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Methanex Corporation

1800 - 200 Burrard St.

Vancouver, BC Canada V6C 3M1

Investor Relations: 604-661-2600

Toll-Free: 1-800-661-8851

http://www.methanex.com

March 13, 2020

United States Securities and Exchange Commission

100 F Street N.E.

Washington, D.C. 20549

Attention: Terence O’Brien, Accounting Branch Chief

RE: Methanex Corporation

Form 40-F for the Year Ended December 31, 2018

Filed March 12, 2019

File No. 000-20115

Response Dated February 21, 2020

Dear Ms. Howser and Mr. O’Brien:

We have reviewed your comments outlined in your letter of February 21, 2020 relating to the captioned items and offer the following responses.

Form 40-F for the Year Ended December 31, 2018

o) Financial instruments, page 56

SEC Comments:

2. We note your response to comment 3 in our letter dated December 12, 2019. For each jurisdiction where your natural gas supply contracts include a revenue sharing mechanism (i.e., Trinidad, New Zealand, Chile, Egypt), please provide a detailed description of the following:

i.)

A breakdown of the consumers for natural gas and the approximate percentage of natural gas used by each. For example, you indicated that in Southern Chile approximately 50% of the natural gas supply is used for domestic residential and commercial/industrial electricity needs and you use the remaining 50% of the natural gas supply. Please help us understand the types of gas consumers and their proportionate consumption in the other regions.


ii.)	The pricing structure of gas supply contracts with gas consumers other than you in each of these regions to the extent you are aware. Please tell us the cost drivers of natural gas in

these regions and how this compares to the portion of the natural gas market that you occupy.


iii.)	The number and type of natural gas suppliers from whom you purchase natural gas. Please describe any differences in how you negotiate with the different types of suppliers (government owned versus private owners) and tell us whether there are any material differences in key contract terms between the types of suppliers.

3. For regions in which there are other methanol producers (e.g., Trinidad), please tell us if those entities’ gas supply contracts are also linked to the price of methanol. If not, please provide information on how those natural gas supply contracts are priced.

4. Please describe how you evaluated whether the economic characteristics and risks of the variable price component are closely related to the economic characteristics and risks of the natural gas supply contract. Please refer to IFRS 9 4.3.3(a) for guidance. To the extent the economics and risks are different among the jurisdictions in which you operate, please provide this analysis for each location.

Our Response:

Background

As noted in previous responses, our primary view is that the natural gas supply contracts held in Trinidad, New Zealand, Chile and Egypt are in effect, royalty arrangements, where the contract formula dictates the natural gas price based on a sharing of our revenue. The contract formulas reflect the anticipated gas conversion ratio specific to the plant or plants supplied and the destination market for the methanol sold.

Additionally, the natural gas in these locations is either government controlled or characterized by natural gas reserves that would not otherwise be consumed. In this sense, the price of natural gas is not determined by an active market. In many instances, pricing for natural gas in these locations is determined by the end use, with government often involved in the initial resource development for economic growth and/or to provide subsidized pricing of the natural gas to local users. The result is an economic relationship between the methanol we produce and the price of natural gas.

Under IFRS 9, there is no explicit test to determine whether the economic characteristics and risks of a variable price component are closely related to the economic characteristics and risks of a host contract. IFRS 9 B4.3.5 provides examples of embedded derivatives that are not closely related to the host contract and IFRS 9 B4.3.8 provides examples of potential embedded derivatives that are closely related to the host contract, none of which are analogous to our contracts.

In the absence of an explicit test, or analogous examples provided by IFRS 9, we have looked to published guidance on the topic. PwC’s Manual of accounting, IFRS 2019, outlines an approach for analyzing whether a pricing mechanism in a commodity contract is closely related to its host in situations where there is not an active market in the following:

“If an active market does not exist for a particular commodity in a similar location to the one specified in the contract, management should consider how other contracts for that particular commodity are normally priced, in the absence of a readily available market price. That pricing mechanism would not be considered an embedded derivative if it can be demonstrated that it is an identifiable industry ‘norm’ and that contracts are regularly

priced according to that norm. This is because such a pricing mechanism does not modify the cash flows under the contract (IFRS 9 4.3.1).” ¹

EY, International GAAP 2019, has similar guidance noting that “…other proxy pricing mechanisms may arise in long-term supply agreements for commodities where there is no active market in the commodity.” ² EY cites natural gas contracts that were indexed to other commodities such as crude oil before an active market developed that were considered closely related to the host contract because similar pricing mechanisms were commonly used by other participants in the market.

