natural gas pipeline, which represented the vast majority of China’s natural gas pipes. The ostensible reason of the restructuring was to “focus more on upstream E&P” and “downstream distribution”, while “relieving capital expenditures” and “gaining access to a nation-wide storage and transmission facility”. We consider this reasoning fairly flimsy, particularly the capex point, as the E&P segment sucks up ~7x more capex than their Natural Gas and Pipeline segment. There could be something to the point that combining all of their pipe assets with a nation-wide network could allow more efficient transmission, but at the same time a lot of their pipes were built specifically for their existing gas field footprint so that also seems suspect. Practically speaking, there could be some non-economic factors at play here, driven by a desire to consolidate most of the country’s pipes under a different administrative organization.

As we can see above, the Natural Gas and Pipeline segment still represents 10% of their revenues, but a larger % of profits (around 25% of the total profits excluding a gain from the Pipeline sale in 2020). This segment’s revenues are generated from the sale of natural gas to end customers. In 2021 they produced 4,420 BCF (billion cubic feet) of natural gas, but in total sold 9,675 BCF. The difference is covered through natural gas imports, whereby PetroChina acts as a reseller. Unfortunately for Petro, natural gas prices are regulated, but PetroChina is nevertheless required to import enough natural gas to meet certain demand levels. This means PetroChina is often in the position of having to procure natural gas that cost more than they can sell it for. This loss-making activity is already included in the segment profit below, accounting for a decrease of profits of RMB ~7.2bn and RMB ~14.1bn for 2021 and 2020, respectively (or ~$1bn and ~$2bn). Clearly this is very undesirable as a shareholder, but the very cheap natural gas they have from their owned fields still allows them to make an ample profit for this segment which was around ~$4.3bn in in 2021 excluding asset disposal gains. Furthermore, natural gas reform is starting to allow market-based pricing on newer (post 2015) operations, and it seems it will slowly expand to the rest of operations. This means overtime we can expect their losses to abate as the government is starting to consider a market pricing system as a good natural inhibitor of excessive consumption.

Starting in 2022, this segment is being renamed to “Natural Gas Marketing” given the large recent sale of their pipelines. Technically the “marketing” comes after the refining, but since they used to include transportation in here, we wanted to first mention that. To clarify, upstream activities are E&P, midstream is transportation, and downstream is refining and marketing. We will now move from midstream to downstream with refining.  

Refining & Chemicals.

Refining is the process of transforming feedstock—what crude oil is called after reaching the refinery– into “finished products” through a multi-stage refining process. There are four main stages to the refining process: 1) Separation, 2) Conversion, 3) Treatment/ Enhancement, and 4) Blending. We will say a few words on what these processes are to get a better understanding of the industry, but it is not necessary to understand the company financially.

Recall that a barrel of crude oil will have various different hydrocarbon molecules that are “heavier” such as those in bitumen (an almost solid substance used in asphalt) or “lighter” molecules such as natural gas liquids. A particular range of molecules is called a “cut” so we can refer to a “light end cut” to describe that the hydrocarbons that are lighter. Separation is the first step of the refining process where the refiners start to separate out all of the different types of hydrocarbon molecules into different cuts so they can be used to create different products. The refiner will first desalt the crude oil and then dewater the crude oil (water is very commonly found with oil and is mostly removed prior to transit) in a settling tank. Then the crude oil is sent through distillation units that use various pressure to vaporize the various products that then collect at different levels of the distillation column. The distillation process is what separates heavier molecules, which collect at lower levels of the column, from lighter molecules which float higher before condensing (bubbles form in the liquid which float through semi-porous trays to various heights based on how heavy the molecules are and when they can’t reach any higher they collect at the higher tray that corresponds to their molecular size).

Crude oil distillation columns that separate different hydrocarbon molecules. The height is necessary to allow Hydrocarbon molecules of lighter size to float up.

The separation process will only yield finished product commensurate with what is in the crude oil. So, if only 25% (making this figure up) of the Daqing crude oil has gasoline boiling range molecules, separation of Daqing crude oil will yield only 25% gasoline. Since gasoline and other “middle distillate products” tend to be the highest value, the refiner will try to make the most of them. (Middle Distillate refers to where the molecules fall in the distillation column and includes kerosene, jet fuel, heating oil, and diesel).

The next step, conversion, is where the refiner cracks (breaks apart), combines, or modifies the hydrocarbon molecules to make more “cuts” that can be turned into higher value products. We will not get into specifics of how this is done, but there are various methods with various cost and energy expended to transform these molecules.

