Current Fiscal Measures

For Petroleum Upstream Sector

Background

In Trinidad and Tobago, revenues in the form of taxes and/or levies from the upstream petroleum sector are extracted under various legislations. Governing the legal, contractual and fiscal framework of the energy sector are several instruments. The key instruments through which the main revenues are derived from the upstream petroleum sector are as follows:

 

1.         The Petroleum Act and Regulations, Chap 62:01 

Among the areas set out in this legislation are the contractual arrangements under which companies can explore and develop the resources within the country.  These arrangements include Exploration and Production Licences (E&Ps) (both Public Petroleum Rights and Private Petroleum Rights) and Production Sharing Contracts (PSCs).  The licensing regime that predominated before the 1990’s was the E&P arrangement, normally referred to as a tax/royalty regime or concessionary arrangement.  Under the Act, companies are required among other things to pay a royalty that is stipulated in the licence as well as contribute to the Petroleum Impost that is used to cover the administrative costs of the Ministry of Energy.

Royalty rates vary from company to company. With respect to crude oil, the rate ranges from 10% to 12.5% of the Field Storage Values.  Up until 1989, the Field Storage Value was based on the Royalty Lease Evaluation 1 Method (RLE1). This method provides for a price for crude oil that was determined by the values of the crude oil fractions (light oils, diesel and fuel oil) less a percentage for refining and handling charges.   For licences signed from 1989, the Field Storage Values are determined using international market prices of references crudes.   In the case of natural gas, the royalty rate ranges from a fixed rate of 0%  to 15% of the value for the natural gas. 

In the 1980s as the petroleum fields reached maturity, a new form of contractual arrangements, viz, sub-licences referred to as farm-outs and lease operatorship agreements were introduced to encourage lower cost operations and ensure continued activities.    

Exploration and Production Licences were the main legislative instruments during the period 1900 – early 1970s. However it was found that given the rapid oil developments, better administration of the contractual arrangements was needed.  In 1974, the first two Production Sharing Contracts (PSCs), for acreage off the east coast of Trinidad, were signed.  These earlier PSCs did not provide for cost recovery, allowed the government a share of production based on production levels and were ring-fenced. 

In 1995, with the adoption of the World Bank PSC Model, the PSC was extensively expanded with enhanced contractual terms and conditions. These included provisions for cost recovery, relinquishment, abandonment, minimum work programmes, shares of Profit Petroleum to the government that were based on both price and production levels, minimum work obligations during the exploration period, procedure to encourage the development of natural gas markets and financial obligations such as signature bonus, research and development, training of nationals and technical equipment bonus.  Like the earlier PSCs, these continued to be ring-fenced and assured the Government of a steady revenue stream. In addition, under these PSCs the Contractor’s tax liabilities were paid by the Government out of its share of profit petroleum..

 

At this time, similar type provisions were slowly being introduced in the E&P licences.

 

A review of the petroleum fiscal regime undertaken in 2005, led to the introduction of a new styled PSC, referred to as a “taxable PSC” that comprised three major features. Firstly, Government received a Share of Profit Petroleum in lieu of some taxes viz Supplemental Petroleum Tax, Royalty, Petroleum Impost and Petroleum Levy. Contractors were therefore exempt from payment of the aforementioned taxes but were required to pay all other taxes namely, Petroleum Profits Tax, Unemployment Levy, Green Fund Levy and Withholding Tax directly to the Ministry of Finance; this represented a departure from the earlier models in which the government paid these taxes on behalf of the Contractor.   Secondly a windfall profits feature was introduced to capture higher shares of profit petroleum as petroleum prices increased.  Thirdly consolidation of the new PSCs, by type either deep water or land/shallow marine was permitted.  This was to promote multi-block development and facilitate investment by consortia and in so doing minimize the increasing risks. 

Also included were provisions for re- openers, accessibility of natural gas supplies for both the domestic and export markets, improved funding procedures for abandonment, and assignments and transfers.  A special incentive that provides for an uplift of 40% on the drilling of exploration wells in the deep water was introduced.  

2.        The Petroleum Production Levy And Subsidy Act, Chap 62:02.  

Established in 1974 to buffer large increases in petroleum product prices and provide a general level of market stability, this Act provides for the subsidization of petroleum products that are sold to the domestic market. The subsidy was initially offset through levy payments made by oil producing companies. 

In 1992, amendments were made to the Petroleum Production Subsidy and Levy Act.  The changes placed a ceiling on each company’s gross levy payments of not more that 3% (later increased to 4%) of its value of its gross income derived from the sale of crude; and included those companies, previously exempt with production level of less than 3,500 barrels of oil per day.   Excess levy payments above the cap were made by the Government.