There is very limited guidance under IFRS to determine what constitutes an active market. IFRS 13-Appendix A, defines an active market as one in “…which transactions for the asset or liability take place with sufficient frequency and volume to provide pricing information on an ongoing basis.”

It is still generally recognized that a global natural gas market does not exist³. Unlike oil (which is widely considered a global commodity), natural gas markets exist at a regional or in some cases, at a sub-regional level, therefore our analysis considers natural gas regionally rather than globally.

Our methanol production facilities outside North America are in government controlled, developing or isolated natural gas markets where there are not sufficient transactions and market players to provide transparent pricing information on an ongoing basis to constitute an active market. One characteristic of each of these regions is that there is no market to purchase a stand-alone financial derivative in which one could hedge the price of natural gas. In addition, gas extraction in each region is heavily regulated and/or controlled by government.

In the absence of an active market, we consider the pricing within the market that the company transacts. IFRS 13 suggests that for purposes of measuring fair value, a company would look to the market to which they have access, acknowledging that different companies may have access to different markets (for example, dealer, retail, wholesale markets) (IFRS 13.19, IE24-26).

Where gas is government controlled, our contractual supply of natural gas cannot be monetized other than in our production and sale of methanol. For other locations, lack of transportation infrastructure and lack of alternative demand isolate these natural gas markets such that Methanex has been a market maker for the price of natural gas. In identifying the market for these regions we often only have access to natural gas that would not otherwise be used for domestic electricity production or consumption. This is either because the location of our plant is isolated; the natural gas supply we use is incremental to domestic needs; or the government restricts access to the market. As such, the market we transact in is best described as the wholesale gas market excluding domestic consumption (e.g. heating/cooking consumption and electricity production) in the regions in which our plants are located.

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¹ Manual of accounting, IFRS 2019, PwC. FAQ 41.62.4

² International GAAP 2019, EY, Chapter 5.2.2

³ "Is Gas Global” publication dated March 23, 2018 by Center for Strategic and International Studies. https://www.csis.org/analysis/gas-global-yet

Consideration also needs to be given to whether there is an industry norm or proxy pricing mechanism used to price natural gas is used in these identified markets.

Natural gas industry publications describe contract pricing linked to the output economics where the gas suppliers participate in the risks and rewards of the end use commodity, such as methanol, as netback pricing (or product indexed pricing). These industry publications describe netback pricing as one of the common pricing mechanisms in determining regional natural gas prices and describe it specifically as a pricing mechanism used when natural gas is used as a feedstock in the petrochemical industry. The International Gas Union, Wholesale Gas Price Survey 2019 Edition⁴ provides the following definition for Netback from final product pricing for natural gas:

With that background as context, we have responded to the comments posed on a region-by-region basis to address all comments within the context of the specific region.

Trinidad

i.)

A summarized breakdown of natural gas consumers by use for the 2019 year as published⁵ by the Ministry of Energy and Energy Industries of the Government of the Republic of Trinidad and Tobago:


•	Liquified Natural Gas (“LNG”) 57%


•	Ammonia 16%


•	Methanol 16%


•	Domestic power and industry 11%


ii.)	The pricing structure of gas supply contracts with gas consumers other than you in each of these regions to the extent you are aware. Please tell us the cost drivers of natural gas in these regions and how this compares to the portion of the natural gas market that you occupy.

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⁴ International Gas Union, Wholesale Gas Price Survey 2019 Edition - A global review of price formation mechanisms. 2019, Page 11

⁵ http://www.energy.gov.tt/meei-consolidated-monthly-bulletin-january-december-2019/

In Trinidad, the pricing for natural gas is determined by the end use⁶. Natural gas pricing for export petrochemical commodities (ammonia and methanol) and LNG reflect a netback on the produced output pricing for the Trinidad government to benefit from the upside movement in these output commodities. This is the case with our natural gas supply contracts in Trinidad which, as previously described, include a fixed base price and a variable sharing formula based on the price of methanol. The variable component has been a substantial portion of the historic cash flows on these supply contracts.

These export commodities are a substantial contributor to the Trinidad economy and represent approximately 90% of the total consumption of natural gas. The allocation of natural gas to these export industries is determined by the government in order to diversify the risks of the economy’s dependence on the gas sector. This netback pricing mechanism, where the natural gas supplier shares in the risks and benefits of the use, clearly links the economic returns on natural gas to the commodities produced including our production of methanol.

Domestic natural gas consumption is priced on a different paradigm to export commodities. Power for residential and commercial users is highly subsidized by the government, while local heavy and light industrial uses are priced on a cost-plus basis. As noted above, domestic use is approximately 10% of the total natural gas consumed in the country.

