The Intersection of Energy Prices, Production and Fiscal Change on T&T’s Energy Revenue
The recent military tension between Iran and the United States has triggered not only global security concerns but also given a temporary boost to oil and gas prices. For Trinidad and Tobago, this minor spur in prices is welcome news. However, it should also propel us to mull over our current and future economic fortunes. We are now in the first innings of the United States shale oil and gas revolution. And, this revolution has led to an oversupply of oil and gas to global markets, a stabilization of energy commodity prices and lower revenue for T&T from our energy resources. This is the new normal.
Oil and gas revenue supports our present-day spending on social services, infrastructure and other public amenities and will be the financial bridge to the country’s future diversification plans. How we use our earnings from the sector will rationalize which direction the country takes in a world where renewables, electric vehicles, Big Data and other disruptions transform the future. But, to rationalize our current or future state, delving into data is essential. Data is supposed to drive decisions and dialogue. In a world where democratizing data is now the norm, the Extractive Industries Transparency Initiative (EITI) helps to provide the public, policy makers and industry analysts with access to key information on the oil, gas and mining sectors.
The sixth Trinidad and Tobago EITI report was recently published. And now, with seven years of TTEITI data on oil, gas and mining revenue, citizens can start spotting trends and see how EITI data continues to tell the story of the country’s economic performance and what this means for our future plans. Below are a few highlights of the latest report’s findings and recommendations for improving governance in the oil, gas and mining sectors.
How Did the Decline in Commodity Prices, Domestic Production and Fiscal Reform Impact Revenue?
The data in the EITI Report gives an account of the economy’s spiral into recession due to declining oil and gas production as well as a marked decrease in global energy commodity prices. In fiscal 2010-2011, the Government earned TT $23.1 billion in revenue from the upstream oil and gas sector while by fiscal 2016-2017 revenue slipped to TT $5.8 billion, a substantial decline.
In 2017, for the fourth year running, the NGC is the largest taxpayer contributing $2.3 billion to Government revenue through dividend payments and taxes. In the same year, EOG Resources and BPTT made payments of $851 million and $846 million respectively. Shell paid $412 million while BHP paid $406 million, followed by Petrotrin with a $378 million payment. Looking at total payments made between 2011-2017, the leading contributors were BPTT ($37.9 billion), NGC ($34.7 billion), Petrotrin ($20.6 billion) followed by EOG ($10.6 billion) and Shell ($8.9 billion) (See Chart 1 and Chart 2).
Other than a payment by NP in 2016, the NGC has been the only energy sector state enterprise to pay dividends over the past eight years. In fiscal 2011, the company paid $350 million in dividends, a figure which ballooned to $5.7 and $4.1 billion in fiscal 2015 and 2016 respectively. The company’s dividend payment for 2019 was $192 million, the lowest payment since 2011.
All these payments must also be viewed in the context of the fiscal regime, where changes to tax rates and allowances impacted State revenue and company expenditure and tax remittances. Over the past decade, the fiscal regime has been amended several times. There has been a constant debate on the trade-off between Government’s need for more revenue from taxes and the exploration and production companies’ need for incentives to stimulate exploration and production.
The country’s earnings from royalty, underscores how fiscal policy, price and production intersect. In January 2018, the Petroleum (Amendment) Regulations was amended to require all companies with exploration and production licenses (E&Ps) and production sharing contracts (PSCs) to pay a royalty rate of 12.5% based on their production. The influence on royalty earnings is clear. In 2019, the Government earned $3.4 billion in royalty payments compared to $1.4 billion and $883 million in 2018 and 2017 respectively. The 2019 royalty payment is the highest royalty payment received in the last decade. The country’s gas production also climbed from 3,332 million standard cubic feet per day ((mmscf/d) in 2016 to 3,612 mmscf/d) in 2019. Royalties are described, by NGO Open Oil, as “a percentage share of production, or the value of the production which goes to the Government regardless of the rate of production or costs to the operator” (See Chart 3). These energy sector payments impact the lives of thousands of citizens. This is evident from how much we spend to subsidize fuel, water, electricity and tertiary education. In 2019, Government spent $435 million on GATE, $369.6 million on CEPEP and $575.2 million on drugs and other related health care materials and supplies. When energy sector revenues decline, we are usually forced into austerity measures. Ensuring that we continue to benefit or gain greater benefits from the sector is, of course, tied to how well we manage the contracts that govern the oil and gas sector.
*The royalty figures for 2018 and 2019 have not been audited by the TTEITI Independent Administrator/Auditor.
Do Our Contracts and Licenses Ensure That The Country Gets Fair Value?
The two families of contractual arrangements or fiscal systems that dominate the T&T upstream sector are the tax/royalty system (which includes the E&P licence) and the contractual system (which includes Production Sharing Contracts – PSCs). The terms in these E&Ps and PSCs determine the profit splits between the State and oil and gas companies, royalty rates, company obligations in case of an oil spill and can even determine how much a company contributes to skills training for nationals.
To give some context, BPTT, the country’s largest gas producer operates the majority of its acreage under E&Ps while BHP, the country’s largest deepwater acreage holder operates under PSCs. Each individual contract or license has its own unique terms but changes to fiscal/tax regime, maintenance schedules and even the timing of an investment in drilling affects what can be earned in a particular period. For instance, in 2012 and 2013, a suite of incentives were offered to upstream companies to stimulate drilling and companies were able to offset capital expenditure costs against their taxable profits. During this period, prices and production feel as well and the impact on revenue was visceral for E&Ps.