An oil refinery.

A key thing to note is that the price of the end products will dictate whether or not it is economical to modify these hydrocarbon molecules into higher value cuts. If prices of gasoline and other middle distillates fall, then the refiner may not produce more of these products as the conversion costs are higher than what they can sell the finished product for. This means that even without extracting more oil there is some fungibility in what end products can be produced. This is exemplified in 2020 for example when PetroChina increased the proportion of chemical products while reducing their refined oil products to respond to the plummeting of global refined oil prices.

Refinery distillation column.

The third process, treatment & enhancement, involves removing undesirable molecules like sulfur and nitrogen among others. This process is becoming more important as fuel regulations proliferate which create a need for more rigorous treatment to meet emission standards. The last process, blending/finishing, involves mixing different refinery products to reach certain industry standards. For instance, different finished product gasolines have different standards (think octane rating) that will be achieved by mixing different blend stock components (like small amounts of butane or naphtha for instance).  

A large oil refinery plant.

PetroChina’s distillation capacity is slightly in excess of 4mn barrels a day, which is almost twice as much as peer Sinopec. They are in the same league as the large global integrated oil companies like Exxon and Shell who have the ability to process 5mn and 3mn barrels a day, respectively. Petro has a little over a third market share of the domestic refining market, with a large amount of independents taking a material share. PetroChina utilizes approximately ~80% of refining capacity with them importing about ~45% of their feedstock from international sources.

Petro’s average yield of “principal products” (% of main finished products as a % of total feedstock by weight) is right under 70% and their total yield (includes all products) is ~94%–in line with peer Sinopec. Said differently, this means ~6% of feedstock is not turned into end-products, which is about in-line with the industry standards.

The mix shift of their principal products is shown above. Expectedly diesel and gasoline are the largest contributors. (Note that the yield calculations are done by weight and not volume: there is something called “refinery gain” whereby the processing of crude oil yields more volume than the feedstock because the hydrocarbons are more often than not “cracked” into smaller molecules for higher value products).

Refinery Footprint is concentrated in the Northwest.

PetroChina’s refining footprint is mostly in the Northeastern and Northwestern regions of China, close to their main oil fields. This reduces transit costs of crude oil into the refineries and also means they incur lower transit costs to distribute finished products in that region. However, to ship products to Southern markets is relatively more expensive. They do not break out how much, but it seems Sinopec, who has their refining footprint more in the South has slightly higher market share there as a result. It is not huge factor, and they are still competitive, but it does mean Petro will face a slight margin headwind to the extent the demand in the South growths faster than the North.

Below we can see the Refining and Chemical segment of PetroChina generates around a quarter of revenues before inter-segment eliminations.

Typically, refinery margins are considered pretty steady since they just make the spread of the difference between the input costs (feedstock) and the finished product price. This spread between the raw crude oil and the finished products is called the “crack spread” (named so after the “cracking” process, which is when a refiner breaks apart the large hydrocarbon molecules that are typically found in crude oil into smaller ones found in products like gasoline). There are different variations of crack spreads that use different crude feed stocks and finished products in the calculation as the prices of both can vary (a very popular one is dubbed the 321 crack spread, which is the spread between the purchase price of 3 barrels of crude oil and 2 barrels of gasoline and 1 barrel of diesel. This is just a popular financial metric and is not indicative of the actual finished product yields that can typically be created from a barrel of crude oil).

As you can imagine (and have probably experienced), the higher the price of crude oil the higher the price of finished products like gasoline become. The refiner tends to be able to keep a somewhat steady margin (at least compared to E&P which can whipsaw in and out of profitability quite regularly) and pass off their higher input costs to the end consumer. However, it is a little more complicated as each product the refiner can make has its own supply and demand curve and at higher prices there can be demand destruction (think a consumer driving less or opting to postpone a vacation since higher jet fuel prices raised the airlines ticket prices). When demand starts to soften on the finished products, the refiner can be left with more expensive feedstock that has to be refined less economically, or potentially at a loss. Thankfully for the refiner, their throughput rates are very quick, but nevertheless they can still be left with “unfinished inventory” risk given the sheer amount of oil that runs through their system in a single day. A refiner may also change the mix of products they make to focus on those with better margins, which in turn reduces the supply of the products with softening demand, helping create an equilibrium. On the other hand, if prices of crude oil drop there will be a lag for it to impact the prices of finished products as their cost of goods is still at the old, higher price.