Methanol price is the primary cost driver for natural gas production into methanol in Trinidad.


iii.)	The number and type of natural gas suppliers from whom you purchase natural gas. Please describe any differences in how you negotiate with the different types of suppliers (government owned versus private owners) and tell us whether there are any material differences in key contract terms between the types of suppliers.

The Natural Gas Company of Trinidad & Tobago (“NGC”) is a State-Owned-Enterprise and the only supplier of natural gas in Trinidad. We have entered into long-term contracts with the NGC to underpin the initial investments in the two methanol plants in Trinidad. As described above, the use of netback (or product indexed) pricing is government policy in Trinidad & Tobago, so negotiations focus around the economic sharing.

For regions in which there are other methanol producers (e.g., Trinidad), please tell us if those entities’ gas supply contracts are also linked to the price of methanol. If not, please provide information on how those natural gas supply contracts are priced.

Trinidad is the only Methanex location outside North America, where there are methanol production facilities that compete for local natural gas.

Methanol Trinidad Holdings Limited (“MHTL”), is a subsidiary of Consolidated Energy which is held by two shareholders Proman AG (Swiss private company) and Helm AG (German private company). MHTL has five methanol plants in Trinidad with total production capacity of

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⁶ Trinidad & Tobago Gas Master Plan: Final Report. Prepared for: Ministry of Energy and Energy Affairs. September 2015. Section 1.9 Gas Pricing in T&T. Page 38.

approximately 4 million MT. There is another 1 million MT methanol plant currently under construction, Caribbean Gas Chemical Limited (“CGCL”), owned by a Mitsubishi consortium, NGC and local Trinidad conglomerate Massy Holdings Ltd.

The Trinidad & Tobago Gas Master Plan (“T&T Gas Plan”) outlines the Government of the Republic of Trinidad & Tobago’s (“GORTT”) use of netback pricing for LNG and product indexed pricing for natural gas supply contracts for use in the production of ammonia and methanol. The report does not provide definitions for each, but as described previously, netback pricing is characterized by a price for natural gas that fluctuates with the price of the product produced. The following excerpt from the T&T Gas Plan describes the pricing concepts in general and describes the pricing for LNG and petrochemicals (ammonia and methanol) as netback pricing in the paragraph below Table 1-9, indicating the terms can be used interchangeably.⁷

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⁷ Trinidad & Tobago Gas Master Plan, Prepared for: Ministry of Energy and Energy Affairs, September 2015, 1-38

Though we do not have visibility over the specific pricing terms between the NGC and other methanol producers, we note that the NGC’s annual report provides explanations relating to both methanol and ammonia prices in the analysis of financial results and risk management disclosures which explain higher earnings as being the result of higher methanol and ammonia pricing in the year ended 2018. The government intention and NGC’s financial results are indicative that the same methanol link is applicable for other methanol producers.

Please describe how you evaluated whether the economic characteristics and risks of the variable price component are closely related to the economic characteristics and risks of the natural gas supply contract. Please refer to IFRS 9 4.3.3(a) for guidance. To the extent the economics and risks are different among the jurisdictions in which you operate, please provide this analysis for each location.

As outlined above, our analysis focuses on two key determinants: one being whether the market for natural gas is active; and secondly, absent an active market, whether there is a predominant or proxy pricing convention used in the market:

Step 1 - Market evaluation


–	In Trinidad, the only supplier of natural gas to downstream consumers is the government through the NGC, and as such there is no active market to purchase natural gas.


–	The NGC acts as the sole wholesaler of gas, purchasing from suppliers and selling to the downstream export industries and local consumers.


–	There is no ability to transfer our rights to natural gas to other consumers.

Evaluation - No active market. Government is the only supplier and determines the allocation of gas.

Step 2 - Pricing evaluation


–	The government mandates netback pricing for all export consumers of natural gas including LNG, ammonia plants and methanol producers.


–	This policy attracts foreign investment and foreign consumers of natural gas to the country with a low-cost structure, with a policy of sharing in the benefits and risks from the ultimate sale of the products generated with the country’s natural resources. This model helps support a highly subsidized domestic electricity market.


–	All methanol competitors must purchase natural gas from the government under the same netback pricing mechanism

Evaluation - There is a close economic relationship for methanol prices and the price of natural gas consumed by the methanol industry in Trinidad because the price of natural gas is indexed to the price of the product for all natural gas purchased in the wholesale market. The T&T Gas Plan mandates this relationship for LNG and petrochemicals, whereby each demand segment has an independent relationship with its price of gas. As such, netback pricing is the proxy market pricing for the price of natural gas in this region, and the methanol price indexation is therefore considered closely related to the host natural gas purchase contract.

