Threat to govt gas revenues

“We can be losing up to 11 billion USD per year due to selling our Gas to low price markets, and the GORTT needs to act now to rectify this.” The threat to gov’t gas revenues 

Apr 17, 2012– Trinidad Express

Last Wednesday, the price of natural gas on the Henry Hub Index plunged to a ten-year low to

US$1.96 per thousand cubic feet (MMBtu). It later fluctuated, hovering around the US$2 mark, where it seems destined to stay – unless unusual weather conditions drive up demand for the commodity in the United States. While Trinidad and Tobago no longer sell most of our LNG on the US market. The reality is that we are very much a gas-based economy. Therefore, when prices plummet in a country like the USA, we need to understand what that could mean.

http://www.trinidadexpress.com/business-magazine/Threat_to_govt_gas_revenues-147862755.html

Note: The above reference link was live on April 2012, but it has since been taken down.

The above article prompted this piece, which I found in my inbox this morning…PLEASE NOTE that I (Derren Joseph) did NOT write it…

Why are WE losing up to 11 billion USD per year: due to selling our Gas to low priced markets?

Review the explanation below:

• Trinidad produces and sells approximately 4.1 billion cubic feet (bcf) or 4,100 million cubic feet (mmscf) or 4,100,000 thousand cubic feet (kcf) of gas per day.
• This gas goes to two types of markets:
• Approximately 1,800,000 thousand cubic feet (kcf) goes to the “local.”
  The market for the main usage in the Point Lisas industrial estate at an average price of US $ 2.00 to the US $3.00 per thousand cubic feet (kcf).
• The National Gas Company sells this gas.
  (NGC) After buying this gas from the main Upstream producers – bpTT, bg, EOG, and BHP, equals 44% of our gas sales.
• The remaining 2,300 000  thousand cubic feet ( kcf) goes to the
  Atlantic trains ( 1, 2, 3, and 4) for liquefaction and sale to international
  markets and is called Export gas. This is equal to 56% of our gas sales. 
• Train 1 contracts end in 2018, Train 2 in 2022, Train 3 in 2023, and Train 4 in 2027

Note: The above reference link was live on April 2012, but it has since been taken down.

What is the first problem:  – This export gas is sold at various prices depending on the gas sales agreements signed by various government administrations in the past.

SOLUTION:

The market forces have changed considerably since these contracts were signed, and the contracts need to be reopened so that our gas price gets the best possible price. 

Let’s understand gas pricing and then take a look at what these changes in the markets mean for Trinidad:

What happens to our gas physically?

• The gas goes from the well to the ALNG plant, where it is liquefied and placed on ships then transported to a foreign country. Here it is regasified and then sold to a gas marketer who sells it to the foreign markets. 
• The price the producer of the gas in Trinidad (bpTT, bg, Repsol ) receives is based on the price the marketer pays for the gas in the foreign country minus the gasification minus the shipping cost minus the Atlantic liquefaction cost.
• The upstream producer then pays taxes or share profit with the government, usually at the rate of 50% to 55%. This is how we get value for our gas.  

Gas is sold in units called “million British thermal units”(MMBtu), which is closely equivalent to its volume measure thousand cubic feet ( kcf), so we can say gas is sold as a dollar per thousand cubic feet or $/kcf.

Typically this final Marketer gas price is be based on one of three systems: the market prices in the regions where the gas is sold, the market prices in other regions (different from where the gas ends up depending on the specific contract that was signed) or it may be based on linkages to the price of other commodities, e.g., fuel oil and this type of contract is typically for long term sales. 

– Generally, gas prices linked to oil products will be higher than gas prices linked to gas or gas products because of the relationship between oil and gas in terms of energy base (which is what oil or gas is used for – energy) -:

– Every barrel of oil is roughly equivalent to 5.60 units of gas. This means that if the oil is selling at 100 $ /barrel, an equivalent gas price will be (100/5.60 ) or 18 $/unit of gas, which is quite high. Currently, US prices called Henry Hub is about 2$ per unit – A large difference

Let’s discuss the different pricing regions in the world: 

There are three main gas market regions in the world, and each has a very different price. 