There is a second feedback loop to finished product prices, which is the energy prices themselves. Refiners require energy just like any other industrial producer and the cost of energy will raise their cost of production and impact the ultimate price of the finished product. The energy the refiner uses is simply called refinery fuel and often is natural gas, but it can vary. Marathon Petroleum Corp noted in 1Q22 that their refinery operating costs are historically ~15% natural gas. However, when energy prices rise, or there is an anomalous price differential like we see in European natural gas versus US natural gas today, that factor can be much larger. This dynamic was expounded on by Valero Energy, who has most of their refining footprint in the US, but a single plant in the UK. They noted in 1Q22 that the price of natural gas in the UK was running around $30 per million BTU (British thermal units) versus $5-7 in the US. Putting these two figures together means that a cost that typically runs 15% of their opex can approach >40% (Assume $4 cash opex per barrel and thus 60 cents of that is natural gas which rises to ~$3 in the UK). This higher energy cost bleeds into the finished refined product cost, which drives energy prices higher. In this case it also means that a refiner who has access to cheaper US (or Chinese) natural gas as refinery fuel has a cost advantage to a European one and thus could reap higher margins.

Now PetroChina’s refining operation has several other considerations: 1) finished products prices are regulated, 2) they are limited in their ability to export oil, leaving them more susceptible to the domestic market, 3) they use a mix of imported and internally extracted oil which has opaque transfer pricing, 4) they are required to import natural gas to cover domestic needs even if uneconomical, which implies a direct cost of using natural gas as a refinery fuel (even if they extracted it a very low cost). In specific regards to regulation, their refining margin starts to phase out when the crude oil price reaches in excess of $80 and is eliminated a price per barrel of $130. At a price below $40 a barrel though, they will continue to calculate a margin as if it was $40 a barrel, effectively setting a floor. Refiners usually have an average gross profit per barrel that vary around $10, but Petro has historically been about half of that.

PetroChina refinery, as shown in their annual report.

Their level of disclosure does not allow us to do a granular analysis the refining operation, but they do disclose the cash refining costs per ton runs around ~160 Yuan or around ~$3.25 per barrel. The cash refining costs tends to capture all expenses with the exception of deprecation, which can be significant. This is in the same neighborhood as other refiners (slightly on the cheaper side) and suggestive of a generally efficient operation. Given the cash opex is similar to other peers, it seems most likely it is the end product price regulations (with potential discounts given to certain important industries) that limit their refinery gross margins.

Petrochina does break out the revenues and segment profits from their refining and chemical operations separately, however the economics are similar (at least in theory). For 2021, their refinery generated revenue of RMB 736bn (~$113bn) and segment profit of RMB 38bn (~$6bn) for a 5% margin. Similarly, the chemical business also earned a 5% margin with RMB 239bn in revenues (25% of total segment revenue) and RMB 12bn of profits. However, in prior years the operations have diverged significantly, with pricing of different refinery and chemical products fluctuating. We generally prefer to think of these businesses together given the common feedstock and largely overlapping PPE.

The net of all of this is shown below: an average operating margin of 4% since 2015 with refinery profits of ~$8bn last year and $7bn pre-pandemic. Given their throughput of 3.35mn barrels a day, this equates to a refinery margin of ~$6.25 per barrel.

In our build we will pick back up on the refining section and how to think about earnings power and long-term costs. Now we will move to the other downstream operation, marketing.


Marketing operations include their wholesale and retail channels, as well as some transportation and storage of finished products. In their wholesale marketing channel, they sell directly and through independent distributors to various companies including utilities, airlines, farms, commercial petrochemical businesses and transportation companies. Their retail channel includes 22,700 service stations under the “uSmile” brand, ~90% of which they own directly and also have a ~convenience store attached.

Looking at revenues before intersegment eliminations, marketing represents 50% of revenues, which makes sense if you think about how the revenues collected here would represent a slight mark-up to other segments and also includes petroleum products they purchase and resale.   

One of their many Gas stations with a “uSmile” convenience store.

The marketing segment of any integrated oil company (IOC) was historically critical to ensure they could place their enormous volume of products somewhere at a fair price and not have to worry about supply gluts backing up their production line. It was their development of a spot market with large volume that obviated the need to fully own distribution in order to fairly monetize. Prior to the “liberation” of oil prices, large oil companies could name a price (called posted prices) and producers were largely stuck selling at it (also because the supply of oil exceeded demand, limiting bargaining power, until around the 70s). In order to avoid being taken advantage of by the large IOCs’ low-ball offers, and capture more economics for themselves, early oil producers would build out or merge with others who had their own refineries and marketing operations. However, with a liquid and large crude oil and finished products spot market, the rationale for full integration has degraded. Nevertheless, many IOCs still have some marketing footprint.

