CALGARY, ALBERTA July 30, 2014 – Oando Energy Resources Inc. (“OER” or the “Company”) (TSX: OER), a company focused on oil and gas exploration and production in Nigeria, today announced the completion of its acquisition of the Nigerian Upstream Oil and Gas Business of ConocoPhillips (NYSE: COP) for a total cash consideration of US$1.5 billion after customary adjustments plus a deferred consideration of US$33 million (the “Transaction”).
The Transaction entails the acquisition of ConocoPhillips’ Nigerian oil and gas businesses consisting of:
a) The Onshore Business
- Phillips Oil Company Nigeria Limited (“POCNL”), which holds a 20% non-operating interest in Oil Mining Leases (“OMLs”) 60, 61, 62, and 63 as well as related infrastructure and facilities in the Nigerian Agip Oil Company Limited (“NAOC”) Joint Venture (“NAOC JV”). The other coventurers are the Nigerian National Petroleum Corporation (“NNPC”) with a 60% interest and NAOC (20% and operator).
b) The Offshore Business
- Conoco Exploration and Production Nigeria Limited (“CEPNL”), which holds a 95% operating interest in OML 131 located 70 km offshore in water depths of 500m to 1,200m.; and
- Phillips Deepwater Exploration Nigeria Limited (“PDENL”), which holds a 20% non-operating interest in Oil Prospecting Licence (“OPL”) 214 located 110 km offshore in water depths of 800m to 1,800m. The other coventurers are ExxonMobil (20% and operator), Chevron (20%), Svenska (20%), Nigerian Petroleum Development Company (15%) and Sasol (5%). In June 2014, the Honorable Minister of Petroleum Resources for Nigeria approved the conversion of OPL 214 to OML 145 for an initial period of 20 years.
Through this Transaction, OER will indirectly own all of the issued share capital of POCNL, CEPNL and PDENL. The effective date of the transaction is January 1, 2012.
In connection with this Transaction, OER retained The Petroleum and Renewable Energy Company Limited (“Petrenel”) as Independent Reserves Evaluator to report on the reserves and resources of the newly acquired assets, OMLs 60, 61, 62 and 63 (together, the “Onshore Assets”) and OMLs 131 and OPL 214 (OML 145, after conversion) (together, the “Offshore Assets”).
The Independent Reserves Report has an effective date of December 31, 2013 and has been prepared in accordance with National Instrument 51-101 standards and the guidelines set out in the Canadian Oil and Gas Evaluation Handbook.
All figures quoted below are gross to OER (i.e. before deduction of royalty and tax) unless otherwise stated. All reserves quoted below have an effective date of December 31, 2013.
HIGHLIGHTS
OER believes that the Transaction represents a significant opportunity for OER to create scale and significant value for its shareholders, adding:
- The total reserves and resources associated with this Transaction are; Proved plus Probable Reserves of 211.6 million barrels oil equivalent (“MMboe”); Best Estimate Contingent Resources of 498.6 MMboe; Unrisked Best Prospective Resources of 656.9 MMboe.
- A 20% working interest in the NAOC JV, which includes forty discovered oil and gas fields, of which twenty-four are currently producing, approximately forty identified prospects and leads, twelve production stations, approximately 1,490 km of pipelines, three gas processing plants, the Brass River Oil Terminal, the Kwale-Okpai 480 MW combined cycle gas-fired power plant (“Kwale-Okpai IPP”), and associated infrastructure.
- OER’s sales production from the onshore assets averaged 36,494 barrels of oil equivalent per day (“boe/d”) in 2013 and 39,266 boe/d in H1 2014. The Onshore Assets contain 211.6 MMboe of Proved plus Probable Reserves, 217.0 MMboe of Best Estimate Contingent Resources and 333.6 MMboe of Unrisked Best Prospective Resources, gross to OER.
- The Offshore Assets include a significant share of six separate discovered fields and eight separate prospects and contain a total of 281.6 MMboe of Best Estimate Contingent Resources and 323.3 MMboe of Unrisked Best Prospective Resources, gross to OER.
