Marginal Field Operation: what pitfalls lie ahead?

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By Ikenna Omeje and Jerome Onoja

While it is prestigious to own a marginal field, the recent winners of Nigeria’s 57 fields who received their letters dated March 1, 2021 would need to be extra cautious in order to avoid the mistakes of those who had gone ahead. The worst case scenario is to have one’s licence revoked from non-performance. However, there are producing marginal fields today which should be doing better than the results they have posted. Unfortunately, many unsuspecting operators encountered pitfalls in the early days of their operations. This article addresses some of these issues.

Marginal Fields in Nigeria evolved from the Petroleum Amendment Act 1996. The Federal Government in February 2003, awarded 24 marginal field licences to 31 indigenous companies, 24 of them designated operators with seven partners. Some of the beneficiary companies include, Midwestern/Suntrust partnership, WalterSmith, Energia/Oando partnership, Pillar Oil 2, Brittania U, Platform Petroleum, and Frontier Oil.
In November 2013, 10 years after, the Department of Petroleum Resources (DPR) announced the commencement of the 2013 Marginal Fields Licensing Round. According to the guidelines by the Department, the objectives of the 2013 bid round were to, “Grow production capacity by expanding the scope of participation in Nigeria’s Petroleum sector, through diversification of resources and inflow of investments; increase oil and gas reserves base through aggressive exploration and development effort, in particular the deeper hydrocarbon plays; provide opportunity for portfolio rationalization; promote indigenous participation in the sector thereby fostering technological transfer; provide opportunity to gainfully engage the pool of high level technically competent Nigerians in the oil & gas sector; and promote common usage of assets/facilities to ensure optimum utilization of available capacities.” Unfortunately, the bid round did not hold as planned.
However, on June 1, 2020, the DPR flagged off another bid round, with a total of 57 fields located on land, swamp and shallow offshore terrains on offer.

Payment by  interested bidders attracted non-refundable chargeable fees as follows: Application fee of N2 million per field, Bid Processing Fee of N3million per field, Data prying fee of $15,000 per field, Data Leasing fee of $25,000 per field, Competent Persons Report of $50,000 and $25,000 for Fields Specific Report.
According to DPR website, a marginal field is any field that has been discovered and has been left unattended for a period of at least 10 years, from the date of first discovery or anyone so-called by the president of Nigeria.
The goal of marginal field program is to create opportunities for Nigerian

oil and gas companies in the upstream sector, grow the country’s oil reserves’ production, encourage economic development through revenue generation, promotion of indigenous participation in oil and gas sector and discouragement of the abandonment of depleting oil fields in Nigeria.

Prolonged litigation against Federal Government

A Federal High Court in Lagos had in June last year issued a restraining order against the Federal Government from selling or accepting bids for eight marginal oil fields (Oil Mining Licences) pending determination of a suit challenging their status.
The order was given following a suit filed by 10 marginal field operators against the Minister of Petroleum Resources, Attorney General of the Federation and Minister of Justice, and the Director, Department of Petroleum Resources (DPR) as respondents in the suit.

Timipre sylva

The court restrained the respondents from advertising a bidding process for the marginal fields which were awarded to the plaintiffs, or selling them, and granted an interim injunction authorising the plaintiffs “to continue to manage, operate, control, explore… the marginal fields pending the hearing and determination of the substantive suit.”
The operators had gone to court to challenge the revocation of their licences by the DPR under the guise that the affected fields had been unattended.
However, in a letter to President Muhammadu Buhari, who doubles as the Minister of Petroleum Resources, the operators acknowledged that they had withdrawn their cases from court.
“…thereafter, we had interaction with the Minister of State for Petroleum Resources who advised us to withdraw our matters from court so that we can have meaningful discussions. Based on that the cases were withdrawn from court,” they explained.
“Following the assurances from the Minister of State for Petroleum we withdrew our cases from court. Even the Director of DPR gave the same assurances on live television but these govt functionaries have not called for any meetings and we have received feedback that the DPR and the Ministry of Petroleum Resources are in the process of reassigning the affected fields to new interests,” the operators stated.
The operators and their marginal oil fields include: Independent Energy Ltd – Ofa OML 30; Associated Oil and Gas Ltd/ Dansaki Petroleum Unlimited – Tom Shot Bank OML 14; Bayelsa Oil Company Ltd – Atala MFOG-2C and Bicta Energy and Management System Ltd – Ogedeh OML 90 MFOG-2D.
Others are: Del Sigma Petroleum Ltd – Ke OML 90 MFOG-2E; Goland Petroleum Ltd -Oriri OML 88 MFOG-2F; Sahara Energy Ltd/African Oil and Gas Ltd – Tsekelewu OML 40 MFOG-2G and Sogenal Ltd Akepo – OML 90 MFOG-2H.
The counsels to the operators had argued in court that the purported

