THIS DOCUMENT IS IMPORTANT AND REQUIRES YOUR IMMEDIATE ATTENTION. If you are in any doubt as to the action you should take, you are recommended to seek your own personal financial advice as soon as possible from your stockbroker, bank, solicitor, accountant, fund manager or other appropriate independent financial adviser authorised under the Financial Services and Markets Act 2000 if you are in the United Kingdom or, if not, from another appropriately authorised independent financial adviser.
If you have sold or otherwise transferred all of your Ordinary Shares or all of your Exchangeable Shares, you should send this document and the accompanying documents as soon as possible to the purchaser or transferee or to the stockbroker, bank or other agent through whom the sale or transfer was effected, for delivery to the purchaser or the transferee. If you sell or have sold part only of your holding of Ordinary Shares or Exchangeable Shares, please consult the stockbroker, bank or other agent though whom the sale or transfer was effected.
J.P. Morgan Cazenove Limited (“J.P. Morgan Cazenove”) has been appointed as Sponsor and Financial Adviser to the Company. J.P. Morgan Cazenove is authorised and regulated in the United Kingdom by the Financial Services Authority. J.P. Morgan Cazenove is acting exclusively for the Company and no-one else in connection with the Disposal and will not regard any other person (whether or not a recipient of this document) as a client in relation to the Disposal and will not be responsible to anyone other than the Company for providing the protections afforded to its clients nor for giving advice in relation to the Disposal or any transaction or arrangement referred to in this document.
Apart from the liabilities and responsibilities, if any, which may be imposed on J.P. Morgan Cazenove by the FSMA or the regulatory regime established thereunder, J.P. Morgan Cazenove accepts no responsibility whatsoever for the contents of this document or for any other statement made or purported to be made by it or on its behalf in connection with the Company or the Disposal.
You should read the whole of this document and, in particular, the risk factors set out in Part II of this document.
HERITAGE OIL PLC (Incorporated in Jersey under the Companies (Jersey) Law 1991, as amended, with registered number 99922)
Proposed Disposal of the Entire Interest in Block 1 and Block 3A in Uganda
and
Notice of General Meeting
Your attention is drawn to the Letter from the Chairman of Heritage Oil Plc which is set out in Part I of this document and which recommends you vote in favour of Resolutions to be proposed at the General Meeting of the Company referred to below.
A notice convening a General Meeting of the Company to be held at the offices of Mourant du Feu & Jeune, 22 Grenville Street, St Helier, JE4 8PX, Jersey, Channel Islands at 3:00 p.m. on 25 January 2010, is set out at the end of this document. The enclosed form of proxy for use at the General Meeting should be completed and returned to Computershare Investor Services (Jersey) Limited at Ordnance House, 31 Pier Road, St Helier, JE4 8PW, Jersey, Channel Islands as soon as possible and to be valid must arrive not less than 48 hours before the time fixed for the General Meeting. The time by which a person must be entered on the register of members in order to have the right to vote at the meetings is 6:00 p.m. on 23 January 2010. Changes to entries on the register of members after that time will be disregarded in determining the right of any person to attend and vote at the General Meeting. Completion and return of a form of proxy will not preclude holders of Ordinary Shares, Exchangeable Shares or the holder of the Special Voting Share from attending and voting in person at the General Meeting should they so wish in respect of any Ordinary Shares or, in relation to the Special Voting Share, any votes attaching to the Special Voting Share, for which no proxy has been appointed. A summary of the action to be taken by the holders of the Ordinary Shares and Exchangeable Shares is set out in Section 11 of Part I of this document and in the accompanying notice of the General Meeting.
This document is a circular relating to the Disposal which has been prepared in accordance with the Listing Rules.
Dated: 21 December 2009 TABLE OF CONTENTS
EXPECTED TIMETABLE OF PRINCIPAL EVENTS ...... ii DIRECTORS, CORPORATE SECRETARY AND ADVISERS ...... iii FORWARD-LOOKING STATEMENTS AND OTHER INFORMATION ...... v PART I—LETTER FROM THE CHAIRMAN OF HERITAGE OIL PLC ...... 1 PART II—RISK FACTORS ...... 14 PART III—FINANCIAL INFORMATION ON THE DISPOSED ASSETS ...... 31 PART IV—PRO FORMA FINANCIAL INFORMATION ON THE CONTINUING GROUP ...... 32 PART V—ADDITIONAL INFORMATION ...... 36 PART VI—TECHNICAL REPORT—HERITAGE GROUP ...... 48 PART VII—DEFINITIONS ...... 156 PART VIII—GLOSSARY ...... 161 NOTICE OF GENERAL MEETING ...... 164
i EXPECTED TIMETABLE OF PRINCIPAL EVENTS
Latest time and date for receipt of forms of proxy for use at the General Meeting ...... 3:00 p.m. on 23 January 2010 General Meeting ...... 3:00 p.m. on 25 January 2010 Expected date of Completion of the Disposal ...... During first quarter of 2010
The expected date of Completion is during the first quarter of 2010. The timing of Completion is, however, dependent upon, among other things, the passing of Resolution 1 at the General Meeting, the Government of Uganda’s consent to the Disposal and the waiver of the Pre-Emption Right.
All times are London times unless specifically stated otherwise. Each of the times and dates in the above timetable are subject to change without further notice. If any of the above times and/or dates change, the revised times and/or dates will be notified to Shareholders by announcement through the Regulatory Information Service of the London Stock Exchange.
ii DIRECTORS, CORPORATE SECRETARY AND ADVISERS
Directors Michael Hibberd (Chairman and Non-Executive Director) Anthony Buckingham (Chief Executive Officer) Paul Atherton (Chief Financial Officer) Gregory Turnbull (Non-Executive Director) John McLeod (Non-Executive Director) General Sir Michael Wilkes (Non-Executive Director) Salim Hassan Macki (Non-Executive Director) Company Secretary Woodbourne Secretaries (Jersey) Limited Ordnance House 31 Pier Road St Helier JE4 8PW Jersey Channel Islands Senior Manager Brian Smith (VP Exploration) Registered Office Ordnance House 31 Pier Road St Helier JE4 8PW Jersey Channel Islands Head Office and Directors’ Fourth Floor Business Address Windward House Route de la Liberation St Helier JE2 3BQ Jersey Channel Islands Sponsor and Financial Adviser J.P. Morgan Cazenove Limited 20 Moorgate London EC2R 6DA United Kingdom English Legal Advisers to the Company McCarthy Tétrault Registered Foreign Lawyers & Solicitors 2nd Floor 5 Old Bailey London EC4M 7BA United Kingdom Canadian Legal Advisers to the Company McCarthy Tétrault LLP Suite 3500 421 7th Avenue S.W. Calgary Alberta T2P 4K9 Canada Jersey Legal Advisers to the Company Mourant du Feu & Jeune 22 Grenville Street St Helier JE4 8PX Jersey Channel Islands Heritage’s Auditors and Reporting KPMG Audit Plc Accountants 8 Salisbury Square London EC4Y 8BB United Kingdom Registrars Computershare Investor Services (Jersey) Limited Ordnance House 31 Pier Road St Helier JE4 8PW Jersey Channel Islands
iii Independent Petroleum Engineering RPS Energy Consultants to the Company 309 Reading Road Henley-on-Thames Oxfordshire RG9 1EL United Kingdom Voting Trustee for the Special Voting Share Computershare Trust Company of Canada Suite 600, 530 8th Avenue S.W. Calgary Alberta T2P 3S8 Canada
iv FORWARD-LOOKING STATEMENTS AND OTHER INFORMATION
This document includes statements that are, or may be deemed to be, “forward-looking statements”. Such statements include, but are not limited to, statements with regard to the intentions, beliefs or current expectations of the Directors or the Heritage Group concerning, among other things, the outcome of the Disposal, future production and grades, projections for sales growth, estimated revenues, reserves and resources, targets for cost savings, the construction cost of new projects, projected capital expenditures, the timing of new projects, future cash flow and debt levels, the amount, declaration and payment of any dividend, the outlook for the prices of hydrocarbons, the outlook for economic recovery and trends in the trading environment and capacity of the Heritage Group and the Continuing Group and the industries in which they operate. These forward-looking statements can be (but are not necessarily) identified by the use of words such as “believe”, “anticipate”, “expect”, “estimate”, “intend”, “aim”, “plan”, “predict”, “continue”, “assume”, “positioned”, “may”, “envisage”, “will”, “should”, “shall”, “risk”, “would”, “could”, “goal”, “target” or, in each case, their negative or other variations or comparable expressions that are predictions of or indicate future events and future trends. These forward-looking statements include all matters that are not historical facts.
Shareholders should not place undue reliance on forward-looking statements because, by their nature, they involve known and unknown risks, uncertainties and other factors and relate to events and depend on circumstances that may or may not occur in the future that are in many cases beyond the control of the Heritage Group or, following Completion, the Continuing Group. The Company cautions Shareholders that forward- looking statements are not guarantees of future performance and that the actual results and developments of operations, prospects, financial condition and liquidity of the Heritage Group and/or the Continuing Group, and the development of the industry in which they operate, may differ materially from those made in or suggested by the forward-looking statements contained in this document. Further, actual developments in relation to the Disposal may differ materially from those contemplated by forward-looking statements depending on certain factors which include, but are not limited to, the risk that the Heritage Group may not realise the anticipated benefits from the Disposal.
In addition, even if the results of the operations, financial conditions and liquidity of the Heritage Group and the Continuing Group (as the case may be), and the development of the industries in which they operate, are consistent with the forward-looking statements contained in this document, those results or developments may not be indicative of results or developments in subsequent periods. Important factors that could cause these differences include, but are not limited to: general economic and business conditions; commodity price volatility; industry trends; competition; the availability of debt and other financing on acceptable terms; changes in government and other regulation, including in relation to the environment, health and safety and taxation, labour relations and work stoppages; changes in political and economic stability; currency fluctuations including £/US$ and RR/US$ exchange rates; the Heritage Group’s and the Continuing Group’s ability to integrate new businesses and recover their reserves or develop new reserves and changes in business strategy or development plans and other risks, including those described in Part II of this document.
The cautionary statements set forth above should be considered in connection with any subsequent written or oral forward-looking statements that the Company, or persons acting on its behalf, may issue. Factors that may cause the actual results of the Heritage Group and/or the Continuing Group to differ materially from those expressed or implied by the forward-looking statements in this document include but are not limited to the risks described in Part II of this document.
These forward-looking statements reflect the Directors’ judgment at the date of this document and are not intended to give any assurances as to future results. Other than in accordance with their legal or regulatory obligations (including the Listing Rules and the Disclosure and Transparency Rules), neither the Directors, the Heritage Group nor J.P. Morgan Cazenove undertakes any obligation and expressly disclaims any intention or obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
None of the cautionary statements above should be taken as qualifying the statement as to the sufficiency of working capital set out in Section 12 of Part I of this document.
v Presentation of Financial and Statistical Information
Presentation of Financial Information
In this document, references to “financial information” are to the information which specifically pertains to the Disposed Assets which has been extracted without material adjustment from the consolidation schedules underlying the audited consolidated accounts of the Heritage Group for the years ended 31 December 2006, 31 December 2007 and 31 December 2008 and the unaudited consolidated financial statements for the six month period ended 30 June 2009.
Unless otherwise indicated, financial information for the Disposed Assets in this document has been prepared in accordance with Adopted IFRS and is presented in US dollars.
Pro forma financial information
In this document, references to “pro forma” financial information in relation to the Continuing Group are to the information which has been extracted without material adjustment from the audited consolidated financial statements of the Heritage Group for the years ended 31 December 2006, 31 December 2007 and 31 December 2008 and the unaudited consolidated financial statements for the six month period ended 30 June 2009.
The unaudited pro forma financial information is provided for illustrative purposes only. Due to its nature, the pro forma financial information addresses a hypothetical situation and, therefore, does not represent the Continuing Group’s actual financial position or results.
Currencies
All references in this document to “Pounds Sterling”, “Pounds”, “£”, “p” or “pence” are to the lawful currency of the United Kingdom, unless otherwise specified. All references in this document to “$”, “Dollar(s)”, “dollar(s)”, “U.S.$”, “U.S. cent(s)”, “US$” and “US cent(s)” are to the lawful currency of the United States, unless otherwise specified. All references in this document to “Canadian dollar(s)”, “Cdn$”, “C$” or “Canadian cent(s)” are to the lawful currency of Canada, unless otherwise specified. All references in this document to “RR” or Russian Rouble(s)” are to the lawful currency of Russia, unless otherwise specified. All references in this document to “Chf” or “Swiss Franc(s)” are to the lawful currency of Switzerland, unless otherwise specified.
Percentages
Percentages in tables in this document have been rounded and, accordingly, may not add up to 100 per cent. Certain financial, statistical and operating data have been rounded. As a result of this rounding, the totals of data presented in this document may vary slightly from the actual arithmetic totals of such data.
Production Figures
All references in this document to “production” are to such stated production figures that are net to the Heritage Group unless specified otherwise.
Presentation of Reserves and Resources
All references to “reserves” and “resources” are to proved, probable and possible in the case of reserves and contingent and prospective in the case of resources.
Estimates of reserves, resources and associated net present values are forward-looking statements based on judgments regarding future events that may be inaccurate. The accuracy of reserves estimates and associated economic analysis is, in part, a function of the quality and quantity of available data and of engineering and geological interpretation and judgment. It should be noted that prospective and contingent resources relate to undiscovered and/or undeveloped accumulations and accordingly by their nature are highly speculative. There is a possibility that prospects and leads will not result in the discovery of economically recoverable resources in which case they would not be commercially developed. This document should be accepted with the understanding that reserves, resources and financial performance subsequent to the date of the estimates may necessitate revision. These revisions may be material. Unless otherwise stated, all information about the Heritage Group’s oil reserves and resources, forward-looking production estimates and other geological information has been extracted without material adjustment from the RPS Report.
vi Reserves are disclosed on two bases: the Heritage Group’s “net entitlement reserves” and, for information only, the Heritage Group’s “net working interest reserves”. Net entitlement reserves are reserves attributable to Heritage Group after deduction of any applicable State royalties, entitlement to profit oil or other interests. In the case of properties within PSCs, the Heritage Group’s net entitlement reserves are calculated in accordance with the terms of the PSC on the basis of forecast price and cost assumptions as evaluated in reports prepared by RPS. Net working interest reserves are reserves attributable to the Heritage Group based on its working interest before any deduction of any applicable State royalties, entitlement to profit oil or other interests.
Estimates of the net present value of the prospective resources are based on future production and revenue analyses. The process of estimating values for prospective resources is much more complex than for reserves because of the wide range of likely outcomes that could occur following the drilling of an exploration well, especially where multiple horizons may be prospective or where economics are tied to revenues from existing reserves entities. In addition, the information available to prepare revenue forecasts for the exploration prospects such as drilling costs, timing of exploration and development drilling and facility requirements is more limited as at the date of this document so all net present values should be considered preliminary. Information in respect of gross and net acres, well-counts and production are as at 30 June 2009, unless indicated otherwise.
RPS has evaluated (on the basis set out below) the Heritage Group’s interest in reserves and resources of crude oil and gas in the Heritage Group’s properties (which includes the Disposed Assets). All estimates of present value are stated prior to provision for indirect costs and calculated after all local country income taxes but prior to the deduction of income taxes in the U.K., Jersey, Canada or elsewhere, if applicable.
The Company’s most recent reserves and resources disclosure, stated as of 30 June 2009, prepared in accordance with the PRMS has been reproduced in its entirety in Part VI of this document and is defined, for the purposes of this document, as the “RPS Report”. The RPS Report was commissioned by the Company in respect of a previously announced, but terminated, transaction and has been amended specifically for the purposes of this document.
The RPS Report is a statement of the estimated oil and gas reserves and resources attributed to the Company as at 30 June 2009. This estimate is based on technical information supplied by the Company to RPS. The technical information supplied by the Company to RPS was not independently verified by RPS and is the responsibility of the management of the Company. In accordance with usual standard industry practice, all technical information that was obtained from the Company or from public sources was accepted, without further investigation. It is RPS’s opinion that the technical information received from the Company was reasonable, based on similar evaluations prepared by RPS.
RPS used the technical information to produce the reserves and resources estimates which formed the basis of the RPS Report. The reserves estimates comprise the proved, probable and possible reserves and related estimated future net present values which are based on the technical information, and continue to be the responsibility of the Company. The reserves and resources were estimated by RPS in accordance with standards set out in the PRMS.
Having carried out the evaluation on the basis set out above, RPS has provided independent reserves and resources estimates which have been determined and presented in accordance with the PRMS.
National Instrument 51-101 (“NI 51-101”) of the Canadian Securities Administrators imposes oil and gas disclosure standards for public companies in Canada engaged in oil and gas activities. The Company has obtained an exemption from Canadian securities regulatory authorities to permit them to provide disclosure in accordance with the relevant legal requirements for public companies in the U.K..
This facilitates comparability of oil and gas disclosure with that provided by the U.K. and other international issuers, given that the Company is active in the U.K. capital markets.
Accordingly, the reserves and resources data and other oil and gas information included or incorporated by reference in this document is disclosed in accordance with U.K. disclosure requirements and practices. Such information, as well as the information that the Company discloses in the future in reliance on the exemption, may differ from the corresponding information prepared in accordance with NI 51-101 standards.
vii IMPORTANT INFORMATION
Unless the context otherwise requires, references in this document to the “Continuing Group” are to Heritage and its subsidiaries and subsidiary undertakings as constituted immediately following Completion and therefore such references include the Heritage Group as reduced by the Disposal. Completion of the Disposal is subject to a number of conditions which are described in detail in Section 4 of Part I of this document.
All times referred to in this document are, unless otherwise stated, references to London time.
Reference to Defined Terms and Incorporation of Terms
Certain terms used in this document, including capitalised terms and certain technical and other terms, are explained in Part VII—“Definitions” and Part VIII—“Glossary” of this document. References to the singular include the plural and vice versa.
Websites
The Company’s website is www.heritageoilplc.com. Without limitation, the information on this website or any website mentioned in this document or any website directly or indirectly linked to this website has not been verified and is not incorporated by reference into this document and investors should not rely on it.
viii PART I—LETTER FROM THE CHAIRMAN OF HERITAGE OIL PLC
(Incorporated in Jersey with registered number 99922)
Directors Registered Office: Michael Hibberd, Chairman and Non-Executive Director Ordnance House 31 Pier Road Anthony Buckingham, Chief Executive Officer St. Helier, JE4 8PW Paul Atherton, Chief Financial Officer Jersey Gregory Turnbull, Non-Executive Director Channel Islands John McLeod, Non-Executive Director General Sir Michael Wilkes, Non-Executive Director Salim Hassan Macki, Non-Executive Director
21 December 2009
To the holders of Ordinary Shares and Exchangeable Shares
Dear Shareholders,
PROPOSED DISPOSAL OF UGANDAN ASSETS
1. INTRODUCTION
On 23 November 2009, the Company announced that a wholly-owned subsidiary had conditionally agreed to dispose of its entire interest in Block 1 and Block 3A in Uganda to Eni. The disposal includes the operatorship of such Blocks together with, at the option of Eni, the whole of the issued share capital of HOGL(U). Aggregate consideration of up to $1.5 billion will be realised on the disposal, with consideration comprising cash of $1.35 billion and additional contingent, deferred consideration of either $150 million in cash or an interest in a mutually agreed producing field independently valued at a similar amount.
The Disposal constitutes a Class 1 transaction under the Listing Rules and, therefore, will require the approval of the Shareholders at the General Meeting, notice of which is set out at the end of this document.
The purpose of this document is to (i) explain the background to and reasons for the Disposal, (ii) provide information about the Disposed Assets, (iii) explain why the Directors unanimously consider the Disposal to be in the best interests of the Company and the Shareholders as a whole, (iv) explain why the Directors believe it is in the best interests of the Company and the Shareholders as a whole to allow the Company to have the ability to make market purchases of Ordinary Shares, and (v) recommend that you vote in favour of the Resolutions to be proposed at the General Meeting.
In connection with Resolution 1 and as described below in Section 5 of this Part I, the Board, based on legal advice, believes that Tullow is entitled to exercise a right of pre-emption in respect of the Disposal. In the event that Tullow validly exercises such a pre-emption right in accordance with the procedure prescribed below in Section 5 of this Part I, a disposal agreement would be entered into between Heritage and Tullow (or a wholly- owned affiliate of Tullow) on the same terms and conditions as the Disposal Agreement.
2. BACKGROUND TO, AND REASONS FOR, THE DISPOSAL
The Heritage Group’s strategy, as stated at the time of Listing and reiterated since in the Company’s 2008 Annual Report, is to generate growth in shareholder value through the development, production and acquisition of a portfolio of oil and gas interests, employing a number of strategic guidelines in its business activities to achieve this.
The Board has concluded that the proceeds from the Disposal will provide the Continuing Group with the financial flexibility to create greater shareholder value without share issuance dilution. The Continuing Group will be able to access cash holdings to bring existing fields to production in a timely manner, thereby generating
1 cash flow, and to continue to explore and develop the Heritage Group’s significant existing resource potential. Selective acquisitions of producing assets and additional development and exploration areas may also be considered, although, as at the date of this document, the Company is not in active negotiations in relation to the acquisition of any specific targets.
Having completed various development and engineering studies, the Board believes that development of the oil fields in Blocks 1 and 3A will take significant time and will require considerable expertise and financial resources, given the lack of an oil infrastructure in Uganda and the remote location of the licences which are approximately 1,250 kilometres from the East African coast.
The Heritage Group retains an interest in the Albert Basin, through its 39.5 per cent. interests in Blocks 1 and 2 on the DRC side of the Albert Basin. Exploration work will only commence in these licences following receipt of a DRC Presidential Decree, the timing of which is uncertain.
3. INFORMATION ON THE DISPOSED ASSETS
In 1997, the Heritage Group became the first licenced oil and gas company in almost 60 years to actively explore in Uganda after being awarded a licence covering the original Block 3 in the Albert Basin of western Uganda. In 2001, the Heritage Group farmed out 50 per cent. of the licence to Energy Africa, which was subsequently acquired by Tullow. Twenty-seven wells have been drilled in the Albert Basin since the beginning of 2006 with twenty-six finding hydrocarbons and three of the wells testing at over 12,000 bopd.
Blocks 1 and 3A are located in the Albert Basin which straddles the border with the DRC in the western arm of the East African rift valley. Approximately 80 per cent. of Block 3A is covered by the south-eastern part of Lake Albert and the remainder of the Block is in the onshore Semliki flats to the south of the lake.
According to the Block 1 and 3A PSCs in Uganda, the Ugandan Government may elect to enter into a joint venture agreement, at any time, for up to a 15 per cent. participation in the properties and the associated production. The Heritage Group has not received any indication from the Ugandan Government that it intends to make this election.
The Ugandan Government has stated that it wishes to achieve early production as a stepping stone to Uganda’s economic growth and to reduce reliance on imports. There have been some initial discussions with the Ugandan Government about routing alternatives for an export pipeline to run to Mombasa in Kenya.
Results from the Heritage Group’s Uganda drilling have established a contingent gross resource of approximately 700 million bbls in the Block 1 and 3A licences according to the RPS Report. This is above the volume considered necessary for major infrastructure development in the Albert Basin. Options to develop the Albert Basin include using the existing rail infrastructure in Kenya or Tanzania and Eastern Uganda, the building of an export pipeline to the east coast of Africa and local refinery schemes.
2 Map of Blocks 1 and 3A and Surrounding Area
3 Block 3A
The original Block 3 licence was awarded in 1997. After drilling three test wells at the Turaco drill site, which were not considered commercial discoveries, all of the area was relinquished in 2004. Most of the exploration acreage which previously constituted Block 3 was reconfigured and re-licenced in 2004, as Block 3A, for a term of six years. Block 3A is located in the southern portion of the Albert Basin and covers an area of 2,024 square kilometres. The Heritage Group holds a 50 per cent. interest in and is the operator of Block 3A where all three wells drilled since 2006 have been successful and found hydrocarbons. Energy Africa (now owned by Tullow) farmed-in to the licence in August 2001, acquiring a 50 per cent. interest in return for funding a seismic survey and partly funding the costs of a well.
The discovered oil in Block 3A is good quality, light (between 30º and 32º API) and sweet with a low gas-oil ratio and some associated wax. The reservoirs are highly permeable sandstones with an estimated permeability of up to 3,000 milliDarcies. The same three sandstone reservoir intervals were encountered in all of the Kingfisher wells highlighting the continuity and the lateral extent of the reservoirs. All three Kingfisher wells drilled to date have been suspended as future producers. • The Kingfisher-1 well was drilled to a depth of 3,195 metres and tested successfully over four intervals for an overall cumulative flow rate of 13,893 bopd. • The Kingfisher-2 well was drilled to a total measured depth of 3,906 metres (3,197 metres true vertical depth) in 2008. Three reservoir intervals were encountered which had a cumulative test rate of 14,364 bopd, surpassing the rate from the same three intervals encountered in Kingfisher-1A, which flowed at a combined rate of 9,773 bopd, in 2007. • The Kingfisher-3 well, located three kilometres south of Kingfisher-2, commenced drilling in September 2008. This well was drilled to evaluate the south-west portion of the Kingfisher structure and encountered a gross vertical hydrocarbon bearing interval of 123 metres, with net vertical pay of 41 metres, based on evaluation of the wireline log data. In addition to finding oil, the well also confirmed that this part of the field was approximately 100 metres structurally higher than expected, thereby increasing the areal extent of the field. The more extensive oil accumulation and greater structural elevation of the reservoir in the south-west part of the field gives confidence that the discovery is larger than initially estimated. The Kingfisher-3A sidetrack, which was drilled as a development well and completed in February 2009, encountered a gross vertical oil-bearing interval of 90 metres with net vertical oil pay of 22 metres.
550 kilometres of 2D seismic, which was acquired in mid-2007, was interpreted during 2008 and identified a number of additional prospects in Lake Albert including the large Crane prospect. The Front End Engineering and Design study for an offshore drilling programme commenced in 2008 following completion of feasibility and pre-Front End Engineering and Design studies and has recently been completed.
Block 1
The Heritage Group holds a 50 per cent. interest in and is the operator of Block 1, which was awarded in 2004. Block 1 is located at the northern end of Lake Albert, and encompasses an area of 3,659 square kilometres. A successful 2008 drilling campaign discovered the Warthog and Buffalo-Giraffe fields.
A seismic survey comprising approximately 670 kilometres of 2D data was completed on Block 1 in February 2008 which identified many encouraging direct hydrocarbon indicators. A three well exploration programme commenced in September 2008 targeting the Warthog, Buffalo and Giraffe prospects.
All wells drilled in Block 1 are relatively shallow with target depths of between 600 and 920 metres. Downhole pressure testing and sampling and the recovery of oil to surface have confirmed the presence of moveable oil in the Block 1 discoveries. Log interpretation and core analysis has confirmed excellent reservoir quality with porosities of up to 35 per cent.. Testing of the Kasamene and Kigogole discoveries, close by in neighbouring Block 2, gives further confidence as flow rates of between 350 and 3,500 bopd were achieved. All three wells drilled to date in Block 1 have been suspended as future producers. • The Warthog-1 well commenced drilling in September 2008 and encountered 46 metres of net hydrocarbon pay. Wireline logging and formation pressure measurements indicated 31 metres
4 of net oil pay in the principal oil-bearing section, overlain by 15 metres of additional net hydrocarbon pay comprising, most probably, natural gas. In addition to the oil discovered, further potential for oil exists in the overlying reservoir section downdip of the Warthog well location and there is additional potential in the adjacent Warthog North prospect.
• Drilling of the Buffalo-1 well commenced in November 2008 and encountered 43 metres of net hydrocarbon pay with 28 metres of net oil pay.
• In December 2008, the Giraffe-1 well commenced drilling 5.5 kilometres from the Buffalo-1 discovery and encountered a gross oil-bearing interval of 89 metres with 38 metres of net oil pay. Pressure and seismic data indicate that the Giraffe discovery is structurally connected to the Buffalo discovery, creating the Buffalo-Giraffe field covering approximately 48 square kilometres with an oil column of approximately 140 metres. The Buffalo-Giraffe field may extend into the Buffalo-East prospect which would result in one very large structure, covering up to 90 square kilometres.
Expenditure on intangible assets in relation to the Disposed Assets between 2006 and 2009, which have been extracted (without material adjustment), from the underlying accounting records for the Heritage Group relating to the audited consolidated financial statements of the Heritage Group for the years ended 31 December 2006, 31 December 2007 and 31 December 2008 and relating to the unaudited interim financial statements of the Heritage Group for the six month period ended 30 June 2009, may be summarised as follows:
Year ended Six month period 31 December ended
2006 2007 2008 30 June 2009
$$$$
Drilling ...... 11,999,638 8,828,100 45,337,300 8,691,450
Seismic ...... — 13,774,700 928,900 4,689
Other ...... 2,934,416 10,391,111 9,525,604 5,822,036
14,934,054 32,993,911 55,791,804 14,518,175
Risked Recoverable Resources Relating to the Disposed Assets (MMboe)
The following is a summary, which has been extracted (without material adjustment) from the RPS Report, of the RPS estimated net working interest contingent and prospective resources for the Disposed Assets, as of 30 June 2009:
Working Interest Share(1)(5)
Low Best High (P90) (P50) (P10) Mean MMboe MMboe MMboe MMboe
Block 1
Contingent Resources(2) ...... 88 222 444 250
Prospective Resources(3) ...... 0 41 239 90
Consolidated Sub-total(4) ...... 114 282 551 339
Block 3A
Contingent Resources(2) ...... 48 95 170 105
Prospective Resources(3) ...... 0 39 229 99
Consolidated Sub-total(4) ...... 63 170 387 204
Consolidated Total(4) ...... 265 497 895 543
5 (1) In the event of discovery and development, net entitlement resources will be a function of the contract terms and will be less than net working interest resources. The Government of Uganda has the right to back-in for up to 15 per cent. which could, if exercised, reduce the working interest in each of Blocks 1 and 3A to 42.5 per cent.
(2) Stochastic consolidation of Contingent Resources with GPoS of 100 per cent.
(3) Stochastic consolidation of Prospective Resources with GPoS for each prospect
(4) Stochastic consolidation of Contingent Resources and risked Prospective Resources
(5) Block 1 resources are quoted net of 15 per cent. losses for steam generation where applicable
The following is a summary, which has been extracted (without material adjustment) from the RPS Report, of the RPS expected value of the Disposed Assets post-tax, discounted at 10 per cent., as of 30 June 2009:
Net Present Value ($ million in money of the day)
Block 1 Block 3A Blocks 1 and 3A Total Expected Value Expected Value Expected Value (Mean) (Mean) (Mean)
Contingent Resources ...... 662 464 1,126 Prospective Resources ...... 258 227 485
Total PSC ...... 920 691 1,611
The expected value of the Total PSC is the probability weighted mean of the value of all possible outcomes of the Contingent Resources plus the drilling of the Prospective Resources
The expected value of the Contingent Resources represents the probability weighted mean value of the resource volume range
According to the unaudited interim financial statements for the six month period ended 30 June 2009, the gross book value of the Disposed Assets as at 30 June 2009 net of liabilities was $145 million.
4. PRINCIPAL TERMS AND CONDITIONS OF THE DISPOSAL
Introduction
Under the terms of the Disposal Agreement, the Heritage Group has agreed to sell the Disposed Assets to Eni. The consideration for the Disposal is up to $1.5 billion, of which $1.35 billion (subject to adjustments to account for certain payables, receivables and other items) will be payable in cash at Completion and a further conditional, deferred amount of up to $150 million will be paid in cash or by way of the transfer to the Heritage Group of an interest in an oil producing field independently valued at a similar amount, on the satisfaction of certain conditions within two years of Completion (the “Deferred Consideration”).
Conditions Precedent
Completion may not occur unless, among other conditions, each of the following conditions has been satisfied:
• the receipt of consent to the Disposal from the Government of Uganda;
• there having been no occurrence after the date of the Disposal Agreement that would constitute a material adverse effect, as defined in the Disposal Agreement;
• Tullow having waived or declined to exercise its right of pre-emption as described below in Section 5 of this Part I; and
• the approval by Shareholders of Resolution 1.
6 Undertakings
The Heritage Group has agreed, between the date of execution of the Disposal Agreement and Completion, to carry on the operation of the Disposed Assets in all respects in the ordinary and usual course in the manner in which they have been carried on prior to the date of the Disposal Agreement and in accordance with good oil industry practice and the respective licence documents. The Heritage Group has provided Eni with customary warranties in relation to the Disposal and Eni has on the date of the Disposal Agreement agreed to deliver to HOGL a guarantee in support of its obligations under the Disposal Agreement by an entity with a credit rating of at least A+ from Standard & Poor’s Corporation. A guarantee given by Eni S.p.A. has been provided pursuant to this provision.
Payment of Deferred Consideration
The payment of the full amount of the Deferred Consideration is conditional on the relevant authorities within the Ugandan Government granting or agreeing to grant to Eni, within a period of two years from the date of Completion, full exemption or relief from direct and indirect taxation for all upstream, midstream and downstream activities of the Disposed Assets.
The amount of the Deferred Consideration will depend on the scale of the tax incentives negotiated.
There can be no assurance that the Deferred Consideration will become payable and, if it is payable, how much Deferred Consideration will be paid. Whilst Eni is obliged under the Disposal Agreement to use its reasonable efforts to negotiate the granting of the tax incentives as soon as possible, the satisfaction of the conditions to the payment of the Deferred Consideration is not within the control of the Heritage Group.
Should any Deferred Consideration become payable on the grant of the tax incentives, Heritage and Eni will agree whether it should be paid in cash or by the assignment by Eni (or an affiliate of Eni) of an interest in one or more oil producing assets. If Heritage and Eni are unable, within 90 days of Eni notifying Heritage of receipt of the tax incentives, to agree and satisfy the terms and conditions of any such assignment, payment of the Deferred Consideration shall be made in cash by Eni. Any such assignment of an interest in a producing field would be subject to the provisions of the Listing Rules and may require, inter alia, Shareholder approval. If in such circumstances Shareholder approval is not granted, the Deferred Consideration will be paid in cash.
If Eni transfers, or enter into negotiations to transfer, all or any portion of the Disposed Assets within the period of two years from the date of Completion at a time when payment of the Deferred Consideration has not been made, the whole of the Deferred Consideration will immediately become payable on the above terms.
As described below in Section 5 of this Part I, the Board believes that Tullow is entitled to exercise rights of pre-emption in respect of the Disposal. In the event that Tullow validly exercises such pre-emption right in accordance with the procedure prescribed below in Section 5 of this Part I, the Deferred Consideration provisions contained in the disposal agreement entered into with Tullow will be on the same terms and conditions as in the Disposal Agreement. This would include the right of Tullow to offer to the Heritage Group an interest in an oil producing field of sufficient value in satisfaction of the Deferred Consideration, subject to the terms of the Disposal Agreement.