Based on the available data, between 2011 and 2017, the country earned more from E&Ps than PSCs – 74 billion compared to 23 billion (See Chart 4). Yet there was a dramatic decline between 2011 and 2017. In 2011, the country earned $17.1 billion from E&Ps, while in 2017 E&P payments fell to just $1.9 billion. In 2016 and 2017, for the first time PSCs earned more than E&Ps and this points to the impact of price, production and the previously discussed fiscal incentives on the country’s revenue.
PSCs also need a deeper assessment, especially as it relates to the share of profit split and its effect on tax liability obligations. The share of profit is split is agreed to by oil and gas companies and Government based on factors such as oil and gas prices as well as production from the particular block. From this share of profit, paid to the Ministry of Energy (MEEI) by operator companies, the MEEI pays all tax liabilities on behalf of the operator and its other partners to the Board of Inland Revenue (BIR). These liabilities can include Green Fund Levy, Petroleum Profits Tax, Unemployment Levy and other taxes. The best scenario and accepted practice is for the share of profit to be sufficient to cover these tax obligations.
In 2014, the TTEITI’s auditor/Administrator, BDO Trinity Limited, started reviewing these tax obligations from PSCs and reconciling what the MEEI paid to the BIR. As a result, between 2014-2017, there is data to highlight whether the share of profit received by the Government was enough to cover the tax obligations for the period.
In table 1 below, the tax obligation is deducted from the share of profit from several producing PSCs. Based on the data, in many instances, the share of profit is not enough to cover the obligations. This trend was prevalent particularly in 2014, when only one company BG Trinidad and Tobago Limited paid enough share of profit for the MEEI to fully cover the tax obligations for its particular blocks. PSCs are normally ring fenced but this company reports for both NCMA 1 and Block 6. The difference between BHP 2C Limited’s share of profits payments and tax obligations for 2014 and 2015 also demands closer inspection.
Intuitively, this data raises questions on the value we receive from PSCs, and whether the terms favour all parties (Government and extractive company) equally. The answer is complicated. And, the question begs: does having a four year snapshot of PSC share of profit versus taxes obligations paid tell the full story of a block that may produce for 25-30 years? The production profile of a block changes over time and influences revenue. There are also other earnings from these blocks that are not accounted for in the share of profit. For example, the Government receives money for the sale of its share of production from these blocks. In 2016 and 2017, the country earned US $308 billion and US $242 billion respectively from the sale of the state’s share of production these blocks. However, the jury is still out on whether the “right and fair” value from these contracts is collected. There has been publicized critiques that transfer pricing misalignment stems from these sales, where an operator company markets Government’s gas on behalf of the State.
It is important to note that without full contract transparency, analysis on whether the terms of E&Ps and PSCs are favourable will be speculative. However, the TTEITI will address this issue in the coming months as the new EITI Standard requirements requires all participating countries to fully disclose contracts by 2021. As a country that has been producing oil commercially for over 100 years, a wider discussion on whether we attain fair value from these contracts would be a valuable exercise.
The exercise can even help us review how the current contracts are structured, gauge the value earned over time and help inform future contractual and fiscal designs. The Poten and Partners Gas Master Plan also suggests a comprehensive rethink of our fiscal regime and regulations if we are to increase gas production in the coming decade. The plan states, “The initial realignment of regulations should include:
- Maximising access for new developments to existing infrastructure to reduce costs;
- Review and updating of fiscal terms (covering profit split and cost recovery) in 1996-05 gas price indexed PSCs to provide new developments with terms similar to the 2011-12 PSCs.
- Review and updating of fiscal terms in production license areas to ensure they provide a comparable investment return for new projects to recent PSC terms.”
Can Energy Sector Fees For Scholarships and Training Usher in New Energy Age for T&T?
Diversification has been on the national agenda for decades and successive administrations have earmarked strategic industries to help reduce reliance on the oil and gas sector. However, some energy analysts have long posited that the country should diversify within the sector, building a cadre of skilled workers capable of offering the region and the world technical expertise in subjects ranging from energy data management to manufacturing for renewables. If the country is to successfully diversify within the sector it will be on the back of skills gap assessments, retraining and retooling of its current work force. Energy companies help with this through tax contributions and specific fees. In fact, most contracts include clauses related to payments on scholarships, R&D and technical assistance. These payments can help build technical capacity and capability within the energy sector and beyond and be used to harness human resource potential. Between 2012 and 2017, oil and gas companies paid contributions totaling just over $1 billion on scholarships and training, R&D and Petroleum Impost and these funds can serve as seed capital for building the skill sets in the energy and other associated sectors.
These numbers mean nothing on their own. Beyond reconciling the difference between receipts and payments, the EITI is supposed to be a catalyst for reform, shining a light on systemic shortcomings and providing solutions related to improving revenue collection, audit and assurance and data management. This reform and the initiative is intended to empower the public to hold both Government and extractive companies to account.
In 2020, the TTEITI will reexamine our responsibilities, focusing on systemic disclosure and reforms of current Government and company systems. Dialogue will help inform this change. Policy planners, industry analysts and citizens rigorously questioning, analyzing and having lucid debate on the numbers can also force us to reassess how we, as a country, address systemic challenges. Whether this means redesign of fiscal regimes to rebalance risk-reward stability between the State and extractive companies, a strategic rethink of our plans for diversifying the economy or training our youth for a new era of global development. The world is in the midst of, sometimes daily, technological revolutions with a glut of oil and gas supply. Beyond the current fears over war and incursions, we must use the data and the required reforms to direct us to a viable future.