1. Henry Hub or the United States market  -the lowest and currently about US 2.00 $kcf ($/ thousand cubic feet). This market was about 4$ /kscf when the contracts were signed and were profitable. The producer currently receives close to no cash or a negative price (meaning the gas producer in Trinidad pays the buyer to take the gas). Luckily most contracts have a floor price of about 1$/kscf. The Henry Hub is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange (NYMEX). It is a point on the natural gas pipeline system in Erath, Louisiana. Spot and future prices set at Henry hub are generally seen as the primary price set for the North American natural gas market.
2. In Europe, the National Balancing Point (NBP) or the English market hub is the largest hub and is the mid-price of the three regions and is currently about US 8.00 $kcf (thousand cubic feet ). NBP is a virtual trading location for the sale and purchase, and exchange of UK natural gas. It is the pricing and delivery point for the ICE (Intercontinental Exchange) natural gas futures contract. It is the most liquid gas trading point in Europe and is a major influence on domestic consumers’ prices at home. It is similar in concept to the Henry Hub in the United States – but differs in that it is not an actual physical location. Additionally, there are by now 6-7 major gas hubs operating in Europe. Gas prices at these hubs have been 25% lower than the long-term contract prices (generally linked to oil prices). Pipeline gas in Europe has been sold at oil-linked prices under long-term (20-25 years) take or pay contracts, meaning that the buyer does not lift the gas. He pays for the gas. Germany initiated this kind of contract with Gazprom of Russia (Soviet.Union) in the 1960s. Europe’s gas-to-oil price ratio has tended to vary between 50% and 75%, 50% at high oil prices, and 75% at low oil prices. For example, Germany’s border gas prices are at 70% of the oil price, which means if the oil is 100$ /bbl, the gas price will be 70% off (100/5.60 ) or 12.50 /unit. Again, it is slightly higher than the trading hubs, e.g., NBP, but drastically higher than the US Henry hub market, where most of our Trinidad contracts are linked.
3. Asian or Far East Markets – the highest payers for gas and currently about US 16 $ /kcf since most contracts are linked to oil markers. As we can see, there are HUGE differences in the pricing – from 2.00  US$  to 16 US$ per unit currently and forecasted depending on smart gas contract pricing. e.g., In June 2011, Henry Hub pricing was 4.41 USD/ unit,  Liquified. Natural Gas spot prices in Europe were 9.60 USD per unit, as opposed to the contracts linked to High Sulphur Fuel Oil with prices of 16.68 USD per unit and with a crude oil-linked contract on a one to one parity with prices of 22.58 USD per unit since oil was at around 125 $/bbl. (125/5.6 = 22.58 $). The corresponding marker prices in Japan in the same time period were 13.9 USD, and DES India was at 13.17 USD. 

What did we get for our gas? No one in public knows since gas contract pricing is kept a secret between the Government and the gas buyers. One wonders why? 

This difference in pricing can be seen from the data below in the table from IHS Cambridge Energy Research Associates forward trends and Historical data derived from Intelligence Press. (Raw data in tables below). A large difference can be seen between Henry Hub, which is the red line, and all other pricing mechanisms, the highest being JCC or Japanese Custom Crude linked contracts generally. 

We can see the trend that the difference between the US markets (Henry Hub), Europe (Europe Contract and NBP), and Far East Markets (Japan Average, Asia Short Term, and JCC Parity) is increasing. In Trinidad, unfortunately, a large percentage of our gas contracts are linked to the price of Henry Hub, as mentioned before. Have we reopened our contracts to maximize the value we get from our remaining limited supply? 

Train 1 has two main buyers: GDF Suez and Gas Natural. Gas is sold to GDF Suez at 77% of Henry Hub (US Gas price) whilst Gas Natural is sold at 69% a Henry Hub variant. 

Woodmac estimates the weighted average forecast for the price BP will receive for its gas at the Train 1 plant entrance in 2011 is US$3.09/mcf under our current contracts.

In Train 2, GDF Suez Train 2 sells for 63% of Henry Hub, Gas Natural, and Gas de Euskadi sell at Gas Oil and Fuel Oil Linkages while gas goes to the Spanish market to what is called the Spanish Market Pool price. This is an interesting one, and the net result is quite a low gas price, even lower than Henry Hub pricing in the past. The Spanish market pool price is when the Spanish gas price regulator sells its gas to the power companies to regulate and control electricity prices to its population. Train 4 is linked to Henry Hub.

Woodmac estimates the weighted average forecast for the price BP will receive for its gas at the Train 4 entrance in 2011 is  US$2.36/mcf.