Termination
Each of the Heritage Group and Eni may terminate the Disposal Agreement in the following circumstances: • the conditions precedent to Completion are not satisfied by the other party six months from 18 December 2009 (or such later date as will allow such reasonable additional period as may be required to secure necessary Government consents); or • the obligations on the other party for Completion are not complied with within five business days following the satisfaction (or waiver) of the conditions precedent to Completion.
Eni may terminate the Disposal Agreement if: • the Board or the board of HOGL solicits superior proposals for the Disposed Assets (in which case the payment of a break payment (as described below) is payable);
7 • as a result of a third party exercising its rights over any part of the Disposed Assets and/or any third party does not consent to the Disposal and/or as a result of the nature of the Ugandan Government’s consent to the Disposal, the Heritage Group is only entitled to assign its interest in one or part of one PSC in Uganda;
• there is a breach of a core warranty or there is a material breach of a warranty given on the date of the Disposal Agreement or matters occur between the date of the Disposal Agreement and Completion which would otherwise constitute a breach of the warranties if deemed repeated at Completion and such breaches have a material adverse effect in respect of the Disposed Assets;
• a material adverse effect occurs in respect of the Disposed Assets;
• there is a material breach or non-fulfilment of the material obligations under the Disposal Agreement on the part of the Heritage Group; or
• the General Meeting has not been convened and held and/or the Shareholders have not considered and voted on Resolution 1 by 31 January 2010 unless the Company is prohibited by law from convening such meeting.
The Heritage Group may terminate the Disposal Agreement in order to enter into an agreement to implement a superior proposal for a sale of the Disposed Assets to a third party in certain circumstances, which right shall cease upon the Shareholders passing Resolution 1. In the event that the Heritage Group terminates the Disposal Agreement for this purpose, a break payment (as described below) is payable.
Break Payment
The Heritage Group has agreed to pay Eni a break payment of up to one per cent. of the Company’s market capitalisation on the close of business on 17 December 2009, being the last business day prior to the announcement of the Disposal, (the “Break Payment”) in certain circumstances, including:
• in the event that the General Meeting has not been convened and held and/or the Shareholders have not considered and voted on Resolution 1 by 31 January 2010 (unless the Company is prohibited by law from convening the General Meeting) and Eni elects to terminate the Disposal Agreement;
• in the event that the Board or the board of HOGL (i) fails to recommend the Disposal; and (ii) withdraws, modifies or changes its recommendation of the Disposal in a manner adverse to Eni;
• in the event that the Company terminates the Disposal Agreement in connection with a superior proposal for the Disposed Assets; and
• in the event that the Board or the board of HOGL solicits superior proposals for the Disposed Assets, and Eni terminates the Disposal Agreement.
As described below in Section 5 of this Part I, the Board believes that Tullow is entitled to exercise a right of pre-emption in respect of the Disposal. In the event that Tullow exercises such pre-emption right, the Break Payment shall not be payable to Eni.
5. POTENTIAL EXERCISE OF PARTNER PRE-EXEMPTION RIGHT IN RESPECT OF THE DISPOSED ASSETS
The Heritage Group as 50 per cent. partner and operator and Tullow as 50 per cent. partner are currently operating Block 1 and Block 3A but have never executed a JOA with respect to these Blocks. The Heritage Group and Tullow were in the process of negotiating a JOA to cover Blocks 1 and 3A but, as at the date of this document, such JOA has not been executed. The Heritage Group and Energy Africa (which was acquired by Tullow in 2004) executed a JOA in August 2002 in respect of Block 3 in Uganda (the “Block 3 JOA”) but that JOA has expired. To the extent that the Block 3 JOA is applicable to operations for Block 1 and Block 3A (and the Board believes, based on legal advice, that it is), there is a provision relating to transfers which the Board believes would give rise to a right of pre-emption in favour of Tullow as a result of the Disposal.
8 In the context of the Disposal, the Heritage Group is required by the provisions of the Block 3 JOA to notify Tullow of its intention to dispose of the Disposed Assets and to provide Tullow with a detailed description of the final terms and conditions contained in the Disposal Agreement (the “Disposal Notice”). Upon receipt of such Disposal Notice, Tullow has the right to acquire the Disposed Assets, providing that Tullow agrees to acquire the Disposed Assets on the same terms and conditions as agreed with Eni in the Disposal Agreement and without any additional reservations or conditions (the “Pre-Emption Right”). If Tullow intends to exercise its Pre-Emption Right in the context of the Disposal, Tullow is required to notify the Heritage Group of its intention within thirty days of the delivery of the Disposal Notice (the “Pre-Emption Notice”).
In accordance with the provisions of the Block 3 JOA, the Heritage Group delivered a Disposal Notice to Tullow on the same day that the Disposal Agreement was entered into with Eni, being 18 December 2009. Should Tullow wish to exercise its Pre-Emption Right, it must deliver a Pre-Emption Notice to the Heritage Group no later than 17 January 2010 and such Pre-Emption Notice must state that Tullow will agree to acquire the Disposed Assets on the same terms and conditions as those agreed with Eni in the Disposal Agreement and without additional reservations or conditions. It is a condition of completion of the Disposal with Eni that Tullow waives or declines to exercise the Pre-Emption Right.
6. FINANCIAL EFFECTS OF THE DISPOSAL AND USE OF PROCEEDS
On a pro forma basis, and assuming that Completion had occurred on 30 June 2009, the Continuing Group would have net assets of approximately $1.6 billion, as illustrated by the pro forma financial statement of the Continuing Group set out at Part IV of this document.
The net proceeds from the Disposal of approximately $1.34 billion (excluding Deferred Consideration) will serve to reinforce the Company’s balance sheet after a successful period of value creation and realisation and provide increased financial flexibility to:
• Continue exploration, appraisal and development activities in the remaining seven countries in which the Continuing Group has licences, in particular in Kurdistan which remains a core area of focus and where the Company has recently commenced a multi-well exploration and appraisal drilling programme on the Miran Block.
• Embark on drilling programmes in the Continuing Group’s remaining licences next year with a number of high-impact exploration wells which could continue to generate significant value for Shareholders.
• Participate in opportunities to generate further value for Shareholders, including the acquisition of oil and gas licences in highly prospective geographies and the acquisition of producing assets when opportunities arise. As at the date of this document, the Company is not in active negotiations in relation to the acquisition of any specific targets.
• Potentially return a portion of the Disposal proceeds to Shareholders through a special dividend following Completion, which could be in the range of 75 pence to 100 pence per Ordinary Share and Exchangeable Share. Heritage will consider the appropriate form of any return of value to Shareholders which may comprise, in whole or in part, a buyback of Ordinary Shares. If paid, between approximately $350 million and $465 million of value would be returned to Shareholders. Thereafter, Heritage would expect to still have a cash position of over $1 billion.
• Commence the acquisition of seismic data and/or drilling activity on its licences in Malta, Mali and Pakistan in 2010.
• Fund the Company’s continued working capital requirements and for general corporate purposes.
On 9 December 2009, HOC issued a notice to holders of the issued and outstanding 8 per cent. convertible bonds due 2012 issued by HOC (the “Bonds”) to convene a meeting of such bondholders (the “Bondholders”) to seek their approval to an amendment to the terms and conditions of the Bonds to delete the current restrictions on the level of any share buyback or other distribution which the Company can make. In consideration for removing this restriction, the Company agreed to pay those Bondholders voting at the meeting the sum of $2,000.00 per $100,000.00 of Bonds held. Bondholders were also asked to waive certain adjustment provisions in the Bond
9 terms which would otherwise apply in relation to any dividend which may be made or declared by the Company in certain circumstances, in consideration for which Bondholders would be paid the dividend they would be entitled to receive as if they had converted their Bonds into Ordinary Shares according to the prevailing conversion price as at the record date for any such dividend.
Should Bondholders not pass these resolutions, the Company intends to extend its accounting reference date into 2010 such that the Disposal proceeds can be recognised in the current financial year, which may allow for a potential special dividend to be declared and paid in 2010.
The meeting of the Bondholders is scheduled to occur on 31 December 2009.
7. SUMMARY OF RESERVES AND RESOURCES OF THE CONTINUING GROUP
Given that the RPS Report had already been prepared for all the Heritage Group’s material assets in relation to a terminated transaction, the Directors consider that the RPS Report should be published in its entirety in this document (see Part VI of this document). Statements of the reserves and resources of the Continuing Group have been extracted from the RPS Report and are set out below.
Resources of Continuing Group—Miran, Kurdistan
A summary of RPS estimated net working interest contingent and prospective resources as of 30 June 2009, which has been extracted from the RPS Report without material adjustment, is set out below:
Continuing Group Working Interest Share(1)
Low Best High (P90) (P50) (P10) Mean MMboe MMboe MMboe MMboe Miran Block, Kurdistan Contingent Resources(2) ...... 25 53 92 53 Prospective Resources(3) ...... 87 849 2,248 850
Consolidated Sub-total(4) ...... 128 902 2,306 1,014
(1) In the event of discovery and development, the Continuing Group’s net entitlement resources will be a function of the contract terms and will be less than the net working interest resources. The Kurdistan Regional Government has the right to back-in for up to 25 per cent. which could, if fully exercised, reduce the Continuing Group’s working interest to 56.25 per cent.
(2) Stochastic consolidation of Contingent Resources with GPoS of 100 per cent.
(3) Stochastic consolidation of Prospective Resources with appropriate GPoS for each prospect
(4) Stochastic consolidation of Contingent Resources and risked Prospective Resources
A summary of the RPS expected value of the Continuing Group’s assets in Kurdistan post-tax, discounted at 10 per cent., as of 30 June 2009, which has been extracted from the RPS Report without material adjustment, is set out below:
Net Present Value ($ million in money of the day)
Miran West Miran East Miran Total Expected Value Expected Value Expected Value (Mean) (Mean) (Mean) Contingent Resources ...... 275 0 275 Prospective Resources ...... 3,645 479 4,125
Total PSC ...... 3,920 479 4,400
The expected value of the Total PSC is the probability weighted mean of the value of all possible outcomes of the Contingent Resources plus the drilling of the Prospective Resources
The expected value of the Contingent Resources represents the probability weighted mean value of the resource volume range
10 Reserves of Continuing Group—Zapadno Chumpasskoye, Russia
A summary (which has been extracted from the RPS Report without material adjustment) of the Continuing Group’s net working interest reserves and their net present value, based on forecast prices and costs, discounted at 10 per cent, as certified by RPS as of 30 June 2009, is as follows:
Net Working and Entitlement Net Reserves Present Value
($ million in money of the MMbbls day) Proved ...... 23.4 60 Probable Additional ...... 37.2 238
Total Proved + Probable ...... 60.6 298
Total Proved + Probable + Possible ...... 164.0 935
8. CURRENT TRADING AND PROSPECTS OF THE CONTINUING GROUP
The Continuing Group is well positioned to benefit from the series of exploration, appraisal and development drilling programmes completed during the last 18 months and is now seeking to optimise the development of these programmes. Drilling of an exploration well commenced in the Miran Block in Kurdistan in December 2008. The Miran West-1 discovery well was tested in April 2009 and a second phase of testing was completed in August 2009 with a flow rate of 3,640 bopd recorded from a single upper reservoir interval. The well has been suspended as a future producer. Testing confirmed the high potential well productivity with the data gathered indicating an estimated productive potential of between 8,000 and 10,000 bopd. Drilling of the Miran West-2 appraisal well commenced on 26 November 2009.
Production from the Zapadno Chumpasskoye field in Western Siberia averaged 422 bopd in the third quarter of 2009 and production is expected to continue at this level in the fourth quarter of 2009.
9. RISK FACTORS
As Kurdistan will remain a core area of focus for the Continuing Group, prior to deciding to vote in favour of the Resolutions, Shareholders should consider the following risks associated with operating in that and other regions:
• political, social and economic instability may affect the Heritage Group and, following Completion, the Continuing Group, their respective operations and personnel;
• developing countries or regions are subject to greater risk than developed countries or regions;
• uncertainties of legal systems in jurisdictions or regions in which the Heritage Group and, following the Completion, the Continuing Group operates;
• the Heritage Group and, following Completion, the Continuing Group cannot completely protect itself against title disputes; and
• the Heritage Group and, following Completion, the Continuing Group may face difficulties in marketing or exporting its oil and natural gas.
10. GENERAL MEETING
A notice convening the General Meeting, to be held at 3:00 p.m. on 25 January 2010 at the offices of Mourant du Feu & Jeune, located at 22 Grenville Street, St. Helier, JE4 8PX, Jersey, Channel Islands is set out at the end of this document. The purpose of the General Meeting is to seek Shareholder approval of the Resolutions in connection with the Disposal.
11 Resolution 1 is an ordinary resolution to approve the Disposal on the terms and subject to the conditions of (i) the Disposal Agreement, or in the alternative (ii) a disposal agreement to be entered into with Tullow and/or a wholly-owned affiliate of Tullow on exactly the same terms and conditions as the Disposal Agreement in the event that after the date of this document Tullow delivers to the Heritage Group a valid Pre-Emption Notice, and to authorise the Directors to take all such steps as may be necessary, or desirable, in connection with, and to implement, the Disposal, and to agree to such modifications, variations, revisions, waivers or amendments to the terms and conditions of the Disposal Agreement, or such disposal agreement to be entered into with Tullow and/or wholly-owned affiliate of Tullow (provided such modifications, variations, revisions, waivers or amendments are not of a material nature) and to any documents relating thereto, in either such case as they may in their absolute discretion think fit.
Resolution 2 is a special resolution to authorise the Company to buy back Ordinary Shares in the market and to authorise the Company to hold such Ordinary Shares in treasury. The Company may use this authority in connection with the potential return of a portion of the Disposal proceeds to Shareholders following Completion, as referred to in Section 6 above, and may cancel such Ordinary Shares or hold them in treasury. The maximum number of Ordinary Shares for which the Company is seeking authority to purchase is 28,755,194 (representing approximately 10.00 per cent. of the Company’s Voting Share Capital). The minimum price, exclusive of any expenses, per Ordinary Share for which the Company is seeking authority to purchase is £0.01. The maximum price, exclusive of any expenses, per Ordinary Share for which the Company is seeking authority to purchase is the higher of (i) an amount equal to 5 per cent. above the average of the middle market quotations for Ordinary Shares taken from the London Stock Exchange Daily Official List for the five business days immediately preceding the day on which such shares are contracted to be purchased, and (ii) the higher of the price of the last independent trade and the highest current independent bid on the London Stock Exchange Daily Official List at the time that the purchase is carried out.
The total number of options to subscribe for Ordinary Shares under the Replacement Stock Option Scheme and the LTIP that are outstanding and vested as at 18 December 2009 (being the latest practicable date prior to the publication of this document) is 23,912,010, representing approximately 8.32 per cent. of the Voting Share Capital and approximately 9.24 per cent. of the Ordinary Shares and Exchangeable Shares in issue if the full authority to buy back Ordinary Shares is used.
The full text of the Resolutions is set out in the notice convening the General Meeting at the end of this document.
11. ACTION TO BE TAKEN
You will find enclosed with this document the Form of Proxy for use at the General Meeting or at any adjournment thereof. You are requested to complete and sign the Form of Proxy in accordance with the instructions printed on it and return it as soon as possible to, but in any event so as to be received no later than 3:00 p.m. on 23 January 2010, by Computershare. You may also deliver the Form of Proxy by hand to Computershare during usual business hours. CREST members may also choose to use the CREST electronic proxy appointment service in accordance with the procedures set out in the notice convening the General Meeting at the end of this document.
12. WORKING CAPITAL
The Company is of the opinion that, taking into account the existing cash resources of the Continuing Group and the cash proceeds of the Disposal, the working capital available to the Continuing Group is sufficient for its present requirements, that is for at least the next 12 months from the date of this document.
13. FURTHER INFORMATION AND RISK FACTORS
Your attention is drawn to the further information set out in Parts II to VIII (inclusive) of this document and, in particular, to the Risk Factors at Part II of this document.
12 14. RECOMMENDATIONS AND VOTING INTENTIONS
The Board, which has been so advised by J.P. Morgan Cazenove, considers that the terms of the Disposal are fair and reasonable. In so advising the Board on the Disposal, J.P. Morgan Cazenove has taken into account the Board’s commercial assessment of the Disposal.
The Board believes the Disposal to be in the best interests of the Company and its Shareholders as a whole, and, accordingly, the Board unanimously recommends holders of Ordinary Shares and Exchangeable Shares vote in favour of Resolution 1. Further, the Board believes that it is in the best interests of the Company and the Shareholders as a whole to allow the Company to make market purchases of Ordinary Shares and to allow the Company to hold such Ordinary Shares in treasury, and, accordingly, the Board unanimously recommends holders of Ordinary Shares and Exchangeable Shares vote in favour of Resolution 2. Each of the Directors intend to do so in respect of their own beneficial shareholdings, amounting to, in aggregate, 86,314,162 Ordinary Shares and Exchangeable Shares, representing approximately 30.02 per cent. of the Voting Share Capital as at 18 December 2009, the latest practicable date prior to the publication of this document.
Yours faithfully,
Michael J. Hibberd Chairman
13 PART II—RISK FACTORS
A decision to vote in favour of the Resolutions is subject to a number of risks. Prior to making any decision to vote in favour of the proposed Resolutions, Shareholders should carefully consider all the information contained in this document, including, in particular, the specific risks described below such as risks relating specifically to the Disposal and the Disposed Assets. If any of the adverse events described below actually occur, the business, prospects, financial condition or results of operations of the Heritage Group or, following Completion, the Continuing Group could be materially and adversely affected to the detriment of the Heritage Group and, following Completion, the Continuing Group, and you may lose all or part of your investment. Some of the following factors relate principally to the Heritage Group’s business and, following Completion, the Continuing Group’s business and the sector in which they operate. Other factors relate principally to an investment in the Ordinary Shares or Exchangeable Shares. The risks and uncertainties described below are not intended to be exhaustive and are not the only ones facing the Heritage Group. Additional risks and uncertainties not currently known to the Directors, or that they currently deem immaterial, may also have an adverse effect on the business, financial condition, results of operations and prospects of the Heritage Group and, following Completion, the Continuing Group. If this occurs, the price of the Ordinary Shares or Exchangeable Shares may decline and investors could lose all or part of their investment. Shareholders should consider carefully whether an investment in the Ordinary Shares or Exchangeable Shares is suitable for them in light of the information in this document and their own personal circumstances.
No statement contained in the risks and uncertainties described below should be taken as qualifying the statement as to the sufficiency of working capital set out in Section 12 of Part I of this document.
Risks relating to the Disposal
Inability to realise shareholder cash value if the Disposal does not proceed
The Directors believe that the Disposal is in the best interests of Shareholders as a whole and that the Disposal provides an opportunity to realise an attractive and certain cash value for the Disposed Assets whilst allowing the Continuing Group to focus on the exploration and development of its remaining core assets. If the Disposal does not complete for any reason (including Resolution 1 not being passed or the Ugandan Government’s consent not being received), the Disposed Assets may be retained by the Heritage Group and the Shareholders would be deprived of the opportunity to realise cash value for the Disposed Assets.
Potential disruptive effect on the Heritage Group if the Disposal does not proceed
On the basis that significant management time is currently being occupied in connection with the Disposal, if the Disposal does not proceed, there may be disruption to the Heritage Group’s Disposed Assets or the business or operations of the Heritage Group in general, including its management and employees. This disruption may divert management attention away from the business and operations of the Disposed Assets and may have a temporary negative effect on the performance or results from the Disposed Assets under the Heritage Group’s ownership. In addition, management of the Heritage Group would be required to allocate time to the supervision and development of the Disposed Assets on a continuing basis.
Risks relating to the terms and conditions of the Disposal Agreement and related documentation
The Disposal Agreement contains certain warranties and indemnities, which are customary for a transaction of this nature, in favour of Eni and the warranties and indemnities are subject to certain limitations. The overall cap under the Disposal Agreement on the aggregate liability of the Heritage group is 35 per cent. of the total consideration of the Disposal in connection with most warranty breaches other than any breach of the warranties relating to the title of the Disposed Assets which is unlimited. The aggregate of all warranty claims cannot exceed 100 per cent. of the total consideration actually paid for the Disposed Assets.
The extent to which the Continuing Group may incur liabilities under the Disposal Agreement is uncertain and, if the Continuing Group should incur such liabilities, they may have a material adverse effect on its business, financial condition and results of operations.
14 In addition, the Disposal Agreement contains a provision for the payment of Deferred Consideration for the Disposed Assets which is conditional upon Eni’s designated purchaser of the Disposed Assets being granted certain tax incentives by the Ugandan Government, within two years of Completion. The conditions around the payment of the Deferred Consideration will not be within the control of the Continuing Group, and if such conditions are not satisfied, then the Continuing Group may not be paid any or all of the Deferred Consideration or only a part thereof which may have a material adverse effect on its business, financial condition and results of operations.
Following Completion, the Continuing Group’s assets will be less diversified
Following Completion, the Continuing Group will have oil and gas assets in fewer jurisdictions and its business and financial prospects will have to rely on a less diversified portfolio that will, in the short-term, be less developed than the Disposed Assets. There can be no assurance that the Heritage Group’s or, following Completion, the Continuing Group’s future exploration and development efforts in what will initially be a less diversified portfolio will result in the discovery and development of additional commercial accumulations of oil and gas. As a result of having a less diversified portfolio, such efforts may be unsuccessful which may result in the Heritage Group’s or the Continuing Group’s reserves not increasing or declining, which could have a material adverse effect on the Heritage Group’s or, following Completion, the Continuing Group’s business, financial condition, prospects and results of operations.
Risks relating to the operations of the Heritage Group and, following Completion, the Continuing Group and risks inherent in the countries or regions within which such operations are carried out
Political, social and economic instability may affect the Heritage Group and, following Completion, the Continuing Group, their respective operations and personnel
Certain countries or regions where the Heritage Group has interests have a publicised history of political and social instability which have culminated and may continue to culminate in security problems which may affect the Heritage Group and, following Completion, the Continuing Group, their respective operations and personnel. Consequently, the Heritage Group’s business, financial condition, results of operations and prospects may be materially and adversely affected in varying degrees by political and economic instability, economic or other sanctions imposed by other countries or regions, terrorism, civil wars, border disputes, guerrilla activities, military repression, civil disorder, crime, instability of the workforce, extreme fluctuations in currency exchange rates and high inflation.
Kurdistan and Iraq
In October 2007, the Heritage Group, through a wholly-owned subsidiary, entered into a PSC with the Kurdistan Regional Government (the “KRG”) to explore for oil and gas in Kurdistan. Kurdistan is a federal region of Iraq which is located in northern Iraq. Iraq is currently experiencing periods of civil unrest and political and economic instability. In addition, in late 2007 the Government of Turkey authorised Turkey’s military to make incursions into Iraq in order to carry out cross-border assaults against the PKK (the Kurdistan Workers Party). At that time the Turkish military amassed a significant number of troops along the Iraqi border, and carried out air strikes and conducted limited shelling of targets in northern Iraq. Since then there has been steady violence between the Turkish military and the PKK, and, although the PKK declared a unilateral truce on 14 April 2009, recent sporadic fighting has resulted in further loss of life.
A planned referendum in Kurdistan, relating to the proposed Kurdistan constitution and control of certain disputed border areas, has been seen by some as contributing to regional instability. Furthermore, the Iraqi central Government does not support the Kurdistan parliament’s claim to the disputed territories in the Kirkuk, Diyala and Ninewa provinces, as stated in the proposed constitution and this has created tension between Iraq and Kurdistan.
No assurances can be given that the Heritage Group or the Continuing Group will be able to maintain or obtain effective security of any of its assets or personnel in Iraq where, at times, terrorism and insurgent activities have disrupted various business activities during the past and may affect the Heritage Group’s or the Continuing Group’s operations or plans in the future. Currently military forces from the United States of America and other allied countries are operating within Iraq to assist the new government to maintain peace and national security
15 and law and order at the national level. In June 2009, the U.S. military formally handed over security duties in Iraqi towns and cities to Iraqi army forces. This handover has increased speculation about potential destabilisation in the security of Iraq, at least in the short term. Despite this official withdrawal, many U.S. troops will remain in the cities in Iraq, embedded with Iraq units, and will remain in various bases in order to be called on when needed. U.S. led combat operations are currently anticipated to end by September 2010, with all U.S. troops anticipated to be withdrawn from Iraq by the end of 2011. There can be no assurances that the commitment of these foreign nations to maintain their military presence will continue, nor can there be assurances that the Government of Iraq can itself provide the necessary degree of peace, order, stability and security without foreign military assistance. If the Heritage Group or, following Completion, the Continuing Group is unable to maintain effective security over its assets or personnel, this could have a material and adverse effect on the Heritage Group’s and, following Completion, the Continuing Group’s business, financial condition and prospects.
Russia
Since 1991, Russia has sought to transform itself from a one party state with a centrally planned economy to a democracy with a market economy. Despite Russia’s broad shift to a market-oriented economy and democratic institutions, the Russian political system remains vulnerable to the consequences of large-scale privatisations in the 1990s and demands for autonomy from certain regional and ethnic groups. Furthermore, as a result of the sweeping nature of these reforms, and the failure of some of them, the Russian political system remains vulnerable to popular dissatisfaction. Labour issues and social unrest may have political, social and economic consequences, such as increased support for a renewal of centralised authority, increased nationalism, including restrictions on foreign involvement in the economy of Russia, and increased violence.
Since 2000, Russia has generally experienced a significantly higher degree of governmental stability. However, possible future changes in the government, major policy shifts or any possible lack of consensus between the President, the government, Russia’s parliament and powerful economic lobby groups could lead to political instability, which could have a material adverse effect on the Heritage Group’s or, following Completion, the Continuing Group’s business, financial condition and prospects.
The Russian Federation is made up of 85 sub-federal political units and the delineation of authority and jurisdiction among the members of the Russian Federation and the federal government is, in many instances, unclear and remains contested. There is an existing division of authority between federal and regional authorities in respect of the development and implementation of state policy, in relation to the exploration, production, transport and sale of oil and gas and industrial and environmental safety concerns, which may lead to a climate of uncertainty in the Heritage Group’s or, following Completion, the Continuing Group’s Russian operations. Such uncertainty could hinder the Heritage Group’s or the Continuing Group’s long-term planning efforts in Russia, and may create uncertainties in its operating environment. These uncertainties may also prevent the Heritage Group or the Continuing Group from effectively and efficiently carrying out their business strategy and may hinder their long-term planning efforts in respect of their Russian operations.
Since the dissolution of the Soviet Union, the Russian economy has experienced at various times (amongst other things) hyperinflation, an unstable currency, growth of black and grey market economies, high levels of corruption and the penetration of organised crime into the economy. Over this period the Russian economy has also been subject to abrupt downturns. Over the last ten years, however, the Russian economy has experienced some periods of positive trends, such as an increase in gross domestic product, a relatively stable Rouble, strong domestic demand, rising real wages and a reduced rate of inflation. No assurance can be given that such positive trends will continue, which could lead to an adverse effect on Russia’s economy. Certain of the Heritage Group’s and, following Completion, the Continuing Group’s costs, relating to purchases and employee salaries, in respect of its operations in Russia may be materially affected by increased inflation rates in Russia. This in turn could affect the Heritage Group’s and the Continuing Group’s operating profits, financial condition and results of operations.
Developing countries and regions are subject to greater risk than developed countries or regions
Generally, most of the Heritage Group’s significant oil and gas interests are located in developing countries or regions (for example, in addition to Kurdistan, Uganda and Russia, countries such as the DRC, Tanzania, Mali and Pakistan), some of which have historically experienced periods of civil unrest, terrorism, violence and war,
16 as well as political and economic instability. Future oil and gas exploration and development activities in such developing countries or regions may be affected in varying degrees by government regulations, policies or directives with respect to restrictions on production or sales, price controls, export controls, repatriation of income, changes in income taxes and other local tax laws, carried interests for the state, expropriation of property and environmental legislation. There are inherent risks of uncertainty in, and changes to, laws such as tax laws in such developing countries or regions. The Heritage Group and, following Completion, the Continuing Group will also be required to negotiate property development agreements with the governments having jurisdiction over some of its properties. Such governments may impose conditions that could affect the viability of any given project such as providing the government with free carried interests, requiring local company participation, or providing subsidies for the development of the local infrastructure or other social assistance. There can be no assurance that the Heritage Group or, following Completion, the Continuing Group will be successful in concluding such agreements with any relevant governmental entity on commercially acceptable terms or that these agreements will be successfully enforced in the foreign jurisdictions in which the Heritage Group’s or, following Completion, the Continuing Group’s properties are located. Operations may also be affected in varying degrees by political and economic instability such as frequent changes to tax laws or fiscal policy, or economic or other sanctions imposed by the other countries or regions, including expropriation of assets, terrorism, civil wars, guerrilla activities, military repression, crime, material fluctuations in currency exchange rates and high inflation. The political status of certain countries or regions in which the Heritage Group operate may make it more difficult, after twelve months from the date of this document, for the Heritage Group or the Continuing Group to obtain any required project financing from senior lending institutions because such lending institutions may not be willing to finance projects in these countries or regions due to the perception of investment risk. This could have a material adverse effect on the Heritage Group’s and, following Completion, the Continuing Group’s financial condition, business, prospects, liquidity or results of operations.
Infrastructure development in many of the countries or regions in which the Heritage Group and, following Completion, the Continuing Group operate is limited. In addition, a significant portion of the Heritage Group’s and, following Completion, the Continuing Group’s properties are located in remote areas, many of which are difficult to access, and some jurisdictions or regions in which the Heritage Group and, following Completion, the Continuing Group, operates such as Kurdistan, are landlocked and have poor infrastructure. These factors may affect the Heritage Group’s and, following Completion, the Continuing Group’s ability to explore and develop its properties and to store and transport its oil and gas production. There can be no assurance that future instability in one or more of the countries or regions in which the Heritage Group operates (or in the neighbouring countries), actions by companies carrying out business there, or actions taken by the international community will not worsen the quality and availability of such infrastructure. This could have a material adverse effect on the Heritage Group’s and, following Completion, the Continuing Group’s financial condition, business, prospects, liquidity or results of operations.
Uncertainties of legal systems in jurisdictions in which the Heritage Group operate
Kurdistan, Uganda, Russia and other jurisdictions or regions in which the Heritage Group operates or might operate in the future may have less developed legal systems than more established economies which could result in risks such as (i) enforcement of international arbitral judgments being more difficult to obtain, particularly against the KRG; (ii) effective legal redress in the courts of such jurisdictions, whether in respect of a breach of law or regulation, or in an ownership dispute, being more difficult to obtain; (iii) a higher degree of discretion and corruption on the part of governmental authorities; (iv) the lack of judicial or administrative guidance on interpreting applicable local rules and regulations; (v) inconsistencies or conflicts between and within various laws, regulations, decrees, orders, resolutions and judgements; or (vi) relative inexperience of the judiciary and courts in such matters. In certain jurisdictions, the commitment of local business people, government officials and agencies and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to the Heritage Group’s, and, following Completion, the Continuing Group’s licences and business agreements. Some or all of these may be susceptible to revision or cancellation and legal redress may be uncertain, unavailable or delayed. There can also be no assurance that PSCs, concession agreements, joint ventures, licences, licence applications or other legal arrangements will not be adversely affected by the actions of government authorities or others and the effectiveness of and enforcement of such arrangements in these jurisdictions cannot be assured. This could have a materially adverse effect on the Heritage Group’s and, following Completion, the Continuing Group’s business, financial condition and prospects.
17 The Heritage Group and, following Completion, the Continuing Group cannot completely protect itself against title disputes in the jurisdictions or regions in which it operates
Although the Directors believe that the Heritage Group has good and marketable title to its oil and gas properties and the rights to explore for and produce oil and gas from, and dispose of, such properties, it cannot control or completely protect the Heritage Group and, following Completion, the Continuing Group against the risk of disputes in relation to such title and/or rights.
In many of the countries or regions in which the Heritage Group operates, land title systems are not developed to the extent found in many industrialised countries and there may be no concept of registered title. There can be no assurance that claims or challenges by third parties against the Heritage Group’s or, following Completion, the Continuing Group’s title to its properties will not be asserted at a future date. Failure to resolve such title disputes, including the ones set out below could have a material and adverse effect on the Heritage Group’s and, following Completion, the Continuing Group’s business, financial condition and prospects.
No assurance can be given that relevant governments will not revoke, or significantly alter the conditions of, the exploration, development and production authorisations, licences, permits, approvals and consents held by the Heritage Group and, following Completion, the Continuing Group, and that such exploration, development and production authorisations, licences, permits, approvals and consents will not be challenged or impugned by third parties. There is no certainty that existing rights or additional rights applied for will be granted or renewed on terms satisfactory to the Heritage Group and, following Completion, the Continuing Group or at all. In the event that any existing rights or additional rights applied for are revoked or not granted on terms satisfactory to the Heritage Group and, following Completion, the Continuing Group, this could have a material adverse effect on the Continuing Group’s business, results of operations, financial condition and prospects.
A. Kurdistan
On the basis of the current legal framework in Iraq and Kurdistan, in particular, the Iraqi constitution, as approved by referendum in October 2005 and which came into force in 2006 (the “Iraqi Constitution”), the Directors believe that the PSC entered into by the Heritage Group with the KRG is valid and enforceable pursuant to applicable laws as at the date of this document. This is notwithstanding the statements and actions of certain members of the Iraqi Government, which are described in the paragraph below. However, there can be no assurance that the PSC in Kurdistan will not be adversely affected in the future by the actions of certain Iraqi Government authorities, including the enactment by the Iraqi Government of its draft oil and gas law (see below), or others, and the validity and effectiveness of and enforcement of such PSC in the future in Iraq cannot be assured. Any such actions could have a material and adverse effect on the Heritage Group’s and, following Completion, the Continuing Group’s business, financial condition and prospects. In addition, disputes with the Iraqi Government relating to the PSC entered into with the KRG could have a materially adverse effect on the Heritage Group’s or the Continuing Group’s ability to obtain oil and gas licences in other areas of Iraq.
By way of background, the Iraqi Constitution, which came into force in 2006 after having been approved by referendum in October 2005, provides, among other things, that the “management of oil and gas extracted from present fields” is a shared power between the federal government and the producing governorates and regional governments, of which the KRG is the only one recognised to date. The Iraqi Constitution does not define the term “present fields” nor does it include oil and gas (or any other natural resource other than water) among the matters for which the federal government is granted exclusive powers under the Iraqi Constitution. The Iraqi Constitution further provides that with regard to powers “shared between the federal government and the regional government, priority shall be given to the law of the regions and governorates not organized in a region in case of dispute.”