The marketing business of petroleum products is fairly straight forward: they slightly market-up products for a typical 5-10% gross margin, which yields 1-2% net margins after operating costs. Station density is important to split distribution costs across and keep costs competitive. In other words, since it is more expensive to transport gasoline to a single distant gas station then a chain of nearby ones, they will have to charge more at that remote one than one in the middle of a city. The sale of lubricants and other specialized petroleum products is higher margin– and in some cases the oil company will have their own brands that help support further price increases—but is much lower volume (estimated around ~1% of total product sales) than their other products. ~20,100 of their ~22,700 service stations have convenience stores attached which sell small food and beverage items, which are moderately higher margin than fuel sales.

A PetroChina uSmile convenience store.

As shown below, this segment teeters between a small 1% profit and a loss over the past 7 years. For “special customers” (in the whole sale channel) the PRC will dictate the prices that PetroChina sells to them and we believe this a factor in their lack of profitability. As we mentioned, in their retail channel as well they have limited ability to pass off higher oil costs to their customers. Hypothetically, so long as the oil originates from their owned low-cost oil fields then this would somewhat ensure their margin somewhere in the value chain. However, as we mentioned they still import ~45% of their oil they refine, so being forced to sell that at a regulated price would be loss making.

However, PetroChina does mention improving marketing profitability through reorganizing their sales force, improving operation integrations, and renovating more gas stations. While it is not entirely clear how this will lead to improved economics in light on many product prices being regulated, but perhaps there is more granularity in their product slate than we can ascertain from their disclosures where a sales force could improve outcomes (it still seems a bit odd to us though). Renovating gas stations also has a dubious ROI as convenience (a location close by) is the overwhelming first order desire in a Consumer’s Hierarchy of Preferences. If this segment were to continue to make a ~1% profit margin, which is still ~$2bn in annual profits, we would consider that at the upper end of our expectations given the regulatory circumstance. Upside could come from them franchising more of their operations or loosening price regulations.

We will now move to our builds for each segment, with a particular focus on the E&P and refining segments right after saying a few words on the oil business.

Oil Business.

We wanted to say a bit on the oil business thinking through first principles. In any business you can either work to 1) sell more, 2) work to increase the price, or 3) work to decrease the costs. These three simple factors are what virtually all business activities are aimed at achieving. As a commodity producer though you cannot do anything to influence the first two factors (demand or price), which leaves you with attempting to improve your cost. We can think of two costs here: the operating costs or lifting costs and the exploration and development costs. The lifting cost a company can improve to a degree, but you will not be able to run such an efficient operation that you gain a meaningful advantage here—and it will largely be dictated by the oil field characteristics anyway. Furthermore, there are many oil service companies that a field owner could always enlist which would put even smaller oil companies in the same operating cost sphere as those large IOCs that benefit from scale. So, all that leaves to improve on is the exploration and development costs.

If we think about what determines the exploration and development costs, the two critical factors are entirely out of the companies’ hands: 1) how easy can they find the oil and 2) how easy the oil can be extracted. On the first factor, an oil company can certainly be uninformed or foolish in how they go about exploring for new oil, but even the most competent explorers for oil have a large band of potential outcomes. While it is true that technological and geological understandings are increasing the ability to detect oil, it is also true that the easiest oil to find has already been found. The net of this is that exploration is inherently speculative with an uncertain cost and uncertain outcome. If you don’t know how much it will cost to find oil beforehand, then you cannot know how many barrels of oil you are amortizing the cost of exploration over and thus you essentially cannot control this aspect of your cost structure either. No doubt it can be much better than expected, but the point is that the business will not be in control of the outcome.

Similarly, the oil company has limited control over the second factor, how easily the oil can be extracted. They can undoubtedly be wasteful or inefficient about how they extract the oil they find, but whether the natural pressures are sufficient for years to bring the oil to surface with limited intervention or if they quickly have to move to costly secondary and enhanced recovery methods is not their decision.