Egypt

i.)

The Egyptian Natural Gas Holding Company (“EGAS”) is a State-Owned-Enterprise and is the only supplier of natural gas in Egypt. Methanex entered into a supply agreement with EGAS to underpin the decision to invest in the construction of the methanol plant in Egypt. This investment was made as Egypt looked to develop new petrochemical industries to develop and increase its natural gas production and GDP from foreign investment in the petrochemicals industries. Following our investment, the revolution in Egypt in 2011 brought uncertainty which limited upstream investment for a period of time. During this time, Egypt did not have sufficient natural gas to continue with LNG exports or fulfill local demand. The government decided to import LNG, but were not able to meet all local demand with significant shortages experienced. More recently, Egypt’s natural gas production has increased to again enable natural gas exports.

A summarized breakdown of natural gas consumers by use for the 2018/19 year provided by EGAS in their annual report⁸ is as follows:


•	Electricity 62%


•	Industrial (fertilizer & steel) 23%


•	Petrochemical (including methanol) 10%


•	Residential/CNG 5%

For the 2018/19 year the above four uses make up approximately 93% of total gas consumption in Egypt. The remaining 7% consumed by LNG (net of LNG imports) and export via pipeline. LNG and pipeline exports have varied over the past number of years due to the reasons noted above.


ii.)	The pricing structure of gas supply contracts with gas consumers other than you in each of these regions to the extent you are aware. Please tell us the cost drivers of natural gas in these regions and how this compares to the portion of the natural gas market that you occupy.

There is limited visibility of gas pricing in Egypt. Unlike Trinidad, the petrochemical industry (including methanol) is characterized in EGAS’ annual report amongst domestic natural gas consumers along with electricity, industrial, and residential (compressed natural gas). However, this characterization as a domestic user does not indicate any specific pricing mechanism. Our

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⁸ Egyptian Natural Gas Holding Company. Annual Report 2018-19. Natural Gas Local Consumption. Page 33.

netback natural gas pricing in Egypt has been in place since the start-up in 2011. Netback pricing for natural gas is known to be used in Egypt in this industry, though we do not have significant visibility to determine its prevalence. An excerpt from the June 2018 report from the Oxford Institute for Energy Studies⁹, noted the following natural gas prices by end-user as dictated by ministerial decree, with the exception of fertilisers and petrochemicals (such as methanol) as:

Electricity is the most significant consumer of natural gas, representing greater than 60% of demand. Electricity from natural gas pricing is known to be heavily subsidized by government while industrial consumers pricing is also government regulated on a cost-plus basis¹⁰.

LNG and export volume via pipeline has been inconsistent over the last number of years following the Egypt revolution in 2011. Local gas production curtailed and was supplemented with import LNG to serve domestic demand as noted above. We have limited visibility into the current pricing for natural gas from EGAS for LNG export. However, when we signed our long-term gas supply agreement with EGAS, we understood at that time that the gas contracts for LNG export were also based on a netback arrangement.

Methanol price is the primary cost driver for natural gas production into methanol in Egypt, which is limited to the E-Methanex joint venture. We cannot comment with certainty, the specific cost drivers of natural gas for other consumers within the region, although the table above notes government set and agreed pricing formulas for fertilizers and petrochemicals.


iii.)	The number and type of natural gas suppliers from whom you purchase natural gas. Please describe any differences in how you negotiate with the different types of suppliers (government owned versus private owners) and tell us whether there are any material differences in key contract terms between the types of suppliers.

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⁹ The Oxford Institute for Energy Studies: Egypt - a return to a balanced gas market?, June 2018. Page 16.

¹⁰ International Gas Union Wholesale Gas Price Survey - 2019 Edition. A Global Review of Price formation mechanisms 2005 to 2018. Page 68.

As noted above, EGAS is a State-Owned-Enterprise and is the only supplier of natural gas in Egypt. We entered into a long-term (25 year) contract with EGAS to underpin the initial investment in the methanol plant in Egypt. This contract was tailored for the specific methanol plant applying a methanol price sharing mechanism specific to the revenue of E-Methanex. Natural gas supply from this contract commenced in 2011. EGAS is also an investor in the E-Methanex methanol facility. The gas supply agreement and investment in E-Methanex was intended to help to develop the petrochemical industry in Egypt, to monetize natural gas and develop and diversify the economy. We believe that similar arrangements were made with LNG exporters in the development of the LNG export industry in Egypt.