In addition, according to the Iraqi Constitution, a referendum should be held in the Kurdish-populated areas of four Iraqi governorates in northern Iraq (including Kirkuk) to determine whether they should be under Baghdad’s control or Kurdistan’s control, and to propose a new constitution, which was approved by Kurdistan’s parliament in June 2009, for Kurdistan. This new constitution for Kurdistan defines Kirkuk and the oil resources in this area as part of Kurdistan and is to be voted upon pursuant to a referendum in the Kurdish-populated areas of northern Iraq, the timing of which is uncertain.
The Iraqi Government has postponed the referendum several times from its original date in 2007, citing that it could create further instability within Iraq. The United Nations issued a report in April 2009 that outlined
18 possible solutions to the dispute over Kirkuk. These solutions include a proposal to make Kirkuk a province of Iraq; another solution would be to make Kirkuk a governorate with special links to both Baghdad and Erbil. The United Nations suggested that all options could be endorsed in a referendum. Officials from the United States have voiced their support for a solution negotiated by the United Nations. However, President Barzani has rejected the United Nations’ proposals stating that any alternative proposed by the United Nations would complicate matters.
In February 2007 the Iraqi Federal Oil and Energy Committee of the Council of Ministers proposed a draft oil and gas law relating to the whole of Iraq, including Kurdistan. This asserts the jurisdiction of the Iraqi Government over oil and gas resources but has not been enacted. In August 2007 the KRG enacted the Oil and Gas Law of the Kurdistan Region asserting the jurisdiction of the KRG over oil and gas resources in the Kurdistan region.
The Iraq Ministry of Oil has disputed the validity of PSCs entered into with the KRG. The Heritage Group received a letter from the Iraq Ministry of Oil dated 17 December 2007, stating that contracts signed with the KRG (without the prior approval of the government of Iraq) are to be considered annulled as they violate the “prevailing Iraqi law”. However, Heritage has not received any further correspondence from the Iraq Ministry of Oil.
Notwithstanding the foregoing and in light of the background above, there can be no assurance that the Iraq Ministry of Oil will not continue to challenge the validity of the licences granted in Kurdistan and any such actions could have a material adverse effect on the business, financial condition and prospects of the Heritage Group or the Continuing Group or on the Heritage Group’s or the Continuing Group’s ability to obtain oil and gas licences in other areas of Iraq.
B. Malta
The Heritage Group received a letter from the chairman of the Management Committee of the National Oil Corporation of Libya, dated 28 February 2008, stating that the Block 7 licence area offshore Malta lies within the Libyan continental shelf and a portion of this area has already been licenced to Sirte Oil Company. This letter also demands that the Heritage Group refrain from any activities over or concerning the Block 7 licence area and asserts the Libyan Government’s right to seek to invoke Libyan and international law to protect its rights in the Block 7 licence area. The Directors believe that the Libyan Government’s claims are unfounded. As at the date of this document, no further correspondence has been received from the National Oil Corporation of Libya on the matter.
C. The DRC
The DRC work programme pursuant to the DRC PSC cannot be commenced prior to the grant of a Presidential Decree from the DRC Government. The validity of the award of the DRC licences to which the work programme relates is currently being disputed by the Congolese Oil Ministry; this is being rigorously defended by the Heritage Group and its partner. There can be no assurance that final approval or ratification will ever be received in respect of the DRC PSC or that the pre-agreed fiscal terms will not be re-negotiated at a later date by the DRC Government. As at the date of this document, the Presidential Decree from the DRC Government was still outstanding.
Failure to follow corporate and regulatory formalities may call into question the validity of the entity or its assets
In jurisdictions in which the Heritage Group or the Continuing Group may obtain interests, both the conduct of its operations and the steps involved in the Heritage Group or the Continuing Group acquiring its current interests involve or may involve the need to comply with numerous procedures and formalities including in relation to obtaining exploration and production licences. In some cases, failure to follow such formalities or obtain relevant evidence of compliance with such formalities may call into question the validity of the entity or the actions taken. In particular, there are various requirements under the Continuing Group’s PSC which, if not complied with, could lead to the PSCs being terminated or make them difficult to enforce or rely upon in the local courts to assert the Continuing Group’s rights and interests, including the minimum expenditure required during the exploration period.
19 Permits, approvals, authorisations, consents and licences may be difficult to obtain, sustain or renew
The operations of the Heritage Group and, following Completion, the Continuing Group, require licences, approvals, authorisations, consents and permits and in some cases renewals of existing licences, approvals, authorisations, consents and permits from various governmental authorities. The Directors believe that the Heritage Group currently holds or has applied for all necessary licences, approvals, authorisations, consents and permits to carry on the activities which they are currently conducting under applicable laws and regulations in respect of their properties, and also believe that the Heritage Group is complying in all material respects with the terms of such licences, approvals, authorisations, consents and permits or extensions thereof. However, the Heritage Group’s or, following Completion, the Continuing Group’s ability to obtain, sustain or renew such licences, approvals, authorisations, consents and permits on acceptable terms are subject to changes in regulations and policies and, to an extent, on the discretion of the relevant governments.
To the extent any such approvals, permits, authorisations, licences and consents are required and not obtained or maintained, the Heritage Group and, following Completion, the Continuing Group may be curtailed or prohibited from proceeding with planned exploration or development of oil and gas properties.
Amendments to current laws, regulations and permits, authorisations, licences, consents and approvals governing operations and activities of oil and gas companies, or more stringent implementation thereof, could result in increases in capital expenditures or production costs or a reduction in levels of production from producing properties or require abandonment or delays in development of new properties, all of which could have a materially adverse effect on the Heritage Group’s or, following Completion, the Continuing Group’s business, financial condition, prospects and results of operations.
Regulatory requirements can be onerous and expensive
The current or future operations of the Heritage Group and, following Completion, the Continuing Group, including development activities and commencement of production on its properties are subject to extensive government laws and regulations, and require permits, authorisations, licences, consents and approvals from various foreign, federal, state and local governmental authorities and such operations are and will be governed by applicable laws and regulations governing oil and gas exploration and development, exports, prices, taxes, royalties, labour standards, occupational health, waste disposal, toxic substances, land use, environmental protection and other matters. There can be no assurance that the acts of present or future governments in the countries or regions where such operations are (or will be) located, or the acts of governments of other countries that touch on such current or future operations, will not materially adversely affect the business or financial condition of the Heritage Group and, following Completion, the Continuing Group.
Furthermore, any changes or requirements additional to any such applicable laws, regulations and permitting requirements may require the installation of additional equipment or remedial actions in order to ensure compliance with such amendments, which may be expensive.
Failure to comply with applicable laws, regulations and permitting requirements may result in enforcement actions in local jurisdictions thereunder, including orders issued by regulatory or judicial authorities causing operations to cease or be curtailed, and may include corrective measures requiring capital expenditures, installation of additional equipment or remedial actions.
Parties engaged in oil and gas operations may be required to compensate those suffering loss or damage by reason of such activities and may have civil or criminal fines or penalties imposed for violations of applicable laws or regulations.
The Heritage Group and, following Completion, the Continuing Group may face difficulties in marketing or exporting its oil and natural gas
The marketability of any oil and natural gas acquired or discovered by the Heritage Group and, following Completion, the Continuing Group will be affected by numerous factors beyond its control, such as market fluctuations, the lack of a significant domestic market, and the availability of processing and refining facilities and transportation infrastructure, including access to ports, shipping facilities, pipelines and pipeline capacity. The right to export oil and gas may depend on obtaining licences and quotas, the granting of which may be at the
20 discretion of the relevant regulatory authorities. In Kurdistan (through an oil pipeline to Turkey), export production commenced in June 2009 and was terminated in October 2009. It is not clear if or when exports will recommence which could result in future potential oil and gas production revenue of the Continuing Group being materially adversely affected.
Oil and gas prices fluctuate
The results of operations and financial condition of the Heritage Group and, following Completion, the Continuing Group are significantly affected by prevailing prices of oil and gas. Historically, prices of oil and gas have been subject to wide fluctuations for many reasons, including:
• global and regional supply and demand, and expectations regarding future supply and demand, for oil and gas;
• global and regional economic conditions;
• political, economic and military developments in oil and gas producing regions;
• prevailing weather conditions;
• prices and availability of alternative sources of energy;
• geopolitical uncertainty;
• the ability of members of OPEC, and other oil producing nations, to set and maintain specified levels of production and prices; and
• governmental regulations and actions, including the imposition of export restrictions and taxes.
It is impossible to accurately predict future oil and gas price movements. The Company can give no assurance that existing prices for oil and gas will be maintained in the future. Any material decline in such prices could result in a reduction of the Heritage Group’s or, following Completion, the Continuing Group’s net production revenue and a decrease in the valuation of the Heritage Group’s or, following Completion, the Continuing Group’s exploration, appraisal, development and production properties. The economics of producing from some wells may change as a result of lower prices, which could result in a reduction in the volumes produced by the Heritage Group and, following Completion, the Continuing Group. The Heritage Group and, following Completion, the Continuing Group might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in the Heritage Group’s or, following Completion, the Continuing Group’s net production revenue and the financial resources available to it to make planned capital expenditures. This would have a material adverse effect on the Heritage Group’s or, following Completion, the Continuing Group’s financial condition, business, prospects and results of operations.
Recovery and reserve and resource estimates may prove inaccurate
Unless stated otherwise, the reserves and resources data contained in this document are extracted without material adjustment from the RPS Report, which has been prepared in accordance with the standards established by the PRMS. The reserves and resources data and the associated estimated future net cash flow from the Heritage Group’s properties contained in the RPS Report have been independently evaluated by RPS and, unless stated otherwise, certified by RPS. There are numerous uncertainties inherent in estimating quantities of reserves and cash flows to be derived therefrom, including many factors that are beyond the control of the Heritage Group and, following Completion, the Continuing Group. Estimating the amount of reserves and resources is a subjective process and, in addition, results of drilling, testing and production subsequent to the date of an estimate may result in revisions to original estimates.
The reserves and resource data and cash flow evaluations set forth in this document represent estimates only and should not be construed as representing exact quantities. These estimates and evaluations include a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, future prices of oil and gas,
21 operating costs and royalties and other government levies that may be imposed over the producing life of the reserves and resources. These assumptions were based on price and cost forecasts in use at the date the relevant evaluations were prepared and many of these assumptions are subject to change and are beyond the control of the Heritage Group and, following Completion, will be beyond the control of the Continuing Group. Actual production and cash flows derived therefrom will vary from these estimates and evaluations, and such variations could be material. The foregoing evaluations are based in part on the assumed success of exploitation activities intended to be undertaken in future years. The reserves and resources and estimated cash flows to be derived therefrom contained in such evaluations will be reduced to the extent that such exploitation activities do not achieve the level of success assumed in the evaluations.
The estimates and evaluations contained in this document (including in data contained within the RPS Report or extracted or derived from the RPS Report and whether expressed to be certified by RPS or otherwise) concerning the reserves and resources or production levels of the Heritage Group and, following Completion, the Continuing Group may prove inaccurate. Whilst reserves and resources are stated in accordance with the PRMS reserve and resource definitions, certain categories of reserves and resources (such as prospective or contingent resources) are inherently less certain than other categories (such as 1P or proved reserves).
If the actual reserves or resources of the Heritage Group and, following Completion, the Continuing Group are less than the current estimates, the Heritage Group or, following Completion, the Continuing Group may be unable to recover and produce the estimated levels or quality of oil or gas and, as a result, the business, prospects, financial condition or results of operations of the Heritage Group and, following Completion, the Continuing Group could be materially and adversely affected.
Exploration activities are capital intensive and involve a high degree of risk
Oil and gas exploration activities are capital intensive and involve a high degree of risk. There is no assurance that expenditures made on future exploration by the Heritage Group and, following Completion, the Continuing Group will result in new discoveries of oil or gas in commercial quantities. It is difficult to estimate the costs of implementing any exploratory drilling programme due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions such as over-pressured zones, tools lost in the hole and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. If exploration activities prove unsuccessful over a prolonged period of time, the Heritage Group and, following Completion, the Continuing Group may not, after twelve months from the date of this document, have sufficient working capital to continue to meet its obligations and their ability to obtain additional financing necessary to continue operations may also be adversely affected.
Future appraisal of potential oil and gas properties may involve unprofitable efforts
The Heritage Group’s or, following Completion, the Continuing Group’s future appraisals of potential oil and gas properties may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs and expenses. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs and expenses. In addition, drilling hazards or environmental damage could greatly increase the cost of operations. Various field operating conditions may also adversely affect the production from successful wells including delays in obtaining governmental approvals, permits, licences, authorisations or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While close well supervision and effective maintenance operations can contribute to maximising production rates over time, production delays and declines from normal field operating conditions cannot be eliminated. Any such productions, delays and declines could be expected to adversely affect revenue and cash flow levels.
Whether the Heritage Group and, following Completion, the Continuing Group ultimately undertakes an exploration or development project depends upon a number of factors, including availability and cost of capital, current and projected oil and gas prices, receipt of government approvals, access to the relevant property, the costs and availability of drilling rigs and other equipment, supplies and personnel necessary to conduct operations at the property, success or failure of similar activities in similar areas and changes in the expected levels of capital expenditures to complete the project.
22 The Heritage Group continues to and, following Completion, the Continuing Group will continue to gather data about its new venture opportunities and new projects on an ongoing basis. Additional information may cause the Heritage Group and, following Completion, the Continuing Group at any time to alter its project schedule or determine that a new venture opportunity or project should not be pursued, which could adversely affect the Heritage Group’s or, following Completion, the Continuing Group’s business and prospects.
Under certain of the Heritage Group’s PSCs and concession agreements, the Heritage Group is obliged to finance exploration, development and operations of the relevant property, and the related facilities and equipment and will only recover its costs if there is successful production in accordance with the terms of the PSCs and agreements. However, there can be no assurance that the Heritage Group and, following Completion, the Continuing Group will discover commercial quantities of oil or gas at such operations. Accordingly, there can be no assurance that the Heritage Group and, following Completion, the Continuing Group will recover its initial outlay of capital expenditures and operating costs at any such operation, and in such event the Heritage Group’s or, following Completion, the Continuing Group’s business, financial condition, results of operations and prospects could be materially and adversely affected.
Without the addition of reserves through exploration, acquisition or development activities, the Heritage Group’s or, following Completion, the Continuing Group’s reserves and production will decline over time as reserves are exploited
The Heritage Group’s or, following Completion, the Continuing Group’s future oil and gas reserves, production and cash flows to be derived therefrom are highly dependent on the Heritage Group’s or the Continuing Group’s success in exploiting its current reserve and resource base and acquiring or discovering additional reserves. Without the addition of reserves through exploration, acquisition or development activities, the Heritage Group’s or, following Completion, the Continuing Group’s reserves and production will decline over time as reserves are exploited. A future increase in the Heritage Group’s or, following Completion, the Continuing Group’s reserves will depend not only on the Heritage Group’s or the Continuing Group’s ability to develop their present properties, but also on their ability to select and acquire suitable producing properties or prospects. There is no assurance that the Heritage Group’s or, following Completion, the Continuing Group’s future exploration and development efforts will result in the discovery and development of additional commercial accumulations of oil and gas. If such efforts are unsuccessful, the Heritage Group’s or the Continuing Group’s total reserves may not increase or may decline, which could have a material adverse effect on the Heritage Group’s or, following Completion, the Continuing Group’s business, financial condition, prospects and results of operations.
Production operations involve many inherent risks
The Heritage Group has one producing asset in Russia. Production operations of the Heritage Group and, following Completion, the Continuing Group or by operators of assets in which the Heritage Group or the Continuing Group has an interest involve risks normally inherent in such activities such as premature declines of reservoirs, blow-outs, oil spills, explosions, fires, equipment damage or failure, natural disasters, geological uncertainties, unusual or unexpected rock formations, abnormal pressures, cratering and sulphur gas releases. Offshore operations of the Heritage Group and, following Completion, the Continuing Group may also be subject to natural disasters as well as to hazards inherent in marine operations and damage to pipelines and subsea facilities from trawlers, anchors and vessels. The occurrence of any of these events could result in environmental damage, injury to persons and loss of life, a failure to produce oil or gas in commercial quantities or an inability to fully produce discovered reserves. Consequent production delays and declines from normal field operating conditions can be expected to adversely affect revenue and cash flow levels to varying degrees. Oil and gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.
The Heritage Group’s production is currently sourced from its interests in one concession agreement. Should the Heritage Group and, following Completion, the Continuing Group encounter any problems in this concession agreement, it could have a material adverse impact upon the Heritage Group’s or, following Completion, the Continuing Group’s planned levels of production.
Interruptions in availability of exploration, production or supply infrastructure
Oil and gas exploration and development activities are dependent on the availability of drilling and related equipment in the particular areas where such activities will be conducted. Historically, high demand for such
23 limited equipment or access restrictions has affected the availability and cost of such equipment to the Heritage Group and operators of production facilities in which the Heritage Group has an interest and from time to time it resulted in delays to exploration and development activities. The ability of the Heritage Group’s or, following Completion, the Continuing Group’s ability to market any oil and gas discovered may depend upon their ability to acquire space on pipelines which deliver oil and gas to commercial markets and to negotiate the terms thereof. There is no export of oil from Kurdistan and so the production may have to be sold in the internal market for lower than international prices. The current intention of the Heritage Group is to truck its crude oil production from its Kurdistan operations by the middle of 2010.
Such interruptions or delays in the availability of infrastructure, including drilling rigs in particular and pipelines and storage tanks, on which exploration and production activities are dependent could result in disruptions to the Heritage Group’s or, following Completion, the Continuing Group’s projects, increase costs, and may have an adverse effect on the Heritage Group’s or, following Completion, the Continuing Group’s profitability.
Reliance on key strategic relationships
In conducting its business, the Heritage Group and, following Completion, the Continuing Group will rely on continuing existing strategic relationships and forming new ones with other entities in the oil and gas industry, such as joint venture parties, farm-in partners, local advisers and also certain regulatory and governmental departments. There can be no assurance that such existing relationships will continue to be maintained or that new ones will be successfully formed and the Heritage Group or, following Completion, the Continuing Group’s business, financial condition and results of operations and prospects could be materially adversely affected by changes to such relationships or difficulties in forming new ones.
The Heritage Group and, following Completion, the Continuing Group is highly dependent on its executive management
The Heritage Group and, following Completion, the Continuing Group is highly dependent upon its executive management and the loss of such executive management could have a materially adverse effect on the Heritage Group and, following Completion, the Continuing Group. The Heritage Group does not have any key-man insurance policy in place, and therefore, there is a risk that the unexpected loss of services of any member of executive management (through serious injury, death or resignation) could have a materially adverse effect on the Heritage Group and, following Completion, the Continuing Group.
Significant competition attracting and retaining skilled personnel
Attracting and retaining additional skilled personnel will be required to ensure expansion of the Heritage Group’s or, following Completion, the Continuing Group’s business. The Heritage Group and, following Completion, the Continuing Group faces significant competition for skilled personnel in the oil and gas sector. Skilled personnel are required in the areas of exploration and development, operations, engineering, business development, oil and gas marketing, finance and accounting relating to the Heritage Group’s and, following Completion, the Continuing Group’s projects. There is no assurance that the Heritage Group or the Continuing Group will successfully attract new personnel or retain existing personnel required to continue to expand its business and to successfully execute and implement its business strategy.
Environmental liabilities can be significant
Significant liability could be imposed on the Heritage Group and, following Completion, the Continuing Group for damages, clean-up costs or penalties in the event of certain discharges into the environment, environmental damage caused by previous owners of property purchased by the Heritage Group or, following Completion, the Continuing Group, acts of sabotage or non-compliance with environmental laws or regulations by the Heritage Group or the Continuing Group. Such liabilities could have a materially adverse effect on the Heritage Group and, following Completion, the Continuing Group. It is not possible to predict what future environmental regulations will be enacted or how current or future environmental regulations will be applied or enforced in the future. The Heritage Group or the Continuing Group may have to incur significant expenditures for the installation and operation of systems and equipment for remedial measures in the event that environmental regulations become more stringent or governmental authorities choose to enforce them more vigorously. Any such expenditure may have a material adverse effect on the Heritage Group’s or the Continuing Group’s
24 business, financial condition and results of operations. Although the Directors are not aware of any environmental issues that may affect the Company’s utilisation of its tangible fixed assets, no assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the cost of production, development or exploration activities or otherwise adversely affect the Heritage Group’s or, following Completion, the Continuing Group’s business, financial condition, results of operations or prospects.
As a party to various PSCs and concession agreements, members of the Heritage Group and, following Completion, the Continuing Group may have undertaken obligations to restore production areas to standards acceptable to the relevant state authorities at the end of the production fields’ commercial lives. Parties to such PSCs are typically liable for their share of any decommissioning work. Any obligation to decommission a production facility may involve substantial expenditure. These decommissioning costs are necessarily incurred at a time when the related production facilities are no longer generating revenue. It is intended that the decommissioning costs, when they arise, will be borne by the Heritage Group or the Continuing Group out of production revenue. There can, however, be no assurance that the production revenue will be sufficient to meet these decommissioning costs as and when they arise, and if the Heritage Group or the Continuing Group has to apply other or additional financial resources to meet these costs instead, it could have a material adverse effect on the Heritage Group’s or, following Completion, the Continuing Group’s business, financial condition, cash flows, results of operations or prospects.
The international oil and gas industry is highly competitive in all its phases
The international oil and gas industry is highly competitive in all its phases. Competition is particularly intense in the acquisition of prospective oil and gas properties, exploration and production licences, and oil and gas reserves. The Heritage Group’s or, following Completion, the Continuing Group’s competitive position depends on its geological, geophysical and engineering expertise, its financial resources, and its ability to develop its properties on time and on budget and its ability to select, acquire and develop proved reserves and on its ability to foster and maintain relationships with governments of the countries or regions in which it operates. The Heritage Group and, following Completion, the Continuing Group compete with numerous other participants in the search for oil and gas, the acquisition of oil and gas properties and in the marketing of oil and gas. The Heritage Group’s and Continuing Group’s competitors include oil and gas companies which have greater financial resources and more local contacts, staff and facilities than the Heritage Group or the Continuing Group. Many of such competitors not only explore for and produce hydrocarbons, but also carry on refining and marketing of oil and gas and other products on a world-wide basis. Additionally, companies not previously investing in oil and gas or operating in that sector may choose to acquire reserves to establish a firm supply or simply as an investment. Such companies will also provide competition for the Heritage Group or the Continuing Group. The Heritage Group’s or, following Completion, the Continuing Group’s ability to increase reserves in the future will depend not only on its ability to develop its present properties, but also on its ability to select and acquire suitable producing properties or prospects for exploratory drilling.
Competitive factors in the distribution and marketing of oil and gas include price and methods and reliability of delivery. The Heritage Group and, following Completion, the Continuing Group compete with major and independent oil and gas companies and other industries supplying energy and fuel in the marketing and sale of oil and gas to transporters, distributors and end-users, including industrial, commercial and individual consumers.
Due diligence of assets and acquisition targets is inherently incomplete
The Heritage Group’s and, following Completion, the Continuing Group’s strategy includes increasing its oil and gas reserves through acquisitions of interests in oil and gas properties. Although the Heritage Group performs a review of the companies, businesses and properties it acquires (or intends to acquire) to standards consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in-depth every individual property involved in each acquisition. The Heritage Group will commonly focus its due diligence efforts on higher value properties and will simply review the lower value interests on a sample basis. However, even in-depth due diligence reviews may not reveal existing or potential problems, nor will they permit the acquirer to become sufficiently familiar with the properties to fully assess their potential or limitations and deficiencies. A physical inspection may not be performed on every well, and structural or environmental problems, such as ground water contamination, are not always observable or evident when a due diligence review is carried out. On that basis, the Heritage Group or the Continuing Group may, in making any acquisition,
25 assume liabilities in relation to the relevant asset, including environmental liabilities. There can be no assurance that any acquisition by the Heritage Group and, following Completion, the Continuing Group will be successful in whole or in part.
Future acquisitions may involve many common acquisition risks
Risks commonly associated with acquisitions of companies, businesses or properties include the difficulty of integrating operations and personnel in relation to any such business or property, problems with minority shareholders if the transactions are structured as the acquisition of companies, the potential disruption of the Heritage Group’s or the Continuing Group’s own business, the diversion of management’s time and resources from the existing Heritage Group or Continuing Group business, and the possibility that indemnification agreements with sellers may be unenforceable or insufficient to cover potential liabilities and difficulties arising out of integration. Furthermore, the value of any business, company or property that the Heritage Group or the Continuing Group acquires or invests in may actually be less than the amount it pays for it or its estimated reserves, resources and production capacity or potential may be lower than expected.
Managing the Heritage Group’s and, following Completion, the Continuing Group’s expected growth and development could be challenging
The Heritage Group has experienced significant growth and development over a short period of time and it or the Continuing Group expects to continue to grow through further exploration success and production increases from its oil reserves. Management of the expected growth requires, among other things, stringent control of financial systems, operations and processes, the continued development of management controls, the training and hiring of new personnel and continued access to funds to finance this growth. Failure to successfully manage the Heritage Group’s or the Continuing Group’s expected growth and development could have a material adverse effect on the Heritage Group’s or the Continuing Group’s business, financial condition, results of operations and prospects.
Insurance may not be available or not be sufficient to cover full extent of liabilities
The Heritage Group’s or, following Completion, the Continuing Group’s involvement in the exploration for and development of oil and gas properties may result in the Heritage Group or the Continuing Group becoming subject to liability for claims for matters including pollution, blow-outs, environmental damage, cratering and fires. Many of those risks are outside the control of the Heritage Group or the Continuing Group and all of them may result in property damage, personal injury or other hazards or for the acts or omissions of sub-contractors, operators and joint venture partners. Although the Heritage Group may have received indemnities from such sub-contractors, operators and joint venture partners, such indemnities may be difficult to enforce given the financial positions of those giving the indemnities or due to the jurisdictions in which the Heritage Group and, following Completion, the Continuing Group may seek to enforce the indemnities.
The Directors believe that the level of insurance cover maintained by the Heritage Group is adequate based on various factors such as the cost of the policies, industry standard practice and the risks associated with the exploration and development of oil and gas properties in the countries or regions in which it operates.
Although the Heritage Group has obtained insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not be insurable in all circumstances or, in certain circumstances the Heritage Group and, following Completion, the Continuing Group may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or for other reasons. It may also be difficult or impossible to obtain insurance coverage to protect against civil strife, labour unrest, outbreaks of infectious disease, armed conflict, acts of war, terrorism and other security incidents and as a result, the Heritage Group’s or the Continuing Group’s insurance programme may exclude such coverage. The payment of such uninsured liabilities would reduce the funds available to the Heritage Group and, following Completion, the Continuing Group. The occurrence of a significant event that the Heritage Group and, following Completion, the Continuing Group is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on the Heritage Group’s or the Continuing Group’s financial position, business, results of operations or prospects.
26 Currency fluctuations and foreign exchange particularly in relation to United States dollars and interest rate fluctuations
The Heritage Group’s current capital expenditures, exploration commitments, revenues and cost base are denominated primarily in United States dollars and, to a lesser extent, in currencies of other countries, such as Russian Roubles. Where there are fluctuations in the United States dollar exchange rate, the Heritage Group’s or the Continuing Group’s revenue margins and capital expenditures may be materially affected. Expenses in Russian Roubles are partially offset by income earned in Russian Roubles. The developing countries or regions in which the Heritage Group and, following Completion, the Continuing Group operate or propose to operate impose or may impose foreign exchange restrictions that may materially affect the Heritage Group’s or, following Completion, the Continuing Group’s financial condition, business prospects and results of operations. Any increase in relevant interest rates will increase the amount the Heritage Group and, following Completion, the Continuing Group will pay to service their debt which could materially adversely affect their financial condition, business prospects and results of operations.
Failure to meet contractual arrangements may result in the loss of the Heritage Group’s or, following Completion, the Continuing Group’s interests
Any change in government or legislation may affect the status of the Heritage Group’s or the Continuing Group’s PSCs or contractual arrangements or its ability to meet its contractual obligations and may result in the loss of its interests in its oil and gas properties. Some of the contracts pursuant to which the Heritage Group holds an interest in its properties permit the other party to terminate the contract if force majeure conditions cause operations to be economically unviable or interrupted. Due to the potential for civil unrest in certain countries or regions in which the Heritage Group’s properties are located, there can be no assurance that these properties will not become subject to force majeure conditions which could have the consequence of putting those contractual interests at risk. To the extent that the laws of Jersey or England do not apply to any of these contractual arrangements, no assurance can be given that these contractual arrangements will be enforced or interpreted in the same manner or to the same extent as would be the case if the laws of Jersey or England did apply.
Discontinuation of operations
Once the Heritage Group and, following Completion, the Continuing Group has an interest in an established oil and gas exploration and/or production operation in a particular country or region, it may be expensive and logistically burdensome to discontinue such operation should economic, physical or other conditions subsequently deteriorate. Such deterioration in any of the countries or regions in which the Heritage Group or, following Completion, the Continuing Group operates could be caused by a number of factors, including some of the ones described below, and could have a material adverse effect on the Heritage Group’s and, following Completion, the Continuing Group’s ability to continue to exploit its established oil and gas exploration and/or production prospects in these countries or regions.
Risks relating to the Heritage Group and, following Completion, the Continuing Group structure
The rights of shareholders under the laws of Jersey may differ from the rights of shareholders of companies incorporated in other jurisdictions
The Company is incorporated in Jersey under the Act. As a result, the rights of Shareholders will be governed by the laws of Jersey and the Articles. The rights of Shareholders under the laws of Jersey may differ from the rights of shareholders of companies incorporated in other jurisdictions and the enforcement of such rights may involve different considerations and may be more difficult than would be the case if the Company had been incorporated in the jurisdiction of an investor’s residence or elsewhere.
There may be difficulty in enforcing against the Heritage Group’s assets and judgments obtained in Jersey courts
While the Company exists under the laws of Jersey and its registered office is located in Jersey, a number of Directors of the Heritage Group (other than Mr Anthony Buckingham and Mr Paul Atherton, who reside in Jersey) and substantially all of the assets of the Heritage Group are located outside Jersey. It may not be possible for holders of Ordinary Shares or Exchangeable Shares to effect service of process within Jersey upon the
27 Directors who reside outside Jersey. As such, there may be difficulty in enforcing against the Heritage Group’s and, following Completion, the Continuing Group’s assets, and judgments obtained in Jersey courts based upon the provisions of applicable Jersey securities legislation may not be recognised or enforceable in jurisdictions where certain of the Directors reside or where the Heritage Group’s and, following Completion, the Continuing Group’s assets are located.
Risks relating to Ordinary Shares and Exchangeable Shares
Market price of the Ordinary Shares and the Exchangeable Shares may fluctuate significantly
The market price of the Ordinary Shares and the Exchangeable Shares may, in addition to being affected by the Heritage Group’s and, following Completion, the Continuing Group’s actual or forecasted operating results, fluctuate significantly as a result of factors beyond the Company’s control, including, among others:
• negative press speculation in respect of the Disposal and the Heritage Group’s results of exploration and production operations;
• the results of exploration, development and appraisal programmes and production operations;
• changes in securities analysts’ recommendations or estimates of earnings or financial performance of the Heritage Group and, following Completion, the Continuing Group, its competitors or the industry, or the failure to meet expectations of securities analysts;
• fluctuations in stock market prices and volumes, and general market volatility;
• changes in laws, rules and regulations applicable to the Company, its operations and the operations in which the Company has interests, and involvement in actual or threatened litigation;
• general economic and political conditions, including in the regions in which the Heritage Group or the Continuing Group operates;
• fluctuations and volatility in the prices of oil, gas and other petroleum products; and
• possible delisting of the Ordinary Shares from the Official List in certain circumstances, including a failure to meet continuing listing obligations of the LSE.
The Major Shareholder has the ability to control some of the actions taken by the Shareholders of the Company
The Major Shareholder and Mr Anthony Buckingham currently own and control in aggregate 84,540,340 Ordinary Shares representing approximately 29.4 per cent. of the Voting Share Capital. As a result of its ownership interest, the Major Shareholder, and thereby Mr Anthony Buckingham, has the ability to exert significant influence on some of the actions taken by the Shareholders. The Major Shareholder, and thereby Mr Anthony Buckingham, currently has sufficient voting power to, among other things, delay, deter or prevent a change in control of the Company that might otherwise be beneficial to the Shareholders and may also discourage acquisition bids for the Company and limit the amount certain investors may be willing to pay for the Ordinary Shares or the Exchangeable Shares. Each of the Major Shareholder and Mr Anthony Buckingham have entered into a relationship agreement with the Company dated 28 March 2008 to ensure that the Heritage Group is capable of carrying on business independently from the Major Shareholder and that transactions and relationships with the Major Shareholder are at arm’s length and on normal commercial terms.
Sales of the Major Shareholder’s Ordinary Shares could decrease the market price of the Ordinary Shares and the Exchangeable Shares
The Company cannot predict whether substantial numbers of the Ordinary Shares will be sold in the open market. Sales of a large number of the Ordinary Shares in the public markets, or the potential for such sales, could decrease the market price of the Ordinary Shares and the Exchangeable Shares and could impair the
28 Company’s ability to raise capital through future offerings of Ordinary Shares. Following Completion, the Major Shareholder and Mr Anthony Buckingham will own and control in aggregate 84,540,340 Ordinary Shares representing approximately 29.4 per cent. of the Voting Share Capital. The Company cannot predict whether the Major Shareholder will sell any of the Ordinary Shares it holds in the open market and, if so, when. Sales by the Major Shareholder of a large number of the Ordinary Shares in the public markets, or the potential for such sales, could decrease the trading price of the Ordinary Shares and the Exchangeable Shares, and could impair the Company’s ability to raise capital through future offerings of Ordinary Shares.
The Company’s shareholding structure may limit claims by Shareholders against subsidiary assets
The Company holds the majority of its assets in its wholly-owned (via its indirectly wholly-owned subsidiary, Alberta CallCo) subsidiary, HOC. In the event of insolvency, liquidation or any other reorganisation of HOC, the holders of the Ordinary Shares and Exchangeable Shares will have no right to proceed against the assets of HOC or to cause the liquidation or bankruptcy of that company under applicable bankruptcy laws. Creditors of HOC would be entitled to payment in full from such assets before the Company, as a shareholder, would be entitled to receive any distribution therefrom. Claims of creditors of HOC will have priority with respect to the assets and earnings of HOC over the claims of the Company, except to the extent that the Company may itself (via its indirectly wholly-owned subsidiary, Alberta CallCo) be a creditor with recognised claims against HOC ranking at least pari passu with such other creditors, in which case the claims of the Company would still be effectively subordinate to any mortgage or other liens on the assets of HOC and would be subordinate to any indebtedness of HOC.