a marginal field is any field that has been discovered and has been left unattended for a period of at least 10 years, from the date of first discovery or anyone so-called by the president of Nigeria.

revocation of the operators’ licences by the DPR violated their constitutional rights to fair hearing, their rights under the Petroleum Act and under the guidelines governing marginal fields in the country.
They urged the court to prevent the Federal Government from including the affected marginal fields in the 2020 bidding rounds for award of marginal fields pending the determination of the substantive suit.
Also, in the letter to President Buhari, the operators argued that the issuance of the instant revocation letters has jeopardised the investments of several state governments, Nigerian entrepreneurs and their foreign technical partners.

They further noted that the revocation of their licences has created additional Non-Performing Loans (NPLs) for the local banks.
According to the National Bureau of Statistics (NBS) the debts owed by energy firms to Nigerian banks rose by N200bn to N5.85tn in the third quarter of 2020.
Oil and gas firms increased their debt by N180bn to N5.12tn in Q3 from N4.94tn in Q2, while the amount of Non-Performing Loans in the sector declined by N30.53bn to N238.26bn in Q3 from N268.79bn in Q2.
“Not only are the actions of the DPR at complete variance with the Marginal Field bid guidelines and the duly executed Farm-out Agreements, we are extremely concerned that the DPR has chosen to pursue such a course of action in the midst of a global economic crisis with its resultant impact on the Nigerian economy at large, and in particular the primary economic contributor thereto, being the oil and gas sector.
“The revocation of the licences will certainly lead to litigation against the Marginal Field Operators by foreign partners and banks who have financed the development of the Marginal Fields, in addition to sending the wrong signal to both Foreign and local investors” the operators argued.
The operators explained, “We have conservatively invested over $ 400 million in developing the affected fields, with a number of them in production, whilst others are in various advanced stages of development including testing of oil wells, drilling of new wells, construction of production facilities, etc.
“These investments were made despite low crude oil prices, militancy and insecurity in the Niger Delta region, resulting in frequent shut down/ vandalisation of crude export pipelines.”

President Muhammadu Buhari

First oil, the game changer

The outlook over the three year period of 2021-2024 is to boost the nation’s crude production capacity by an additional 600kbpd. Also, the DPR last October, said that the country is targeting to substantially increase its oil reserves, including condensates, to 40 billion barrels by 2025.
The 57 fields awarded by DPR is estimated to generate additional 100 million barrels of crude oil to the country’s current production capacity in years to come.
Out of the 24 fields awarded in 2003, 11 fields have remained undeveloped locking in over 40 million barrels of oil. However, the DPR has identified the challenges that affected the attainment of full development of the 2003 marginal fields award.
“With the lessons of the previous exercise we want to refocus, change the approach, we have developed strategy to ensure you (the companies) and the awarded fields achieve early development.
“The DPR will continue to guide all of you every step of the way. For instance, the guiding template for working agreement has been drafted for joint awardees and discussions have reached advance stage between DPR and lease holders on the farm out agreement”, Auwalu said at the award ceremony.

Engr Sarki Auwalu,

“The revocation of the licences will certainly lead to litigation against the Marginal Field Operators by foreign partners and banks who have financed the development of the Marginal Fields,