- Upon completion of the Transaction, OER will be positioned as one of the leading E&P players in the Nigerian Oil & Gas sector, as measured by end-2013 Proved plus Probable Reserves of 230.6 MMboe, Best Estimate Contingent Resources of 536.8 MMboe, Unrisked Best Prospective Resources of 2,051.8 MMboe and H1, 2014 production of 44,512 boe/d, all gross to OER.
- The Transaction was financed with an approximate 50/50 debt-equity ratio. Half of the deferred consideration of US$33 million is due six months after closing with the balance due 12 months after closing.
- The Transaction is immediately cash generative and will contribute significantly to the cashflows of the Company.
“This transaction represents a transformational leap forward for our Company and is in keeping with our overall strategy to grow our portfolio of Nigerian-based assets by focusing on those opportunities that deliver high quality growth in reserves and production,” said Pade Durotoye, CEO, OER. “Our management team is familiar with these assets and possess the managerial experience and technical expertise necessary to unlock their value for our shareholders.”
Also commenting, Mr. Wale Tinubu, Chairman, OER said “we believe in the significant potential that the Nigerian oil and gas industry holds and are privileged to play a pivotal role in its consolidation, growth and development. We will continue to seek strategic opportunities that provide a platform for enhanced growth and value creation for our stakeholders”.
ANALYST CONFERENCE CALL
OER will be hosting a conference call to discuss the Transaction on Friday, August 1, 2014 at 10:00 a.m. Eastern Standard Time. To access the conference call, please dial 1-855-481-5362. If dialing internationally (outside of North America) the conference call can be accessed by calling any of the following numbers:
Participants must request the Oando Energy Resources Acquisition Conference Call.
A replay of the conference call will be available through August 6, 2014. To access the replay, dial 1-855-481-5363 (North America) and enter playback code 32145#.
THE TRANSACTION
Large oil and gas asset base with substantial production and resources
The Onshore Assets are currently producing substantial quantities of oil and gas. OER’s sales production from the onshore assets averaged 36,494 boe/d in 2013 and 39,266 boe/d in H1 2014.
Higher oil and gas recovery factors are expected to be achieved with a focused and committed development program. OER believes there are many opportunities to further develop the existing fields and increase production.
OER’s Independent Reserves and Resources Evaluation
Petrenel has assigned estimates of Proved plus Probable Reserves of 211.6 MMboe, Best Estimate Contingent Resources of 217.0 MMboe (OER gross share) to the Onshore Assets. These Contingent Resources have not been classified as Reserves as either (i) oil and gas production associated with these Contingent Resources is not likely to start within five years, (ii) definition of development activities will require more technical work; (iii) gas will be produced and sold after expiration of gas sales contracts, or (iv) oil and gas will be produced after expiration of license.
For the Offshore assets Petrenel has assigned Best Estimate Contingent Resources of 281.6 MMboe, gross to OER. These Contingent Resources have not been classified as Reserves due to the following reasons: (i) lack of firm development plans, (ii) undemonstrated commerciality for any development plan, (iii) undemonstrated commerciality of gas development in Niger Delta deep-water, (iv) pending approval of development plans by the Nigerian government (v) significant portion of oil and gas being produced after license expiry.
It is expected that Contingent Resources will be progressively transferred to Reserves as development activity is matured and the licenses and gas contracts are extended. Significant positive factors associated with the estimates include (i) high probability that the license and gas contracts will get extended at current terms, (ii) further detailed technical studies are likely to identify additional resources, (iii) developing commercial plans for exploitation of oil and gas for Offshore assets and (iii) reducing bunkering in Onshore assets with likely result of upward revision in oil sales. Significant negative factors associated with the estimates include (i) uncertainty over historical field production, technical recovery factors and new well productivity, (ii) logistical and security difficulties, which may delay development, and (iii) increased development and operating costs, which may reduce the economically recoverable volume.