Raising of future equity funds for the Company could result in dilution
Depending on future exploration, development, production or acquisition plans, the Heritage Group and, following Completion, the Continuing Group may, after twelve months from the date of this document, require additional financing and the Company may choose to raise such additional finance by way of an equity offering of additional Ordinary Shares or securities convertible into Ordinary Shares. Any such offering may be dilutive to the existing Shareholders’ interests in the Company. In addition, if any outstanding options or convertible bonds are exercised further dilution of the existing Shareholders’ interests in the Company will occur.
United States and Canadian shareholders may not be able to participate in any future equity rights offering
U.S. and Canadian shareholders may not be entitled to exercise pre-emption rights unless the rights and the Ordinary Shares are registered under applicable U.S. or Canadian securities legislation or an exemption from the registration requirements of such legislation is available, and may suffer significant dilution as a result. The Directors cannot at this time predict whether the Company would seek such registration and the Company would evaluate, at the time of any rights offering, the costs and potential liabilities associated with registration or qualifying for an exemption, as well as the indirect benefits to the Company of enabling U.S. and Canadian Shareholders to exercise rights and any other factors the Company considers appropriate at that time, prior to making a decision whether to file a registration statement or prospectus or utilise an exemption from the registration requirements of applicable U.S. and Canadian securities legislation.
Jersey law significantly limits the circumstances under which shareholders of companies may bring derivative actions
Jersey law limits the circumstances under which shareholders of companies may bring derivative actions, and, in most cases, only the company can bring an action in respect of any wrongful act committed against it. Under Jersey law, derivative actions are available to shareholders of a Jersey company only if all other alternative remedies have been exhausted.
An unforeseen event may cause the Heritage Group and, following Completion, the Continuing Group to lose or impair its title to their oil and gas properties
Although the Heritage Group has invested substantially in their respective risk management strategies and techniques, and will continue to do so, such strategies and techniques may nonetheless fail, particularly if the Heritage Group and, following Completion, the Continuing Group are confronted with some of the risks
29 associated with the Disposal which they have not anticipated or identified. For example, an unforeseen defect in title, any changes in laws or changes in such laws’ interpretation or political events may arise to defeat or impair the Heritage Group’s or, following Completion, the Continuing Group’s claims to its titles to their oil and gas properties. If such circumstances arise that the Heritage Group did not identify, anticipate or correctly evaluate, the Heritage Group and, following Completion, the Continuing Group could suffer unexpected losses, which could have a material adverse effect on their business, financial condition and results of operations.
Risks relating to the Disposed Assets and operational and country risks associated with Uganda
Political, social and economic instability in Uganda and the surrounding countries may affect the Disposed Assets
The Disposed Assets relate to an interest currently held by the Heritage Group to explore and develop oil and gas properties in and around Lake Albert, which straddles the border of Uganda and the DRC. Uganda has historically been subject to armed fighting among hostile ethnic groups, rebels, armed gangs, militias, and various government forces that has, in the past, extended across its borders into the DRC. For nearly a quarter of a century there has been a well-publicised civil conflict between the government forces of Uganda and members of the Lord’s Resistance Army who have sought to overthrow the Government of Uganda, although there has been no, or very limited, activity in Uganda by the Lord’s Resistance Army for the past three years.
In 2005, the Ugandan military pushed the Lord’s Resistance Army out of northern Uganda. The Lord’s Resistance Army escaped to the DRC and continued to operate there, in southern Sudan, and occasionally in the Central African Republic. Following further military pressure, the Lord’s Resistance Army requested peace talks and the Government of southern Sudan mediated a two and a half year peace process which resulted in a peace agreement in April 2008. The leader of the Lord’s Resistance Army, Joseph Kony, refused to sign the peace agreement and continued to commit atrocities against local populations in the DRC, southern Sudan and the Central African Republic. On 14 December 2008 the Governments of Uganda, the DRC and southern Sudan launched a joint military operation against the Lord’s Resistance Army in northeastern DRC.
Although this operation is still ongoing, there have been no reported Lord’s Resistance Army attacks in northern Uganda since August 2006. However, there can be no assurance that the conflict between Uganda and the Lord’s Resistance Army or that internal conflict in the DRC or Southern Sudan countries will not continue. Any such conflicts may lead to political and social instability in the region which may culminate in security problems which may affect the operations of, and personnel related to, the Disposed Assets. Consequently, any political and social instability or security problems which may arise in the region where the Disposed Assets are located could have a material and adverse effect on the business, financial condition and prospects of the Disposed Assets following Completion.
The Disposed Assets cannot be completely protected against title disputes in Uganda
There is an ongoing tribal dispute in the Lake Albert region of Uganda. The tribal dispute is between the indigenous Banyoro and the Bakiga. The number of Bakiga in the region swelled after a series of resettlement schemes instituted after the Second World War. Their number in the region swelled again in the 1990s when the Bakiga fled to Uganda to escape persecution in Rwanda. The current tension between the Banyoro and Bakiga people is over the legality of the Bakiga’s settlement in the region. Since the discovery of oil in the region, the dispute has been exacerbated and both sides are now placing more importance on the issue of land ownership. The distribution of oil wealth in Uganda will most likely be governed by the existing Mining Law. Under this legislation, the largest share of the oil revenue (80 per cent.) will go to the Ugandan central government. The remaining 20 per cent. is split between local government (17 per cent.) and the local landowners (3 per cent.). The Banyoro tribe view the Bakiga as illegal immigrants who have been displaced by warfare and conflict. The Banyoro wish to ensure that the Bakiga do not receive any of the oil revenue of the region at the expense of the Banyoro people. The Government of Uganda has stepped in to intervene amongst escalating tension, but local residents fear that, unless an agreement is reached that is satisfactory to all parties, war could descend upon a region of Uganda that has enjoyed decades of relative peace. Against the backdrop of these ongoing tribal disputes and the uncertainty in Uganda as to the distribution of oil revenue, there can be no assurance that claims or challenges by third parties on the title to the Disposed Assets will not be asserted at a future date. Failure to resolve such title disputes could have a material and adverse effect on the business, financial condition and prospects of the Disposed Assets following Completion.
30 PART III—FINANCIAL INFORMATION ON THE DISPOSED ASSETS 1. Nature of Financial Information relating to Disposed Assets The following financial information relating to the Disposed Assets has been extracted without material adjustment from the consolidation schedules underlying the audited consolidated financial statements of the Heritage Group for the years ended 31 December 2006, 31 December 2007 and 31 December 2008 and the unaudited consolidated financial statements of the Heritage Group for the six month period ended 30 June 2009. The segmental information relating to the Heritage Group’s interest in Uganda as included in these financial statements differs from the financial information set out below as that interest includes certain assets which do not comprise part of the Disposed Assets. The financial information in this Part III does not constitute statutory financial statements, is unaudited and has not been reported by an independent accountant and has been prepared in accordance with Adopted IFRS. Shareholders should read the whole document and not just rely on the information contained in this Part III. 2. Income Statement The table below summarises the income statement attributable to the Disposed Assets prepared in accordance with Adopted IFRS for the three years ended 31 December 2006, 31 December 2007 and 31 December 2008 and for the the six month period ended 30 June 2009. Year Ended Year Ended Year Ended 6 months ended 31 December 2006 31 December 2007 31 December 2008 30 June 2009
$$$$ Finance cost ...... — 6,232 13,161 20,435
Loss after tax ...... — 6,232 13,161 20,435
3. Balance Sheet The table below summarises the balance sheet attributable to the Disposed Assets prepared in accordance with Adopted IFRS as at 31 December 2006, 31 December 2007, 31 December 2008 and 30 June 2009. 31 December 31 December 31 December 30 June 2006 2007 2008 2009
$$$$ ASSETS Non-current assets Intangible exploration assets ...... 41,246,317 74,240,229 130,032,034 144,550,209 Property, plant and equipment ...... 240,141 278,448 648,773 651,251
41,486,458 74,518,677 130,680,807 145,201,460 Current assets Trade and other receivables ...... 1,725,123 2,798,500 5,552,183 1,038,838 Cash and cash equivalents ...... 3,541,097 1,402,840 18,987,416 4,233,991
5,266,220 4,201,340 24,539,599 5,272,829
46,752,678 78,720,017 155,220,406 150,474,289 LIABILITIES Current liabilities Trade and other payables ...... 6,405,504 5,964,750 30,023,607 5,223,954
6,405,504 5,964,750 30,023,607 5,223,954 Non-current liabilities Provisions ...... 62,322 71,758 460,812 242,179
62,322 71,758 460,812 242,179
6,467,826 6,036,508 30,484,419 5,466,133
Net Assets ...... 40,284,852 72,683,509 124,735,987 145,008,156
31 PART IV—PRO FORMA FINANCIAL INFORMATION ON THE CONTINUING GROUP
1. Pro Forma Financial Information on the Continuing Group
The following pro forma financial information of the Continuing Group as at 30 June 2009 has been prepared for illustrative purposes only and because of its nature only addresses a hypothetical situation and, therefore, does not represent the actual financial position of the Continuing Group. It is prepared to illustrate the effect of the Disposal on the consolidated balance sheet of the Continuing Group as if the Disposal had taken place on 30 June 2009.
2. Combined and Consolidated Balance Sheet
Heritage 30 June 2009 Adjustment 1 Adjustment 1 (note 1) (note 2) (note 3) Pro forma
$$$$ ASSETS Non-current assets Intangible exploration assets ...... 245,923,367 (144,550,209) — 101,373,158 Property, plant and equipment ...... 60,537,547 (651,251) — 59,886,296 Other non-current assets ...... 851,065 — — 851,065
307,311,979 (145,201,460) — 162,110,519
Current assets Inventories ...... 41,986 — — 41,986 Prepaid expenses ...... 2,558,789 — — 2,558,789 Trade and other receivables ...... 4,124,807 (1,038,838) — 3,085,969 Cash and cash equivalents ...... 255,407,425 (4,233,991) 1,340,000,000 1,591,173,434
262,133,007 (5,272,829) 1,340,000,000 1,596,860,178
569,444,986 (150,474,289) 1,340,000,000 1,758,970,697
LIABILITIES Current liabilities Trade and other payables ...... 25,553,696 (5,223,954) — 20,329,742 Borrowings ...... 616,473 — — 616,473
26,170,169 (5,223,954) — 20,946,215
Non-current liabilities Borrowings ...... 133,276,286 — — 133,276,286 Provisions ...... 471,793 (242,179) — 229,614
133,748,079 (242,179) — 133,505,900
Total liabilities ...... 159,918,248 (5,466,133) — 154,452,115
Net Assets/(Liabilities) ...... 409,526,738 (145,008,156) 1,340,000,000 1,604,518,582
SHAREHOLDERS’ EQUITY ATTRIBUTABLE TO EQUITY HOLDERS OF THE COMPANY Share capital ...... 455,683,783 — — 455,683,783 Reserves ...... 80,471,429 — — 80,471,429 Retained (deficit)/earnings ...... (126,628,474) (145,008,156) 1,340,000,000 1,068,363,370
409,526,738 (145,008,156) 1,340,000,000 1,604,518,582
32 Notes
1) The consolidated balance sheet of the Heritage Group has been extracted without material adjustment from the unaudited interim financial statements of the Company for the six months ended 30 June 2009 which were published on 28 August 2009.
In connection with the Disposal, the following adjustments have been made:
2) Assets and liabilities relating to the Disposed Assets at 30 June 2009 have been extracted without material adjustment from Part III of this document.
3) The cash component of the disposal consideration of $1.35 billion, net of estimated disposal costs of approximately $10 million was added to the consolidated cash balance of the Company.
The contingent, deferred consideration of $150 million was not included in the Pro Forma Financial Information of the Continuing Group because the receipt of the contingent, deferred consideration is contingent on several conditions specified in the Disposal Agreement.
As disclosed in Section 6 of Part I of this document, the Company is considering returning a portion of the Disposal proceeds to Shareholders through a special dividend following Completion, which could be in the range of 75 pence to 100 pence per Ordinary Share. This potential dividend has not been included in the Pro Forma Financial Information of the Continuing Group.
Impact on Earnings
The Heritage Group is an independent upstream exploration and production company which was listed on the Official List and admitted to trading on the Main Market of the London Stock Exchange in 2008. For the six month period ended 30 June 2009, the Heritage Group reported a net loss of $12.8 million. Loss per share for the same period was $0.05 per Ordinary Share, based on a weighted average number of Ordinary Shares in issue of 258.5 million.
The Disposed Assets are not expected to have any negative material impact on the immediate future level of earnings of the Continuing Group as all historic costs relating to the Disposed Assets have been capitalised on the balance sheet and had no direct impact on earnings.
The future level of earnings per share of the Continuing Group will benefit from increased financial income as a result of higher treasury resources.
33 ACCOUNTANT’S REPORT ON PRO FORMA FINANCIAL INFORMATION
KPMG Audit Plc 8 Salisbury Square London EC4Y 8BB United Kingdom
The Directors Heritage Oil Plc Ordnance House 31 Pier Road St. Helier JE4 8PW Jersey Channel Islands
21 December 2009
Dear Sirs
We report on the pro forma financial information (the ‘Pro forma financial information’) set out in Part IV of the Class 1 circular dated 21 December 2009, which has been prepared on the basis described in note 1, for illustrative purposes only, to provide information about how the transaction might have affected the financial information presented on the basis of the accounting policies adopted by Heritage Oil Plc in preparing the financial statements for the period ended 30 June 2009. This report is required by paragraph 13.3.3R of the Listing Rules of the Financial Services Authority and is given for the purpose of complying with that paragraph and for no other purpose.
Responsibilities
It is the responsibility of the directors of Heritage Oil Plc to prepare the Pro forma financial information in accordance with paragraph 13.3.3R of the Listing Rules of the Financial Services Authority.
It is our responsibility to form an opinion, as required by paragraph 7 of Annex II of the Prospectus Directive Regulation, as to the proper compilation of the Pro forma financial information and to report that opinion to you.
In providing this opinion we are not updating or refreshing any reports or opinions previously made by us on any financial information used in the compilation of the Pro forma financial information, nor do we accept responsibility for such reports or opinions beyond that owed to those to whom those reports or opinions were addressed by us at the dates of their issue.
34 Save for any responsibility which we may have to those persons to whom this report is expressly addressed and which we may have to the holders of ordinary shares of Heritage Oil Plc and the holders of exchangeable shares in Heritage Oil Corporation as a result of the inclusion of this report in the Class 1 circular, to the fullest extent permitted by law we do not assume any responsibility and will not accept any liability to any other person for any loss suffered by any such other person as a result of, arising out of, or in connection with this report or our statement, required by and given solely for the purposes of complying with Listing Rule 13.4.1R(6), consenting to its inclusion in the Class 1 circular.
Basis of opinion
We conducted our work in accordance with the Standards for Investment Reporting issued by the Auditing Practices Board in the United Kingdom. The work that we performed for the purpose of making this report, which involved no independent examination of any of the underlying financial information, consisted primarily of comparing the unadjusted financial information with the source documents, considering the evidence supporting the adjustments and discussing the Pro forma financial information with the directors of Heritage Oil Plc.
We planned and performed our work so as to obtain the information and explanations we considered necessary in order to provide us with reasonable assurance that the Pro forma financial information has been properly compiled on the basis stated and that such basis is consistent with the accounting policies of Heritage Oil Plc.
Our work has not been carried out in accordance with auditing or other standards and practices generally accepted in the United States of America or other jurisdictions and accordingly should not be relied upon as if it had been carried out in accordance with those standards and practices.
Opinion
In our opinion:
• the Pro forma financial information has been properly compiled on the basis stated; and
• such basis is consistent with the accounting policies of Heritage Oil Plc.
Yours faithfully
(Signed) “KPMG Audit Plc”
KPMG Audit Plc 21 December 2009
35 PART V—ADDITIONAL INFORMATION
1. RESPONSIBILITY
The Directors (whose names appear in Section 2.1 below) accept responsibility for the information contained in this document. To the best of the knowledge and belief of the Directors (who have taken all reasonable care to ensure that such is the case), the information contained in this document is in accordance with the facts and does not omit anything likely to affect the import of such information.
2. DIRECTORS AND REGISTERED OFFICE
2.1 The Directors and Senior Manager of the Company and their functions are as follows:
Michael Hibberd ...... Chairman and Non-Executive Director Anthony Buckingham ...... Chief Executive Officer Paul Atherton ...... Chief Financial Officer Gregory Turnbull ...... Non-Executive Director John McLeod ...... Non-Executive Director General Sir Michael Wilkes ...... Non-Executive Director Salim Hassan Macki ...... Non-Executive Director Brian Smith ...... VP Exploration
2.2 The Company’s registered office is at Ordnance House, 31 Pier Road, St. Helier, JE4 8PW, Jersey and it has a place of business at Fourth Floor, Windward House, Route de la Liberation, St. Helier, JE2 3BQ, Jersey.
3. DIRECTORS’ INTERESTS
3.1 The table below sets out the direct and indirect interests of the Directors (and of persons connected with them) and the Senior Manager in the share capital of the Company as at 18 December 2009, the latest practicable date prior to the publication of this document:
Percentage of Voting Number of Share Director/Senior Manager Ordinary Shares(1) Capital
Michael Hibberd ...... 125,000 0.04% Anthony Buckingham(2) ...... 84,540,340 29.40% Paul Atherton ...... 1,140,000 0.40% Gregory Turnbull ...... 350,070 0.12% John McLeod ...... 20,000 0.01% General Sir Michael Wilkes ...... 0 0 Salim Hassan Macki ...... 138,752 0.05% Brian Smith ...... 0 0
(1) Includes Exchangeable Shares
(2) Mr Anthony Buckingham’s Ordinary Shares include the Ordinary Shares held by Albion Energy Limited as at the date of this document, a company owned and controlled by Mr Buckingham
36 3.2 As at 18 December 2009, the latest practicable date prior to the publication of this document, the Directors and the Senior Manager hold the following Options granted pursuant to the Scheme: Number of Director/Senior Manager Options Expiry Date Exercise Price per Ordinary Share
Michael Hibberd ...... 1,150,000 23 June 2011 150,000 Options at £0.81 14 December 2011 750,000 Options at £1.43 21 December 2012 250,000 Options at £2.45
Anthony Buckingham ...... 10,129,510 30 May 2010 500,000 Options at £0.48 14 December 2011 9,129,510 Options at £1.43 21 December 2012 500,000 Options at £2.45
Paul Atherton ...... 2,875,000 20 May 2010 1,250,000 Options at £0.48 14 December 2011 1,125,000 Options at £1.43 21 December 2012 500,000 Options at £2.45
Gregory Turnbull ...... 600,000 20 May 2010 150,000 Options at £0.48 14 December 2011 300,000 Options at £1.43 21 December 2012 150,000 Options at £2.45
John McLeod ...... 400,000 14 December 2011 250,000 Options at £1.43 21 December 2012 150,000 Options at £2.45
Brian Smith ...... 1,200,000 14 December 2011 900,000 Options at £1.43 21 December 2012 300,000 Options at £2.45
3.3 As at 18 December 2009, the latest practicable date prior to the publication of this document, the following Directors and the Senior Manager hold the following LTIP awards granted pursuant to the terms of the LTIP: Number of Ordinary Share Price on Date of Director/Senior Manager Shares Earliest Vesting Date Grant
Anthony Buckingham ...... 2,347,826 18 June 2011 £3.45 Paul Atherton ...... 1,159,420 18 June 2011 £3.45 Brian Smith ...... 195,651 18 June 2011 £3.45
3.4 Save as set out in this Section 3.4 and in Section 3.1 above, the Company is not aware of any person who has as at 18 December 2009, the latest practicable date prior to the publication of this document, interests which represents 3 per cent. or more of the Voting Share Capital: Number of Ordinary Percentage of Shares Voting Share Shareholder currently held Capital
Albion Energy Limited and Mr Anthony Buckingham ...... 84,540,340 29.4% Capital Research and Management Company ...... 31,920,045 11.10% Landsdowne Partners ...... 28,776,161 10.01% London & Capital Satellites SPC ...... 9,903,861 3.44%
37 3.5 Save as detailed in Sections 3.1 and 3.4 above, the Company is not aware of any person who as at 18 December 2009 (the latest practicable date prior to the publication of this document) exercises, or could exercise, directly or indirectly, jointly or severally, control over the Company.
3.6 Service Contracts/Terms of Employment
Mr Anthony Buckingham entered into an executive service agreement with the Company, dated 28 March 2008, in which he agreed to act as Chief Executive Officer. The agreement is terminable on not less than 24 months’ written notice by the Company at any time or 6 months notice by Mr Buckingham at any time; in addition, the Company may terminate the agreement and make payment in lieu of notice. Mr Buckingham’s annual base package is £675,000 and he is eligible to receive an annual performance-related bonus which will be determined at the discretion of the Board. Mr Buckingham has also been granted options under the Scheme. Mr Buckingham is entitled to the benefits of private medical insurance, life insurance, an allowance in the amount of £100,000 and executive participation in the retirement and welfare benefit schemes of the Company from time to time. In the event of a change of control of the Company, if Mr Buckingham resigns or the Company terminates his appointment within twenty-four months of such change of control, he shall be entitled to an immediate payment in lieu of notice of a sum equivalent to three times his annual base package.
Mr Paul Atherton entered into an executive service agreement with the Company, dated 28 March 2008, in which he agreed to act as Chief Financial Officer. The agreement is terminable on not less than 24 months’ written notice by the Company at any time or 6 months’ notice by Mr Atherton at any time, in addition, the Company may terminate the agreement and make payment in lieu of notice. Mr Atherton’s annual base package is £500,000 and he is eligible to receive an annual performance-related bonus which will be determined at the discretion of the board. Mr Atherton has also been granted options under the Scheme. Mr Atherton is entitled to the benefits of private medical insurance, life insurance, an allowance in the amount of £77,500 and executive participation in the retirement and welfare benefit schemes of the Company from time to time. In the event of a change of control of the Company, if Mr Atherton resigns or the Company terminates his appointment within twenty-four months of such change of control, he shall be entitled to an immediate payment in lieu of notice of a sum equivalent to three times his annual base package.
Mr Michael Hibberd, Mr Gregory Turnbull, Mr John McLeod and General Sir Michael Wilkes are engaged as non-executive directors of the Company under the letters of appointment dated 28 March 2008 respectively. They were each entitled to a one-off payment of £20,000 in 2008 for their work in connection with the Listing. Mr Macki was appointed as a non-executive director in August 2008. Mr Hibberd, Mr Turnbull and Mr McLeod are also each entitled to fees of Cdn$22,500 per annum payable by HOC for their roles as directors of HOC.
Pursuant to these, such non-executive directors each receive an annual fee of £80,000, £50,000, £50,000, £80,000 and £80,000, respectively plus an additional fee of £2,000 respectively (or such other amount as the board in its sole discretion deems appropriate) per day worked in excess of 20 days per annum. Mr Hibberd’s, Mr Turnbull’s, Mr McLeod’s and General Sir Michael Wilkes’ agreements are terminable on three months’ written notice by either party. Subject to early termination, Mr Hibberd, Mr Turnbull, Mr McLeod and General Sir Michael Wilkes were each appointed for an initial period of 2, 1, 1 and 3 years, respectively (and for a period of a further 3 years after the initial term of their appointments if re-appointed after their initial term; Mr Turnbull and Mr McLeod were reappointed at the Company’s annual general meeting held on 18 June 2009). Mr Hibberd and Mr Turnbull are entitled to a change of control bonus (relating to a change of control in HOC) in the amount of $75,000 plus a pro-rata amount of his previous year’s bonus multiplied by a stock price performance factor.
In addition to the fees due to General Sir Michael Wilkes as described above, he also received a payment of £50,000 upon joining the board of the Company in March 2008.
The Directors are not on fixed term contracts, but they are required to retire by rotation in accordance with the Articles.
38 All existing Directors (both executive and non-executive (excluding General Sir Michael Wilkes and Mr Macki who are not directors of HOC)), are entitled to a $75,000 payment in the event they are asked to resign from the board of HOC in any event other than as result of a change of control.
No member of the administrative, management or supervisory bodies’ service contracts with the Company or any member of the Group provide for benefits upon termination of employment.
Save as detailed in this Section 3.6, there are no other service contracts between any of the Directors and the Heritage Group providing for benefit upon termination of employment.
In the financial year ended 31 December 2008, the total remuneration paid (including contingent or deferred compensation) and benefits in kind granted (under any description whatsoever) to each of the Directors and the Senior Manager by members of the Heritage Group was:
Remuneration Paid (Including Contingent Director/Senior Manager or Deferred Compensation) Benefits in Kind
Michael Hibberd(2) ...... Director’s fee of £74,900 — Additional fee of £20,000(5) Anthony Buckingham(6) ...... Base package of £675,000 £134,800(1) Additional fee of £300,000 Paul Atherton(6) ...... Base package of £495,300 £119,600(1) Additional fee of £262,500 General Sir Michael Wilkes(3) ...... Director’s fee of £96,700 — Additional fee of £20,000(5) Gregory Turnbull(2) ...... Director’s fee of £46,400 — Additional fee of £20,000(5) John McLeod(2) ...... Director’s fee of £47,400 — Additional fee of £20,000(5) Salim Hassan Macki(4) ...... Director’s fee of £31,800 — Brian Smith ...... Base package of £250,000 — Additional fee of £152,500
(1) Shows the taxable value of benefits, comprising private medical insurance, school fees for Paul Atherton’s children and life insurance. The figures also include living allowances of £100,000 (Anthony Buckingham) and £77,500 (Paul Atherton) but exclude pension contributions.
(2) Michael Hibberd, Gregory Turnbull and John McLeod receive fees of Cdn$22,500 per annum paid by HOC as directors of that company.
(3) General Sir Michael Wilkes received a payment of £50,000 on joining the board in 2008.
(4) Salim Macki was appointed on 12 August 2008.
(5) Michael Hibberd, Gregory Turnbull, John McLeod and General Sir Michael Wilkes were paid an additional fee of £20,000 for the work they undertook in connection with the Listing.
(6) Anthony Buckingham and Paul Atherton are entitled to receive pension contributions of an annual amount equal to 10 per cent. of their base package which have been excluded from the above table.
39 3.7 Gregory Turnbull is a partner of McCarthy Tétrault LLP, a firm of solicitors which has advised the Heritage Group as to Canadian law since 1996 and in respect of the Disposal. McCarthy Tétrault LLP is a related party of McCarthy Tétrault Registered Foreign Lawyers and Solicitors (together “McCarthy Tétrault”) which has advised the Heritage Group as to English law in respect of the Disposal. McCarthy Tétrault will receive fees from the Company in respect of their advice and will continue to provide services to the Continuing Group following Completion.
3.8 Save for Section 3.7 above, none of the Directors or the Senior Manager have (as at the date of this document) any potential conflicts of interests between their duties to the Company and their private interests or other duties.
4. KEY INDIVIDUALS IN RESPECT OF THE DISPOSED ASSETS
The Heritage Group do not consider that there are any key individuals important to the Disposed Assets.
5. MATERIAL CONTRACTS
5.1 Continuing Group
The following are the only contracts (not being contracts entered into in the ordinary course of business) which have been entered into by members of the Continuing Group within two years immediately preceding the date of this document and which are, or may be, material or which have been entered into at any time by members of the Continuing Group and which contain any provision under which any member of the Continuing Group has any obligation or entitlement which is, or may be, material to the Continuing Group as at the date of this document:
(a) Arrangement Agreement
On 22 February 2008, HOC entered into an arrangement agreement with the Company, DutchCo and Alberta CallCo which provided for the reorganisation of the share capital of the HOC through the Plan of Arrangement pursuant to the Business Corporation Act (Alberta).
(b) Voting and Exchange Trust Agreement
Also in connection with the Arrangement Agreement, HOC entered into a voting and exchange trust agreement with the Company, Alberta CallCo and the Trustee on 27 February 2008. Pursuant to the Voting and Exchange Trust Agreement, the Company issued one Special Voting Share to the Trustee for the benefit of the Beneficiaries. The Special Voting Share has the number of votes, which may be cast at any meeting at which holders of Ordinary Shares are entitled to vote, equal to the number of Exchangeable Shares outstanding at the relevant time.
Each Beneficiary on the record date for any meeting at which holders of Ordinary Shares are entitled to vote will be entitled to instruct the Trustee to exercise those votes attached to the Special Voting Share for each Exchangeable Share held by such Beneficiary or to obtain a proxy from the Trustee entitling the Beneficiary to vote directly, at the relevant meeting, the votes attached to the Special Voting Share to which the Beneficiary is entitled.
All rights of a holder of Exchangeable Shares to exercise votes attached to the Special Voting Share will cease upon the exchange (whether by redemption, retraction or liquidation or through the Exchange Right (defined below)) of such Exchangeable Shares for Ordinary Shares.
The Voting and Exchange Trust Agreement also provides for the grant by the Company to the Trustee of the Exchange Right (the “Exchange Right”), upon HOC facing certain insolvency events, to require the Company to purchase from each Beneficiary all or any part of the Exchangeable Shares held by the Beneficiary. The purchase price payable by the Company for each Exchangeable Share pursuant to the Exchange Right shall be satisfied in full by the Company delivering to each Beneficiary one Ordinary Share for each Exchangeable Share held by such Beneficiary plus, to the extent not paid by HOC, an additional amount equal to the full amount of all declared and unpaid dividends on each such Exchangeable Share.
40 The Voting and Exchange Trust Agreement continues until the earlier of the following:
(i) no outstanding Exchangeable Shares are held by a Beneficiary;
(ii) each of HOC and the Company elects in writing to terminate the trust created by the Voting and Exchange Trust Agreement and such termination is approved by the Beneficiaries; and
(iii) twenty-one (21) years after the date of the Voting and Exchange Trust Agreement.
(c) Support Agreement
In connection with the Arrangement Agreement, HOC, the Company, DutchCo and Alberta CallCo entered into a support agreement on 17 March 2008.
Pursuant to the Support Agreement, for so long as any Exchangeable Shares remain outstanding, the Company has made certain covenants, to the fullest extent permitted by law, in favour of HOC including, but not limited to, the following:
(i) the Company will not declare or pay dividends on Ordinary Shares unless HOC is able to declare and pay and simultaneously declares and pays, as the case may be, an equivalent dividend on the Exchangeable Shares;
(ii) the Company will advise HOC in advance of the declaration of any dividend by the Company; and
(iii) the Company will take all actions and do all things reasonably necessary to enable and permit HOC and Alberta CallCo to perform their obligations, if any, arising upon the liquidation, dissolution or winding-up of HOC, the receipt of a Retraction Request, the exercise by Alberta CallCo of its right to purchase Exchangeable Shares that are the subject of a Retraction Request and the exercise and the exercise by Alberta CallCo of its right to purchase all Exchangeable Shares in the event of the a proposed liquidation, dissolution or winding-up of HOC.
The Company has agreed to take all such actions as are reasonably necessary to cause all Ordinary Shares deliverable in connection with Exchangeable Shares to be listed and posted for trading on all stock exchanges on which outstanding Ordinary Shares are listed. The Company has also agreed not to exercise any voting rights attached to the Exchangeable Shares owned by it or any of its affiliates on any matter considered at meetings of holders of Exchangeable Shares.
Pursuant to the Support Agreement, HOC is required to notify the Company and Alberta CallCo of certain events, such as the liquidation, dissolution or winding-up of HOC and the receipt of a Retraction Request.
The Support Agreement shall continue until such time as no Exchangeable Shares are held by any person or entity other than the Company and its affiliates.
(d) Relationship Agreement with Anthony Buckingham and Albion Energy Limited
Pursuant to the terms of such relationship agreement, Mr Buckingham agreed to exercise all powers of control, and procure (to the extent possible) that Albion Energy Limited exercised all powers of control, in relation to the Company so as to ensure that: (i) at all times each of the Company and the other Heritage Group members was capable of carrying on, and did carry on, its business independently of Mr Buckingham and Albion Energy Limited and any of their associates, having regard to the interests of the Heritage Group, rather than for the benefit of any particular shareholder or group of shareholders in the Company; (ii) at all times the business and affairs of the Company were to be managed by the Board in accordance with the
41 Articles and all applicable law and for the benefit of its shareholders as a whole; (iii) all transactions and relationships between any Heritage Group member and Albion Energy Limited or Mr Buckingham, or any of their associates were conducted on arm’s length terms and on a commercial basis in compliance with the Listing Rules; (iv) the requirements relating to transactions with related parties set out in Listing Rule 11 were complied with in relation to transactions between Mr Buckingham, Albion Energy Limited or any of their associates on the one hand and the Heritage Group on the other hand; and (v) the terms of such relationship agreement were complied with in all respects.
(e) Sponsor’s Agreement for the Listing
On 28 March 2008, the Company, HOC, the Directors and the Sponsor entered into a sponsor agreement, pursuant to which, inter alia:
(i) each of the Company and HOC appointed J.P. Morgan Cazenove as sponsor in connection with their applications for admission;
(ii) the Company confirmed that it had made all relevant applications to the FSA, the LSE, the Jersey Financial Services Commission, TSX, and CRESTCO, in respect of admission, and formal approval for the prospectus and for admission of all the Ordinary Shares and the Exchangeable Shares to the Official List and to the LSE for the admission of all the Ordinary Shares and the Exchangeable Shares to trading on its main market for listed securities;
(iii) HOC confirmed that it had made all relevant applications to the FSA, the LSE, the Jersey Financial Services Commission and CRESTCO, in respect of admission, and formal approval for the prospectus and for admission of all the Exchangeable Shares to the Official List and to the LSE for the admission of all the Exchangeable Shares to trading on its main market for listed securities;
(iv) the Company agreed to pay the Sponsor a management fee of £1,000,000 plus VAT (if applicable) on admission;
(v) the Company agreed to pay (together with any related value added tax) certain costs, charges, fees and expenses, in connection with, or incidental to admission; and
(vi) the Company, HOC and the Directors gave certain warranties and undertakings to the Sponsor and the Company and HOC have on a joint and several basis given certain indemnities to the Sponsor that are typical of an arrangement of this nature.
(f) Placing Agreement for 2007 Equity Financing
On 14 November 2007, HOC completed an equity financing raising proceeds of Cdn$181.5 million from the issue of 3,000,000 HOC Common Shares. As part of the same transaction, Mr Anthony Buckingham via Albion Energy Limited sold 3,000,000 HOC Common Shares that it held, reducing its interest from 52 per cent. to 33.2 per cent. of the issued and outstanding HOC Common Shares.