Lastly, it is important to remember that while the output is a commoditized product, the input is not homogenous—that is crude oil varies a lot in hydrocarbon composition, undesired elements like sulfur, and of course location all of which can increase the cost of the end product. As a price taker, the market doesn’t care how much processing or transportation your crude oil underwent versus a local and more easily refined barrel, you’ll be paid the same. So, after all of the trouble of finding oil, the oil you find may be at a structural cost disadvantage. The result of all of this means that at best you have a great asset, but not a great company since almost definitionally a great company would need to be able to sustain their ROIC—something you cannot do when your asset is self-depleting and reinvestment yields widely variable returns (we are talking about over the long term and acknowledge something like an existing field extension can have a more reliable return). Ironically, reinvestment might actually make a good oil company a worse one as new investment is plowed into assets that have worse economics than their existing base. And this ambiguity of ROI is before bringing price into the equation, which amplifies the band of returns many fold.

This is why oil companies work to keep their cost of production as low as possible and will tend to shelf any oil production that would take a long time to develop with high per barrel break even, as even if it is economical today that could change in the future. We see $30-50 breakeven price as a common range of oil prices that a company will be comfortable underwriting investments at. However, as we have seen in April 2020 (when oil prices went negative), that isn’t always adequately conservative.

To get a sense of oil prices and how supported they are, analysts will look at global demand estimates and current supply, as well as excess capacity. However, the problem lies not with what happens most of the time, but rather the extraneous “unpredictable” shocks to demand or supply that create “unforeseen” volatility. (We inserted quotes because we tend to be rather cynical about the utility of attempting to predict something that the predicter gets wrong the only time it matters). On the demand side, a weak economy, technology improving efficiency, and environmental concerns are all common factors that cause demand to soften. It’s true though that aside from the recent pandemic and a period in the 1970s-80s when fuel economy increased materially aside, demand for oil tends to be relatively steady. However, oil supply can fluctuate significantly too. There are many reasons such as new technology making previously unrecoverable oil economically feasible, as recently happened with the Shale boom in the US or wars, sanctions, embargos decreasing the availability of supply, as we are today living through with the Russia Ukraine war (but also with Iranian and Venezuelan sanctions). When the supply curve gets shifted out with more production, there can be an oil glut leading to prices plummeting and high-cost providers being forced out of the market (or business altogether if they have high loads of debt). Whereas adverse supply shocks can drive the price of oil higher in the short-term, and also sow the seeds for a period of oversupply as oil companies build out production assuming recently elevated oil prices are the “new normal” and governments encourage further production to alleviate domestic issues (The US’s Inflation Reduction Act will auction off millions of acres of federal land for drilling for instance). Without getting into the argument of whether this time is different as we have seen claims that oil companies are being more cautious to increase capex this time around, we will simply say we have no idea where oil prices will go and the higher the oil price a company must assume to make an adequate return the riskier it is. When prices are high the amount of operating leverage in an oil company can be incredible: Occidental Petroleum reported 2Q22 oil & gas revenues of $7.7bn with $3bn of segment earnings up from $4.5bn in revenues last year and $0.4bn in segment earnings, an incremental margin of >80%. While in this context it can be seen as a positive thing for the company, all the same a company’s earnings will be disproportionately impacted by a fall in oil prices.

In this regard though, PetroChina is slightly different. Owing to state regulations around pricing, they have some insulation against the troughs and peaks of oil price, with an effective price floor set at $40 to base retailing prices off of should prices fall below that. This downside protection is more than offset by their cap on profits when oil prices are higher.

If you think of where the best returns are in the value chain of petroleum production, there is only one area that really has built tremendous wealth overtime. Pipelines are a pretty good business, but oil being a global market with alterative transit options keeps returns from becoming exceptional (furthermore, the huge capex involved in making a pipeline means you will already have to have a lot of capital prior). Marketing has just about zero competitive moat and very standardized returns, although they do tend to at least have steady profit margins. Refining is a bit better, especially now that no one seems to be willing to invest in new refining capacity, but still the best refiner and an average refiner will generate close to the same return. It is only in successfully finding oil that a disproportionate amount of the value is accrued. As far as only wanted to invest in companies with superior and reliable returns goes though, this is a problem as a company has little control over whether they drill a dry hole or hit an elephant field. Thus, the most value-additive node in the value chain is essentially as sure as a venture capital bet. We say this all to make the point that the issue most investors have is confusing finding a great asset for having a great business. PetroChina clearly had a great asset in the Daqing oil field, but we are seeing how hard it is to replicate anything similarly as valuable as that.