 

3.           The Income Tax Act, Chap 75:01

The Act together with the Corporation Tax Act sets out the over-arching framework and principles under which companies are required to pay taxes or other impositions.   These are the fore-bearers to legislation that was enacted later on.  The Income Tax Act provides for the payment of Withholding Tax at specified rates.  This tax is applicable to upstream operators that are non-resident companies.

 

 4.           The Petroleum Taxes Act, Chap 75:04 

The Petroleum Taxes Act was enacted by Act 22 of 1974 and is applicable to all operators engaged in petroleum operations specifically production business and/or refining business. The Act addresses the two main taxes paid by petroleum operators. These are Petroleum Profits Tax (Part 1 of the Act) and Supplemental Petroleum Tax (Part 11) as follows:

 

4.1       The Petroleum Profits Tax: 

The Petroleum Profits Tax (PPT) is applicable to all oil and gas producers as well as refinery operators and is applied to the net profits (chargeable income) from operations. The net profit is derived by deducting from the gross income all operating expenses, capital allowances and other allowable deductions. The deductions for oil and gas producers include royalties, Supplemental Petroleum Tax, Petroleum Levy/Impost, decommissioning/abandonment costs and management fees paid to non-resident companies (limited to 2% of expenses).  Other special allowances are granted for dry holes, work-overs, qualifying sidetracks, heavy oil as well as signature and production bonuses.The current applicable tax rate charged on producers as well as refinery operators is 50% (reduced to 35% from income year 2011 for deep water operations only) ,  Over the years, changes have been effected to the PPT as market conditions require.

 

 4.2      The Supplemental Petroleum Tax (Part 11 of the PTA)

Introduced by Act 5 of 1981, the Supplemental Petroleum Tax (SPT) has been amended on several occasions. The SPT is imposed on income generated from production of crude oil net of royalty and over-riding royalty.  Prior to the review that was undertaken in 2005, SPT was levied on the gross income from the disposals of crude oil (not natural gas income) less certain allowances based on expenditure incurred in specified exploration and development activities. Although the tax was imposed on crude oil sales, companies involved in both oil and gas activities benefitted from the allowances since they were broadly applied to exploration and development field activities. This anomaly significantly contributed to the development of the natural gas industry in Trinidad and Tobago.

 

The SPT rates vary for marine and land operations and for licences or contracts that were agreed prior or post 1988.  In 2006, SPT rates for deep-water operations were fixed as those for land operations post 1988.  Although SPT rates were based on a sliding scale for prices ranging from US$15.00 to $49.50 per barrel, thereafter the rate remained fixed.  Over the years, as economic and industry related factors warranted, several amendments were made to this tax.   A major change was made in 2005, when the allowances, with the exception of royalty and overriding royalty, were removed and the rates adjusted accordingly.   The SPT schedule was last amended in 2010.

 

5.     The Income Tax (In Aid of Industry) Act Chap. 85:04

Enacted in 1950, this act provides, among other things,  mechanisms, through accelerated allowances to encourage investment.  The capital allowances are granted in accordance with the category set out under the Income Tax (In  Aid of Industry) Act.  These categories are as follow: 

• Part 1              -           Industrial Buildings
• Part 11            -           Plant & Machinery (Tangibles)
• Part 11A          -           Plant & Machinery - Refinery
• Part 111          -           Mines, Oil Wells etc.(Intangibles)

 

Under each of these categories initial and annual allowances are granted.  With respect to Part II - tangible expenditures made in exploration and development operations, the initial allowance is computed as 20% of the tangible expenditure for the first year while the annual allowance over a five year period is 20% on the residue of expenditure taken on a straight-line basis.

 

Similar allowances are granted for plant and machinery within the refinery, except that these are based on expenditures that are uplifted by 20%.

 

For intangible expenditure, the initial allowance of 10% and annual allowance of 20% of residual expenditure taken on a declining basis are computed.  In the case of intangible exploration expenditure the annual allowance is taken from the first year while for intangible development expenditure, the annual allowance is taken from the second year. 

 

6.            The Unemployment Levy Act Chap 75:03

This Act was enacted in 1970 and is intended to provide funds to assist in the Government’s social programmes. Initially the levy was applicable to individuals as well as all businesses but this was amended by Act 6 of 1989 to apply only to companies charged to Petroleum Profits Tax. The applicable rate is 5% of the chargeable income before loss relief plus any exempt income, other than those exempted under the PTA.

 

7.              The Green Fund Levy

This Levy came into effect from January 2001, under the Miscellaneous Taxes Act Chapter 77:01.    It is computed as a percentage (currently 0.1%) of the gross sales or receipts, and these payments are not tax deductible.   As the name suggests, this levy is used in the maintenance, reforestation, restoration and conservation of the environment.  