The placing agreement for this financing contains customary warranties and undertakings which were given by HOC and the Directors as to the accuracy of the information contained in the placing agreement and other matters relating to the HOC Common Shares, the Heritage Group and its business.
(g) Facility Agreements
In October 2007, a wholly-owned subsidiary of HOC received a loan of $9,450,000 to refinance the acquisition of a private corporate jet delivered in 2007. Interest on the loan is variable at a rate of LIBOR plus 1.6 per cent. The loan, which is secured on the aircraft, is
42 scheduled to be repaid by 20 consecutive quarterly instalments of principal. Each instalment equals to $117,500 with the final instalment being $7,217,500. HOC provided a corporate guarantee to the lender.
In November 2007, a bank guarantee for $3,037,500 to cover 50 per cent. of the Heritage Group’s share of the Sanjawi work programme in Pakistan was provided by Standard Bank Jersey Limited on behalf of HOGL upon awarding of the Sanjawi licence. The cash-backed bank guarantee has a term until 31 December 2010.
In November 2006, a subsidiary of HOC received a loan facility of $200 million from HOGL for exploration and development purposes in the Zapadno Chumpasskoye field as well as to support the operational and commercial activities of the subsidiary and other activities agreed in advance by the parties. Interest on the loan is variable at a rate of LIBOR plus 4 per cent. The loan facility is scheduled to be repaid by instalments determined at HOGL’s discretion over a 30 year period.
In July 2007, a wholly-owned subsidiary of HOC granted separate charges over its holding of shares in SeaDragon in favour of ABN AMRO and Lloyds TSB Bank plc. These charges were made to support an overdraft facility of $6 million for use by Gander Drilling Limited, a wholly-owned subsidiary of SeaDragon.
(h) Placing Agreement for 2009 Equity Financing
On 18 June 2009, the Company completed an equity financing raising gross proceeds of £132 million from the issue of 25,400,000 Ordinary Shares.
On 15 June 2009, the Company, J.P. Morgan Cazenove and J.P. Morgan Securities Limited entered into a placing agreement for this financing, which contained customary warranties, indemnities and undertakings given by the Company as to the accuracy of the information contained in the placing announcement and other matters relating to the Ordinary Shares, the Heritage Group and its business. J.P. Morgan Cazenove was paid a commission of five per cent. of the gross proceeds.
(i) Disposal Agreement
Under the terms of the Disposal Agreement, the Heritage Group has agreed to sell the Disposed Assets to Eni. The consideration for the Disposal is up to $1.5 billion, of which $1.35 billion (subject to adjustments to account for certain payables, receivables and other items) will be payable in cash at Completion and a further conditional, deferred amount of up to $150 million will be paid in cash or by way of the transfer to the Heritage Group of an interest in an oil producing field independently valued at a similar amount, on the satisfaction of certain conditions within two years of Completion.
Completion may not occur unless, among other conditions, each of the following conditions has been satisfied:
• the receipt of consent to the Disposal from the Government of Uganda;
• there having been no occurrence after the date of the Disposal Agreement that would constitute a material adverse effect, as defined in the Disposal Agreement;
• Tullow having waived or declined to exercise its Pre-Emption Right; and
• the approval by Shareholders of Resolution 1.
The Heritage Group has agreed, between the date of execution of the Disposal Agreement and Completion, to carry on the operation of the Disposed Assets in all respects in the ordinary and usual course in the manner in which they have been carried on prior to the date of the Disposal
43 Agreement and in accordance with good oil industry practice and the respective licence documents. The Heritage Group has provided Eni with customary warranties in relation to the Disposal, and Eni has on the date of the Disposal Agreement agreed to deliver to HOGL a guarantee in support of its obligations under the Disposal Agreement by an entity with a credit rating of at least A+ from Standard & Poor’s Corporation. A guarantee given by Eni S.p.A. has been provided pursuant to this provision.
The payment of the full amount of the Deferred Consideration is conditional on the relevant authorities within the Ugandan Government granting or agreeing to grant to Eni, within a period of two years from the date of Completion, full exemption or relief from direct and indirect taxation for all upstream, midstream and downstream activities relating to the Disposed Assets.
The amount of the Deferred Consideration will depend on the scale of the tax incentives negotiated.
There can be no assurance that the Deferred Consideration will become payable and, if it is payable, how much Deferred Consideration will be paid. Whilst Eni is obliged under the Disposal Agreement to use its reasonable efforts to negotiate the granting of the tax incentives as soon as possible, the satisfaction of the conditions to the payment of the Deferred Consideration is not within the control of the Heritage Group.
Should any Deferred Consideration become payable on the grant of the tax incentives, Heritage and Eni will agree whether it should be paid in cash or by the assignment by Eni (or an affiliate of Eni) of an interest in one or more oil producing assets. If Heritage and Eni are unable, within 90 days of Eni notifying Heritage of receipt of the tax incentives, to agree and satisfy the terms and conditions of any such assignment, payment of the Deferred Consideration shall be made in cash by Eni. Any such assignment of an interest in a producing field would be subject to the provisions of the Listing Rules and may require, inter alia, Shareholder approval. If in such circumstances Shareholder approval is not granted, the Deferred Consideration will be paid in cash.
If Eni transfers, or enter into negotiations to transfer, all or any portion of the Disposed Assets within the period of two years from the date of Completion at a time when payment of the Deferred Consideration has not been made, the whole of the Deferred Consideration will immediately become payable on the above terms.
Each of the Heritage Group and Eni may terminate the Disposal Agreement in the following circumstances:
• the conditions precedent to Completion are not satisfied by the other party six months from 18 December 2009 (or such later date as will allow such reasonable additional period as may be required to secure necessary Government consents); or
• the obligations on the other party for Completion are not complied with within five business days following the satisfaction (or waiver) of the conditions precedent to Completion.
Eni may terminate the Disposal Agreement if:
• the Board or the board of HOGL solicits superior proposals for the Disposed Assets (in which case the payment of a break payment (as described below) is payable);
• as a result of a third party exercising its rights over any part of the Disposed Assets and/or any third party does not consent to the Disposal and/or as a result of the nature of the Ugandan Government’s consent to the Disposal, the Heritage Group is only entitled to assign its interest in one or part of one PSC in Uganda;
44 • there is a breach of a core warranty or there is material breach of a warranty given on the date of the Disposal Agreement or matters occur between the date of the Disposal Agreement and Completion which would otherwise constitute a breach of the warranties if deemed repeated at Completion and such breaches have a material adverse effect in respect of the Disposed Assets; • a material adverse effect occurs in respect of the Disposed Assets; • there is a material breach or non-fulfilment of the material obligations under the Disposal Agreement on the part of the Heritage Group; or • the General Meeting has not been convened and held and/or the Shareholders have not considered and voted on Resolution 1 by 31 January 2010 unless the Company is prohibited by law from convening such meeting.
The Heritage Group may terminate the Disposal Agreement in order to enter into an agreement to implement a superior proposal for a sale of the Disposed Assets to a third party in certain circumstances, which right shall cease upon the Shareholders passing Resolution 1. In the event that the Heritage Group terminates the Disposal Agreement for this purpose, a break payment (as described below) is payable.
The Heritage Group has agreed to pay Eni a break payment of up to one per cent. of the Company’s market capitalisation on the close of business on 17 December 2009, being the last business day prior to the announcement of the Disposal (the “Break Payment”) in certain circumstances, including: • in the event that the General Meeting has not been convened and held and/or the Shareholders have not considered and voted on Resolution 1 by 31 January 2010 (unless the Company is prohibited by law from convening the General Meeting) and Eni elects to terminate the Disposal Agreement; • in the event that the Board or the board of HOGL (i) fails to recommend the Disposal; and (ii) withdraws, modifies or changes its recommendation of the Disposal in a manner adverse to Eni; • in the event that the Company terminates the Disposal Agreement in connection with a superior proposal for the Disposed Assets; and • in the event that the Board or the board of HOGL solicits proposals for the Disposed Assets, and Eni terminates the Disposal Agreement.
In the event that Tullow exercises its Pre-Emption Right, the Break Payment shall not be payable to Eni.
(j) J.P. Morgan Cazenove Engagement Letter for the Disposal
On 18 December 2009, the Company signed an engagement letter with J.P. Morgan Cazenove, pursuant to which, inter alia the Company appointed J.P. Morgan Cazenove as sponsor and financial adviser in connection with the Disposal.
5.2 Disposed Assets
Other than those contracts described in Sections 5.1(i) and 5.1(j) above, there are no contracts (not being contracts entered into in the ordinary course of business) that relate specifically to the Disposed Assets which have been entered into by members of the Heritage Group within two years immediately preceding the date of this document and which are, or may be, material or which have been entered into at any time by members of the Heritage Group and which contain any provision under which any member of the Heritage Group has any obligation or entitlement which is, or may be, material in relation to the Disposed Assets as at the date of this document.
45 6. RELATED PARTY TRANSACTIONS
In the financial year ended 31 December 2008, the Company incurred transportation costs of US$134,978 with respect to the services provided by a company indirectly owned by Mr Anthony Buckingham, CEO and a Director of the Company.
On 9 March 2007, the Heritage Group acquired 605,000 common shares of SeaDragon through the sale of its 65 per cent. interest in Natural Pipelay Worldwide Limited and Naturalay Technologies Limited. At the time of the acquisition, Mr Paul Atherton was a director of both HOC and SeaDragon.
In the financial years ended 31 December 2006 and 31 December 2007, Mr Anthony Buckingham (who was appointed CEO of HOC on 6 October 2006) charged HOC advisory fees of US$1,494,317 and US$1,878,560, respectively.
7. LITIGATION
7.1 Continuing Group
As at the date of this document, Mr Michael Gulbenkian, a former chairman and CEO of HOC, who was dismissed on 6 October 2006, has commenced two arbitration procedures and separate court proceedings against the Heritage Group in Switzerland and Canada. In the first arbitration the sole arbitrator has not been appointed yet (after waiver of the first three arbitrators) and at the date of this document no formal statement of claim has been served on the Heritage Group in the first arbitration procedure whereas the parties have already exchanged two sets of written pleadings and witness hearings commenced in September 2009 in connection with a second arbitration. A statement of claim and statement of defence have been filed in the Canadian proceedings. The Heritage Group is defending all these cases. The Directors do not know what the potential outcome of these claims will be and the Heritage Group, and following Completion, the Continuing Group will continue defending any action.
Save as set out in the preceding paragraph, as at the date of this document neither the Company nor any member of the Heritage Group is or has been involved in any governmental, legal or arbitration proceedings (including any such proceedings which are pending or threatened of which the Company is aware) which may have, or have had during the 12 months prior to the date of this document, a significant effect on the Company and/or the Continuing Group’s financial position or profitability.
7.2 Disposed Assets
The Heritage Group is not and has not been engaged in, nor so far as the Company is aware, has pending or threatened, any governmental, legal or arbitration proceedings relating specifically to the Disposed Assets which may have, or have had during the 12 months preceding the date of this document, a significant effect on the gross book value of the Disposed Assets.
8. CONSENTS
8.1 KPMG Audit Plc is a member firm of the Institute of Chartered Accountants of England and Wales and has given and not withdrawn its written consent to the inclusion of its report set out in “Pro Forma Financial Information for the Continuing Group” in Part IV, in the form and context in which it appears and has authorised the contents of that part of this document which comprise of its report for the purposes of paragraph 13.4.1R(6) of the Listing Rules.
8.2 RPS has given and has not withdrawn its written consent to the inclusion of its report set out in “Technical Report—Heritage Group” in Part VI, in the form and context in which it appears and RPS has authorised those parts of this document which comprise of its report for the purpose of paragraph 13.4.1R(6) of the Listing Rules.
8.3 J.P. Morgan Cazenove has given and not withdrawn its written consent to the inclusion in this document of its name and the references thereto in the form and context in which they appear.
46 9. SIGNIFICANT CHANGE
9.1 Continuing Group
There has been no significant change in the financial or trading position of the Continuing Group since 30 June 2009, the date to which the Heritage Group’s interim financial statements and the RPS Report have been prepared.
9.2 Disposed Assets
There has been no significant change in the gross book value of the Disposed Assets since 30 June 2009, the date to which the financial statements contained in Part III of this document were prepared and the date of the RPS Report.
10. DOCUMENTS AVAILABLE FOR INSPECTION
Copies of the following documents will be available for inspection during normal business hours on any weekday (Saturday, Sundays and public holidays excepted) at the offices of McCarthy Tétrault, 2nd Floor, 5 Old Bailey, London EC4M 7BA up to and including 25 January 2010:
(a) the Memorandum and Articles of the Company;
(b) the report from RPS set out in Part VI of this document;
(c) the report from KPMG Audit Plc set out in Part IV of this document;
(d) the audited consolidated accounts of the Heritage Group for the three financial years ended 31 December 2006, 31 December 2007 and 31 December 2008 and the unaudited consolidated interim accounts of the Heritage Group for the six month period ended 30 June 2009;
(e) the service agreements and terms of appointment for the Directors;
(f) the Disposal Agreement;
(g) the consent letters referred under “Consents” at Section 8 above; and
(h) this document.
47 PART VI—TECHNICAL REPORT—HERITAGE GROUP
Set out on the following pages is the statement of reserves data and other oil and gas information in relation to the Heritage Group (including the Disposed Assets), effective 30 June 2009, prepared in accordance with the PRMS.
48 The Directors Heritage Oil Plc Fourth Floor, Windward House, La Route de la Liberation Jersey, JE2 3BQ Channel Islands
J.P. Morgan Cazenove Limited 20 Moorgate London EC2R 6DA
Project Ref: ECV1522 December 21st 2009
Gentlemen,
EVALUATION OF HERITAGE OIL CORPORATION’S PETROLEUM ASSETS
In response to your request, and the subsequent Letter of Engagement dated June 10th 2009, RPS Energy (“RPS”) has completed an independent evaluation of certain oil and gas properties in Russia, Uganda and Kurdistan in which Heritage Oil Plc (“Heritage”) has an interest (“the Properties”). This report is prepared as a mineral expert’s report in accordance with the recommendations of the European Commission’s Regulations on Prospectuses No 809/2004 published by the Committee of European Securities Regulators (“CESR”).
We have estimated a range of reserves and resources as at June 30th 2009, based on data and information available up to that date.
In estimating resources we have used standard petroleum engineering techniques, which combine geological and production data with information concerning fluid characteristics and reservoir pressure, where available. We have estimated the degree of uncertainty inherent in the measurements and interpretation of the data and have calculated a range of reserves and resources and risk factors in accordance with the 2007 SPE/WPC/AAPG/SPEE Petroleum Resource Management System (See Section 2.2).
We have taken the working interest that Heritage has in the Properties, as presented by Heritage, and we have not investigated nor do we make any warranty as to Heritage’s interest in the Properties.
The data set included geological, geophysical and engineering data, together with reports and presentations pertaining to the contractual and fiscal terms applicable to the assets. In carrying out this review RPS has relied solely upon this information.
RPS prepared a Competent Person’s Report for Heritage in February 2008. That report, dated 28th March 2008, formed part of the prospectus for Heritage’s listing on the London Stock Exchange.
49 Summary of Reserves and Resources
Reserves
The gross reserves and the net reserves attributable to Heritage are in Zapadno Chumpasskoye in Russia and are given in Table 1.
Heritage Net Gross Working Remaining Interest Reserves Reserves Proved Reserves (1P) 24.7 23.4 Proved plus Probable Reserves (2P) 63.4 60.6 Proved plus Probable plus Possible Reserves (3P) 172.6 164.0
Table 1: Summary of Reserves for Zapadno Chumpasskoye Field as of 30th June 2009
Resources
A summary of the gross Contingent Resources and the net working interest Contingent Resources in Heritage’s Properties is given in Table 2.
Gross Estimate Heritage (MMstb) Equity Working Interest Share (%) (MMstb) Operator 1C 2C 3C 1C 2C 3C (Low) (ML) (High) (Low) (ML) (High) Block 3, Uganda1 Kingfisher2 95 189 340 501 47 95 170 Heritage Block 1, Uganda1 Buffalo/Giraffe 163 479 1,000 50 82 240 500 Heritage Warthog 17 37 67 50 9 19 34 Heritage Kurdistan3 Miran West 33 71 123 75 25 53 92 Heritage Arithmetic Total4 308 776 1,531 163 407 796 Notes 1 The government has the right to back-in for up to 15% which would reduce the Heritage net working interest to 42.5% 2 Statistical consolidation of Kingfisher North and South culminations 3 The government has the right to back-in which could reduce the Heritage net working interest to 56.25% 4 Arithmetic summation of individual probabilistically estimated 1C, 2C and 3C quantities will not produce a total P90, P50 and P10. The process of statistical addition will, as a result of the central limit theorem, produce a P90 that is greater than the arithmetic sum of all P90 quantities and a P10 that is less than the arithmetic sum of all P10 quantities. However, despite this PRMS suggests that arithmetic summation of these quantities should be undertaken on a portfolio scale
Table 2: Summary of Contingent Resources Reviewed by RPS
A summary of the gross Prospective Resources and Heritage’s equity interest Prospective Resources1 that have been reviewed by RPS is given in Table 3 along with the RPS estimate of Geological Probability of Success (GPoS).
1 In the event of discovery and development Heritage net entitlement resources will be a function of the contract terms and will be less than the net working interest resources.
50 Gross Estimate Heritage Working Interest Share Low Best High Low Best High GPoS3 (P90) (P50) (P10) Mean (P90) (P50) (P10) Mean (%) Block 3A, Uganda1 Pelican 6 76 275 96 3 38 138 48 63 Crane 15 158 1,001 290 8 79 500 145 31 Heron 8 44 182 61 4 22 91 31 10 Block 1, Uganda1 Warthog North 28 73 158 77 14 37 79 38 47 Buffalo East5 125 449 1,086 476 74 264 640 280 12 Crocodile5 9 25 60 27 5 13 30 14 37 Crocodile East5 68 213 512 231 34 107 256 116 12 Leopard5 21 60 139 65 11 30 70 33 37 Kob 2 7 16 7 1 4 8 4 41 Sub-total Unrisked Mean Uganda4 1,472 737 Miran Block, Kurdistan2 Miran West (deeper zones) 303 1,134 2,767 1,253 227 851 2075 940 85 Miran East 56 301 982 394 42 226 737 296 36 Sub-total Unrisked Mean Kurdistan4 1,647 1,236
Total Unrisked Mean4 3,119 1,973 Notes 1. The government has the right to back-in for up to 15% which would reduce the Heritage net working interest to 42.5% 2. The government has the right to back-in which could reduce the Heritage net working interest to 56.25% 3. The chance or probability of discovering hydrocarbon volumes within the range defined. This is not an estimation of commercial chance of success 4. Arithmetic summation of individual P90, P50 and P10 quantities will not produce a total P90, P50 and P10. The process of statistical addition will, as a result of the central limit theorem, produce a P90 that is greater than the arithmetic sum of all P90 quantities and a P10 that is less than the arithmetic sum of all P10 quantities. The arithmetic sum of the mean quantities however is always equal to the mean of the distribution produced by the process of statistical addition. 5. The Block 1 resources highlighted have been quoted net of 15% losses for steam generation All assets operated by Heritage
51 Table 3: Summary of Prospective Resources Reviewed by RPS (MMstb)
As it is statistically incorrect to sum the P90, P50 and P10 volumes, the risked recoverable Contingent and Prospective resources in Blocks 1 and 3A in Uganda have been consolidated stochastically and are quoted in Table 4 and for Kurdistan in Table 5.
Heritage Gross Estimate5 Working Interest Share1 Low Best High Low Best High (P90) (P50) (P10) Mean (P90) (P50) (P10) Mean Block 1, Uganda Contingent Resources2 175 444 887 499 88 222 444 250 Prospective Resources3 0 82 478 179 0 41 239 90 Consolidated Sub-total4 227 563 1,102 678 114 282 551 339 Block 3A, Uganda Contingent Resources2 95 189 340 210 48 95 170 105 Prospective Resources3 0 77 457 197 0 39 229 99 Consolidated Sub-total4 125 340 773 407 63 170 387 204 Consolidated Total 530 993 1,789 1,085 265 497 895 543 Notes 1. In the event of discovery and development, Heritage net entitlement resources will be a function of the contract terms and will be less than the net working interest resources. 2. Stochastic consolidation of Contingent Resources with GPoS of 100% 3. Stochastic consolidation of Prospective Resources with appropriate GPoS for each prospect 4. Stochastic consolidation of Contingent Resources and risked Prospective Resources 5. Block 1 resources are quoted net of 15% losses for steam generation where applicable
Table 4: Stochastically Consolidated Risked Resources in Uganda (MMstb)
Heritage Working Interest Share1 Low Best High (P90) (P50) (P10) Mean Contingent Resources2 25 53 92 53 Prospective Resources3 87 849 2,248 850 Consolidated Sub-total4 128 902 2,306 1,014 1. In the event of discovery and development, Heritage net entitlement resources will be a function of the contract terms and will be less than the net working interest resources. The KRG has the right to back-in for up to 25% which could, if exercised, reduce Heritage’s working interest to 56.25% 2. Stochastic consolidation of Contingent Resources with GPoS of 100% 3. Stochastic consolidation of Prospective Resources with appropriate GPoS for each prospect 4. Stochastic consolidation of Contingent Resources and risked Prospective Resources
52 Table 5: Stochastically Consolidated Risked Resources in Kurdistan (MMstb)
Valuation
Economic valuation of reserves and resources are linked to a long term price forecast for Brent. The RPS Base Case price, used for all valuations presented in this report, is given in Table 6.
US$/bbl, MOD 2H 2009 65.00 2010 72.00 2011 78.00 2012 84.00 2013 86.00 2014 88.00 2015 90.09 2016 91.89 2017 93.73 2018 95.61 2019 97.52 2020 99.47 2021 101.46 2022 onwards + 2% p.a.Š
Table 6: RPS Price Base Case Forecasts (US$/bbl Money of the Day)
Reserves
The post-tax Net Present Values (NPV) of Heritage’s Reserves at various discount rates, applying the Heritage Base Case price forecasts, are tabulated in Table 7.
Economic Post-Tax Net Present Value Limit (US$ Million, Money of the Day) 0% 5.0% 7.5% 10.0% 15.0% Proved Reserves (1P) 2030 238 128 90 60 18 Proved plus Probable Reserves (2P) 2031 844 503 388 298 174 Proved plus Probable plus Possible Reserves (3P) 2034 3,005 1,624 1,225 935 560
53 Table 7: Post-Tax Valuation (Net Heritage Share) of Heritage’s Reserves as of 30th June 2009
Contingent Resources
The Contingent Resources in Uganda have been valued separately on a standalone basis and the 1C, 2C and 3C values at the Base Case price are summarised in Table 8.
Post-Tax Net Present Value Economic Limit Net Heritage Share (US$ Million, Money of the Day) Discount rate 0.0% 5.0% 7.5% 10.0% 15.0% 1C Resources Block 1, Buffalo/Giraffe 2039 1,207 552 377 257 112 Block 1, Warthog 2027 121 60 41 25 5 Block 3A, Kingfisher 2029 568 334 255 190 103 2C Resources Block 1, Buffalo/Giraffe 2040 3,126 1,383 947 639 312 Block 1, Warthog 2035 312 168 123 89 47 Block 3A, Kingfisher 2037 1,549 843 635 482 284 3C Resources Block 1, Buffalo/Giraffe 2040 4,703 1,894 1,251 841 385 Block 1, Warthog 2037 451 246 184 140 78 Block 3A, Kingfisher 2037 2,810 1,353 971 710 389
Table 8: Ugandan Contingent Resources Post-Tax Valuation (Net Heritage Share)
The Contingent Resources in Miran West have been valued separately on a standalone basis and the 1C, 2C and 3C values are summarised in Table 9. The values are unrisked and do not include any chance of development.
Post-Tax Net Present Value Economic Limit Net Heritage Share (US$ Million, Money of the Day) Discount rate 0.0% 5.0% 7.5% 10.0% 15.0% 1C Resources 2028 233 119 79 46 -1 2C Resources 2028 738 455 357 280 169 3C Resources 2035 1,225 751 597 478 308
Table 9: Miran West Contingent Resources Post-Tax Valuation (Net Heritage Share)
Prospective Resources
The Expected Mean Value of the Prospective Resources Post-Tax at 10% Discount Rate is given in Table 10.
Expected Value (Post-Tax @ 10% Discount Rate) Uganda Block 1 258 Block 3A 227 Kurdistan Miran West 3,645 Miran East 479
54 Table 10: EMV (Post Tax at NPV10) of Prospective Resources (Net Heritage Share)
Summary of Expected Value of Assets in Uganda and Kurdistan
A summary of the expected value of Heritage’s Ugandan assets Post-Tax at 10% Discount Rate is given in Table 11.
Post-Tax Net Present Value @10% Discount Rate Net Heritage Share (US$ Million, MOD) Block 1 Block 3A Blocks 1 and 3A Expected Value Expected Value Total Expected (Mean) (Mean) Value (Mean) Contingent Resources 662 464 1,126 Prospective Resources 258 227 485 Total PSC 920 691 1,611 The expected value of the Total PSC is the probability weighted mean of the value of all possible outcomes of the Contingent Resources plus the drilling of the Prospective Resources. This is also known as the EMV. The expected value of the Contingent Resources represents the probability weighted mean value of the resource volume range. This is sometimes known as the ENPV.
Table 11: EMV (Post Tax at NPV10) of Assets in Uganda (Net Heritage Share)
A summary of the expected value of Heritage’s assets in Kurdistan Post-Tax at 10% Discount Rate is given in Table 12.
Post-Tax Net Present Value @10% Discount Rate Net Heritage Share (US$ Million, MOD) Miran West Miran East Miran Total Expected Value Expected Value Expected Value (Mean) (Mean) (Mean) Contingent Resources 275 0 275 Prospective Resources 3,645 479 4,125 Total PSC 3,920 479 4,400 The expected value of the Total PSC is the probability weighted mean of the value of all possible outcomes of the Contingent Resources plus the drilling of the Prospective Resources. This is also known as the EMV. The expected value of the Contingent Resources represents the probability weighted mean value of the resource volume range. This is sometimes known as the ENPV.
Table 12: EMV (Post Tax at NPV10) of Assets in Kurdistan (Net Heritage Share)
Qualifications
RPS is an independent consultancy specialising in petroleum reservoir evaluation and economic analysis. Except for the provision of professional services on a fee basis, RPS does not have a commercial arrangement with any other person or company involved in the interests that are the subject of this report. Mr Roy Kelly, Technical Director, Reservoir Engineering for RPS Energy, has supervised the evaluation.
Mr. Kelly has over 26 years oil and gas experience with international oil companies, as well as with international consultancies. He is a Member of the Society of Petroleum Engineers and a Fellow of the Energy Institute, as well as being a Chartered Petroleum Engineer. Other RPS Energy employees involved in this work hold at least a Masters degree in geology, geophysics, petroleum engineering or a related subject or have at least five years of relevant experience in the practice of geology, geophysics or petroleum engineering.
Basis of Opinion
The evaluation presented herein reflects our informed judgement based on accepted standards of professional investigation, but is subject to generally recognised uncertainties associated with the interpretation of geological,
55 geophysical and engineering data. The evaluation has been conducted within our understanding of petroleum legislation, taxation and other regulations that currently apply to these interests. However, RPS is not in a position to attest to the property title, financial interest relationships or encumbrances related to the properties. Our estimates of reserves and resources and value are based on the data set available to, and provided by, Heritage. We have accepted, without independent verification, the accuracy and completeness of these data.
The report represents RPS’ best professional judgement and should not be considered a guarantee or prediction of results. It should be understood that any evaluation, particularly one involving exploration and future petroleum developments, may be subject to significant variations over short periods of time as new information becomes available. This report relates specifically and solely to the subject assets and is conditional upon various assumptions that are described herein. The report, of which this letter forms part, must therefore be read in its entirety. Except with permission from RPS, this report may not be reproduced or redistributed, in whole or in part, to any other person or published, in whole or in part, for any purpose without the express written consent of RPS. However in instances where excerpts only are to be reproduced or published, other than in relation to the circular and prospectus in connection with the acquisition of Aztec, this cannot be done without the express permission of RPS. The report was provided for the sole use of Heritage and its advisors on a fee basis,
RPS accepts responsibility for the information contained in the RPS report set out in this part of this document and to the best knowledge and belief of RPS, having taken all reasonable care to ensure that such is the case, the information contained herein is in accordance with the facts and does not omit anything likely to affect the import of such information.