Significant exploitation and exploration upside
OER believes that there is significant upside potential from an active exploitation and exploration program on the Onshore and Offshore assets, with a multi-year inventory of newly available oil and gas drill-ready opportunities, including an opportunity to supply additional gas to potential off takers and other gas supply opportunities in the growing domestic market.
Petrenel has assigned a total Unrisked Best Prospective Resources of 656.9 MMboe (gross to OER), of which 333.6 MMboe is assigned to the Onshore Assets and 323.3 MMboe to the Offshore Assets.
Ideal location with extensive production and infrastructure
The Onshore assets contained within OMLs 60 to 63 are located favorably, with a well-developed network of facilities, transportation and logistics infrastructure as well as localized processing facilities, including an oil processing centre and three gas processing facilities, which can process up to 125,000 barrels of oil per day (“bbls/d”) of oil and over 1 billion cubic feet per day (“Bcf/d”) of natural gas.
Other facilities and infrastructure include 12 production stations and about 1,490 km of oil, NGL and natural gas pipelines, the Brass River Oil Terminal, which has a storage capacity of 3.6 millions of barrels of oil (“MMbbls”), and the 480 Megawatt Kwale-Okpai Independent Power Plant which accounts for approximately 15% of Nigeria’s current available national power generation capacity.
Nigeria has 37.1 billion barrels of proved reserves, (Source: BP Statistical Review of World Energy 2014), a large proportion of which is located in the Niger Delta Region. Within this region, there are a large number of discovered but undeveloped fields with significant upside potential. OER believes that the centrally located Brass River Terminal, Obiafu-Obrikom (“Ob-Ob”) gas plant, and associated pipeline network offers a significant opportunity to capture additional third party production, transportation and processing business.
OER believes that this Transaction will provide OER with a platform for future growth in the region.
High quality crude oil production that trades at a premium to Brent Crude Oil
The crude oil produced from these onshore fields is light and sweet with API gravities ranging from 29 to 47 degrees and low sulfur contents of 0.05% to 0.3% and trades at a premium to Brent crude.
Highly profitable and strong historical cash flow
The NAOC JV has yielded high drilling success rates (89% over last 15 years), high production volumes and premium pricing on crude oil and natural gas and NGLs. For the year ended December 31, 2013, the Onshore Assets generated net revenues of US$ 620.9 million, profit after tax of US$132.8 million and cashflow from operations of US$177.9 million prepared in accordance with International Financial Reporting Standards.
BUSINESS INFORMATION
Onshore Assets:
- OMLs 60, 61, 62 and 63 are located in the onshore Niger Delta basin and have a long history of proven production. OER’s share of sales production in 2013 was 36,494 boe/d (10,579 bbls/d of oil and condensate, 139 MMcf/d of sales gas and 2,556 boe/d of NGLs) and in the first half of 2014 it was 39,266 boe/d (10,385 bbls/d of oil and condensate, 161 MMcf/d of sales gas and 2,076 boe/d of NGLs).
- Petrenel’s estimates of Proved plus Probable reserves totaling 211.6 MMboe for the Onshore Assets consisting of 68.0 MMbbls of oil & condensate, 758.8 billion Cubic Feet (Bcf) of sales gas (126.5 MMboe) and 17.2 MMboe of natural-gas-liquids (gross to OER). The Best Estimate Contingent Resources are 217.0 MMboe which consist of 97.4 MMbbls of oil and condensate, 655.0 Bcf of sales gas (109.2 MMboe) and 10.4 MMboe of NGLs (gross to OER).
- The NAOC JV supplies approximately 20% of the feed gas utilized by the NLNG plant (Source: Nigeria LNG Limited) or approximately 85% of the NAOC JV natural gas sales under a long term contract which is based on a net back pricing formula. The remainder of the gas is sold to a Petrochemical producer and an independent Power Producer under long term contracts. In addition, some of the gas is utilized as fuel gas in the Kwale-Okpai IPP. Finally, NGLs are sold to a petrochemical producer under a long term contract.
- The Kwale-Okpai IPP plant supplies power under a long term contract to the Power Holding Company of Nigeria.