When thinking of an oil company’s earnings it doesn’t make sense to focus on a single year and capitalize it due to the depleting nature of the asset. Whereas with many other companies’ higher revenues denotes a better probability of higher future revenues, the opposite is true for oil companies whose revenues come at the cost of their ability to sustain that level of revenue. Every barrel of oil they extract and sell in one period is a barrel they cannot sell in the next. Given the nature of an oil company’s assets being inherently non-renewable, we thought it made sense to do a “burn down analysis” on their E&P segment which estimates the lifetime cash flows that we can expect from PetroChina’s current asset base. We sensitized the burndown analysis, varying it with price and replenish rate, assuming a relatively steady cost and production rate. (Of course, these also are assumptions, and you may adjust the excel worksheet as you see fit). We decided to do it this way since comparatively price and replenish rate seemed more variable than their cost structure and production rate, but certainly these factors are all linked and can vary well.

It’s worth talking through how all of these variables are related. A higher price will incentivize more exploration and make economic extraction of higher cost oil which will increase the production rate and potentially the replenish rate as well, but with higher unit cost. Higher unit costs though, puts Petro in a more precarious position by making their economics dependent on high oil prices. If oil prices should fall, then their latest operations could be loss making and impaired. Under falling oil prices exploration is curtailed and only the lowest cost oil is produced. Petro’s variable costs–by only producing the lowest cost oil–drop, but since their fixed costs are the same despite a lower production level they experience negative operating leverage, which further incentives curtailing exploration and field development. Now a risk that we will detail more later is that since PetroChina has an SOE majority shareholder, they may push for further exploration, development, and production when it doesn’t make economic sense to do so. We haven’t seen this historically, but the situation could be different as their fields dry up and the lowest cost oil disappears (meaning the needed price to produce oil profitably increases).

Below is the output of our DCF for various scenarios. The methodology was to take their crude oil and natural gas reserves and assume similar production and replenishment rates as we’ve observed in recent years. While we explicitly note the price and replenish rates, other items were also adjusted to make it consistent (i.e. if we said that the replenish rate would drop than we assumed annual production would slow). There is nothing very scientific about the assumptions we used, but rather the point is to just get some sense of how much the valuation can vary with price and lifetime of the reserves. Our model also showed that with prices dropping towards $50 a barrel and $4.00 for natural gas, without drastic cost cutting measures, they will likely be loss making. To repeat ourselves, in reality, if prices do reach that level, they will take offline their more expensive wells and only produce from the lowest costs one (which is not modeled below). We had to back into what the itemized E&P segment P&L looks like because they do not give that level of granularity for “the company” (noted in the E&P section), so that is also worth remembering when thinking about the veracity of these outputs.

It is tempting to think of the valuation of any company on a single set of assumptions, but Petro is likely to experience all of these scenarios (and then some) over the course of its business life. Usually an investor will focus on “normalized” or “midcycle” earnings to ascertain a fair valuation over the life of the business. The issue with that however is that there is no way you can confidently predict energy prices over a multi-decade period and given the feedback in the model, your price assumption will have a multifactorial impact on the output. (Prices dictate production rate and timing, exploratory expense, development outlays, willingness to go up the oil cost curve, etc.). The most straightforward methodology is to just see how low prices can go which allows Petro to still make a profit and whether you are comfortable with that assumption, with an understanding that if prices are higher things can be much, much better. As mentioned, we model their profit disappearing around $50 crude oil and $4 natural gas (under the current cost structure). 

We will mention another way to think about the valuation towards the end of this section. Next, we will value the refining segment.

Refining is a more stable business relative to E&P, but it also has very high capex and is tooled for specific oil from a region. If the supply of crude oil in a region runs out, they will likely have to undergo further expenditures to retool and optimize the refinery for the new source of oil. We don’t have segment info to look at ROIC, but their ROA has averaged 10% since 2015 (excluding pandemic years) which isn’t bad nor phenomenal. However, with the exception of capacity utilization which can pick up moderately from the current low 80s level, any growth requires huge capital outlays. We are currently seeing this with their Guangdong Petrochemical project, which has increased capex by ~$5bn in 2021 compared to recent years with at least another ~$3.5bn planned. The biggest issue though is clearly regulation: above an $80 oil price they start reducing the profit margin on refined oil products until it reaches zero. Above $130 the profit margin will not only be eliminated, but it sounds like the producer will have to bear the costs as the end product price is regulated. Simultaneously though, PetroChina could be compelled to continue production despite the losses. This is a critical risk, among a few others we will mention in the risk section. We sensitized earnings around different refinery margins and utilization figures, capitalized at a 10x multiple. We just figured we’d want at least a 10% earnings yield for a low growth, capex-intensive, regulated industry, but investors can adjust accordingly.