Speaking with Majorwaves in the same vein, Emeka Ene the chief executive of Oildata and a member of the Board of Directors at Energia- the Joint Venture Operator of the Ebendo/Obodeti Marginal Field, has come out to say that, the new operators should focus on the goal of attaining first oil as quickly as possible.
“Because of the issue of forced marriage, we may see the human element come to play and distract the operators. If that can be handled, I’ll suggest the best approach to the operators would be to push for production as quick as possible.
“Re-entry into existing well should be a priority, not drilling new wells. The operator should then nurture the production for a while before commencing plans for drilling campaigns.
On his part, Abiodun Adesanya, chief executive officer of Degeconek told Majorwaves in an exclusive interview that operators who veered off existing wells into fresh drilling campaigns, most of the times, were unfortunate. He noted that every drilling campaign has a margin of error and as a result could be unsuccessful in spite of the cost.
“Marginal fields are existing oilfields. It is better for  the new marginal field operators  to approach the development of the fields by re-entering those wells to find the gas or oil that have been discovered, try to complete them and bring the oil out.
“There are mechanical and geological challenges an operator may encounter in the course of deploying seismic. Because the fields are small, in comparison to blocs, there have been several failed drilling campaigns. Should a wrong location be drilled on a marginal field, the entire investment, despite the opportunity cost, would have been lost.
According to Adesanya, the use of additional seismic for the development of the 57 marginal fields is not mandatory. He added that, the 57 fields had 3-D seismic data acquired for them in the past. He said rather than use seismic at this stage, the operators should instead use the money for seismic to re-enter those wells and begin to generate revenue, which will accrue more advantages to  them,  such as lenders being willing to lend them money, categorization of their fields by the DPR as producing fields, and elimination of chances for revocation of licence.
 On the cost of seismic, he said, “A typical land seismic will cost not less than $60,000 to $65,000 per square kilometer. So, if you are doing 100, you are already at about $6.5 million. With a bit of luck, we can beat it down. With a bit of bargain, we can beat it down. With a bit of knowledge, we can cut it and it comes around  $5 million or $5.5 million.”
He noted that seismic in the swamp area is a bit more expensive than in land area. He said that in some swamp areas, the cost may go up to $80,000, while in other areas, it might go up to $90,000 per square kilometer.
For onshore, he said that if the operator is not close to the coast line, or is in a water depth of 100 feet, seismic per square kilometre might cost up to  $25,000 or $30,000 per square kilometer. But if an operator is close to the cost line, it is about $100,000 per square kilometer.

Emeka Ene

“A typical land seismic will cost not less than $60,000 to $65,000 per square kilometer. So, if you are doing 100, you are already at about $6.5 million.

Choice of technology

Ene also noted that, rather than focus on cost reduction, it is more profitable to improve efficiency and productivity.
He advocated Rigless Workover and Enhanced Oil Recovery technologies as innovations that can help operators increase production without incurring the huge cost associated with deploying an entire rig to the site.
Rigless Workover is fitted for marginal fields, because they are usually old wells that have been discovered, such that an operator can actually re-enter an oil well without having to bring a rig in place, he said.
“It actually has fair application for brown fields and marginal fields. If you have a damaged well, you need to bring a rig to fix it. That alone will cost you at least $3 million; though it varies around $5 to $10 million to fix that problem. Also, it is  going to take an average of 30 to 45 days to fix it.

“Rather than spend  $5 to $10 million, you can spend less than a $100,000 by intervening with a Rigless Workover, without a rig. You save on the cost of mobilizing a rig, you save on time, because you can fix the problem in less than a week, compared to 45 days or even 60 days as the case may be,” he said.

rather than focus on cost reduction, it is more profitable to improve efficiency and productivity.

Abiodun Adesanya

“Rather than spend  $5 to $10 million, you can spend less than a $100,000 by intervening with a Rigless Workover,

 On the level of production, Ene said that though production is peculiar with the field, because every field is different, with Rigless Workover, production problem is zero. He noted that the average well production in the Niger Delta is between 800 and 1,000 barrels per day, but with the Rigless Workover production is significant, because the operator is going to bring back a well that was completely dead or damaged back to production.
Similarly, he said that Enhanced Oil Recovery allows an operator to unlock lost barrels. He said that in the Niger Delta, recovery factor is between 35 to 45 percent, which means that in a field an operator loses about 55 percent of the production, which they cannot produce, because the oil is bound to the rock. But with Enhanced Oil Recovery, the operator can recover 80 percent of the barrels that are normally lost.