Yours faithfully,
RPS Energy
EurIng Roy T. Kelly, CEng, FEI Technical Director
56 Table of Contents
1. DESCRIPTION OF ASSETS ...... 65 1.1. Liabilities ...... 68 2. METHODS USED IN THIS REPORT ...... 69 2.1. General ...... 69 2.2. Reserves and Resource Classification ...... 69 2.3. Risk Assessment ...... 69 2.3.1. Contingent Resources ...... 69 2.3.2. Prospective Resources (Exploration Prospects) ...... 69 2.4. Uncertainty Estimation ...... 70 3. ZAPADNO CHUMPASSKOYE ...... 71 3.1. Data Available ...... 71 3.2. Geology ...... 71 3.2.1. Regional Setting ...... 71 3.2.2. Zapadno Chumpasskoye Field ...... 71 3.2.3. Petrophysics ...... 72 3.3. In Place Volumes ...... 74 3.4. Petroleum Engineering ...... 75 3.4.1. Reservoir Fluid Properties ...... 75 3.4.2. Well Performance & Deliverability ...... 75 3.4.3. Development Plan (Subsurface) ...... 77 3.4.4. Recovery Mechanisms ...... 77 3.4.5. Production Profiles ...... 78 3.4.6. Developmental Risk ...... 80 4. UGANDA—BLOCKS 1 AND 3A ...... 81 4.1. Overview ...... 81 4.2. Geological Setting ...... 81 4.3. Data Available ...... 82 4.3.1. Block 3A ...... 82 4.3.2. Block 1 ...... 82 4.4. Block 3A ...... 82 4.4.1. Kingfisher Discovery ...... 83 4.4.1.1. Mapping ...... 86 4.4.1.2. Depth Conversion ...... 87 4.4.1.3. Reservoir Quality ...... 88 4.4.1.4. Saturation ...... 88 4.4.1.5. Fluid Contacts ...... 89
57 4.4.1.6. Kingfisher Field In-place Volumes ...... 90 4.4.1.7. Kingfisher South Culmination—Recovery Factors and Resources ...... 92 4.4.1.8. Kingfisher South Development Concept ...... 92 4.4.1.9. Kingfisher South Production Forecasts ...... 94 4.4.1.10. Kingfisher North Culmination ...... 94 4.4.1.11. Kingfisher South Development—Facilities and Cost Assumptions ...... 95 4.4.1.12. Kingfisher North Development—Facilities and Cost Assumptions ...... 97 4.4.2. Exploration Prospectivity ...... 97 4.4.2.1. Pelican Prospect ...... 98 4.4.2.2. Crane ...... 101 4.4.2.3. Heron ...... 103 4.4.2.4. Exploration Prospects Recovery Factors and Resources ...... 104 4.4.2.5. Development Concepts for Prospective Resources ...... 104 4.4.2.6. Production Forecasts ...... 105 4.4.2.7. Kingfisher North and Exploration Prospects—Facilities and Cost Assumptions ...... 106 4.5. Block 1 ...... 107 4.5.1. Well Results ...... 107 4.5.2. Structural Mapping ...... 110 4.5.3. Block 1 Prospectivity ...... 111 4.5.4. In-Place Volumes ...... 111 4.5.5. Buffalo-Giraffe Recovery Factor and Resources ...... 112 4.5.6. Buffalo-Giraffe Development Concept ...... 112 4.5.7. Buffalo Giraffe Production Forecasts ...... 114 4.5.8. Warthog Recovery Factor and Resources ...... 114 4.5.9. Warthog Development Concept ...... 115 4.5.10. Warthog Production Forecasts ...... 115 4.5.11. Block 1 Prospects Recovery Factor and Resources ...... 115 4.5.12. Block 1 Prospects Development Concept ...... 116 4.5.13. Block 1 Prospects Production Forecasts ...... 117 4.5.14. Block 1 Facilities and Cost Assumptions ...... 120 5. KURDISTAN—MIRAN BLOCK ...... 121 5.1. Available Data ...... 121 5.2. Miran West ...... 121 5.2.1. Miran West-1 Drill Stem Tests ...... 123 5.3. Structural Interpretation ...... 123 5.4. Oil Water Contacts ...... 124 5.5. In Place Volumes ...... 124 5.5.1.1. Miran West ...... 126 5.5.1.2. Miran East ...... 126
58 5.6. Reservoir Engineering ...... 126 5.6.1. Miran West Recovery Factor and Resources ...... 126 5.6.2. Miran West Development Concept ...... 128 5.6.3. Production Forecasts ...... 129 5.7. MIRAN EAST ...... 131 5.7.1. Recovery Factor and Resources ...... 131 5.7.2. Development Concept ...... 131 5.7.3. Production Forecasts ...... 132 5.8. Facilities and Cost Estimates ...... 132 5.8.1. Capital Expenditure ...... 133 5.8.2. Operating Costs ...... 133 5.8.3. Abandonment Costs ...... 133 6. ECONOMICS ...... 134 6.1. Valuation Assumptions ...... 134 6.1.1. General ...... 134 6.1.2. Oil Prices ...... 134 6.2. Valuation Methodology ...... 135 6.2.1. Reserves ...... 135 6.2.2. Contingent and Prospective Resources ...... 136 6.3. Russia—Zapadno Chumpasskoye ...... 136 6.3.1. Fiscal Regime and Contract Terms ...... 136 6.3.2. Price Assumptions ...... 137 6.3.3. Transportation Costs ...... 138 6.3.4. Exchange rate and Tax Losses ...... 138 6.3.5. Valuation Summary ...... 138 6.3.6. Sensitivity to Oil Price ...... 138 6.4. Uganda—Blocks 1 and 3A ...... 139 6.4.1. Fiscal Regime and Contract Terms ...... 139 6.4.2. Price Assumptions ...... 139 6.4.3. Sunk Costs ...... 140 6.4.4. Valuation Summary ...... 140 6.4.5. Third Party Pipeline Tariffs ...... 141 6.4.5.1. Phase 1 ...... 141 6.4.5.2. Phase 2/3 ...... 141 6.4.6. Capital Costs ...... 141 6.4.6.1. Kingfisher South ...... 141 6.4.6.2. Block 1 Contingent and Prospective Resources ...... 141 6.4.6.3. Block 3A Prospective Resources and remaining Contingent resources in Kingfisher . . 142
59 6.4.7. Operating Costs ...... 142 6.4.7.1. Kingfisher South ...... 142 6.4.7.2. Block 1 Contingent and Prospective Resources ...... 142 6.4.7.3. Block 3A Prospective Resources and remaining Contingent Resources in Kingfisher ...... 142 6.4.8. Abandonment Costs ...... 142 6.4.9. Valuation Results ...... 142 6.4.9.1. Block 3A Contingent Resources ...... 142 6.4.9.2. Sensitivity to Oil Price ...... 143 6.4.9.3. Block 3A Prospective Resources ...... 143 6.4.9.4. Block 1 Contingent Resources ...... 144 6.4.9.5. Sensitivity to Oil Price ...... 145 6.4.9.6. Block 1 Prospective Resources ...... 145 6.5. Kurdistan—Miran Block ...... 146 6.5.1. Fiscal Regime and Contract Terms ...... 146 6.5.2. Price Assumptions ...... 147 6.5.3. Sunk Costs ...... 147 6.5.4. Valuation summary ...... 147 6.5.4.1. Contingent resources ...... 147 6.5.4.2. Sensitivity to Oil Price ...... 148 6.5.4.3. Prospective Resources ...... 148 APPENDIX A: GLOSSARY OF TECHNICAL TERMS ...... 149 APPENDIX B: SPE/WPC/AAPG/SPEE RESERVE/RESOURCE DEFINITIONS ...... 152
60 List of Figures
Figure 1-1: Russian Licence Location Map ...... 66 Figure 1-2: Kurdistan Licence Location Map ...... 67 Figure 1-3: Ugandan and DRC Licences Location Map ...... 68 Figure 3-1: Lower J1 Sand—RPS Net Pay Map (P50 Case) ...... 73 Figure 3-2: CPI for Well P3 over Reservoir Interval for P50 Saturation Case ...... 74 Figure 3-3: Zapadno Chumpasskoye Production History (Rate versus Time) ...... 76 Figure 3-4: Zapadno Chumpasskoye Production History (Rate versus Cumulative) ...... 76 Figure 3-5: Illustration of Inverted Five-spot Patterns at Zapadno Chumpasskoye ...... 77 Figure 3-6: RPS 1P Production Profile for Zapadno Chumpasskoye ...... 78 Figure 3-7: RPS 2P Production Profile for Zapadno Chumpasskoye ...... 79 Figure 3-8: RPS 3P Production Profile for Zapadno Chumpasskoye ...... 79 Figure 4-1: Kingfisher Field and Well Results ...... 84 Figure 4-2: Kingfisher Well Correlation ...... 85 Figure 4-3: Seismic Section through Kingfisher-3 and -3A Wells ...... 86 Figure 4-4: Kingfisher Depth Map (RPS Depth Conversion) ...... 87 Figure 4-5: Example Kingfisher Log Character (K-3) ...... 88 Figure 4-6: RPS Log Analysis, A Sand, Well K-3 ...... 89 Figure 4-7: K-3 and K-3A MDT Pressure Gradients ...... 90 Figure 4-8: Kingfisher Volumetric Models ...... 91 Figure 4-9: RPS Production Profiles for Kingfisher South Culmination ...... 94 Figure 4-10: RPS Production Profiles for Kingfisher North ...... 95 Figure 4-11: Location of Block 3A Exploration Prospects ...... 97 Figure 4-12: RPS Top Miocene Depth Map at Pelican Prospect ...... 98 Figure 4-13: Arbitrary 3D Seismic Traverse through Pelican Prospect ...... 99 Figure 4-14: Crane Prospect Depth Map ...... 101 Figure 4-15: 2D Seismic Line through Crane Prospect ...... 102 Figure 4-16: Heron Prospect Depth Map ...... 103 Figure 4-17: RPS Production Profiles for Pelican Prospect ...... 105 Figure 4-18: Range in Production Profiles for Crane Prospect ...... 105 Figure 4-19: RPS Production Profiles for Heron Prospect ...... 106 Figure 4-20: RPS Top Reservoir Depth Map, Block 1 ...... 107 Figure 4-21: Seismic Line HOG-B1-07-12 through Buffalo-1 and Giraffe-1 ...... 108 Figure 4-22: Reservoir Section in Buffalo-1 ...... 108 Figure 4-23: Reservoir Section in Giraffe-1 ...... 109 Figure 4-24: Seismic Line HOG-B1-07-12 through Warthog-1 ...... 110 Figure 4-25: Reservoir Section in Warthog-1 ...... 110 Figure 4-26: RPS Production Profiles for Buffalo-Giraffe Discovery ...... 114
61 Figure 4-27: RPS Production Profiles for Warthog Discovery ...... 115 Figure 4-28: RPS Production Profiles for Warthog North Prospect ...... 117 Figure 4-29: RPS Production Profiles for Buffalo East Prospect ...... 118 Figure 4-30: RPS Production Profiles for Crocodile Prospect ...... 118 Figure 4-31: RPS Production Profiles for Crocodile East Prospect ...... 119 Figure 4-32: RPS Production Profiles for Leopard Prospect ...... 119 Figure 4-33: RPS Production Profiles for Kob Prospect ...... 120 Figure 5-1: Seismic Line HEML-08-05 through Miran West-1 ...... 121 Figure 5-2: Miran West-1 Reservoir Section ...... 122 Figure 5-3: Operator’s Top Tanjero (Near Top Shiranish) Depth Map ...... 124 Figure 5-4: Analogue Fracture Porosity Values from the Taq Taq Field ...... 125 Figure 5-5: Recovery Factor Evidence for Type II Fractured Reservoirs (from SPE84459) ...... 127 Figure 5-6: RPS Single Well Profiles for Miran West ...... 130 Figure 5-7: RPS Forecasts for Contingent Resources in Miran West (OWC at 200 m TVDSS) ...... 130 Figure 5-8: RPS Production Forecast for All Resources in Miran West (Contingent plus Risked Prospective Resources) ...... 131 Figure 5-9: RPS Production Forecasts for Miran-East ...... 132 Figure 6-1: Heritage Base Forecast Price ...... 135 Figure 6-2: Plot of Brent vs. URALS (Mediterranean)—1997 to June 2009 ...... 137 Figure 6-3: Reverse Cumulative Distribution showing Total Value of Block 3A Resources ...... 143 Figure 6-4 Reverse Cumulative Distribution showing Total Value of Block 1 Resources ...... 145 Figure 6-5: Plot of Brent vs. Kirkuk Blend—2008 to June 2009 ...... 147
62 List of Tables
Table 1-1: Summary of the Heritage Properties ...... 66
Table 3-1: Lower J1 Sand Input Parameters ...... 74
Table 3-2: Zapadno Chumpasskoye, Lower J1 Sand, STOIIP Estimates (MMstb) ...... 74 Table 3-3: Summary of Results for Zapadno Chumpasskoye ...... 80 Table 4-1: Kingfisher GRV Input Distributions for Model 2 (MMm3 )...... 91 Table 4-2: Kingfisher Reservoir Parameters ...... 92 Table 4-3: Kingfisher Discovery In-place Volumes (100% Basis) ...... 92 Table 4-4: Kingfisher South Contingent Resources (100% Basis) ...... 92 Table 4-5: Kingfisher North Contingent Resources (100% Basis) ...... 94 Table 4-6: Pelican Prospect—Modelled Spill Points ...... 100 Table 4-7: Pelican Prospect In-Place Volumes (100% Basis, On-block) ...... 100 Table 4-8: Crane Prospect—In-place Volumes (100% Basis) ...... 102 Table 4-9: Heron Prospect In-place Volumes (100% Basis, On-block) ...... 103 Table 4-10: Prospective Resources for Lake Albert Prospects (100% Basis, On-block) ...... 104 Table 4-11: Well Count and Production Plateau Assumptions for Lake Albert Prospects ...... 104 Table 4-12: Volumetric Input Parameters ...... 111 Table 4-13: In-place Volume Estimates for Block 1 Discoveries (100% Basis) ...... 111 Table 4-14: In-place Volume Estimates for Block 1 Prospects (100% Basis, On-block) ...... 112 Table 4-15: Buffalo-Giraffe Contingent Resources based on Steam-Injection (100% Basis) ...... 112 Table 4-16: Well count and Production Plateau Assumptions for Buffalo-Giraffe ...... 113 Table 4-17: Warthog Contingent Resources (100% Basis, On-block) ...... 114 Table 4-18: Resource Volumes for Block 1 Prospects ...... 116 Table 4-19: Well count and Production Plateau Assumptions for Block 1 Prospects ...... 117 Table 5-1: DSTs in Miran West-1 ...... 123 Table 5-2 Fracture Porosity Ranges in Miran West and Miran East ...... 125 Table 5-3: Miran West STOIIP (zone above 200 m TVDSS successfully tested) ...... 126 Table 5-4: Miran West STOIIP (zones below 200 m TVDSS—not successfully tested) ...... 126 Table 5-5: Miran East STOIIP ...... 126 Table 5-6: STOIIP and Contingent Resources above 200 m TVDSS for Miran West (100% Basis) .... 128 Table 5-7: STOIIP and Contingent Resources above 200 m TVDSS for Miran West (100% Basis) .... 128 Table 5-8: STOIIP and Total Risked Resources for Miran West (100% Basis) ...... 128 Table 5-9: Well count and Production Plateau Assumptions for Miran West ...... 129 Table 5-10: STOIIP and Prospective Resources for Miran East (100% Basis) ...... 131 Table 5-11: Well Count and Production Plateau Assumptions for Miran East ...... 132 Table 6-1: Heritage Forecast Price Cases ...... 134 Table 6-2: Table of Base Case Forecast Prices ...... 135 Table 6-3: Zapadno Chumpasskoye Post-Tax Valuation (Net Heritage Share) ...... 138
63 Table 6-4: Zapadno Chumpasskoye Reserves Summary ...... 138
Table 6-5: Sensitivity of Zapadno Chumpasskoye NPV10 to Oil Price ...... 138 Table 6-6: Block 3A Contingent Resources Post-Tax Valuation (Net Heritage Share) ...... 142
Table 6-7: Sensitivity of Block 3A Contingent Resources NPV10 to Oil Price ...... 143 Table 6-8: Block 3A Prospective Resource Valuation Summary ...... 144 Table 6-9: Block 1 Contingent Resources Post-Tax Valuation (Net Heritage Share) ...... 144
Table 6-10: Sensitivity of Block 1 Contingent Resources NPV10 to Oil Price ...... 145 Table 6-11: Block 1 Prospective Resource Valuation Summary ...... 146 Table 6-12: Miran West Contingent Resources Post-Tax Valuation (Net Heritage Share) ...... 147 Table 6-13: Miran West Contingent Resources Summary ...... 148
Table 6-14: Sensitivity of Miran West Contingent Resources NPV10 to Oil Price ...... 148
Table 6-15: Miran Field Post Tax NPV10 ...... 148
64 1. DESCRIPTION OF ASSETS
Heritage has a portfolio of assets that include production in Russia (Zapadno Chumpasskoye), undeveloped discoveries in Uganda (Blocks 1 and 3A) and Kurdistan (Miran Block) and an exploration portfolio including licences in Mali, Malta, DR Congo, Tanzania and Pakistan. As the licences in Malta, Mali, DR Congo, Tanzania and Pakistan contain immature exploration acreage the terms of the RPS Letter of Engagement were to review and value only the properties in Russia, Uganda and Kurdistan for this report.
Details of the assets, provided by Heritage, are summarised in Table 1-1, below.
Area Heritage Licence (sq km) Date Awarded Equity Partners RUSSIA* Zapadno Chumpasskoye 195.65 September 1999 95% UGANDA* Block 11 3,659.00 July 2004 50% Tullow Oil Block 3A1 2,024.50 September 2004 50% Tullow Oil KURDISTAN* Miran Block2 1,015.00 October 2007 75% Genel Energy D.R. CONGO Block I 3,825.00 Signed July 2006 39.5% Tullow Oil3 (awaiting Presidential Decree) Cohydro Block II 2,634.00 Signed July 2006 39.5% Tullow Oil3 (awaiting Presidential Decree) Cohydro MALI Block 7 39,804.00 July 2006 75% Centric Energy Block 11 32,810.00 June 2005 75% Centric Energy MALTA Area 2 9,190.00 December 2007 100% Area 7 8,778.00 December 2007 100% PAKISTAN Block 3068-2 (Sanjawi) 2,412.00 November 2007 54% Sprint Energy, Trakker Energy, Hycarbex Block 2667-8 (Zamzama 1,229.00 December 2007 48% Sprint Energy, North) Trakker Energy, Hycarbex TANZANIA Kisangire 7,280.00 May 2005 55% Dominion Petroleum Lukuliro 8,828.00 May 2005 55% Dominion Petroleum Kimbiji 4,298.00 September 2006 70% Petrodel Resources Latham 5,056.00 September 2006 29.9% Petrodel Resources * Reviewed in this CPR 1 The government has the right to back-in for up to 15% which would reduce the Heritage net working interest to 42.5%. 2 Heritage has a 75% working interest which could reduce to 56.25% in the event that the Government exercises all of its back-in rights 3 Tullow is Operator.
65 Table 1-1: Summary of the Heritage Properties
Locations of the properties reviewed are shown in Figure 1-1 to Figure 1-3.
Figure 1-1: Russian Licence Location Map
66 Figure 1-2: Kurdistan Licence Location Map
67 Figure 1-3: Ugandan and DRC Licences Location Map
1.1. LIABILITIES
The work programmes associated with the PSAs in Uganda and Kurdistan are discussed in Section 7. In addition to the exploration work programme in the Kurdistan PSA, there was also a commitment to build a small refinery, which would have a capacity of 20,000 barrels of oil per day, in strategic partnership with the Kurdistan Regional Government (KRG). This commitment has now been waived in exchange for a future payment of US$35 million from Heritage to the KRG from future revenue received solely from production from the Miran Field.
68 2. METHODS USED IN THIS REPORT
2.1. GENERAL
The evaluation presented in this Competent Persons Report (“CPR”) has been conducted within our understanding of petroleum legislation, taxation and other regulations that currently apply to these interests. RPS is not in a position to attest to the property title, financial interest relationships or encumbrances related to the properties.
Our estimates of potential resources and risks are based on the limited data set available to, and provided by, Heritage. We have accepted, without independent verification, the accuracy and completeness of these data.
Volumes and risk factors are presented in accordance with the 2007 SPE/WPC/AAPG/SPEE Petroleum Resource Management System (PRMS).
2.2. RESERVES AND RESOURCE CLASSIFICATION
Reserves or resources are estimated according to the 2007 PRMS. The PRMS Definitions are summarised in Appendix B.
In estimating reserves and resources we have used standard petroleum engineering techniques. These techniques combine geological and production data with detailed information concerning fluid characteristics and reservoir pressure. RPS has estimated the degree of uncertainty inherent in the measurements and interpretation of the data and has calculated a range of recoverable reserves. RPS has assumed that the working interest in each asset advised by Heritage is correct and RPS has not investigated nor does it make any warranty as to the Heritage interest in these properties.
Hydrocarbon resource and reserve estimates are expressions of judgement based on knowledge, experience and industry practice and are restricted to the data made available. They are, therefore, imprecise and depend to some extent on interpretations, which may prove to be inaccurate. Estimates that were reasonable when made may change significantly when new information from additional exploration or appraisal activity becomes available.
2.3. RISK ASSESSMENT
For all prospects and appraisal assets estimates of the commercial chance of success for Contingent Resources, and estimates of geological chance of success for Prospective Resources, have been made. In PRMS the former is called Chance of Development (CoD) and the latter Chance of Discovery (also CoD) in the PRMS system. To avoid confusion with acronyms we have used the term Geological Probability of Success (GPoS) in this document synonymously with Chance of Discovery.
2.3.1. Contingent Resources
The chance of success in this context means the estimated chance, or probability, that the volumes will be commercially extracted.
A Contingent Resource includes both proved hydrocarbon accumulations for which there is currently no development plan or sales contract and proved hydrocarbon accumulations that are too small or are in reservoirs that are of insufficient quality to allow commercial development at current prices. As a result the estimation of the chance that the volumes will be commercially extracted may have to address both commercial (i.e. contractual or oil price considerations) and technical (i.e. technology to address low deliverability reservoirs) issues.
2.3.2. Prospective Resources (Exploration Prospects)
Unlike risk assessment for Contingent Resources, when dealing with undrilled prospects there is a more accepted industry approach to risk assessment for Prospective Resources. It is standard practice to assign a Geological Probability of Success (GPoS) which represents the likelihood of source rock, charge, reservoir, trap and seal combining to result in a present-day hydrocarbon accumulation. RPS assesses risk by considering both a Play
69 Risk and a Prospect Risk. The chance of success for the Play and Prospect are multiplied together to give a Geological Probability of Success (GPoS). We consider three factors when assessing Play Risk: source, reservoir, seal and we consider four factors when assessing Prospect Risk: trap, seal, reservoir and charge. The result is the chance or probability of discovering hydrocarbon volumes within the range defined (Section 2.4). It is not an estimation of commercial chance of success.
2.4. UNCERTAINTY ESTIMATION
The estimation of expected hydrocarbon volumes is an integral part of the evaluation process. It is normal practice to assign a range to the volume estimates because of the uncertainty over exactly how large the discovery or prospect will be. Estimating the range is normally undertaken in a probabilistic way (i.e. using Monte Carlo simulation), using a range for each input parameter to derive a range for the output volumes. Key contributing factors to the overall uncertainty are data uncertainty, interpretation uncertainty and model uncertainty.
Volumetric input parameters, gross rock volume (GRV), porosity, net-to-gross ratio (N:G), water saturation (Sw), fluid expansion factor (Bo or Bg) and recovery factor, are considered separately. RPS has internal guidelines on the best practice in characterising appropriate input distributions for these parameters.
Systematic bias in volumetric assessment is a well-established phenomenon. There is a tendency to estimate parameters to a greater degree of precision than is warranted2 and to bias pre-drill estimates to the high side3. Rose and Edwards observe the tendency towards assessing volumes in too narrow a range with overly large low-side and mean estimates. RPS uses benchmarked P90/P10 ratios and known field size distributions to check the reasonableness if estimated volumes.
2 Rose, P.R., 1987. Dealing with Risk and Uncertainty in Exploration: How Can We Improve? AAPG Bulletin, 71 (1), pp. 1-16.
3 Rose, R.P. and Edwards, B., 2001. Could this prospect turn out to be a mediocre little one-well field? Abstract, AAPG Bulletin, 84(13)
70 3. ZAPADNO CHUMPASSKOYE
The Zapadno Chumpasskoye Licence is located in the West Siberian Basin in the Khanty-Mansyisk Province of Russia. Six producing oil fields operated by Lukoil surround Zapadno Chumpasskoye. The nearest city is Langepass located 8 km to the east. Heritage acquired the field in November 2005 from TNK-BP and created a subsidiary, ChumpassNefteDobycha (CND), to operate and develop the field. Previous work on the licence included the drilling of nine exploration wells and the acquisition of several hundred km of 2D seismic.
In 2006 CND prepared the necessary approvals to commence work on the field, including gathering 202 km of new seismic, constructing a road, separation facility and drilling cluster to conduct further appraisal drilling and commence a pilot operation. An existing well was re-entered and three new wells have been drilled. On May 27, 2007, the Russian authorities approved Phase 1 of the development, consisting of reservoir studies and early wells to establish the efficacy of a full field development (“FFD”) using an inverted 5-spot pattern. The initial approval covers the drilling of up to 53 wells including 13 injection wells. However, following falls in the oil price planned drilling in 2008 and 2009 has been deferred until 2010
3.1. DATA AVAILABLE
Data from the surrounding fields are sparse because competitor data is proprietary. A variety of data were available for this review. Seismic data coverage (2006 survey and the older data) comprises 2D lines shot at fairly wide spacing. A number of Russian drilled wells were available with Russian style wireline logs limited to SP, Conductivity and the Russian BKZ gradient (lateral) logs with 2.25 electrode spacing. Two new wells were drilled in 2007 (P3 and P2) and a third (P4) was drilled in 2008. New wells drilled since 2007 by Heritage have modern western-style logs. DST data from new wells, summaries of previous reservoir simulation studies and production data from wells 226, P3, P2 and P4 were provided. During the course of this update, the Operator has located an old well, well “No 14”, from which Jurassic-sourced oil has been sampled. This well may provide further data that might in turn impact future reserves estimates, depending on the results of re-entry and testing (scheduled for 1Q, 2010).
3.2. GEOLOGY
3.2.1. Regional Setting
The Upper Jurassic sequence in the Zapadno Chumpasskoye Licence is understood to comprise a sequence of shallow marine clastics, which are widely deposited in the West Siberian Basin. The Upper Jurassic is some 60 to 70 m thick and includes a lower section of claystones and an upper sand sequence interbedded with siltstones and claystones. The Upper Jurassic in the area is overlain by the Bazhenov Formation, a 20 to 25 m thick bituminous shale, which is both the source and the cap rock for the reservoir.
The six fields surrounding Zapadno Chumpasskoye are also reported to be producing from the Upper Jurassic.
3.2.2. Zapadno Chumpasskoye Field
The data from Russian drilled wells available for evaluating net sand, net pay and fluid contact is limited to SP, Conductivity and the Russian BKZ gradient (lateral) logs with 2.25 electrode spacing. These are low resolution tools and the resistivity logs are unfocused. There are no porosity logs. The SP logs were normalised to enable a consistent comparison of sand quality between wells. Net sand was initially picked at a typical VCL cut-off of 50%. However, to compensate for the low resolution of the SP and the presence of thin beds, a higher VCL cut-off was accepted for the thinner layers (i.e. thickness less than 5 m). The Russian lateral logs were reviewed for evidence of hydrocarbons in the wells and to determine the fluid contacts. The log response is asymmetrical and only a qualitative interpretation was possible. The shallower hydrocarbon bearing sands were found to indicate resistivities approaching and exceeding 40 Qm, whereas the deeper formation, closer to the hydrocarbon-water contact, tended towards 15 Qm. The resistivity measurements in some of the thinner sands were uncertain due to poor log resolution.
Prior to the new wells, Heritage presented a correlation of the upper part of an Upper Jurassic clastic sequence based on lithostratigraphy (no biostratigraphic data is available). Two sandstone intervals (the Upper and Lower
J1 Sandstones) were identified in the upper part of the sequence and correlated between most of the wells using
71 the SP logs. These occur below the base of the ‘low conductivity zone’, equating to the Bazhenov shale which is the seal and source rock for the Jurassic reservoirs. The correlation has been revised based on data from the 2007 wells and additional older well data that has become available to Heritage.
The revised interpretation suggests that the Upper J1 Sand is very localised and no volumes are now assigned to this sand. Well spacing is large in this licence (between 2 and 7 km) and lateral variations in sand content and quality, plus sand pinch-outs and amalgamations, are likely to occur within such distances. The model of pinch-out of the Upper Sand onto the high in the south is a reasonable interpretation of the logs and is supported by evidence from well P2.
Seismic data quality in this licence is of moderate quality. However, the frequency content of the data at reservoir level is insufficient to define the reservoir thickness. Effectively the only presently perceived use for this dataset is to define the structure at the top of the reservoir sequence which is seen to be a simple north-westerly dipping surface.
Heritage provided depth structure maps at Top Upper Sand levels. Seismic data have been reviewed. No faults are shown on the maps, but it is expected that faults will cut the sequence and offset the relatively thin (generally less than 10 m) sands. Due to the stratigraphic nature of the trap, seismic interpretation is not regarded as critical to the volumetric evaluation.
Heritage’s Net Oil Pay thickness maps were reviewed and modified as appropriate including an estimate of the pinch out edge to the south (the exact position of this pinch out cannot be precisely located on the seismic). No definitive OWC has been identified, but possible fluid contacts were picked at 2,702 m TVDSS (deepest dry oil production in Well 226), 2,724 m TVDSS (ODT in Well 943) and 2,756 m TVDSS (possible ODT in Well 100). The Net Oil Pay thicknesses above each of these contacts were hand contoured, digitised and Net Pay Rock Volumes calculated. The P50 Net Pay Map is shown in Figure 3-1.
3.2.3. Petrophysics
RPS undertook an independent petrophysical review of wells P2ST and P3. The Sw values interpreted from western logs in Well P3 were higher than expected. As a result a detailed review of core and water analysis data derived from core taken from well P3 was undertaken. These data provided a basis for calibrating the logs from P2 ST and P3. Well P3 was drilled with a water base mud and was tagged with a fluorescent dye during coring. The core barrel contained a glass fibre inner barrel that was filled with depolarized mineral oil. To obtain the background reading of fluorescent dye concentration, the tagged mud was sampled regularly during coring. However, no fluorescence was detected from the water extracted from the core and it is therefore considered that the core did not suffer filtrate invasion in the volumes sampled for water extraction; consequently no invasion corrections were applied.
Values of Rw were taken from the data supplied by Heritage where residual water was extracted from the core and its resistivity determined. The average value from 8 samples reported was 0.277 Qm at 20° C with standard deviation from the mean of 0.012 Qm. Arps’ equation was used to convert this to reservoir temperatures4. This resistivity represents an equivalent NaCl concentration of approximately 24,000 ppm. The result is in line with a previously reported salinity from well 14 which gave a value of 22,105 ppm. The ambient Archie Cementation exponent “m” and Saturation exponent “n”, derived from P3 core, were 1.77 and 1.85, respectively. A produced water analysis was supplied by Heritage which was obtained by centrifuging an oil sample from co-mingled production from wells S226 and P3. The chemical analysis obtained a salinity of 49,454 ppm, which has an estimated Rw of 0.143 Qm at 20° C.
4 Arps, J.J. (1953) “The Effect of Temperature on the Density and Electrical Resistivity of Sodium Chloride Solutions” Petroleum Transactions, AIME, Vol 198, 327-330.
72 Figure 3-1: Lower J1 Sand—RPS Net Pay Map (P50 Case)
Because of the ambiguity in the results from the brine analyses, the 0.277 Qm Rw at 20° C was used to calculate saturations at the P90 level, and the 0.143 Qm Rw at 20° C was used to calculate saturations at the P50 level.
In the case of well P2ST, VCL was derived from the lower value from the density/neutron cross plot method and a linear Gamma Ray VCL method derived from the Potassium and Thorium component of the gamma ray count. For well P3, shale volume was determined from a density/neutron crossplot using the parameters presented in Table 2 in the Appendix.
For wells P2ST (all zones) and P3 (zones LCa and LCb only) porosity was derived using the density/neutron crossplot method. Foe zone LCc in P3 the density log was used on its own for porosity determination. The parameters used in calculating porosity for both wells are presented in Tables 1 and 2 in the Appendix.
For both wells, total water saturation was calculated using the Archie equation5. Effective water saturation was derived using the shaley sand “Indonesia” Equation of Poupon and Leveaux6. A CPI (for the P50 saturation case) from well P3 is shown in Figure 3-2.
5 Archie, G.E. “The Electrical Resistivity Log as an Aid in Determining Some Reservoir Characteristics”. Petroleum Transactions of the AIME 146 (1942).
6 Poupon, A and Leveaux, J “Evaluation of Water Saturation in Shaly Formations”. SPWLA 12th Annual Logging Symposium, May 2-5 1971.
73 Owing to the silty and thin bedded nature of parts of the reservoir, it is possible that thin beds are not being resolved fully by tool responses and that the results of the interpretations have been influenced by smoothed tool responses.
RPS CPI Results
2 200 M2R9 [ohmm]
2200 M2R6 [ohmm]
200 2 M2R3 [ohmm]
140 40 2 200 01 DT[usec/ft] M2R2 [ohmm] VSHND [fr]
MD - 410.6885 410.2 10 5 0.450 -0.150 0102 200 010.0 0.30 10 TEN [lbf] CALX [in] CNC [fr] PE[brne] M2R1 [ohmm] SWT_P50 [fr] PHIT_FIN [fr] PHIE_FIN [fr] 1:79 0 200 5101.950 2.950 1 0.0 0.30 1 0 GR [gapi] CALX [in] ZDEN [g/cc] 243 267 2 200 0 SWE_P50 [fr] BVWE_P50 [unkn] SP[mv] M2RX [ohmm] PHIE_FIN [fr] 3387 LCa
LCb
LCc
3400
Figure 3-2: CPI for Well P3 over Reservoir Interval for P50 Saturation Case
3.3. IN PLACE VOLUMES
Porosity, saturation and formation volume factor ranges were estimated based on the RPS review of petrophysical data from wells P2ST and P3 and from the Operator’s interpretation of the older Russian wells. This interpretation was based on their regional knowledge and on assumptions that the reservoirs are analogous to those in the surrounding area. As a result of the differences in interpreted Sw a broad range of Sw was used in the volumetric calculations. Input parameters are shown in Table 3-1.
Low Mid High Net Pay Rock Volume (MM m3) 131 455 854 Porosity (%) 15 17 19 Oil Saturation (%) 45 60 65 Boi (rb/stb) 1.2 1.25 1.30
Table 3-1: Lower J1 Sand Input Parameters
STOIIP has been estimated probabilistically and is summarised in Table 3-2 below.
STOIIP (MMstb) P90 P50 P10 90.3 233 419
Table 3-2: Zapadno Chumpasskoye, Lower J1 Sand, STOIIP Estimates (MMstb)
74 3.4. PETROLEUM ENGINEERING
3.4.1. Reservoir Fluid Properties
The Lower J1 Sand contains an undersaturated oil at an initial pressure and temperature of approximately 28 MPa (4,018 psia) and 83° C (181 °F), respectively, at a depth of 2,750 m. The produced oil has a density of 834 kg m-3 (~38° API). The in-situ viscosity of the oil is likely to be 2-3 times that of water, and the bubble point of the reservoir oil is 1,320 psia: the implication of these factors is discussed below. The initial solution GOR (Rsi)is 410 scf/stb, and the initial formation volume factor (Boi) is 1.25 rb/stb.
3.4.2. Well Performance & Deliverability
RPS’ previous evaluation was issued in February, 2008 and had an effective date of 30 September, 2007. Since that time, another well has been commissioned (P4), and production to date is shown below in Figure 3-3 and Figure 3-4. The individual well rates at the June, 2009 were: 234 stb/d (well 226), 239 stb/d (P3), and 19 stb/d (P4) for a total of 492 stb/d and cumulative production since start-up of 0.257 MMstb.
Well P2 will be converted into an injector later in the year, and well P4 awaits a workover to remedy water production (from behind casing) and the installation of artificial lift. The notable works and activity in the last year are:
• Well P3 responded favourably to fracture stimulation;
• In 2008, an independent review was undertaken by Sibtechneft, a Russian reserves agency, as a requirement of the licence. Their review was accepted by the GKZ (an agency within the Russian Ministry of Natural Resources) on 4 July 2008. The C1+C2 reserves approved by GKZ was 63.4 MMstb, which is within 1 MMstb (1.5%) of RPS’ previous estimate of 2P reserves (the Russian “C1+C2” is almost identical to the 2P Reserves7 of PRMS).
• This approval is the first step in the preparation of an FDP;
• Formal design of the processing and Transneft tie-in equipment is underway
• Old well No. 14 (drilled in 1967 and located outside of the currently mapped Jurassic accumulation) was located and found to have pressure and oil at surface;
The field was shut-in between December 2008 and February 2009 following a temporary reduction in the domestic oil price in Russia. Whilst the field has returned to production and will continue thus with the current well stock, Heritage has deferred the full field development (“FFD”) for two years to allow the local market prices to recover and stabilize.
Clearly, with only three wells in production the large majority of Reserves in the field (see Section 6) are undeveloped.
7 These reserves categories were “mapped” by the SPE, viz.: Society of Petroleum Engineers Oil and Gas Reserves Committee “Mapping” Subcommittee, Comparison of Selected Reserves and Resource Classifications and Associated Definitions, Final Report, December 2005
75 Figure 3-3: Zapadno Chumpasskoye Production History (Rate versus Time)
Figure 3-4: Zapadno Chumpasskoye Production History (Rate versus Cumulative)
76 3.4.3. Development Plan (Subsurface)
On May 27, 2007, the Russian authorities approved phase 1 of the development, consisting of reservoir studies and early wells to establish the efficacy of a full field development (“FFD”) using an inverted 5-spot pattern. The initial approval covers the drilling of up to 53 wells including 13 injection wells. Zapadno Chumpasskoye is currently being developed under the terms of this Pilot Development Project. (“PDP”), which expires at the end of 2009. The FDP consultants, Tyumen Institute of Oil and Gas will start preparing the FDP in mid-2009, and Heritage expects approval of the FDP by December, 2009. Whilst the FFD has not yet been approved we believe it is reasonably certain that such approval will be forthcoming.
The long-term development plan is to drill a number of inverted 5-spot patterns, though alternative patterns and other schemes are under evaluation, consisting of injectors inside a “square” with a producer in each corner of this square. Figure 3-5 illustrates how several of these patterns might look.
Source: Heritage
Figure 3-5: Illustration of Inverted Five-spot Patterns at Zapadno Chumpasskoye
The well count will be built up over the next few years after resumption of drilling in 2010. The plan remains to maintain reservoir pressure by injecting water at high voidage replacement ratios (“VRR”s) (in excess of 1) to re-pressure the reservoir. Wells will be drilled from well pads, with a maximum step-out of 1.5 km from the surface location.
3.4.4. Recovery Mechanisms
Whist under natural depletion, wells will produce through oil expansion with perhaps some aquifer influx. It is unlikely that reservoir pressure will reach the bubble point at any point in the reservoir before water injection commences, so solution gas drive should not be developed. Once water injection commences, planned at VRR in excess of 1, the unfavourable mobility ratio will cause some of the water to create viscous fingers through the oil leg.
77 3.4.5. Production Profiles
Inspection of Figure 3-3 and Figure 3-4 suggests that beyond the early trends in wells 226 and P3, there are no easily discernable decline trends in either the well or field scale data. Since there are no changes to our perception of reservoir quality or STOIIP, we have simply deferred our previous forecasts by two years using the same assumptions on: well count and type, recovery per well, drilling and facility constraints, and so on. The deferred development results in the profiles are shown in Figure 3-6 to Figure 3-8.