Offshore Assets:
The Offshore Assets add 281.6 MMboe of 2C Contingent Resources and 323.3 MMboe of Unrisked Prospective Resources to the OER portfolio.
- OML 131 is a large deep water offshore block located in a prolific area about 70km south of the Niger Delta coastline and covering 1,204km2 at water depths ranging between 500 and 1,200 meters. OML 131 has two oil and gas discoveries, including the Chota field, which was discovered in 1998. The Nigerian Department of Petroleum Resources (DPR) has approved the unitization of the Chota field in OML 131 with the Bolia field in OML 135 and Shell has been appointed the operator of the unitized area
The Best Estimate Contingent Resources are estimated to be 101.2 MMbbls of oil and 592.5 Bcf of gas (98.7 MMboe) gross to OER.
- OPL 214 is a large deepwater offshore license covering 2,586km2 in the prolific central part of the offshore Niger Delta. The area is approximately 110km from the coastline at water depths ranging between 800 and 1,800 meters. OPL 214 is located close to large discoveries (Bonga, Nsiko, and Agbami). In June 2014, the Honorable Minister of Petroleum Resources for Nigeria approved the conversion of OPL 214 into OML 145 for an initial period of 20 years. OML 145, after conversion from OPL 214, will hold four oil and gas discoveries including the Uge field, which was discovered in 2005.
The Best Estimate Contingent Resources are estimated to be 52.8 MMbbls of oil and 173.1 Bcf of gas (28.9 MMboe) gross to OER.
About Oando Energy Resources Inc. (OER)
OER currently has a broad suite of producing, development and exploration assets in the Gulf of Guinea (predominantly in Nigeria). With the completion of this transaction, OER’s sales production was 41,071 boe/d in 2013 and 44,512 boe/d in the first half of 2014.
With the completion of this transaction, reserves and resources attributable to OER as of as of December 31, 2013 include Proved plus Probable reserves of 230.6 MMboe and Best Estimate Contingent Resources of 536.8 MMboe
OER has been specifically structured to take advantage of current opportunities for indigenous companies in Nigeria, which currently has the largest population in Africa, and one of the largest oil and gas resources in Africa.
Forward Looking Statements:
This news release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “objective”, “ongoing”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends” and similar expressions are intended to identify forward-looking information or statements. In particular, this news release contains forward-looking statements relating to intended acquisitions.
Although the Company believes that the expectations and assumptions on which such forward-looking statements and information are reasonable, undue reliance should not be placed on the forward-looking statements and information because the Company can give no assurance that such statements and information will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties.
Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: risks related to international operations, the actual results of current exploration and drilling activities, changes in project parameters as plans continue to be refined and the future price of crude oil. Accordingly, readers should not place undue reliance on the forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive.
Additional information on these and other factors that could affect the Company’s financial results are included in reports on file with applicable securities regulatory authorities and may be accessed under the Company’s profile on SEDAR website (www.sedar.com). The forward-looking statements and information contained in this news release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Cautionary Statements
Production information is commonly reported in units of barrel of oil equivalent (“boe” or “BOE”) or in units of natural gas equivalent (“Mcfe”). However, BOEs or Mcfes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 barrel, or an Mcfe conversion ratio of 1 barrel:6 Mcf, is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
There is no certainty that it will be commercially viable to produce any portion of the contingent resources.
There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
Defined Terms
“Reserves” are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by development and production status.
“Proved Reserves” are those quantities of petroleum, which by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods and government regulations.
“Probable Reserves” are those additional Reserves which analysis of geosciences and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves.
“Contingent Resources” are those quantities of petroleum that are estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not yet considered mature enough for commercial development because of one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. Contingent Resources are further categorized into low case (1C), best case (2C) and high case (3C) according to the level of certainty associated with the estimates and may be sub-classified based on economic viability.
“Prospective Resources” are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity.
“Best Estimate” is considered to be the best estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be a 50 percent probability that the quantities recovered will equal or exceed the best estimate.