Economies of scale, collaboration and joint facility ownership 

Speaking at the presentation of letters to the winners of the 2020 marginal bid round, Auwalu, said that a total of 591 firms submitted expression of interest forms, out of which 540 were pre-qualified, while 482 were bids submitted by 405 applicants.
“In the end, 161 companies were shortlisted as potential awardees, out of which 50 per cent has met all conditions and therefore eligible for awards today. We are set to ensure opportunities are extended to other deserving applicants to fill the gap.
“The DPR is not just a regulator, we are an opportunity house. We drive creativity and transformation and we use these in all of our activities. This is done in the overriding national interest,” he said.
Some of the successful companies awarded letters, included: Matrix Energy, AA Rano, Andova Plc, Duport Midstream, Genesis Technical, Twin Summit, Bono Energy, Deep Offshore Integrated, Oodua Oil, MRS and Petrogas.
Others are: North Oils and Gas, Pierport, Metropole, Pioneer Global, Shepherd Hill, Akata, NIPCO, Aida, YY Connect, Accord Oil, Pathway Oil, Tempo Oil and Virgin Forest, among others.
A major issue of concern is the purported forced marriage of companies. Speaking with Majorwaves on this concern in January, the Managing Director of IESL, Dr Diran Fawibe said that oil and gas is a multi-million dollar investment, and for that reason, companies should not be forced to work together, rather, it should be willingly done by companies who are interested in working together. But with increasing oil price volatility and increased pressure for cost reduction, the Nigeria’s oil and gas industry needs to reinvent itself so that it can fully utilize the dividends to set the country on the path to industrialization and prosperity. 
Speaking in this regard in his opening remarks at the 2021 Nigeria International Petroleum Summit (NIPS), now Nigeria International Energy Summit (NIES), which held in Abuja, with the theme, “From Crisis to Opportunity: New approaches to the future of hydrocarbons,” the Minister of State for Petroleum Resources, Chief Timipre Sylva, called on the leaders in the country’s’s oil and gas industry to embrace the culture of collaboration.
Sylva said, “We need to fully entrench that culture of collaboration by working together, sharing knowledge and expertise, pooling talent and resources amongst teams, industry peers and MDAs at all levels. That is a sure way the industry can decrease waste, improve efficiency and lower its breakeven costs for the industry’s survival and chart its eventual return to sustainable profitability.”
He said that with the recent issuance of licences to successful bidders in 2020 bid round, there is no better time  to embrace collaboration than now, adding that the unprecedented crisis caused by Covid-19 pandemic has made collaboration key to achieve success, especially for the new marginal fields.

The Minister, however, acknowledged that increased competition and low level of trusts put stumbling block to collaboration, but noted that there is no better way to deal with the increased risks and global market instability the industry is facing at this time than through collaboration.
He said, “I know that collaboration has been a buzz word in the oil and gas industry for years but the industry has equally paid lip service to it. With new set of marginal field licenses on the scene, there is no better time to shift the mindset but now. I say this because at this time

Dr. Diran Fawibe

of unprecedented crisis occasioned by the COVID-19 pandemic, there is no better strategy to achieve success for these new marginal fields especially for the cluster of contagious fields.
“I understand that increased competition, low levels of trusts are all barriers to collaboration but at the same time there is no better way to deal with the increased risks and global market instability we face at this time. The industry needs to overcome the strategy of working in silos and embrace collaboration and knowledge sharing.”
Lower cost is critical. This will continue to matter as the world pushes towards greener energy. The industry needs to drive down cost per barrel before it is exterminated by crisis, falling below production cost – a phenomenon the country experienced at the onset of Covid-19 pandemic. In this regard, collaboration becomes key. Joint facility ownership by field holders should be encouraged, so that they can enjoy economies of scale. 

“The DPR is not just a regulator, we are an opportunity house. We drive creativity and transformation and we use these in all of our activities. This is done in the overriding national interest,”