The next segment, Marketing, is hard to value since they combine wholesale and retail channels and do not break out their convenience stores. The regulations, special contracts and intra-company transactions further convolute it. High level, we do know in 2021 they generated about $2bn in segment earnings and thus far in 1Q22 they are run-rating an annualized ~$2.8bn. As a reminder, since 2015 they have lost money in 4 out of the 7 years. If we value this operation at 4x, given average returns, no competitive insulation, and volatile earnings we would get a $8-10bn valuation. If we average the past 7 years of earnings (including losses) we get just ~$400mn, which implies a valuation of 20-25x, a rather high multiple for such an indefensible business. There are a lot of factors dictating whether they will consistently stay above their current earnings rate of >$2bn or fall prey to their historical cyclicality. As mentioned, there is more of a focus recently to keep this segment profitable, but regulation and potential loss-making long-term contracts in the wholesale business might mean this is out of their control. We do not have a strong opinion either way.

 Lastly, we get to the pipeline and natural gas segment. This is also hard to value given they recently sold a lot of assets to PipeChina and they continue to import natural gas at a loss by state mandate. It’s true there has been movement on natural gas price deregulation and it is possible that these losses go away soon. They generated ~$4.3bn in profits in 2021 (ex-gains) and are run-rating at ~$5.5bn for this year so far. But several pipeline deals, the last of which closed at the end of March 31st, 2022 (sold a 60% interest in Beijing pipeline and a 75% interest in Dalian LNG for ~$6bn to PipeChina from the Kunlun Energy subsidiary—this is a separate from their other larger PipeChina deal) makes it hard to figure out what earnings will be after all of these transactions. Furthermore, with high natural gas prices it is likely their import gas loss increases for an undetermined amount of time (but in 1Q this was effectively offset by a tax refund).

A pipeline in theory is a great business owing to the minimal upkeep capex, inherent cost advantage versus other transit methods, and limited customer alternatives. However, the leverage that a pipeline business has is offset by the Chinese regulatory environment, which can always step in if they feel profits are excessive. Given the moving pieces mentioned above we do not have enough confidence in normalized earnings to attach a multiple to. Instead, we look to their midstream sale to PipeChina where they recorded a ~$6.5bn gain on a sale worth ~$38bn. This implies a value premium of ~20% versus the book value of assets. At the end of 2021 they reported segment assets of ~$25bn in the Natural Gas and Pipeline segment, which with a similar premium would be worth $30bn. We acknowledge this is a very rough and imprecise methodology and we would have no problem if an investor instead zeroed out this value for conservatism (we would be inclined to do that ourselves).

Before getting to the SOTP table, we want to explore how each segment profits varies with one another. Below you can see a consolidated segment financial table, that informed the subsequent heat map below.  

It’s important to note that many of the segments are at or near all-time highs of profitability. However, when not looking at the extremes of profits, there is more diversification between each segment then you may of thought. Below we rank the profits of each segment from 2015 – 2021 to show how often their most profitable years group by segment.

Here we see that two of the four segments (refining and marketing) are at all time profitability highs with the other two segments still generating above average profits. The SOTP analysis we show below assumes operating performance that is generally in line with today, so this heat map above helps show how today’s profits are high versus history.

Rolling this all up together you get the output below, which shows a valuation range of $117-177bn. We are only using a selected band of outcomes based off of today’s operating metrics to inform the below table, so be conscious that the potential distribution of outcomes is much larger.

At a market cap of ~$82bn today, they trade at ~6x 2021 earnings with a 7.5% dividend yield. If the current macro environment holds, they could be generating as much as $24bn next year (made ~$6bn in 1Q22) which implies an even lower ~4x earnings multiple. Such a valuation strongly suggest that the market doesn’t believe these high oil and gas prices have long-term sticking power or the perceived risks (listed in the next section) are just too significant. Another way to look at it is to assume the market value and see what the implied valuation on the E&P segment is. If we take today’s market cap and assume the midpoint of each segment’s valuation, then the implied value attributed to the E&P segment is ~$32bn. If you look back at our E&P output table, that likely means the market is assuming a long-term oil price closer to $60 then where it is today—it’s an oil investors prerogative to judge what price they are comfortable underwriting long term.