7,000
6,000
5,000
4,000
3,000
Gross Oil Rate (s NOTE: 1/2 year rates (to straddle effective date, 30/06/2009)
2,000
1,000
0
2007 2008 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2009 1H2009 2H
Figure 3-6: RPS 1P Production Profile for Zapadno Chumpasskoye
78 iue38 P PPouto rfl o aan Chumpasskoye Zapadno for Profile Production 3P RPS 3-8: Figure Chumpasskoye Zapadno for Profile Production 2P RPS 3-7: Figure
Gross Oil Rate (st Gross Oil Rate (stb 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 10,000 10,000 12,000 14,000 16,000 18,000 5,000 2,000 4,000 6,000 8,000
2007 0 0 2007 (to straddle effective date, (to straddleeffectivedate, 2008 NOTE: 1/2 year year 1/2 NOTE: rates
2009 1H NOTE: 1/2yearrates
2009 30/06/2009) 30/06/2009) 2009 2H
2010 2010
2011
2012 2012
2013
2014 2014
2015
2016 2016
2017 79 2018 2018
2019
2020 2020
2021
2022 2022
2023
2024 2024
2025
2026 2026
2027
2028 2028 2029
2030 2030 2031
2032 The summary output from the three RPS cases, at an effective date of 30 June 2009, combined with the STOIIP estimates from Section 3.3, above is given in Table 3-3 (commercial reserves are shown in the economic section below), simply reflecting the production of some 0.2 MMstb since our last evaluation:
1P 2P 3P STOIIP (MMstb) 90.3 233.0 419.0 URR (MMstb) 24.7 64.2 172.6 URR/well (MMstb) 0.509 0.767 0.971 Notes 1. Ultimately Recoverable Resources—this may not be the finally quoted reserves (see economics section) if economic analysis terminates the profile before this cumulative is reached 2. There are no commercial gas reserves as all gas is and will be used in the field for fuel, flare pilot and so on, with the remainder flared. We are not aware of any limitations to the volume of gas that can be flared.
Table 3-3: Summary of Results for Zapadno Chumpasskoye
3.4.6. Developmental Risk
RPS has categorised these volumes as reserves despite the absence of formal approval of the FFD as there is a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame (as required under the PRMS guidelines). Despite the delay, Heritage has given us a written assurance of its commitment to develop the field.
At this pre-production stage, there are the normal developmental risks, in addition to the obvious reservoir risks. These risks, which may impact the timing and amount of future cash flow—all standard at this stage of a development and by no means specific to Zapadno Chumpasskoye—include but may not be limited to the following:
• The timing and any conditions of the formal approval by the Russian authorities of the development plan.
• The efficient functioning of the facilities.
• The timing, location and results of the numerous development wells to be drilled.
• The installation and commissioning of new facilities of appropriate size for the production, processing and transportation of the produced oil.
• The raising of sufficient capital funds to cover these development costs.
80 4. UGANDA—BLOCKS 1 AND 3A
4.1. OVERVIEW
Ugandan Block 3A is located in the south of Lake Albert and covers the southern part of the Ugandan side of Lake Albert; Block 1 is located on land to the north of Lake Albert. Lake Albert is the largest lake in the northern sector of the Western Rift. The lake surface is approximately 618 m above sea level and its rifted margins are more than 2,200 m above sea level in the west and more than 1,300 m in the east. Here, the basin has an average width of 45 km and is approximately 190 km long. Whilst many of the Western Rift segments contain deepwater lakes, such as Lake Malawi (750 m) and Lake Tanganyika (1,500 m), Lake Albert has relatively shallow water depths (approximate maximum of 60 m) but is believed to have similar sediment thicknesses as the other lakes.
The Albert Basin is the most prospective petroleum area in Uganda and is a classical active rift basin of the East African Rift system.
4.2. GEOLOGICAL SETTING
The following discussion of the geological setting is based on RPS regional experience in the rift system.
The Albert Basin system is part of the western arm of the East African Rift System. It is segmented along its length into individual, asymmetric basins, many of which contain lakes. Lake Albert is in the northern sector which trends from NNE to SSW. The rift is bordered on both sides by steeply dipping fault systems that may have a strike-slip component. The fault systems have cumulative vertical heaves of up to 10 km, and the rift flanks may have been uplifted as recently as 500,000 years ago.
The main morphological components of the Albert Basin are the Albert Nile, Lake Albert, Semliki valley, Lake George and Lake Edward basins, changing progressively in trend from NNE-SSW to N-S, towards the south. The major tectonic stresses in the Albert Basin are extensional with a strike-slip component although there is evidence of compression. Compressional anticlines interpreted from public domain seismic data reveal these compressional effects and probably represent localised inversion taking place within the rifting process due to oblique extension or as a result of compression on restraining bends in a strike-slip system.
The western border fault is a more steeply dipping fault than the eastern border fault, with steeper uplifted flanks. Magnetic and gravity data suggest there are two main sub-basins separated by a basement high, which is a possible accommodation zone/transfer zone that formed along the NE-SW trending eastern border faults.
In general, the stratigraphic sequence in the Albert Basin is divided into two mega sequences, pre-rift and syn-rift. The pre-rift sequence is composed predominantly of Pre-Cambrian basement rocks that are exposed on the rift flank and shoulder of the basin. Basement consists of meta-sediments to high-grade metamorphic rocks, mainly comprising gneisses, granitic gneisses and quartzites. The sequence is unconformably overlain by Early Tertiary syn-rift sediments in many parts of the basin. However, there is also a strong possibility that the Tertiary overlies Mesozoic sediments, although no direct evidence of Mesozoic sediments has been found to date. The syn-rift sequence contains thick fluvio-lacustrine and lacustrine sediments, possibly ranging from Early Miocene to Recent.
Oil is believed to be sourced from organic shales deposited in a lacustrine environment, where organic material is concentrated. Oil seeps occur along both the Ugandan and DRC shores of Lake Albert; over 15 confirmed oil seeps are reported, with five seeps sampled in the Kibuku, Paraa, Kibiro, Hohwa and Kabyosi areas.
Sedimentation patterns in the Albert Basin are believed to be typical of a rift system with coarse clastics, in settings ranging from alluvial to deep water fans, forming narrow depositional belts in the hanging wall of major fault systems. The oldest syn-rift sedimentary units are coarse grained fluvial-deltaic sands. The coarse-grained basal syn-rift sequence passes upwards and laterally into a shale dominated sequence marking the deep lacustrine phase, which can provide important seals and source rocks. Large rift bounding faults control the location and bathymetry of most rift lakes. Once extension stopped there was no mechanism for preserving the water depth and sediments begin to fill the basin to base level. The fill comprises Miocene to Pliocene age coarse grained fluvio-deltaic deposits that prograde over lacustrine sediments.
81 These sediments are capped by an approximate 200 m thick layer of Pleistocene alluvium. Fluvio-deltaic sandstones may be thick and have good porosity. Interbedded shales, particularly where they correspond with lake high-stands are likely to be relatively thick and continuous, thus forming good regional seals.
Block 1 lies to the north of Lake Albert and from gravity maps appears to contain two sub-basins. The northern sub-basin trends almost N-S and is separated from the NNE-SSW trending southern sub-basin by basement structural highs. The Pakwach Basin is a small half graben, which has a NNE-SSW orientation and is separated from the main Albert Basin by a basement high. The basin is probably filled by fluvio-lacustrine and lacustrine sediments of Late Pliocene to Pleistocene age and Recent alluvial plain sediments.
Two live seeps on the Victoria Nile near Paraa have been confirmed by oil freely bubbling onto the surface of the river. The presence of the oil seep indicates that the lacustrine shales are capable of generating oil but its presence also suggests a risk of seal capacity. However, since only these two seeps and possibly one other seep have been identified in the area, the presence of the seep could simply be due to the fact that basins may not seal perfectly. The presence of seeps in Block 3A and in Block 2, close to existing discoveries, also supports this hypothesis. The sub-basins and basement structural highs are prospective. There is, however, a risk that traps will be under-filled because of a possibly restricted source kitchen area in the Pakwach sub-basin. However, the prospects mapped in the southern part of this block should receive their oil from the Albert Basin via a good migration route.
4.3. DATA AVAILABLE
4.3.1. Block 3A
The seismic database in Block 3A comprises 68 closely spaced 2D seismic lines of varying vintages (2003- 2008). The data quality varies by vintage: the most recent 2008 survey has sufficient quality to give confidence in the interpretation to the base Tertiary and deeper; the 2003 survey only has sufficient quality for confident interpretation to the top of the Early Pliocene. A 3D survey also exists over the Kingfisher discovery and Pelican Prospect covering 450 sq km along the south-eastern lake shore; data quality is reasonable. Shallow data at Kingfisher lose coherency, but this is above the zones of interest in the wells. Well data from 5 wells, Kingfisher-1 (K-1) and sidetrack (K-1A), Kingfisher-2 (K-2), and Kingfisher-3 (K-3) and sidetrack (K-3A) were made available. K-1 did not penetrate the reservoir section as it passed through a fault into the basin margin footwall before reaching the reservoir. Full log suites were made available for these wells as well as geological and test data. A second sidetrack of Kingfisher-1 (K-1B) kicked off below the reservoir section.
Tullow has been exploring in Block 2. They appear to be exploring two plays in a fault terrace, to the north of Heritage’s Block 3A in Lake Albert and an onshore play in the area immediately south of Block 1. RPS has no access to data from these wells.
4.3.2. Block 1
Block 1 is currently covered by 44 2D seismic lines across the southern portion of the Block. Data quality is generally very good with retention of amplitudes, coherent reflector packages and fairly crisp fault terminations.
Well data from three wells, Buffalo-1, Giraffe-1 and Warthog-1 were made available to RPS, including full log suites and geological data. None of these three wells has been tested.
4.4. BLOCK 3A
There is one discovery, called Kingfisher and a number of prospects in the Block. Heritage advises RPS that they intend to submit a FDP to the Ugandan authorities for the Kingfisher Field. The southern part of the field will be developed first as the reservoir can be reached by drilling wells from the lake shore. This project has been valued separately. The development drilling in the north of Kingfisher and exploration drilling on the prospects depends on availability of an offshore drilling rig.
The location, some 1,300 km from the coast, and properties of the Kingfisher crude, which has high wax content, present considerable challenges in terms of transporting the crude to an offshore loading point at Mombasa. Initial development of Kingfisher South will rely on export by truck to a railhead at Jinja and then by rail.
82 Heritage plans to build a pipeline to Jinja to replace the trucks in due course. In the event of further success of the exploration programme, Heritage envisages that area will be serviced by a large buried export pipeline to the coast. The pipeline will need to be heated and several pumping stations will be required along the route. Heated storage at Mombasa for approximately 1MMstb is necessary together with a new loading jetty. It is anticipated that the pipeline, storage and loading facilities will not be available for use until 2016.
The following sections of the report (Section 4.4.1) discuss the Kingfisher Field and the Kingfisher development. Section 4.4.1.11 discusses the exploration prospects and their possible development.
4.4.1. Kingfisher Discovery
Kingfisher was discovered by well K-1A8 and subsequently appraised by K-2, K-3 and K-3A (Figure 4-1). The structure is mapped by Heritage as a single structure with two culminations, Kingfisher South and Kingfisher North. Both culminations may be part of a single accumulation or they may be separated by a structural saddle, the northern culmination has not yet been penetrated by a well.
The wells encountered a stacked series of sands and shales within an approximate 100 m interval spanning the Miocene-Pliocene boundary (Figure 4-2). Oil was encountered in three distinct reservoir units (Units 1–3) and confirmed the presence of a significant oil accumulation. Within these units, three individual sand reservoirs are identified, A, B and C, which vary in thickness from 10 to 30 m. Two of the wells, K-1A and K-2, flowed oil to surface, at good rates from all three reservoirs; wells K-3 and K-3A were not tested (Figure 4-1). Other thin sands are also present within the reservoir units but have not been tested. A thin Late Pliocene sand in Kingfisher-1 (zone P2a9), which overlies the main reservoirs, also tested oil but this proved to be very locally developed as the sidetrack, K-1A, was water-bearing at this level.
No oil-water contacts were seen in any of the sands in the Kingfisher wells but contacts could be derived from RFT and DST data.
8 Original well K-1 and subsequent sidetrack K-1B did not penetrate the reservoir section
9 Heritage stratigraphic nomenclature
83 The Kingfisher structure is a 3-way dip closure against the southern basin-bounding fault (Figure 4-3 and Figure 4-4). The maximum areal closure is approximately 37 sq km. A deeper, basal sand, probably also Miocene in age, was the primary target of the initial well but the well encountered basement before reaching this target and the K-1B sidetrack failed to reach target depth. The K-2 well penetrated the targeted basal sand but it was water- bearing. Heritage believes that this sand failed to encounter oil because it is not connected to the source kitchen.
Figure 4-1: Kingfisher Field and Well Results
84 Source: Heritage
Figure 4-2: Kingfisher Well Correlation
85 Figure 4-3: Seismic Section through Kingfisher-3 and -3A Wells
4.4.1.1. Mapping
Heritage has mapped two horizons that have been reviewed and modified by RPS:
• Kingfisher P1/M6 (“Kingfisher reservoir top base seal” on Figure 4-3). Interpretation of this unit is fairly robust over the 3D area. Seismic data quality drops around the faults in Kingfisher, but deeper units show the general trend of the data. RPS has reinterpreted the area and modified the fault interpretation in the area of Kingfisher North (and Pelican).
• Pliocene Light Blue (“Top Early Pliocene” on Figure 4-3): Interpretation of this unit is good over the area mapped, although Heritage and RPS differ on the interpretation of this horizon over the Pelican structure (see Section 4.4.1.11).
86 Figure 4-4: Kingfisher Depth Map (RPS Depth Conversion)
4.4.1.2. Depth Conversion
Well coverage in Block 3A is limited to the flank of the basin where the three Kingfisher wells have been drilled. There is therefore some uncertainty in rock velocities in the deeper parts of the basin and in predicting lateral velocity variations away from well control. In addressing this issue RPS has carried out two depth conversions to bracket the range of uncertainty:
• RPS has produced a polynomial velocity function based on the well data. This method honours the trend of increasing velocity with depth but does not account for lateral variations away from well control caused by thickness changes in the overburden. The depth map derived by this method is shown in Figure 4-4.
• RPS has also used Heritage’s interval velocity method, which models lateral velocity changes in the overburden but does not account for increasing velocities with depth.
Each method has its merits, but each also fails to account for all aspects of velocity variation. For this reason RPS considers that the two methods are equally valid end-members of the depth conversion uncertainty range. For the purposes of volumetrics they have been designated the P90 (RPS polynomial method) and P10 (Heritage interval velocity method) of a normal distribution.
87 4.4.1.3. Reservoir Quality
The reservoir sands in Kingfisher are interpreted to have been deposited as fluvial/alluvial sands in a lacustrine deltaic or fan setting. The source of sediment is believed to have been a point source where the (precursor to the) River Kafu discharged into an incipient Lake Albert that was developing during active East African rifting. The sands are interpreted as channel and crevasse splay/overbank bodies within a generally muddy setting. Correlation of overall sediment packages is possible, albeit not definitive (Units 1-3), but detailed correlation of individual sands is uncertain (Figure 4-2). However, in this general setting, connectivity between sand bodies is likely to be moderate to good due to anastamosing and downcutting (erosive) geometries.
Reservoir quality is good to excellent. Core data from well K-3A, together with log interpretation of all field wells, indicates porosities in the range 18-30% (down to a cut-off of 10%), and permeabilities mostly in the range 100-1000 mD. Such reservoir quality is supported by test flow rates, which range from 2254 to 5178 stb/d (Figure 4-1). Well K-3 is presented as an example well log display showing key log responses and computed porosity and saturation (Figure 4-5). Note that some thin sands not included within the A, B or C Sands have not been tested and may contribute to oil-in-place and recoverable oil if connected to the main sands.
Source: Heritage
Figure 4-5: Example Kingfisher Log Character (K-3)
4.4.1.4. Saturation
The petrophysical interpretation of the Kingfisher wells was problematic due to unusually high grain densities, low salinity formation water and low resistivity clays. The initial interpretation by Heritage used a simple Archie equation, which resulted in lower than expected porosities and considerably higher than expected water saturations (when compared to test indications of oil without water). Core data recently acquired from well K-3A were used to refine the interpretation of porosity but still the Archie equation yielded higher than expected water saturations.
RPS performed an independent analysis of the data using the Poupon Shaly Sand equation6, which takes account of conductive clays in the formation. This resulted in a more realistic water saturation profile (Figure 4-6), although it is still a little higher than expected.
88 The Poupon analysis is based on a porosity exponent (m) of 1.8 and a saturation exponent (n) of 1.8. RPS understands that new SCAL data will become available shortly after the issue of this report and should yield reliable estimates of m and n.
Source: RPS
Figure 4-6: RPS Log Analysis, A Sand, Well K-3
Attempts were made by Heritage to derive a saturation/height relationship from capillary pressure data from K-3A core samples. However, it seemed to work only in the high porosity range as all samples taken from the core were from the good quality sands and the derived function did not give reasonable saturations at moderate to low porosities. Porosities of 18%, still well above the applied cut-off for net sand (10%), yielded water saturations of about 100% even in crestal areas. For this reason the saturation-height function was not used in the volumetrics. Instead the Poupon analysis was used to define the most likely average saturation value for each reservoir and a range of uncertainty around this value was derived from a statistical analysis of the computed results.
4.4.1.5. Fluid Contacts
None of the Kingfisher wells penetrated an oil-water contact within the reservoir sands. An interpretation of fluid contacts was made from MDT pressure data (Figure 4-7). The A Sand is clearly in a different pressure regime from B and C and indicates a free water level (FWL) at approximately 1,700 m (TVDSS). There is some uncertainty as to the precise intersection of the oil and water lines and, for the purpose of volumetrics, an oil-water contact (OWC) was taken at 1,694 m (TVDSS). This is the level of the base case OWC used by Heritage in their 3D Petrel model10. An uncertainty range of +/- 20 m was estimated around this base case level.
10 The 3D Petrel model was constructed on behalf of Heritage by Senergy Ltd.
89 The B and C Sand pressure points fall on a single oil line, with the exception of three points in the B Sand of K-3 (Figure 4-7). This might indicate a degree of lateral compartmentalisation within the field, in this case of the B Sand, although the bulk of the B and C Sand pressures in K-3 and K-3A suggest pressure continuity. The main B/C oil line intersects the water gradient and hence defines a FWL at approximately 1,950 m (TVDSS); the Petrel model takes a depth of 1,944 m (TVDSS) as the base case OWC for volumetrics, with an uncertainty range of +/- 35 m.
Figure 4-7: K-3 and K-3A MDT Pressure Gradients
4.4.1.6. Kingfisher Field In-place Volumes
In estimating oil-in-place (STOIIP) RPS considered two models (Figure 4-8):
• First, that Kingfisher South and North form a single accumulation and that the Northern culmination simply represents part of the uncertainty range of a proven accumulation,
• Second, that Kingfisher North is an untested structural segment that still carries some geological risk. Volumes for South and North were calculated separately and then consolidated stochastically to give a STOIIP distribution for this model.
The STOIIP distributions from these two models were then consolidated as mutually exclusive, but equally likely, outcomes to give a distribution of STOIIP for the Kingfisher field.
Gross rock volumes (GRV) were computed from the alternative depth maps (polynomial and interval velocity depth conversions) for the southern and northern culminations and for the combined structure. These volumes were assigned P90 and P10 values, respectively, of a normal distribution. Volumetric sensitivity runs within Petrel indicated that GRV uncertainty due to fluid contact uncertainty, while slightly different for each reservoir, was in the order of +/- 10%. The initial GRV distributions from the depth maps were therefore modified to account for this level of fluid contact uncertainty. The final input GRV distributions are shown in Table 4-1.
90 Figure 4-8: Kingfisher Volumetric Models
South North Interval P90 P50 P10 P90 P50 P10 Unit 1 (A) 185 285 385 30 57 84 Unit 2 (B) 810 1,045 1,280 85 155 225 Unit 3 (C) 675 870 1,065 110 170 230
Table 4-1: Kingfisher GRV Input Distributions for Model 2 (MMm3)
Average N:G and net weighted porosity were derived from the log analyses of the Kingfisher wells using cut-offs of 10% porosity and 30% Vshale. These averages defined the P50 values of normal distributions. For N:G the P90 and P10 were estimated to give a realistic spread of values to capture the interbedded nature of the reservoir interval and to include all potential reservoir sands within Units 1, 2 and 3 (i.e. not restricted to sands A, B and C). For porosity the P90 and P10 were defined as 2 porosity units below and above the P50 value.
The P50 water saturation was taken from the Poupon Shaly Sand log analysis results, derived independently by RPS. Field-wide saturation uncertainty was estimated by statistical analysis of the Poupon results. Initially, a normal distribution was defined about the P50 value based on this uncertainty analysis. However, the P90 water saturation (or P10 oil saturation) derived by this method was still considered to be overly pessimistic when set against the consistently dry oil tests obtained from the wells; the test results suggest lower water saturations than derived from the log analysis. Consequently, for Units 1 and 2 (A and B Sands) the P90 water saturations defined from the uncertainty analysis were reduced to 30% (70% oil saturation) and the distributions were changed to triangular to accommodate the imposed skewness. The P90 water saturation for Unit 3 (C Sand) did not have to be altered as it was already 28%.
Formation volume factors (Boi) provided by Heritage were independently validated by RPS and used in volumetrics. The Boi range was 1.10 – 1.15 – 1.20 rb/stb.
91 A summary of input reservoir parameters for volumetrics is given in Table 4-2. With the exception of GRV these parameters were used for both Kingfisher South and Kingfisher North.
N:G (%) Porosity (%) Sw (%) Boi (rb/stb) Reservoir P90 P50 P10 P90 P50 P10 P90 Mode P10 P90 P50 P10 Normal Normal Triangular Normal Unit 1 (A Sand) 20 35 50 23 25 27 30 50 60 1.10 1.15 1.20 Unit 2 (B Sand) 15 32 49 21 23 25 30 52 61 1.10 1.15 1.20 Unit 3 (C Sand) 20 39 58 22 24 26 28 41 54 1.10 1.15 1.20
Table 4-2: Kingfisher Reservoir Parameters
Based on the procedure and inputs described above, the Kingfisher range of STOIIP estimated by RPS is given in Table 4-3.
STOIIP (MMstb)1 P90 P50 P10 Mean 418 634 907 651 Note 1 Results of the stochastic consolidation of the two models
Table 4-3: Kingfisher Discovery In-place Volumes (100% Basis)
4.4.1.7. Kingfisher South Culmination—Recovery Factors and Resources
There are four well penetrations of the reservoir sequence in Kingfisher South, of which two were tested. The oil in Kingfisher South field is waxy, but has an in-situ oil viscosity at just over 4 cP. Excellent permeabilities were derived from the well tests, which were in line with the in-situ core permeabilities from K-3A. Two DST interpretations were verified (K-1A DST#1 and K-2 DST#3) by RPS using Saphir™ software and these proved to be in accordance with the interpretations provided by Heritage.
An Eclipse simulation model was available for the Kingfisher South culmination. Although the model did not reflect the precise geology of the field, nor the STOIIP, the model was used to determine the recovery factor for Kingfisher South. On the advice of RPS, the simulation model was altered by including a realistic aquifer size, formation compressibility and absolute and relative permeabilities. Due to the expected aquifer size, water injection was assumed as the main recovery mechanism. The Eclipse™ model was run for a number of years with 12 producers and 4 injectors and a recovery factor of 31% resulted.
The total field recovery factor range has therefore been assumed to be 20-30-40% in line with Heritage’s estimates. The recovery factor was multiplied deterministically with the STOIIP ranges for Kingfisher South to yield the following range in Contingent Resources (Table 4-4):
STOIIP (MMstb)1 Contingent Resources (MMstb) P90 P50 P10 1C 2C 3C 357 551 791 71 165 316 Note. 1. STOIIP for Kingfisher South culmination only prior to consolidation with Kingfisher North as in Table 4-3
Table 4-4: Kingfisher South Contingent Resources (100% Basis)
PRMS requires the Chance of Development (CoD) to be estimated for Contingent Resources (see Section 2 and Appendix B for discussion and details). RPS judges the CoD for Kingfisher to be about 75%. At this stage RPS classifies the volumes as Contingent Resources—Development Pending.
4.4.1.8. Kingfisher South Development Concept
Heritage is in the process of preparing a Field development Plan (FDP) which, Heritage has assured RPS, is planned to be submitted to the Ugandan authorities in the second half of 2009. The elements of this FDP have been discussed with RPS and form the basis of the following discussion.
92 With four well penetrations and a number of production tests, the Kingfisher South culmination is most advanced in its development planning. The Kingfisher South culmination is also the only field which can be drilled from an onshore location (Kingfisher North and other prospects in Block 3A can only be reached via offshore drilling). Because of this, RPS has valued the two culminations Kingfisher North and Kingfisher South separately. Due to the uncertainty in potential evacuation routes and their corresponding economical viability, the hydrocarbons in Kingfisher South are still classified as Contingent Resources—Development Pending. It is expected that with more clarity on the development options and export routes the Kingfisher South culmination will move into the Reserves category.
Heritage plans to implement early production from Kingfisher South. Evacuation of oil from Lake Albert is ultimately envisaged as going to a local refinery or by means of a trunk pipeline to the East African coast (Mombasa or Dar Es Salaam). However, to achieve this advanced development, Heritage envisages a railway evacuation of the oil. This railway evacuation will have a limitation of 40,000 stb/d, based on five trains per day. For this valuation the following key features have been assumed for the development of Kingfisher South:
• Production by (ultimately) 12 wells (including the three current wells, K-1A, K-2 and K-3A which are available for completion) and water injection via 4 wells. Since Kingfisher South is complete in terms of its appraisal, development well numbers were kept constant for the P90, P50 and P10 cases.
• Production facilities are sized to a maximum of 40,000 stb/d.
• Early production from three existing wells of up to 7,500 stb/d as of 1/7/2011 (P10) 1/1/2012 (P50) and 1/7/2012 (P90). This will be exported by trucks to the town of Jinja which is located on the Kampala-Mombasa railway. Export from Jinja to Mombasa will be by rail.
• A gradual ramping up of the trucking option to Jinja to a maximum 15,000 bopd enabled by additional drilling until the pipeline to Jinja is finalised.
• Heritage asserts that there will be a pipeline to Jinja available from 2013 onwards, eliminating the trucking option and allowing a 40,000 stb/d maximum production rate. In the conceptual development plan for Buffalo Giraffe a start up date of 2014 is mentioned for this pipeline. RPS has therefore conservatively assumed an evacuating pipeline to Jinja from mid 2013 (P50) and 1/1/2014 (P90) onwards. For the P10 case RPS has assumed the same timeframe for the pipeline start (1/1//2013) as Heritage.
• After the pipeline implementation, production capacity continues to ramp-up and is reaching the 40,000 bopd by 1/1/2015 for the P10 and P50 cases, whilst the P90 case assumes a later date of 1/7/15.
• A 5% downtime factor.
93 4.4.1.9. Kingfisher South Production Forecasts
Based on the ultimate recoveries in Table 4-4, and the forecast assumptions discussed above, production forecasts were generated. They are presented in Figure 4-9. The quoted rates are yearly averages, without the 5% downtime assumptions.
45
40
35
30
25
20
15
10 Annual Average Oil Rate (Mbopd)
5
0 6 4 5 2 4 047 0 0 2011 2017 2023 2 2041 2014 2029 2032 2038 2 2050 2062 2020 2035 2 2053 2056 2059 206
1P Case 2P Case 3P Case
Figure 4-9: RPS Production Profiles for Kingfisher South Culmination
4.4.1.10.Kingfisher North Culmination
The Kingfisher North accumulation has oil in similar geological formations to Kingfisher South but requires offshore wells to develop the hydrocarbons. It is expected that a similar range of recovery factors as modelled for Kingfisher South can be achieved. The range of resources was calculated deterministically by multiplying P90-P50-P10 in-place volumes by recovery factors of 20%, 30% and 40%, respectively.
STOIIP (MMstb)1 Contingent Resources (MMstb) P90 P50 P10 1C 2C 3C 33 79 135 7 24 54 Note1. STOIIP for Kingfisher North culmination only and quoted above unrisked prior to consolidation with Kingfisher South
Table 4-5: Kingfisher North Contingent Resources (100% Basis)
The resources will be developed in the same way as Kingfisher South, which assumes development with water injection. The only difference is in the cost of the development, since Kingfisher North can only be drilled from offshore locations. The well numbers were pro-rated from the Kingfisher South values, but were allowed to vary between the P90, P50 and P10 cases. This is also reflected in the assumed plateau rate (Table 4-11).
94 Based on the ultimate recovery in Table 4-5 the production forecasts shown in Figure 4-10 were generated.
14000
12000
10000
8000
6000
4000 Annual Average Oil Rate (bopd)
2000
0 2010 2015 2020 2025 2030 2035 2040 2045 2050
1P Case 2P Case 3P Case
Figure 4-10: RPS Production Profiles for Kingfisher North
4.4.1.11.Kingfisher South Development—Facilities and Cost Assumptions
The location of Kingfisher, some 1,300 km from the coast, and properties of the crude, with high wax content, present considerable challenges in terms of transporting the crude to an offshore loading point at Mombasa or Dar Es Salaam.
Initial development of Kingfisher South will rely on export by pipeline to a storage facility at Hoima and then by truck to a railhead at Jinja and then by rail to Mombasa. Heritage plans to build a pipeline to Jinja to replace the trucks in due course. Eventually, when fully developed, Heritage envisages that the Lake Albert area will be serviced by a large buried export pipeline to the coast. The pipeline will need to be heated and several pumping stations will be required along the route. Heated storage at Mombasa for approximately 1MMstb is necessary together with a new loading jetty. It is anticipated that the pipeline, storage and loading facilities will not be available for use until 2016.
Kingfisher South Export
As discussed above, Heritage has opted for an early production scheme (EPS) and advised RPS that they will submit a Field Development Plan (FDP) to the Government in the second half of 2009. The EPS is based on initial evacuation via truck from Hoima and later via pipeline to the town of Jinja on the Kampala-Mombasa railway. Onward transportation is envisaged via the railway system to Mombasa. Heritage commissioned Mott Macdonald to undertake an extensive survey of the railway system. Mott Macdonald has concluded that it is feasible to move up to 40,000 stb/d by the rail system. It has also been established by Mott Macdonald that an alternative export route exists via Lake Victoria and the Tanzanian railway system to Dar Es Salaam.
The investment required to upgrade the railway infrastructure to Mombasa and rolling stock will be up to US$1bn. This will be split into three phases with full capacity (40,000 stb/d) being achieved by 2015. The investment will include maintaining existing flat bed wagons and the provision of new rail tanker wagons and locomotives as well as repair of large sections of track to maintain functionality and reliability. Re-instatement of pre-existing loops in the track are necessary to provide sufficient passing points on the single track and an updated signalling system will be required for the increased traffic levels.
95 RPS does not opine on whether an undertaking of this nature is indeed achievable. As a result RPS accepts the Mott Macdonald conclusions.
RPS is concerned about the practicalities of transporting waxy crude over this distance by truck and rail. It will be necessary to maintain the transported oil in heated wagons or containers at a minimum of 60° C otherwise crystalisation occurs. Should crystalisation occur there would be considerable downtime and expense to remove deposited wax from the system. Heritage asserts that the oil can be allowed to cool and be reheated at Mombasa.
Kingfisher South Field Development Costs
This development of Kingfisher South requires a 40,000 stb/d processing facility as well as a 40,000 bwpd water injection facility near the shore of Lake Albert. RPS estimates the CAPEX for this at US$365 MM (plus 20% indirect costs and 20% contingency) to be phased over four years. Transport from Hoima to the Jinja rail loading terminal will initially take place via ‘bitutainers’ loaded on flat-bed trucks. These containers will be heated at Jinja for the onward journey by rail to Mombasa. It is envisaged that around 1,400 bitutainers are needed for 40,000 stb/d, based on a six day round trip from Lake Albert to Mombasa. An estimated US$28 MM is required for these bitutainers, spread out over four years.
Initially trucking is envisaged to take the production from a capacity of 5,000 stb/d to 15,000 stb/d in the timeframe discussed in Section 4.4.1.8. This ramp-up reflects the anticipated gradual improvements to the Jinja- Mombasa railway and phasing in of the amount of trucks (N.B. a total of 200 trucks are needed for 15,000 stb/d capacity). When the pipeline from Lake Albert to Jinja is fully operational it will replace the trucking option.
Trucking, pipeline and railway costs are all calculated as tariffs, which are back-calculated from the assumed capital investments with a 15% rate of return over the lifetime of the project.
The RPS estimated trucking tariff of US$8 per stb is based on the following assumptions:
• Distance: 260 km to Jinja
• Fuel Cost: US$0.63 per km per truck
• Return journey: 2 days
• Truck hire: US$367 per day
• Trucks required: 65 daily for the initial 5,000 stb/d
The assumptions for the pipeline tariff calculation to Jinja are based on a US$600 MM capital investment spread over three years together with pipeline heating costs for 40,000 stb/d throughput.
The RPS estimated railway tariff of US$9.30 per stb is based on the following assumptions:
• Storage and Loading facilities in Jinja: US$25 MM
• Rolling stock and improvements to Jinja-Mombasa railway: US$1,000MM
• Storage and Port Facilities in Mombasa: US$300 MM
• Indirect costs and contingency: 20%
Kingfisher South Drilling Costs
Three Existing Kingfisher wells will be converted to producers for the early production scheme at an estimated cost of US$9 MM. Nine new producers and four water injectors will be required to achieve 40,000 stb/d at an average cost of US$30 MM per well according to a study for Heritage by EP Consult that was made available to RPS.
96 Kingfisher South Field OPEX
Fixed OPEX costs of US$10 MM per annum have been included for the Lake Albert Processing Plant. Workover costs every three years are estimated at US$5 MM and General & Admin (G&A) costs are added at US$5 MM per annum. The export route costs are considered as tariff. Tariff calculations are discussed in the economics section of the report. Heating costs of $1.5/stb are implied during both railway and pipeline evacuation.
Kingfisher South Abandonment Costs
Abandonment costs are estimated at US$75 MM for removal of plant, plugging wells, sealing pipelines where necessary, and environmental clean-up.
4.4.1.12. Kingfisher North Development—Facilities and Cost Assumptions
Kingfisher North, and the exploration prospects in Lake Albert, cannot be drilled from onshore locations. As a result the facilities and cost assumptions for these are treated similarly and are discussed in Section 4.4.2.7, below.
4.4.2. Exploration Prospectivity
In addition to Kingfisher, Heritage has identified three exploration prospects within Block 3A: Pelican, Crane and Heron (Figure 4-11). The primary target in each of these prospects is the same reservoir section as that of Kingfisher, namely Late Miocene to Early Pliocene sands interbedded with shales. Secondary reservoirs are also identified by Heritage for which volumes have been estimated and risks assessed.
Figure 4-11: Location of Block 3A Exploration Prospects
97 4.4.2.1. Pelican Prospect
The Pelican prospect is an analogue of the Kingfisher structure to the south and is bounded to the east by the major rift margin fault (Figure 4-12). RPS interprets the structure to be split into three segments, South, Central and North. The South segment lies entirely within Block 3A but Central and North extend across the Block 3A/ Block 2 boundary.