Deliberate mining of gas

As at January 1, 2021, Nigeria’s proven natural gas reserve stood at 206.53 trillion cubic feet (tcf), according DPR boss, Auwalu.
Auwalu who disclosed this while speaking at NIPS 2021, said the new figure represents an increase of 3.37tcf, representing 1.66 per cent percentage increase over the 203.16tcf recorded in the corresponding date of January. 1, 2020.
He said: “Nigeria attained the target of 200tcf of natural gas reserves by the Reserve Declaration as at Jan.1, 2019, before the 2020 target
“Thereafter, the government set a target to attain a Reserve Position of 2020tcf by 2030.
“As a department, we have continued to drive industry performance to grow reserves via dedicated gas exploration, deep drilling, optimal appraisal, field studies and improved oil recovery.
“It is, therefore, my pleasure to formally declare the National Gas Reserves Position as at Jan. 1, 2021 at this important forum.
“Nigeria’s Natural Gas Reserves as at Jan. 1, 2021, stands at 206.53tcf. Associated Gas is 100.73tcf and Non-Associated Gas is 105.80tcf, making a total of 206.53tcf.’’
The growth of gas reserves is a critical factor to achieving the Federal Government’s “Decade of Gas” initiative’’, which aims to make the country a gas-powered economy by 2030
The current global push towards low carbon energy presents the country with an opportunity to harness its huge gas reserves. Gas will become the dominant fuel for generating power, especially in Africa and Asia, and the country needs to position itself to take advantage of this opportunity.

“Nigeria’s Natural Gas Reserves as at Jan. 1, 2021, stands at 206.53tcf. Associated Gas is 100.73tcf and Non-Associated Gas is 105.80tcf, making a total of 206.53tcf.’’

Host communities as defence wall

According to Nigeria National Petroleum Corporation (NNPC) Monthly Financial Report, the country recorded 2,181 vandalised pipeline points between October 2018 and October 2019.
It goes to prove that above ground cost happens to be the highest in Nigeria, compared to other oil producing countries due to insecurity issues. For instance, from January 2019 to January 2021, repairs of NNPC pipelines and other facilities came at an outlay of about N15 billion. The destruction is largely from vandalism and oil theft.
Over a third of that amount was expended within two months. May 2021 saw NNPC spend about N3.2 billion on repairs. Prior to that, March 2020 gulped N2.6 billion for the same purpose.
Against this backdrop, new operators would need to manage the host communities in order to have the indigenous youths as first line of defence.
Adesanya warned that the new marginal field operators need to be more sensitive to the host community. He urged that due diligence be conducted in getting to know more about the area in which they are to operate in, so as to avoid clashes with the host communities. He said that data from the DPR might be minimal, adding that the new operators need to get all the necessary data from the former operators, so as to develop a good Global Memorandum of Understanding (GMoU) with their host communities.

Funding options available locally and international

Investment in exploration and production of oil and gas is capital intensive, and there are not many financial options for indigenous firms locally. On the international scale, it is a bit difficult to secure credit facility without a big guarantor, like the Federal Government.
While speaking with Majorwaves on the margins of 2019 Nigerian Oil and Gas Conference and Exhibition, on the challenges of indigenous E&P companies in this regard, the Head,

Energy Covering Downstream and International Oil  Trading  within Corporate Banking Directorate, First Bank of Nigeria, Oluwatoyin Aina said, “Hedging is a major requirement for most Reserve Based Lending financing as it provides a buffer to falling prices. Commercial banks generally are not positioned to take exploration risk due to the nature of our foreign currency capital which isn’t long term.
Our long term financing are usually in local currency. For foreign currencies, banks borrow the funds at an expensive cost and the tenure is usually short.”
She admonished local E&P companies in the country to look outside of Nigeria while seeking credit facility to fund their projects, like targeting African Finance Corporation (AFC) and International Finance Corporation (IFC) for fund. But with the trend in favour of greener energy, access to credit from big lenders has been a big challenge lately.
Many big lenders in Europe and the United States are taking steps to stop funding investment in fossil fuel, while others have announced plans to reduce the environmental impact of their financing activities from engaging with clients in fossil fuel-intensive sectors to lower their carbon footprints or stop financing of certain sectors entirely.

“Hedging is a major requirement for most Reserve Based Lending financing as it provides a buffer to falling prices. Commercial banks generally are not positioned to take exploration risk due to the nature of our foreign currency capital which isn’t long term.