Let’s calculate Trinidad’s revenue under the different price assumptions: *bpTT received on average, 2.83 $/kscf for its gas in 2011.  Remember, bpTT produces 2500 MMscfd out of 4100 MMscfd or 60% of our gas. This is still a huge difference from if they had received 8$/kscf or 16$ /kscf

Sample calculation for the above table:

Export LNG Sales = 2300 MMcfd= 2300 * 1000 Kcfd = 2,300, 000 Kcfd

NBP Price Loss

If we assume NPB pricing at 8.00 $/kcf plus we have to pay an additional $ 1.00 for Liquefaction plus 1.00 $ shipping to get to Europe and 0.50 $ regassification, we get: 2,300,000* (8.0 -3.0) = 12,650,000 per day or 4,617,000,000 $ per year.  

ASIAN Market Price Loss

If we assume Asian pricing at 16.00 $/kcf plus we have to pay an additional $ 1.00 for Liquefaction plus 1.50 $ shipping to get to Europe and 0.50 $ regassification, we get: 2,300,000* (8.0 -2.5) = 29,900,000 per day or 10,913,500 $ per year.   

We are losing between 4.6 billion USD and 10.9 billion USD per year in cash coming

into Trinidad if all of our cargoes are priced at the Henry Hub price. This is a huge difference for a small country like us since our entire budget is only 42 billion TTD or 7 billion USD. This gas is the property of EVERY CITIZEN of Trinidad and Tobago, and we deserve to understand why any of our gas is being sold at a lower price, and even the lowest price available and not to the HIGHEST VALUE MARKET Is this acceptable…..NO

More so because we have only about 13 years of gas remaining at the current consumption rates. -We produce 4.1 bcf per day (4100 MMCFD)  and have 19 tcf remaining. We have about 13 years of gas supply, as is documented by Wood Mackenzie below. We need to ACT now.

Additional Problems:

In 2009, the previous administration, under Mr. Conrad Enill, realized another alarming situation. Our multinationals were selling the gas to their intermediate companies within their group, which in turn, was selling the gas or maybe diverting the cargoes to higher-priced markets.

The local arm of the global multinational, say bpTT out of bP global received only what bp gas marketing company paid bpTT. The group made the remainder of the cash through its gas marketing affiliate. Therefore the taxes paid were not on the final sale price but some low intermediate price. Imagine this for operating ethically. What is sad is that our locals who worked for these companies allowed this to happen.

In September 2009, the then Government proposed a change in the tax system whereby the Minister of Energy will determine the sale price of gas sold by Trinidad  ( and thereby determining the profits to be taxed by the multinationals) calling the  “Deemed price of Gas” based on the ministry research on current pricing. This was an attempt to prevent this ethically bankrupt mode of operation. This idea was vehemently opposed by the multinationals who promised to share the profits equally with the government going forward. The proposal was scrapped because the government was under pressure with respect to looming elections, etc.

What has developed and developing the world has done in terms of market changes?

• Many countries have decided to adjust gas prices
  upward (Iran, Bahrain, Egypt, Brazil); others have regularly renegotiated selected gas supply contracts to ensure their population gets the best value from a disappearing resource.
• Argentina has nationalized the Spanish owned assets of Repsol since the Spanish giant may have failed to meet contractual obligations and is not investing sufficiently but removing profits through dividends to Spain. 
• Brazil has decided to hold multinationals accountable for their actions by deciding to prosecute acts of perceived negligence by Chevron and BHP and seizing the directors’ passports so they can’t leave the country until the prosecution is complete.

The US is now a NET EXPORTER of GAS and does not need our gas anymore. Therefore, it will not affect the US or affect relations if we move our gas to higher-value markets. They DO NOT need it.