From our experience, we understand that the development of the petrochemicals industry was a key strategic initiative in Egypt’s planned development of its natural gas. Applying a netback pricing mechanism for methanol and ammonia/urea production from natural gas established a specific industry-based return, for the benefit of the government, similar in our view to Trinidad.

Not applicable.

As described previously, we have evaluated the relationship of the variable price component to the economic characteristics and risks of the natural gas supply contract as follows:

Step 1 - Market evaluation


–	In Egypt, the only supplier of natural gas to downstream consumers is the government, and as such there is no active market to purchase natural gas.


–	Gas supply was constrained following the 2011 revolution, resulting in government making allocation decisions to determine the demand segments serviced.


–	EGAS acts as the sole wholesaler of gas, purchasing from suppliers to market to the downstream export industries and local consumers.


–	The government has allocated natural gas for export (LNG) or have decided to import LNG over the last number of years in response to changes in natural gas reserves available.


–	There is no ability to transfer our rights to natural gas to other consumers.

Evaluation - No active market. Government is the only supplier and determines the allocation of gas.

Step 2 - Pricing evaluation


–	The pricing for the primary uses for natural gas in the region (electricity and industrial) are government subsidized and/or government mandated, and as such not comparable to the production of a commodity for export to other markets.


–	Netback pricing exists for other petrochemical applications (ammonia/urea), though prevalence of this pricing mechanism is unknown. We also believe that netback pricing is applied for LNG export.


–	E-Methanex has had a supply contract with netback pricing since inception which links the natural gas price to the ultimate sale price of the product produced.

Evaluation - There is a close economic relationship for methanol prices and the price of natural gas consumed for methanol production at the E-Methanex plant in Egypt. Netback pricing has also been applied for other petrochemical demand and LNG. Since E-Methanex commenced operations, Egypt’s natural gas market has been evolving through initial investment and development, turmoil through the revolution, followed by further investment and development.

New Zealand

i.)

New Zealand is an isolated natural gas market with no cross-border pipelines or LNG facilities. A summarized breakdown of natural gas consumers by use from the Ministry of Business, Innovation & Employment¹¹ of the New Zealand government is as follows:


•	Methanol ~45%


•	Electricity ~33%


•	Heating/Cooking (residential, commercial, industrial) ~12%


•	Dairy <5%


•	ammonia-urea/(fertilizer) <5%


ii.)	The pricing structure of gas supply contracts with gas consumers other than you in each of these regions to the extent you are aware. Please tell us the cost drivers of natural gas in these regions and how this compares to the portion of the natural gas market that you occupy.

Methanex is the single biggest consumer of natural gas in New Zealand and the only substantive use for export. Netback pricing is in place for all of our contracted supply. The methanol plants were first constructed in the 1980’s as a government initiative to develop local natural gas resources. There is no alternative use for the gas consumed by Methanex in New Zealand, and no other export alternatives, such as LNG, and as such Methanex is viewed as the incremental market for all natural gas in the region.

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¹¹ https://www.mbie.govt.nz/building-and-energy/energy-and-natural-resources/energy-statistics-and-modelling/energy-statistics/gas-statistics/

Domestic electricity is the other primary use for natural gas in New Zealand which competes with other electricity sources (primarily hydroelectricity and geothermal). Local dairy and ammonia-urea represent approximately 10% of natural gas consumption and we do not have direct visibility of pricing as contracts would be negotiated directly between supplier and consumer with the output from these plants used in the domestic New Zealand market.

Methanol price is the primary cost driver for natural gas production into methanol in New Zealand. Natural gas used for electricity must be competitive with other sources of electricity, and as such, the price of gas for this demand segment is unrelated to methanol. However, there is not enough capacity to consume all natural gas into electricity within the region and as such the demand for natural gas is capped in volume. We cannot comment with certainty, the specific cost drivers of natural gas for other consumers within the region.


iii.)	The number and type of natural gas suppliers from whom you purchase natural gas. Please describe any differences in how you negotiate with the different types of suppliers (government owned versus private owners) and tell us whether there are any material differences in key contract terms between the types of suppliers.

In New Zealand we have two primary suppliers OMV (an Austrian energy company) and Todd Energy (New Zealand energy company). OMV purchased Shell’s New Zealand assets in 2018 and the negotiation of our long-term supply agreement with OMV was a key determinant in OMV’s decision to invest in New Zealand.

The OMV and Todd contracts are both long-term contracts with netback pricing.