In the United States, American Banker reports that the four largest United States banks decreased their fossil fuel financing by a combined $44 billion in 2020 from the year before, according to a report from the Rainforest Action Network and five other groups that analyzed bank financing of 2,300 fossil fuel companies worldwide.
However, a report published in the Q1 of this year from a collection of climate organisations titled “Banking on Climate Chaos 2021”, 60 largest commercial and investment banks have collectively financed $3.8 trillion in fossil fuel companies  between 2016 and 2020, the five years since the Paris Agreement was signed.
During the period under review, two banks from China led the chart of banks that financed fossil fuel. Postal Savings Bank of China had the largest percent change in fossil fuel financing — it increased over 1,200 percent from $168 million in 2016 to $2.2 billion in 2020, according to CNBC analysis using data from the Banking on Climate Chaos 2021 report.

four largest United States banks decreased their fossil fuel financing by a combined $44 billion in 2020 from the year before, according to a report from the Rainforest Action Network

The same analysis showed that China Minsheng Bank had the second highest percentage change in fossil fuel financing from 2016 to 2020 with a 550 percent increase, as its financing went from $1.7 billion to $10.8 billion.
Currently, most of the International Oil Companies are already cutting down investments in oil exploration and production. They are now shifting investments into renewable energy, which means that if the country wants to harness its vast crude oil resource, new funding models need to be adopted going forward.
As part of the solutions to address challenges regarding access to credit facility, the Ministry of Petroleum Resources should partner with the Central Bank of Nigeria to ensure that Nigerian banks begin to engage in long term financing of projects in oil and gas industry. This will help indigenous exploration and production companies not to lose their licences due to their inability to develop their fields.
Also, China looks like the next port of call regarding credit facility, as most of the banks in Europe and the United States are taking drastic measures to stop funding exploration and production of fossil fuel.
Locally, operators could have alternative funding arrangement for operations and drilling campaigns with service companies without upfront cash commitments. This model was deployed by a consortium consisting of indigenous service companies largely under the aegis of Petroleum Technology Association of Nigeria (PETAN), when they helped deliver first oil for Waltersmith.

Exit strategy and conclusion

As at 2005, the contribution of indigenous oil and gas companies to Nigeria’s oil reserves was less than 10 million barrels. Currently, it has grown significantly to about 62 million barrels in 2020.
Speaking at NIPS 2021, DPR Director, Auwalu, said that indigenous oil and gas companies are now contributing as much as 33 percent to the country’s crude oil reserves and about 30 percent to its gas reserves. This growth, he attributed to current efforts being made on gas exploration in the country, especially the Decade of Gas Initiative.
He said, “Nigeria attained the target of 200tcf of natural gas reserves by the Reserve Declaration as at Jan 1 2019, before the 2020 target.

four largest United States banks decreased their fossil fuel financing by a combined $44 billion in 2020 from the year before, according to a report from the Rainforest Action Network

Thereafter, the government set a target to attain a Reserve Position of 2020tcf by 2030.’’
According to Auwalu, independent companies are driving value addition to gas. He added that acquisition of divested assets, as well as accelerated appraisal and development efforts, are other driving factors, and that the country is already benefiting from the deliberate national efforts to boost indigenous participation in the sector.
Similarly, while speaking at a News Agency of Nigeria (NAN) forum recently, the Minister of Petroleum Resources, Sylva said that the present 206tcf of proven gas reserves in the country were accidentally discovered, adding that the country could discover an additional 600 trillion cubic feet reserve to enable it achieve the desired development required of a gas nation.
He said, “We have a lot of gas in this country. We have 206 trillion cubic feet of gas reserves.
“This number is already discovered in gas reserves and this 206 trillion cubic feet reserve was found while looking for oil, so it was accidentally discovered.
“We were actually going to look for crude oil and we found gas, and in that process of accidentally finding gas, we have found up to 206 tcf.
“So, the belief is that if we really aim to look for gas dedicatedly, we will find up to 600 trillion cubic meters of gas.”
With the current global push towards energy transition, Nigeria should depend less on the International oil companies to develop its oil and gas resources, but should rather look inward and build the capacity of indigenous companies. This is the opportunity that the award of marginal field licence provides.
Beyond the present 57 fields, the Federal Government needs to apply some urgency to its exploration campaign in the frontier basins. There should be a deliberate strategy to quickly move in and exploit the reserves through JV, sole risk or other arrangements that will bring in the right partners to develop the fields.
To harness the country’s huge gas reserves, the Federal Government must continue to create friendly business environment to encourage indigenous oil and gas companies. Also new funding models need to be developed to provide easy access to credit facility. With these things put in place, the new operators of marginal field will build capacity to drive the country’s oil and gas industry in no distant time.

indigenous oil and gas companies are now contributing as much as 33 percent to the country’s crude oil reserves and about 30 percent to its gas reserves.

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