 

New Fiscal Regime

 

A new petroleum fiscal regime was approved and subsequently implemented by the Finance Act 13 0f 2010. The new fiscal regime introduced initiatives that sought to improve this country’s competitiveness and attractiveness to potential investors, both locally and globally.  In achieving these objectives, emphasis was placed on the competitive bid process, the terms and conditions of the contractual arrangements to be offered under future competitive bid rounds as well as the incentives offered under the concessionary (tax/royalty) arrangements.  Details of the 2010 fiscal initiatives are outlined below under the following headings:

 

1. The Competitive Bidding Process
2. Production Sharing Contract – Form, Terms and Conditions
3. Tax/Royalty Arrangement – Supplemental Profits Tax Amendment
4. Sub-Licence Arrangement

 

A.        The Competitive Bidding Process

Administratively, a new competitive bid process was designed to provide for simplicity and a shorter time-frame between the start of the bid process and the signing of the contract.  A major feature of the process is the reduction of biddable items to two items, namely the work programmes and Government’s Share of Profit Petroleum.  Under the new process companies are able to self-assess their work programmes, while the Government’s Share of Profit Petroleum which is a more competitive item is assessed by the Technical Evaluation Committee.

 

A new requirement of the process is the prequalification of companies to determine not only their financial and technical competencies but most importantly, their status as a potential Operator for the acreage.  This will ensure that the most suitable and efficient companies are selected to operate this country’s acreage.

 

Another feature that has been introduced is the nomination of acreages by companies.  This feature provides an opportunity for companies to indicate the acreages they wish to be considered for inclusion into the upcoming competitive bid rounds.  The Ministry of Energy and Energy Affairs still reserves the right to decide on the final acreage that would be offered under any competitive bid round. 

 

It is planned that the entire process from the official announcement of the competitive bid round to the signing of the contract should take no more than nine months.    

 

B.        Production Sharing Contract – Form, Terms and Conditions

A more conventional-styled PSC similar in some aspects to the 1995/1996 Competitive Bid Round has replaced the 2006 Taxable PSC.  This new form PSC is designed to treat with risks and encourage investment in shallow water-depths (less than 400 metres); average water depths (of more than 400 to 1000 metres) and deep-water (depths greater than 1000 metres) acreage. 

 

Under the 2010 PSC model, the GORTT’s Share of Profit Petroleum is required to satisfy the Contractor’s liability for Petroleum Profits Tax, Unemployment Levy, Supplemental Petroleum Tax, Royalty, Oil Impost, Petroleum Production Levy and Green Fund. The exceptions are Withholding Taxes and Stamp Duty which must be paid directly by the Contractor.  Legislative changes were made to the Petroleum Taxes Act to give effect to this form of production sharing contract.  A major feature of the PSC is that it provides fiscal stability to the companies.

 

Like the 1995/1996 PSC, the matrices for the Government’s Share of Profit Petroleum are open for bidding by the companies.  Further to this, the price bands and production bands for these matrices are reflective of the expected pricing and cost environments. The windfall feature, first introduced under the taxable production sharing contract, is retained. 

Some other features of the model PSC include as follows:

1.         Ringfenced  (Non-consolidation)

 

Like the 1995/1996 models, these new PSCs do not provide for consolidation. As such costs and expenses incurred are recoverable from the given production sharing contract; no consolidation of accounts between contracts or licences will be allowed.  This departs from the Taxable PSC that provided for some limited consolidation.

 

2.         Carried Participation

 

A Carried Participation for the State of not more than 20% is a feature of the shallow water-depth acreage (400 metres and less) only. At this time carried participation is not considered for the average and deep water-depths acreage.  This measure forms part of Government’s overall policy for broadening accessibility to its resources and as an avenue for expanding capability and capacity within the state sector.

 

3.         Financial Obligations

 

Many of the financial obligations of the PSC are no longer biddable items and are clearly fixed and stated in the contract.  By so doing, this has removed the upfront risk to investors and improved the project economics. Additionally, this allows focus to be placed on the two key areas - the work programmes and sharing of profit petroleum. 

 

Payment of signature bonuses remains a feature of the shallow and average water depth acreage. However for the deep water acreage, signature bonuses will only be required in the event that   two or more companies achieve equal points at the end of the bid process. 

 

4.         Cost Recovery

 

Cost recovery limits were fixed at 50%, 55% & 60% for shallow, average and deep water-depth acreages, respectively in the 2010 Competitive Bid Round.  However for the 2012 Deep-water Competitive Bid Round the cost recovery limit for the deep is increased to 80%.  In earlier production sharing contracts, these limits were biddable items.

 

5.         Additional Incentives

 

Given the cost and risks involved in exploring in average-water depths and deep water environments, additional incentives were provided to increase the attractiveness of these areas. For tax purposes only, firstly, the definition of deep water acreages was amended to include areas that are located in depths of more than 400 metres and secondly, a Petroleum Profit Tax rate of 35% was introduced specifically for the deep water acreage.