There are other suppliers, some of whom we have had contracts with on a short-term basis. These short-term contracts have also been based on netback pricing.

There are no government owned producers or gas suppliers in New Zealand, though government approval is required for transfers of interests in petroleum permits, as was required in the OMV purchase of Shell’s assets.

Not applicable.

As described previously, we have evaluated the relationship of the variable price component to the economic characteristics and risks of the natural gas supply contract as follows:

Step 1 - Market evaluation


–	New Zealand is an isolated natural gas market as there are no connecting pipelines or LNG import/export infrastructure to transport natural gas to or from the north island of New Zealand.


–	The New Zealand wholesale gas market is relatively small and concentrated as there are a limited number of suppliers from a limited number of natural gas fields (resources) and a limited number of consumers.


–	Methanex is the only producer of methanol in New Zealand and is the single highest consumer of gas in the country making up approximately the same demand as the domestic heating/electricity segment.

–

A natural gas trading platform (emsTradepoint) has been established in recent years in New Zealand to facilitate short-term balance within the gas market. The volume traded on this platform is inconsequential in the scope of both Methanex’s gas consumption in New Zealand and the gas market overall. We do not believe transactions on this platform take place with sufficient frequency and volume to provide pricing information on an ongoing basis to constitute an active market as defined in IFRS 13.


–	There are contractual constraints and as such, no substantive ability, to transfer our rights to natural gas to other consumers as there is insufficient capacity to consume our natural gas supply.

Evaluation - The natural gas market is relatively small, isolated and limited to a small number of players. A short-term trading market has emerged in recent years, but this market is small and does not have sufficient liquidity to absorb any substantial volume. We are the incremental demand in New Zealand and consume nearly half the natural gas produced and are the only export consumer of natural gas with the other uses competing based on local economics. As a result, we do not view this as an active market.

Step 2 - Pricing evaluation


–	Pricing for the primary domestic use (electricity) is determined by its competitiveness with other electricity sources (hydro-electric, geothermal, other).


–	There is limited visibility of other local industry natural gas pricing.


–	Netback pricing is the only pricing mechanism in place for natural gas used in the production of methanol and has been in place for a number of years.


–	Given that Methanex uses netback pricing and has 100% of the methanol market in New Zealand and represents >80% of the consumption of natural gas for wholesale in the country, netback pricing is the industry norm proxy price for the wholesale market.

Evaluation - Methanex has been the market-maker for pricing of natural gas for the wholesale market in New Zealand, given that it is the incremental user of natural gas in the region and the market is physically isolated from other markets. As a result, the methanol price indexation is therefore considered closely related to the host natural gas purchase contract.

Chile

i.)

Our production site in Chile is in the Magallanes region near the city of Punta Arenas at the Southern tip of South America. This site currently receives natural gas from suppliers in Argentina and Chile (collectively the Austral-Magallanes basin).

Our supply from Chile is restricted to gas produced in Southern Chile in the Magallanes region This region is the only gas producing region in the country and has no connecting natural gas infrastructure to the rest of Chile. The natural gas resources in Chile are increasingly unconventional in nature and higher cost than the resources nearby in Argentina.

We make up approximately half of the demand for natural gas produced in Southern Chile with the other half used by the local population for heating/cooking, electricity and transportation (LPG). The percentage of natural gas demand in this region for heating and electricity is highly seasonal with demand highest during the Southern-hemisphere Winter months. As we are the incremental consumer for local gas producers, we are impacted by this seasonal demand shift receiving less gas in the Winter months and more in the Summer.

There are one-way natural gas pipelines connecting the Magallanes region of Chile with Southern Argentina established to export natural gas from Argentina into Chile, however we did not receive natural gas from Argentina from 2007 to 2018 due to Argentina government restrictions on gas exports. This restriction severely impacted our production of methanol in Chile and during this time, we relocated two idled methanol plants from Chile to the US. Our remaining two methanol plants in Chile operated well below capacity, supplied by Chile produced gas.

Late in 2018, the Argentine government recommenced granting export permits for natural gas, including permits from our contracted Argentine suppliers to our production site in Chile.

The Southern Argentina Austral basin has significantly higher natural gas reserves than the neighboring Chilean Magallanes. There is natural gas pipeline infrastructure in Argentina connecting these natural gas resources to the Northern population bases, however the Austral basin is located the furthest South amongst the Argentine natural gas basins and as such is less competitive than geographically advantaged resources further North, closer to the population base of the country. In addition, the pipeline infrastructure from the Austral basin has limited capacity, restricting the volume that can be sent to the North. As a result, we view the Argentine Austral basin to be trapped to some degree for regional consumption which served as a rationale for our investment in the region.


ii.)	The pricing structure of gas supply contracts with gas consumers other than you in each of these regions to the extent you are aware. Please tell us the cost drivers of natural gas in these regions and how this compares to the portion of the natural gas market that you occupy.