One of the strongest cases for owning PetroChina in the past has been that they payout a large portion of their earnings regularly to shareholders. This can be especially important for oil investors who want to know that they are getting at least some immediate, “guaranteed” return, given incremental investment ROIs are so uncertain. Their policy stipulate dividends will be at least 30% of profits provided operating cash flows can support their needs, but it usually has been ~45% of net profits. Against our full year 2022 estimates of $24bn in profits (similar to 1Q22 annualized) that would be at least a ~9% dividend yield (30% payout) and up to ~13% at last year’s payout ratio of 45%. If current prices held, then PetroChina could theoretically pay back shareholders their entire investment in ~10 years while continuing to invest in the business.

While a 7.5% dividend yield with the prospect for it to increase much more is attractive for many investors, the risks to PetroChina are significant as well. Aside from the operating assumptions (namely high oil and gas prices), there is considerable risk owing to their state relationship and recent geopolitical events. 


    1. Regulation. We have already mentioned various pricing related risks, specifically the elimination of margins in the refinery segment when oil prices exceed $80, the petroleum end product pricing regulation, and long-term contracts to provide products at a loss. These all either reduce the profitability of PetroChina today or in the future. However, there is always the risk that regulation becomes more onerous and increases losses for PetroChina in order to subsidize the CCP’s other aims.
    2. Sanctions. PetroChina has certain business operations that have direct or indirect ties to US and EU sanctioned entities in Russia, Venezuela and potentially Iran. We understand this to technically mean certain investors (including US and EU) are prohibited from owning them, but in practice how this works we are unclear. This probably will be an untenable risk for many investors depending on where they are domiciled.
    3. State-Interest Supersede Investors. As their majority owner is a state-owned enterprise (and generally since companies are compelled to follow the CCP’s dictate), there is the risk that the government wants to implement policies that could adversely impact the minority shareholders, such as importing products at a loss, selling products at a loss, or exploring and producing oil & gas without a consideration for returns to boost domestic production. There also is the possibility that there are asset swaps or sales without fair compensation.
    4. Prices. Prices falling for a plethora of reasons is an obvious risk for any E&P company whereby if they become cheap enough then they will be loss making. However, even though prices are low they may not be allowed to reduce production.
    5. Reserves. Their reserve estimates can prove to be overly optimistic and have to be marked down. Additionally future efforts to find new reserves can fail. As a national oil company they may double down on efforts to find more domestic sources of oil for security reasons rather than be complacent running their depleting reserves profitability.
    6. Capital Allocation. Their general dividend policy could be revoked and instead earnings could be plowed back into projects with dubious economic utility.
    7. Geopolitical Tensions Impact International Operations. Their international operations are a relatively small portion of their business, but is growing. Most of these are joint ventures or other arrangements to work with local companies and could potentially be at risk. Their international operations span the Middle East, Central Asia, Pacific Asia, and South America.
    8. Reporting Complexity Can Hide Misrepresentations. Their financial statements are very complex with inter-company transactions, many affiliates, and subsidiaries, as well as unclear “group” vs “company” distinctions. There were several calculations (like simply multiplying crude oil and gas production x realized price to get E&P revenues) that did not seem to add up (we checked that others had similar issues to us). In addition to these inconsistencies, there was not adequate disclosure around certain segments and cost items (for instance it is unclear the cost structure of the refining segment that implies a steady cost per barrel in excess of $100 for the past several years). This coupled with the lack of a PCAOB inspection and recent pending ADS delisting is not entirely comforting. However, we know these issues are related to more general geopolitical tensions, rather than specific accounting shortcomings with Petro. While we can say that the lack of clarity and disclosure on many items makes it hard to invest in them, the truth is as a minority shareholder, next to the Chinese government in a company that is critical to domestic policy, the shareholders were always just along for the ride.

An investor is of course more than welcome to disagree with our assessment and their particular situation may different as well that better suits them to make such an investment.

Summary Model.

Below is our summary model that we tried to model assuming price levels stayed within the same vicinity. We converted all USD EPS figures at a RMB 6.7 to 1 USD ratio, so an investor can get a better sense of earnings power in US dollars (and not to capture forex translations differences overtime).


Thank you all for reading this months deep-dive! We hope you learned about the Oil Industry even if this particular investment isn’t for you. Please send us any comments or questions you have, especially if you disagree or if you think there is a mistake! We greatly appreciate all of your support.

After getting a lot of subscriber feedback and recent changes in our audience’s interest in a Chinese-centric coverage, we will be opening up our coverage universe to be global. This will allow us from here on out to only write about great companies that will have the most interest to our audience and investor base. Stay tuned, more to come! Please feel free to reach out if you have any questions or concerns.

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