 

It should be noted that an uplift of 40% in computing capital allowances was granted for capital expenditures on exploration activities in respect of deep water.

 

 

C.        Tax/Royalty Arrangements - Supplemental Petroleum Tax

With respect to the concessionary arrangements, emphasis was placed on those areas and activities where incentives for revitalization and sustainability were required, such as in the small offshore oil acreages, mature acreages both offshore and on land as well as where enhanced oil recovery projects are undertaken.  The incentives geared specifically to encourage investment in crude oil production, directly impact the Supplemental Petroleum Tax that will be payable by companies.  In so doing, it will provide companies with additional cash flows for re-investment in the upstream sector. 

 

The Supplemental Petroleum Tax is regarded as a windfall tax that is charged on gross income from the disposal of crude oil less royalty and over-riding royalty. 

 

Under the new SPT regime, the classification of differing rates for pre and post 1988 was maintained for marine operations. However with respect to land produced crudes, due to several joint arrangements, new entrants and the new licences that were granted to Petrotrin in 2007, this concept was no longer relevant.  Consideration was also taken of the prevailing cost environment in which the companies operate.

 

As such, the new schedule of rates was simplified accordingly as follows:

 i. At crude oil prices at US$50.00/bbl and below, the SPT rate is set at zero percent; 

 ii. At crude oil prices above $US50/bbl and up to $US90/bbl, a fixed SPT rate is charged; 

 iii. At crude oil prices above $US90/bbl  and up to $200/bbl a formula-based sliding scale is applied; and thereafter

 iv. At prices above US$200/bbl, the SPT rates are capped for Marine (pre 1988) at 64%; Marine (post 1988) at 55% and for Land and Deepwater operations at 40%.

 

Sustainability incentives are granted for mature marine and small marine oil fields. These incentives provide a 20% discount on SPT rates for both mature marine and small marine oil fields.  A mature oil field is defined as a field that is 25 years or more from the date of first commercial production, while a small marine oil field is defined as one with production levels of 1,500 barrels of oil equivalent per day (boe/d) or less.  It should be noted that companies will only be allowed to qualify for one of these discounts in respect of any particular field.

 

An Investment Tax Credit equivalent to 20% on qualifying capital expenditure is provided for mature oil fields (either land or marine). With respect to enhanced oil recovery projects utilising either steam, carbon dioxide (CO₂₎, or water flood injection, a 20% tax credit on qualifying capital expenditure is also granted. Under this provision, companies will only be eligible for one of these investment tax credits in respect of any particular field. Only expenditure in respect of crude oil operations will be considered for this incentive.

 

The  investment tax credit could  be claimed only in the quarter in which the expenditure giving rise to the credit is incurred and is limited to the total SPT liability for a financial year.  At the end of a company’s financial year, any shortfall in claiming the credit could be addressed by requesting an amendment to any previous quarter in the same financial year.  Excess credits in a financial year will not be allowed to be carried forward to offset in any succeeding financial year. Additionally in instances where the plant and machinery is disposed of within three years, the credits will be recaptured.

 

Qualifying capital expenditure for investment tax credit will be defined as direct tangible and intangible costs (exclusive of all dry holes) incurred in field development activity for both marine and land oil fields, and capital expenditure incurred in the acquisition of plant and machinery as specified for EOR projects. Finance costs, administrative costs and other indirect costs are not to be included for the credit.

 

These fiscal measures together with several others are geared towards improving this country’s investment climate and creating opportunities for enhanced activities in the petroleum sector. In so doing, these measures will promote this country’s economic recovery and long term sustainability.  

 

D.        Sub-Licence Arrangement

 

An amendment was made to the Petroleum Act to allow licensees to issue sub-licences in marine areas. Previously, this provision was only applicable to land operations.  It offers companies opportunities to stimulate activities on idle and/or maturing acreage. 

 

Commercial Evaluation Division

Ministry of Energy & Energy Affairs

June 2011

 

Appendix 1

Main Taxes At A Glance

 

Tax	Rates	Deductions
Royalty	Crude Oil: 10% - 12.5%   Natural Gas: TT$0.015/mscf – 15%
Supplemental Petroleum Tax	As prescribed in Schedule (Applicable only to Crude Oil Income)	Royalty & Over-riding Royalty
Petroleum Profit Tax	50% of Net Taxable Income   35% of Net Taxable Income (Deep water)	See Appendix 2
Unemployment Levy	5% of Net Taxable Income	See Appendix 2
Petroleum Production Levy	Up to 4% of gross income from crude
Petroleum Impost	Rate specified in Order provide under the Petroleum Act
Green Fund Levy	0.1% of gross sales or receipts
Withholding Tax	Rate as specified in Schedule under the Income Tax Act

 

 

Appendix 2

Basic Tax Computation For PPT, UL & Withholding Tax