As in New Zealand, Methanex is the only substantive consumer of natural gas for commodity export in Southern Chile. Historically all of our natural gas was priced on a netback basis and today substantially all of our natural gas for future years is priced on a netback basis.

In the coming years, we expect less than 10% of gas at a fixed price. This fixed price arrangement is specific to a defined reserve block (Dorado Riquelme) which is unconventional and higher cost, with a single government owned gas supplier (ENAP), where Methanex historically had invested in upstream development. The fixed price arrangement was entered into in consideration of our Chilean supplier requiring certainty in price for a period of time to justify capital investment to continue to supply natural gas from this block to Methanex. This

arrangement is unique to both the supplier and location and is not comparable to our arrangements with our other Chilean and Argentine suppliers as the cost structure for resource development for each reserve block in the region can vary significantly with more unconventional and higher cost resources primarily located in the Magallanes.

Gas pricing for local demand in Southern Chile is subsidized by the government with highly seasonal demand.

As noted above, supply from Argentina was restricted by the Argentina government from 2007-2018. All contracts from Argentine suppliers prior to government restriction in 2007 were on a netback pricing basis. All contracts with Argentine suppliers in force today are also on a netback pricing basis and require Argentina government issued export permits to deliver gas across the border through the one-way pipelines to Chile. There is no assurance that permits will be renewed for future years.

Methanol price is the primary cost driver for natural gas production into methanol in Chile. As noted above, we have a fixed price contract from a single supplier related to a reserve block where Methanex had historically invested in the development. The nature of this contract is unique in the region, with one government owned gas supplier, and is specifically to supply natural gas to Methanex from a certain unconventional reserve block. Pricing for local demand for natural gas is highly subsidized by the government, and as such, the fixed price contract has no specific impact on the price of gas for other users. The negotiation of the fixed price itself, was based on meeting our production cost targets, while still covering our supplier’s capital required to continue to deliver.


iii.)	The number and type of natural gas suppliers from whom you purchase natural gas. Please describe any differences in how you negotiate with the different types of suppliers (government owned versus private owners) and tell us whether there are any material differences in key contract terms between the types of suppliers.

There are two Chilean suppliers: Empresa Nacional del Petróleo (“ENAP”) (State-Owned-Enterprise) and GeoPark Fell SpA (“GeoPark”) (South American public company).

The majority of our contracts with ENAP have been based on netback pricing, with limited short-term contracts on a fixed price basis as described above. Following the restrictions on natural gas exports from Argentina, Methanex invested with ENAP to develop upstream natural gas resources in the region. We continue to have interest in one upstream natural gas block in Chile (Dorado Riquelme).

GeoPark became the first privately-owned oil and gas producer in Chile in 2006 and increased its investment in Southern Chile following the Argentina government restriction on Argentina’s natural gas exports from 2007. At this time, GeoPark and Methanex entered into a 10-year netback priced gas supply agreement to purchase all natural gas from the Fell block near the Chile/Argentina border. In 2017, Methanex and GeoPark renewed the agreement with a netback price for another 10 years.

We have contracts with Argentine suppliers, including YPF SA - (State-Owned-Enterprise) and four with international and South American energy companies. These four suppliers are Pan American Sur SA, Wintershall Energia SA, Total Austral SA, and Compania General de Combustibles (“CGC”) SA. We have been receiving natural gas from these Argentine suppliers since late 2018.

With the exception of short-term fixed price contracts with the State-Owned-Enterprise in Chile our gas contracts from all other suppliers in the both the Austral and Magallanes regions are netback priced.

The majority of our contracts in the region are interruptible, as they are either dependent on export permits from the Argentina government or dependent on us receiving natural gas from other suppliers to be able to run the plants on an economic basis. As a result, the notional volume received in Chile has a number of uncertainties.

There are no other methanol producers in Southern Chile or Southern Argentina.

As described above, we have noted the differences between our natural gas suppliers from Chile and Argentina and as such have evaluated the relationship of the variable price component to the economic characteristics and risks of the natural gas supply contracts separately, as follows:

Step 1 - Market evaluation (Chile - Magallanes)


–	Southern Chile is an isolated natural gas market with limited demand.