Immediate Steps:

1. Can the readers of this article please investigate the above study and question the current decision-makers as to why nothing is being done.
2. Educate the public about what is going on with their gas to understand that their inheritance is their inheritance. Once educated, they will question why they’re best interest is not being sought after.
3. We need an Immediate Review and Termination of all sales to low price markets. Parliament can make or unmake any contract, especially if it is this unfair to the owners of the resources…imagine the public does not know what is happening to our gas!!
4. We need to sell as would any sensible and reasonable man, to the highest possible the price he would get for his goods.. …..no one would sell their property to for the lowest price……Why then have we allowed past governments to do so and present governments to continue allowing this to happen  ……, mostly when it is sold, it is gone forever?? The government will say we are diverting cargoes to higher price markets since the USA does not need our gas anymore. This is true to an extent since the USA is very recently a Net Exporter of Gas. HOWEVER, we need to be sure the gas is diverted to the highest-priced markets and that fundamentally ALL is sent there now and in the long term. The public must be informed on the average gas pricing we receive each month for our Export gas and why we did not receive the highest value. Finally, remember every day goes by, we can be losing between 12.6 M USD (4.6 billion/ 365) and 30 MUSD (10.9 Billion /365). This is between 80 million TT$ and 191 M TTS.

Readers, please investigate and act now.

Appendix 1: – More detail on Gas Pricing in the Atlantic Export LNG Trains

1. Train 1: Twenty-year gas purchase agreements for 100% of Train 1 output were signed on 27 July 1995.  Cabot LNG (now part of GDF Suez) agreed to purchase 60% of output and Enagás (subsequently transferred to Gas Natural) the remaining 40%.  The gas is sold FOB on a netback basis. Hence, the revenues received by upstream producers are determined by the US and Spanish markets’ prices. The variations in FOB (Trinidad) price is shared between BP and Atlantic LNG on an approximate 55:45 split.  There is no wellhead floor price.  The FOB netback price in Trinidad for deliveries into the Americas is generally calculated by taking into account the difference between Henry Hub and the local price of gas (the Pricing Point Differential), subtracting a regas cost of roughly US$0.35/mmbtu (depending on the terminal), pipeline transportation and a shipping cost.  Our estimates of shipping costs vary depending on destination, but for the US Gulf Coast terminals, they are in the order of US$0.45 – 0.55/mmbtu.  Regas costs are inflated at 1% and shipping costs at 0.50%. The FOB netback price in Trinidad for deliveries into Spain is calculated by taking into account the DES (delivered ex-ship) price of the LNG in Spain, set by an oil-linked contract, and deducting a shipping cost of around US$0.80/mmbtu.

Woodmac estimates the weighted average forecast for the price BP will receive for its gas at the Train 1 plant entrance in 2011 is US$3.09/mcf under our current contracts.

2. Trains 2 and 3 gas: are sold under a netback mechanism in which the upstream producers and the Government carry all the price risk. To guard against falls in upstream tax revenues during times of low gas prices, the government secured a floor price in the pricing mechanism of US$0.75/mmbtu.  Train 2 and 3 plants do not take any price risk (unless the gas price falls below US$0.75/mmbtu).  Instead, they charge a processing fee (‘tolling arrangement’) for the gas passing through them to recover costs and receive an agreed return (of around 12% nominal). The tolling fee in 2011 will average around US$0.83/mmbtu per unit of LNG sold. The netback gas price is calculated by taking the prevailing gas price at the point of delivery of the regasified LNG into the end-user market (primarily North America or Spain) and subtracting the re-gasification cost, the cost of shipping the LNG from Trinidad, the tolling fee, and plant losses. The FOB netback price in Trinidad for deliveries into the Americas is generally calculated by taking into account the difference between Henry Hub and the local price of gas (the Pricing Point Differential), subtracting a regas cost of roughly US$0.35/mmbtu (depending on the terminal), pipeline transportation and a shipping cost.  Our estimates of shipping costs vary depending on destination, but for the US Gulf Coast terminals, they are in the order of US$0.45 – 0.55/mmbtu.

3. 3. Gas sold to Train 4 is sold under a similar tolling arrangement to T2 and T3.  The allowed rate of return for the plant is similar (11% nominal) but, because Trains 2 and 3 are effectively a two-train operation, they have slightly lower unit operating costs than T4.  Hence T4 needs to charge a somewhat higher tolling fee.  In 2011 the tolling fee will average around US$1.15/mmbtu per unit of LNG sold.

As with Trains 2 and 3,  the netback gas price is calculated by taking the prevailing gas price at the point of delivery of the liquefied LNG into the end-user market (primarily in North America) and subtracting the re-gasification cost, the cost of shipping the LNG from Trinidad, the tolling fee, and plant losses. FATCA Law Singapore 

Woodmac estimates the weighted average forecast for the price BP will receive for its gas at the Train 4 entrance in 2011 isUS$2.36/mcf.