–	Natural gas does not flow from Chile to Argentina.


–	Supply is provided by a State-Owned-Enterprise which supplies the local demand and Methanex, and a non-governmental supplier (GeoPark) which sells virtually all natural gas it produces in Chile to Methanex.


–	Natural gas prices for local demand is highly subsidized by the government.


–	There is no legal or practical ability to transfer our rights to natural gas to other consumers as there is insufficient demand to consume our natural gas supply.

Evaluation - The natural gas market is relatively small, isolated and limited to two suppliers. There is no pricing information on an ongoing basis or other relevant consumers within the region. We are the only export consumer of natural gas with the other uses heavily subsidized by government, therefore represent the only incremental demand. The one commercial natural gas supplier has an exclusive arrangement for a specific reserve block with Methanex and entered Southern Chile based on the opportunity to sell gas to Methanex due to the Argentina government restriction on Argentina gas exports. As a result, we do not view this as an active market.

Step 2 - Pricing evaluation (Chile - Magallanes)


–	Pricing is dominated by netback pricing for methanol and government subsidized pricing for local consumption.


–	Fixed prices for natural gas into methanol have been short-term in nature, limited volume and in consideration of other factors specific to the contracting parties. Therefore, fixed prices do not represent a predominant pricing mechanism.

Evaluation - There is a close economic relationship for methanol prices and the price of natural gas consumed by methanol in Chile. Methanol production is the incremental user of natural gas and as such is a market maker for this demand segment. The pricing for other users are government subsidized and therefore not comparable to the gas consumed by the production of methanol. As a result, the methanol price indexation is therefore considered closely related to the host natural gas purchase contract.

Step 1 - Market evaluation (Argentina-Austral)


–	Government restrictions prevented the export of natural gas from Argentina to Chile from 2007-2018.


–	The government of Argentina continues to regulate the export of natural gas to Chile through the granting of export permits.


–	There is no export of natural gas from the Austral basin, except to Methanex.


–	Natural gas from the Austral basin transported to the North is limited by pipeline capacity and sold for Argentine domestic use which has a history of government involvement.


–	There is no current active market dictating the price for the sale of natural gas in Argentina as the natural gas market is heavily regulated and prices for electricity and heating are set by the Argentina government.

Evaluation - The Argentina natural gas market is substantial and mature, though subject to significant government regulation. The Austral basin, within Argentina, is isolated due to the more significant natural gas reserves geographically advantaged to supply the Northern population base and gas pipeline constraints. There is more gas available than domestic need, partially due to logistic constraints. When permitted for export by the Argentina government, natural gas flows from Argentina to Methanex’s Chile site, but does not compete with Chilean natural gas for local demand and does not get exported to other consumers. As a result of the Argentina government’s involvement in permitting exports of natural gas and no other consumers of Argentine gas in the region, we do not view this as an active market.

Step 2 - Pricing evaluation (Argentina-Austral)


–	All of our contracts with Argentine suppliers use netback pricing.


–	Demand for natural gas in Argentina is highly seasonal, as opposed to demand from Methanex which is stable throughout the year. As such, Methanex acts as a market maker, establishing the incremental price for export gas from the Austral basin.

–

Methanex prices its natural gas contracts in US dollars as opposed to local pricing which is in Argentine currency (Peso), which has been subject to severe inflation over time. The currency clearly segregates the pricing for natural gas between natural gas for export to Methanex and natural gas for domestic use. In addition, natural gas consumed locally for electricity and heating is subject to regulatory pricing as dictated by the Argentina government whereas export pricing is not regulated and based on negotiations between the supplier and customer, subject to obtaining export permits.

Evaluation - There is a close economic relationship for methanol prices and the price of natural gas exported from Southern Argentina and consumed by us as we are the only customer for this exported natural gas. Methanol production is the incremental user of natural gas and as such is

a market maker for this demand segment. As a result, the methanol price indexation is therefore considered closely related to the host natural gas purchase contract.

Conclusion

Based on our analysis above, we believe that there is substantial evidence that the economic characteristics and risks of methanol and natural gas are closely related in each of the markets analyzed. This assessment augments our previous position communicated relating to the non-financial nature of the pricing feature in our natural gas supply contracts.

Methanex Corporation (the Company) acknowledges that:


•	the Company is responsible for the adequacy and accuracy of the disclosure in the filing;


•	staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and


•	the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Sincerely,

METHANEX CORPORATION

Ian P. Cameron

Senior Vice President, Finance and Chief Financial Officer

cc: KPMG

McCarthy Tetrault LLP