A SW-NE seismic line through the prospect shows the RPS interpretation and the distinct structural separation of the three segments (Figure 4-13). Pelican South is fault closed not only against the eastern margin fault, but also against a NW-SE trending conjugate fault, throwing to the south, that defines the uplifted Block of Pelican Central. Pelican North is similarly separated from Central by a smaller E-W fault throwing to the north.
Heritage interprets the seismic data differently. They interpret the high amplitude events of Pelican Central to indicate hydrocarbon charge in the overlying Pliocene section. Although they recognise a fault at the boundary of South and Central, they do not interpret a significant throw on this fault and they believe that seismic basement continues as a dimmed reflector beneath these high amplitude events (Figure 4-13). RPS commissioned a specialist structural geologist to review the seismic over the prospect and he concurred with the RPS interpretation. This interpretation is also consistent with the RPS 2008 CPR and, since no new data has become available since then, RPS does not feel a change in interpretation can be justified.
Figure 4-12: RPS Top Miocene Depth Map at Pelican Prospect
98 Figure 4-13: Arbitrary 3D Seismic Traverse through Pelican Prospect
The primary reservoir target is the Late Miocene to Early Pliocene section that is proven in Kingfisher. This section is prospective in all three segments, although the Central and North segments extend across the Block boundary and so their prospective volumes are reduced. A younger, Late Pliocene target is also recognised, where a very small oil accumulation was encountered in Kingfisher-1. The Late Pliocene target is only recognised over Pelican South.
The volumetric determination for Pelican was based on the following methodology:
• GRV was determined by inputting area, thickness, stacking factor and spill point, rather than direct input of GRV’s, as was the case with Kingfisher.
• Area uncertainty was estimated from the two different depth conversion cases (polynomial and interval velocity) of the RPS TWT interpretation. The mid point of the two areas was taken as the P50 case and the difference between them was taken to represent the P90 to P10 spread of the area uncertainty distribution (normal). For the primary Late Miocene to Early Pliocene reservoir this range was: 95% (P90)—105% (P10); for the secondary Late Pliocene reservoir it was 70% (P90)—130% (P10).
• The thickness data of the three individual Kingfisher reservoirs (A, B and C) was used to define a normal distribution of 8 m (P90)—16 m (P50)—24 m (P10). These thicknesses relate to the specific reservoirs as tested in Kingfisher, not to the whole units. The reason for this is that, unlike Kingfisher, a stacking factor was used for Pelican. For the Late Pliocene reservoir a skewed triangular distribution was defined using 8 m (P90)—16 m (mode) and 40 m (P10). The greater upside thickness was justified by the potential for thicker sands in the younger section as indicated in the Kingfisher wells.
• Spill points were interpreted from the depth converted maps. End member cases of spill point were input as the minimum and maximum of a rectangular distribution (Table 4-6).
99 Minimum Maximum Reservoir Segment (m, TVDSS) (m, TVDSS) L. Pliocene South 1,930 2,200 South 2,520 3,160 L. Miocene—E. Pliocene Central 1,510 1,870 North 2,150 2,590
Table 4-6: Pelican Prospect—Modelled Spill Points
• A rectangular stacking factor distribution was used with a minimum of 2 and a maximum of 4. This was selected because the mid-point (3) is the number of reservoirs encountered in Kingfisher.
• A N:G range was determined from the Kingfisher wells, restricted to the A, B and C Sands themselves (ignoring the intervening, mainly non-reservoir sections). The N:G range was: 50% (P90)—65% (P50)—80% (P10) and this was used for both primary and secondary reservoirs.
• A porosity range was similarly determined from the Kingfisher wells. For the main reservoir, South and North segments, this was 21% (P90)—24% (P50)—27% (P10) but for the Central segment and the Late Pliocene target this was increased by 1 porosity unit to reflect the shallower depths.
• A water saturation distribution similar to that of Kingfisher was used but, in the absence of specific test data, a normal distribution was defined as 30% (P90)—40% (P50)—50% (P10).
• The Boi range was the same as Kingfisher for the main reservoir, South and Central segments, namely 1.10 (P90)—1.15 (P50)—1.20 (P10), but was decreased slightly for the shallower Central segment and Late Pliocene reservoirs, to 1.05—1.10—1.15 rb/stb.
The estimated STOIIP for the Pelican prospect is summarised in Table 4-7.
STOIIP (MMstb) GPoS Reservoir / Segment P90 P50 P10 Mean (%) L. Pliocene South Segment 63 212 556 273 19 L. Miocene—E. Pliocene South Segment 93 272 621 321 39 Central Segment (x 0.85)1 22 63 137 73 22 North Segment (x 0.20)1 613261539 Consolidated L. Miocene—E. Pliocene 19 219 605 273 55 Pelican Prospect Consolidated Total2 29 255 688 320 63 Notes 1 Central and North have been multiplied by factors (0.85 and 0.20, respectively) reflecting the areal proportion of the prospect within Block 3A 2 Stochastically consolidated total of risked volumes of both L. Pliocene and L. Miocene to E. Pliocene in all segments
Table 4-7: Pelican Prospect In-Place Volumes (100% Basis, On-block)
The chance of success (GPoS) is shown in the right hand column of Table 4-7. For the primary target, source and seal risks are low as there are proven oil discoveries to the south (Kingfisher) and north (Block 2). The main risks for this reservoir are in trap (seismic interpretation and possible fault leakage) and reservoir (unknown presence and effectiveness of sands further from the point source). Both trap and reservoir risks are higher for the Central segment.
100 Overall risk for the Late Pliocene target is higher owing to poorer seismic definition, lack of significant hydrocarbon occurrences at this level and longer migration paths from a source kitchen.
The consolidated risk for the prospect as a whole is quite low, with a GPoS of 63%, reflecting its favourable position with respect to known discoveries to the north and south on the eastern margin of the Albert Rift.
4.4.2.2. Crane
The Crane prospect lies to the southwest of Kingfisher, further from the eastern rift margin and close to the southern end of Lake Albert (Figure 4-14). It has been interpreted and mapped at Late Miocene and Late Pliocene levels, both potential reservoir intervals; the Late Miocene is equivalent to the horizon used to map the Kingfisher reservoirs.
At Late Miocene level, the structure is a large, low relief dip closure with minor fault closure in the northwest and southeast (Figure 4-14). The time interpretation provided by Heritage was reviewed and validated by RPS, who then performed alternative depth conversions: first, by replicating the Heritage interval velocity conversion and second, by using the polynomial function derived from the Kingfisher wells. The resulting depth maps are very similar in structural form (and hence area and GRV) although the depth structure derived from interval velocities is about 350 m shallower than that from the polynomial function. At Late Pliocene level the two depth structures are again very similar but dip closure is much reduced, restricted to the south-eastern portion of the deeper Late Miocene closure.
Heritage also interprets a deeper Miocene reservoir target at a level somewhere between the mapped Late Miocene horizon and Basement. No depth map was provided for this reservoir target and Heritage has assumed parallelism with the Late Miocene structure.
Source: RPS
Figure 4-14: Crane Prospect Depth Map
101 Figure 4-15: 2D Seismic Line through Crane Prospect
For the Late Miocene and Late Pliocene intervals Crane volumetrics were calculated separately from the alternative depth maps for each horizon (inputting area/depth pairs) and then consolidated within REP into a single volume. Consolidation was by “mutually exclusive events” with each outcome being equally likely. N:G, porosity, saturation and Boi input distributions were as for Pelican. The main difference to Pelican was that the primary, Late Miocene reservoir was assigned a more favourable P10 thickness, of 40 m rather than 24 m (and distribution converted to triangular). This was to account for the possibility of thicker sands in the middle of the lacustrine fan/delta.
In the absence of a specific depth map for the deeper Miocene target, the Late Miocene area/depth pairs and spill points were used (assuming parallelism). Reservoir thickness was reduced to 5 m (P90)—10 m (P50)—15 m (P10) and the stacking factor range to 1 – 3. N:G and saturation were left unchanged but porosity was reduced and Boi increased to reflect greater depth.
Once each reservoir STOIIP had been consolidated from the different depth maps, the resulting STOIIP volumes were then consolidated into a total prospect volume (Table 4-8). This was done using the “stacked prospects” option.
Reservoir STOIIP (MMstb) GPoS P90 P50 P10 Mean (%) L. Pliocene 31 173 612 260 11 L. Miocene—E. Pliocene 205 1020 3204 1417 18 Miocene (Deep) 62 277 780 361 6 Consolidated Total1 75 527 2502 967 31 Note1. Stochastically consolidated totals
Table 4-8: Crane Prospect—In-place Volumes (100% Basis)
Prospect risks at the individual reservoir levels are moderate to high, the Late Miocene target having the highest chance of success because it is a proven reservoir in Kingfisher. The Late Pliocene is higher risk for reasons similar to that of Pelican, while the deeper Miocene target is largely speculative.
102 4.4.2.3. Heron
Heron is mapped as a simple, 4-way dip closed structure at Late Miocene level (Figure 4-16). Data coverage and quality across the prospect is poor and although the presence of a structure is likely, it is not clear that closure can be demonstrated, particularly to the northwest. Heritage interprets a fault closure in this area but such a fault cannot be observed on the two lines with adequate data, where reflectors at Late Miocene level show no offset.
Figure 4-16: Heron Prospect Depth Map
RPS has performed volumetrics for a Late Miocene target using the same approach and same reservoir parameter distributions as for Crane. The results are shown in Table 4-9.
Heritage also includes a Late Pliocene reservoir in their volumetrics but no map was provided for this level and RPS has not included this reservoir in the prospect volumes.
Overall risk is high (GPoS 10%) with the main risk being on trap.
STOIIP (MMstb) GPoS P90 P50 P10 Mean (%) 40 145 454 202 10
Table 4-9: Heron Prospect In-place Volumes (100% Basis, On-block)
103 4.4.2.4. Exploration Prospects Recovery Factors and Resources
The three exploration prospects in Lake Albert are geologically similar to Kingfisher and it is expected that a similar recovery factor can be applied to these prospects. A range of resources was calculated deterministically by multiplying P90-P50-P10 in-place volumes by recovery factors of 20%, 30% and 40%, respectively. A summary of these Prospective Resources is listed in Table 4-10.
STOIIP (MMstb) Prospective Resources (MMstb) GPoS Prospect (%) P90 P50 P10 P90 P50 P10 Pelican 29 255 688 6 76 275 63 Crane 75 527 2502 15 158 1001 31 Heron 40 145 454 8 44 182 10
Table 4-10: Prospective Resources for Lake Albert Prospects (100% Basis, On-block)
4.4.2.5. Development Concepts for Prospective Resources
In the event of success the Prospective Resources will be developed in the same way as Kingfisher, which assumes development with water injection. The only difference is in the costs of the developments, since the prospects can only be drilled from offshore locations. Well numbers were pro-rated from the Kingfisher South values, but were allowed to vary between the P90, P50 and P10 cases. This is also reflected in the plateau rate assumptions (Table 4-11).
Plateau Rate Producers Injectors (stb/d) Pelican P90 3 1 5,000 P50 6 2 25,000 P10 10 3 40,000 Crane P90 4 1 10,000 P50 12 4 60,000 P10 30 7 120,000 Heron P90 2 1 7,000 P50 4 2 16,000 P10 8 3 32,000
Table 4-11: Well Count and Production Plateau Assumptions for Lake Albert Prospects
The plateau production was allowed to vary, dependent on the outcome of the discovery well. The plateau rates for each prospect form the basis for the sizing of a future Lake Albert processing plant and future evacuation pipeline. For valuation purposes of the prospects, no early production was assumed and consequently production could only commence as of 2015/2016 onwards (see section 4.4.2.7), when the evacuating pipeline to Mombasa will be ready. A 5% downtime assumption has been assumed in the generation of the production forecasts.
104 4.4.2.6. Production Forecasts
Production forecasts were generated based on the ultimate recovery outlined in Table 4-10 and the forecast assumptions described in the previous section. The forecasts are presented graphically in Figure 4-17 to Figure 4-19. The quoted rates are yearly averages, without the 5% downtime assumptions. The spread in outcomes can be large (note the 1,000 MMstb P10 prospective resource for Crane, which will take a long time to produce).
45000
40000
35000
30000
25000
20000
15000
Annual Average Oil Rate (bopd) 10000
5000
0 2010 2020 2030 2040 2050 2060 2070
1P Case 2P Case 3P Case
Figure 4-17: RPS Production Profiles for Pelican Prospect
140000
120000
100000
80000
60000
40000 Annua lAverage Oil Rate (bopd)
20000
0 2010 2020 2030 2040 2050 2060 2070 2080 2090 2100
1P Case 2P Case 3P Case
Figure 4-18: Range in Production Profiles for Crane Prospect
105 35000
30000
25000
20000
15000
10000 Annual Average Oil Rate (bopd) 5000
0 2010 2020 2030 2040 2050 2060 2070 2080 2090 2100 1P Case 2P Case 3P Case
Figure 4-19: RPS Production Profiles for Heron Prospect
4.4.2.7. Kingfisher North and Exploration Prospects—Facilities and Cost Assumptions
Neither the northern part of the Kingfisher field nor any of the exploration prospects can be drilled from onshore locations.
In the event of success of the exploration programme, Heritage envisages that area will be serviced by a large buried export pipeline to the coast. The pipeline will need to be heated and several pumping stations will be required along the route. Heated storage at Mombasa for approximately 1MMstb is necessary together with a new loading jetty. It is anticipated that the pipeline, storage and loading facilities will not be available for use until 2015 (P10 and P50 cases) or 2016 (P90 case). It is noted that 2016 was used as a start date in the Heritage conceptual development plan for Buffalo-Giraffe but Heritage has verbally reiterated that a 2015 start date is feasible. Heritage also feels that export can also take place via a refinery to be built along the Hoima-Jinja pipeline route. RPS considers that this assumption does not materially alter the valuation of the Ugandan assets.
Offshore wellhead platforms or sub-lake tie-backs will need to be installed with flowlines laid on the lake floor back to an onshore processing facility (CPF). For valuation purposes, cost matrices for CPFs and flowlines have been developed as a function of the estimated range of resources. These are described in the economics section of the report. Estimated CAPEX has been based on recent studies undertaken by Heritage together with RPS in-house data and suitably benchmarked where necessary.
No oil related infrastructure exists in the Lake Albert and an offshore support infrastructure will have to be created. Before field development can take place a number of major activities will need to be undertaken including construction of a fabrication yard on the lake shore, creation of additional local infrastructure, construction of airstrip, heliport, workers camp, fabrication of work vessels (barges, tugs, etc) and importation and re-construction of a jack-up drilling rig or barge- based drilling solution. Transportation of materials and equipment is regarded as a major logistical operation with most of the hardware being trucked some 1,300 km. RPS has made appropriate allowances for the infrastructure and logistical problems in our estimates.
Simple offshore wellhead towers that have been assumed will be built at an estimated cost of US$25 MM for a totally installed platform with 24 slots available. Offshore well costs are included at US$14 MM per well.
Costs of the main export line to Mombasa have been estimated based on Chicago Bridge & Iron’s pipeline study made available by Heritage. A cost estimate of US$2.2 billion for a 1,230 km heated pipeline to Mombasa. RPS has added a 20% contingency to these base costs for the evaluation.
106 The cost of the pipeline has been incorporated in a tariff. Tariff calculations are discussed in Section 6.
OPEX has been estimated as a function of daily production rates, which range from 50,000 to 130,000 stb/d. For resources greater than this the OPEX has been estimated by linear extrapolation.
4.5. BLOCK 1
Block 1 lies at the Northern end of the Albert Basin where the River Nile exits Lake Albert. Heritage has drilled three wells in the block, Buffalo-1, Giraffe-1 and Warthog-111. The Block lies updip of the Lake Albert source kitchen, and is at the focal point of potential hydrocarbon migration from the basin depocentre. Heritage has two discoveries, the Buffalo-Giraffe structure and the Warthog structure. In addition, Heritage currently recognises six further prospects in the Block (Figure 4-20).
Figure 4-20: RPS Top Reservoir Depth Map, Block 1
4.5.1. Well Results
Buffalo/Giraffe
The Buffalo/Giraffe accumulation is a fault-bounded footwall dip closure (Figure 4-20). The Buffalo-1 discovery well was drilled as a vertical well to a depth of 637 m MD (-79 m TVDSS) in metamorphic basement (Figure 4-21). It encountered a series of stacked sands and shales in the Pliocene at a depth of 393-516 m MD, defining a gross reservoir interval of 123 m of which 52 m was net pay (Figure 4-22). The presence of hydrocarbons was established through log interpretation and RFT pressures and gas and oil samples. The well was not tested but the RFT pressure data indicate the presence of an oil column with an overlying gas cap.
11 Buffalo-1, Giraffe-1 and Warthog-1 are also referred to as, respectively, Jobi-1, Rii-1 and Ngiri-1.
107 Figure 4-21: Seismic Line HOG-B1-07-12 through Buffalo-1 and Giraffe-1
Gas was encountered in the top 50 m of the reservoir section. Individual reservoir sands vary in thickness from 5 to 15 m and are often separated by thin shales; complexes of these sand/shale packages have thicknesses of approximately 40 m. Thin isolated water bearing sands were encountered in the deepest part of the well (Figure 4-22).
M2RX s nd
r ZDEN 0.2 ohmm 200 SW SPOR Depth a Depth 1.5 g/cc 2.5 M2R6 0100.4_ TVDSS 0.2 ohmm 200 tS e
Laye GR CNC DPOR M2R1 Contact N Comments 0 API 150 72 % 12 0.2 ohmm 200 0 _ 0.4
400 Dry Gas 1 Gross thickness 47.6m G
B Net pay 15m -300 (upside for additional 1-2m low resistivity pay) Typical porosity 31-34% Net:gross 31-36% 75% hydrocarbon saturation GOC
450 BG2 Oil Gross thickness 75.3m Net pay 28m -250 Typical porosity 31-34% Net:gross 37% 70-90% hydrocarbon saturation
3 Oil proven down to 515.7 500 G B but fluorescence recorded in tight sands at 527m -200 4
G Base Seal 550 B Isolated water sand at 551-552m -150
BG5 OWC t n
600 e m
e Basement s a -100 B
Source: Heritage
Figure 4-22: Reservoir Section in Buffalo-1
108 The Giraffe-1 well was a down-dip appraisal of the southern part of the Buffalo structure and encountered a similar series of sands and shales in the Pliocene, with a top at 436 m MD (-222 m TVDSS) (Figure 4-23). The well penetrated a 164 m gross reservoir section. The overall sand/shale ratio is higher than in Buffalo-1, with individual sands of 5 to 25 m thickness and amalgamated sand bodies of up to 50 m. Total net pay is lower (43 m) due to its down-dip location, with most of the reservoir interval being in the water leg. The well encountered the OWC at 525 m MD (-133 m TVDSS), which was confirmed by both log interpretation and pressure data. Oil was recovered from RFT and the associated pressure data indicate an oil column in communication and on trend with the Buffalo well.
M2RX ZDEN SW SPOR Depth 00.2 ohmm 20 Depth 1.5 g/cc 2.5 M2R6 0 1 0 _ 0.4 TVDSS 0.2 ohmm 200
Layers GR CNC DPOR M2R1 Contact Net Sand Comments 0 API 150 72 % 12 00.2 ohmm 20 0 _ 0.4
Isolated Oil Sand Gross thickness 13.8m Net pay ~1m Typical porosity 27% Net:gross 8% ~60% hydrocarbon saturation 450
-200 BG1 Shale interval, limited pay
Oil Gross thickness 54.2m 2
G Net pay 33-38m 500 B Typical porosity 31-34% -150 Net:gross 60-70% 70-90% hydrocarbon saturation
OWC 3 G 550 B -100 Water Sands and shale interbeds
600 BG4 -50
Basal Shales 5 G B
650 Basement Wash? t
0 en m Basement Base
Source: Heritage
Figure 4-23: Reservoir Section in Giraffe-1
Warthog
The Warthog-1 well was drilled 5km NE of Tullow’s Kasamene discovery (Figure 4-20). It targeted a fault- bounded footwall closure (Figure 4-24) and encountered a series of stacked Pliocene sands and shales at 618 m MD (-41 m TVDSS). A 222 m thick gross reservoir interval was penetrated, of which 47 m was net pay (Figure 4-25). Individual sands vary in thickness from 5-10 m and repeated sand/shale packages have thicknesses of around 30 m. Gas was encountered in the top 78 m of the reservoir and log interpretation and RFT pressure data indicated a GOC at 696 m MD (37 m TVDSS) and an OWC at 769 m MD (110 m TVDSS). TD was in metamorphic basement at 876 m MD.
109 Figure 4-24: Seismic Line HOG-B1-07-12 through Warthog-1
M2RX d n
rs ZDEN 0.2 ohmm 200 SW SPOR Depth e M2R6 Depth y 1.5g/cc 2.5 0100.4_ tSa TVDSS a 0.2 ohmm 200
L GR CNC DPOR M2R1 Contact Ne Comments 0API 150 72% 12 00.4_ 600 0.2 ohmm 200 -50
Gas-bearing sands with shales, 83m gross gas column, 15m proven pay, with potential for 650 1 additional pay. RCI data suggest 0 BG compartmentalised pay. Typical hydrocarbon saturations in the thicker sands 60-70%. Excellent reservoir quality, average porosity 35% Probable multi-darcy permeability. Proven net:gross 18%. 700 GOC 50 Oil-bearing sands with shales 67m gross oil 2 column, 31m proven pay. RCI pressures imply BG single oil column. Typical hydrocarbon saturations in the thicker sands 70-80%. Excellent reservoir quality, average porosity 35% 750 in the thicker cleaner sands with probable 100 multi-darcy permeability. Proven net:gross 46% OWC BG3
800 Water-wet sands with shales 150 G4 B 850 200 Shales 5 BG Regolith/Weathered Zone
Basement Basement
Source: Heritage Figure 4-25: Reservoir Section in Warthog-1 4.5.2. Structural Mapping Heritage has mapped the Top Reservoir horizon and this has been reviewed by RPS. Heritage prospect mapping is based on a strong reflector which they interpret, based on seismic facies, to be the top of a sandy sequence. The interpretation of this unit is very robust as the seismic quality is very good. Amplitude anomalies at the crest of some structures throughout the Block could be indicative of gas fill although the anomalies do not cover the entire area of the larger discoveries and prospects. RPS has made minor modifications to the horizon interpretation and revised the fault correlation. The resulting map is shown in Figure 4-20. Uncertainty in fault correlation and closure of some of the discoveries and prospects exists because large areas of Block 1 are not covered by sufficiently closely spaced seismic data.
110 Heritage has created an average velocity map down to top reservoir based on results from the three wells in Block 1. They then used control points to model the velocity variation across the Block. These data were not provided to RPS so RPS derived a velocity/time function from well data and applied this function to the TWT map to produce an average velocity map across the Block. The average velocity map was then used to depth convert the time structure map.
4.5.3. Block 1 Prospectivity
Although the northern part of Block 1 is still relatively unexplored, high resolution satellite data is understood to show the presence of some potentially interesting structures in this part of the Block. The existing discoveries are in fault bounded structures. Four further fault bounded structures have been identified and Heritage also identifies two prospects, Buffalo East and Crocodile East, which depend on the updip trapping mechanism being provided by a tar mat.
4.5.4. In-Place Volumes
The RPS depth map has been used to derive area-depth curves for each discovery and prospect. The GWC and OWC observed in the wells were used to estimate GRV and a range of uncertainty on possible spill points were applied to the prospects.
RPS undertook an independent petrophysical evaluation of the Buffalo, Giraffe and Warthog wells, the results of which confirmed Heritage’s petrophysical evaluation. These results have been used to constrain the range of N:G, porosity and Sw values used in the volumetric estimates for the discoveries. RPS has applied the same ranges when estimating volumes in the undrilled prospects. However, as the reservoir section thins to the northeast, gross thicknesses have been varied depending on the thickness between the top reservoir interpreted in each prospect and the top basement.
RPS has estimated Boi and 1/Bgi (or gas expansion factor) from PVT data in the PVT reports provided for the discovery wells.
A summary of input values for the Block 1 volumetrics is given in Table 4-12.
N:G (%) Porosity (%) Sw Boi (rb/stb) 1/Bgi (scf/rcf) P90 P50 P10 P90 P50 P10 P90 P50 P10 P90 P50 P10 P90 P50 P10 Discoveries Buffalo- Giraffe 34 43 52 26 28 30 30 35 40 1.04 1.06 1.08 36 38 40 Warthog 34 43 52 26 28 30 30 35 40 1.04 1.06 1.08 66 68 70 Prospects Buffalo East 34 43 52 26 28 30 20 30 40 1.04 1.06 1.08 36 38 40 Crocodile 34 43 52 26 28 30 20 30 40 1.04 1.06 1.08 36 38 40 Crocodile East 34 43 52 26 28 30 20 30 40 1.04 1.06 1.08 36 38 40 Kob 34 43 52 26 28 30 20 30 40 1.04 1.06 1.08 66 68 70 Leopard 34 43 52 26 28 30 20 30 40 1.04 1.06 1.08 36 38 40 Warthog North 34 43 52 26 28 30 20 30 40 1.04 1.06 1.08 66 68 70
Table 4-12: Volumetric Input Parameters
The estimated in place volumes for the Buffalo-Giraffe and Warthog discoveries are given in Table 4-13.
STOIIP GIIP (MMstb) (Bscf) Low Best High Low Best High (P90) (P50) (P10) Mean (P90) (P50) (P10) Mean Buffalo-Giraffe 814 1597 2501 1627 19 27 39 28 Warthog 84 122 169 125 21 30 42 31
Table 4-13: In-place Volume Estimates for Block 1 Discoveries (100% Basis)
111 The estimated in place volumes for the Block 1 prospects are given in Table 4-14
STOIIP (MMstb) GIIP (Bscf) Low Best High Low Best High GPoS Prospect (P90) (P50) (P10) Mean (P90) (P50) (P10) Mean (%) Buffalo East 735 1,760 3,195 1,886 18 85 339 139 12 Crocodile 49 97 174 105 3 8 19 10 37 Crocodile East 400 835 1,504 905 14 67 204 91 12 Kob 10 22 40 24 0.2 1 4 2 41 Leopard 126 238 409 255 8 19 44 23 37 Warthog North 138 244 394 257 1 4 19 8 47 Total Unrisked Mean1 3,432 273 Notes 1 Arithmetic summation of individual P90, P50 and P10 quantities will not produce a total P90, P50 and P10. The process of statistical addition will, as a result of the central limit theorem, produce a P90 that is greater than the arithmetic sum of all P90 quantities and a P10 that is less than the arithmetic sum of all P10 quantities. The arithmetic sum of the mean quantities however is always equal the mean of the distribution produced by the process of statistical addition
Table 4-14: In-place Volume Estimates for Block 1 Prospects (100% Basis, On block)
4.5.5. Buffalo-Giraffe Recovery Factor and Resources
Relatively heavy oil is inferred from the PVT-data from Buffalo and Giraffe. The Buffalo PVT inferred an in-situ oil viscosity of 38 cP and a 23º API gravity oil. The PVT was considered very reliable, since the bubble point (570 psia at reservoir temperature) was close to the pressure observed at the GOC (approx. 580 psia). The Giraffe-1 in-situ oil viscosity amounted to 62 cP with a higher bubble point at 674 psia (at reservoir temperature) and a slightly lower API gravity of 22º API . Reservoir pressures for Buffalo and Giraffe are in line with each other.
Due to its oil viscosity, Heritage proposes to develop Buffalo-Giraffe by means of an alkaline waterflood or a 5-spot steamflood. No test or core data are available for the Buffalo and Giraffe wells. Reservoir permeabilities are therefore implied from production test data of the neighbouring Kasamene discovery (Tullow, Block 2) and are believed to be in excess of 10 D. With the moderate oil viscosity and the assumed high reservoir permeability, RPS believes that recovery factors of 20-30-40% can be attained by 5-spot steam injection with a 1,000 m well spacing.
The Contingent Resources were therefore calculated by multiplying the STOIIP range deterministically with the recovery factor range (Table 4-15),
STOIIP (MMstb) Contingent Resources (MMstb) P90 P50 P10 1C 2C 3C 814 1,597 2,501 163 479 1,000
Table 4-15: Buffalo-Giraffe Contingent Resources based on Steam-Injection (100% Basis)
PRMS requires the CoD to be estimated for Contingent Resources. RPS judges the CoD for Buffalo-Giraffe to be about 35%. At this stage RPS classify the volumes as Contingent Resources—Development Unclarified.
4.5.6. Buffalo-Giraffe Development Concept
Large amounts of oil resources are expected in Block 1. Evacuation via rail is seen as a major constraint by RPS and therefore a large pipeline to the East African coast (Mombasa) is scheduled for the evacuation of Block 1 oil. The earliest available date for this pipeline is 2015 (P10 and P50 cases) or 2016 (P90 case). It is noted that 2016 was used as a start date in the supplied conceptual development plan for Buffalo Giraffe, Heritage has later verbally reiterated that a 2015 start date of the main evacuating pipeline was feasible. Heritage is planning an early production scheme for Block 1 oil prior to 2015/2016. However RPS considers this period not relevant for valuation purposes, since:
• Production via steam injection or alkaline flood will be on a pilot basis, which is likely to have increased downtime and increased operating costs.
112 • Evacuation via truck to Mombasa is very expensive and prone to large downtimes.
• The Jinja to Kampala rail-link is believed to be fully utilised by Kingfisher South production.
• Investments for temporary use of the rail link to Dar El Salaam are high (ferries, rail upgrade, and storage).
RPS production forecasts for Block 1 discoveries and prospects are therefore starting as of 2015/2016 only for valuation purposes.
RPS agrees with the conceptual development of an inverted five spot steamflood with a 1,000 m spacing. Heritage calculated 41 producers and 60 injectors for this set up, to cover the Buffalo-Giraffe field.
The well numbers were kept the same for the P50 and P10 cases, but for the P90 case, the well numbers were reduced to reflect the fact that the western part of Buffalo-Giraffe may not be oil-bearing.
Although no permeability data are available for Buffalo-Giraffe, a well inflow analysis, based on an assumed 9 D permeability, pressure maintenance and conservative cold oil viscosities, provided comfort for a plateau rate of a development well of approx. 2000 stb/d. The development assumptions are summarised in Table 4-16.
Injectors Plateau Rate Producers Water Steam (stb/d) P90 20 — 30 40,000 P50 41 — 60 82,000 P10 41 — 60 82,000
Table 4-16: Well Count and Production Plateau Assumptions for Buffalo-Giraffe
To facilitate the valuation process, all wells were assumed to be available by means of pre-drilling at the start of the production forecast in 2016. A 5% downtime assumption has been assumed.
113 4.5.7. Buffalo Giraffe Production Forecasts
Based on the ultimate recovery discussed in 4.5.4 and the forecast assumptions mentioned in the previous section, production forecasts were generated by means of decline curves. The forecasts are graphically presented in Figure 4-26. The quoted rates are yearly averages, without the 5% downtime assumptions. The downtime assumptions are correctly included in the cumulatives. Note that the high case has an extremely long forecast, but its duration is similar to the production life of other giant fields.
90
80
70
60
50
40
30
20 Annual Average Oil Rate (Mbopd) 10
0 2010 2020 2030 2040 2050 2060 2070 2080 2090 2100 2110 2120
1P Case 2P Case 3P Case
Figure 4-26: RPS Production Profiles for Buffalo-Giraffe Discovery
4.5.8. Warthog Recovery Factor and Resources
The Warthog discovery well has no PVT analysis available. However the RFT gradient from Warthog amounts to 0.34 psi/ft, equivalent to an in-situ density of 0.78 g/cc. This is a lot lighter than the in-situ density of Buffalo- Giraffe (0.88 g/cc) and the same as the Kingfisher oil-gradient (0.34 psi/ft). Until further testing and analysis is carried out, it is reasonable to assume that the Warthog field will act similarly to Kingfisher and that no steam- injection is required. For that reason a similar recovery factor range of 20-30-40% is assumed for Warthog, based on water injection. The Contingent Resources for Warthog are summarised in Table 4-17 and are obtained by multiplying the P90, P50 and P10 STOIIP range deterministically with these recovery factors.
STOIIP (MMstb) Contingent Resources (MMstb) P90 P50 P10 1C 2C 3C 84 122 169 17 37 67
Table 4-17: Warthog Contingent Resources (100% Basis, On-block)
PRMS requires the CoD to be estimated for Contingent Resources. RPS judges the CoD for Warthog to be about 35%. At this stage RPS classify these volumes as Contingent Resources—Development Unclarified.
114 4.5.9. Warthog Development Concept
The development concept for Warthog is based on that for Kingfisher (given our current understanding that the reservoir fluids are similar). A total of three producers and one water injector are planned to develop Warthog. An initial plateau production of 10,000 stb/d has been assumed (or approx. 3,300 stb/d per well). As for Buffalo- Giraffe, a downtime of 5% and first production in 2016 has been assumed.
4.5.10. Warthog Production Forecasts
Based on the ultimate recovery mentioned in Table 4-17 and the forecast assumptions mentioned in the previous section, production forecasts were generated by means of decline curves. The forecasts are graphically presented in Figure 4-27. The quoted rates are yearly averages, without the 5% downtime assumptions. The downtime assumptions are correctly included in the cumulatives.
12
10
8
6
4 Annual Average Oil Rate (Mbopd) 2
0 2010 2020 2030 2040 2050 2060 2070
1P Case 2P Case 3P Case
Figure 4-27: RPS Production Profiles for Warthog Discovery
4.5.11. Block 1 Prospects Recovery Factor and Resources
There are six remaining prospects in Block 1. Four of these (Buffalo-East, Crocodile, Crocodile East and Leopard) are expected to be look-alikes of Buffalo-Giraffe, containing heavier oil and requiring steam injection. These prospects have therefore been given a similar 20-30-40% recovery factor range. The other two prospects are close to Warthog (Warthog North and Kob) and are therefore expected to contain lighter oil. The recovery factor range for these prospects was therefore also 20-30-40%, but only water injection will be needed.
115 As with the contingent resources, the Prospective Resources were calculated by deterministic use of the recovery factor range to the STOIIP range. The results are summarised in Table 4-18.
STOIIP (MMstb) Prospective Resources (MMstb) GPoS P90 P50 P10 P90 P50 P10 Warthog North 138 244 394 28 73 158 47% Buffalo East 735 1,760 3,195 147 528 1,278 12% Crocodile 49 97 174 10 29 70 37% Crocodile East 400 835 1,504 80 251 602 12% Leopard 126 238 409 25 71 164 37% Kob 10 22 40 2 7 16 41%
Table 4-18: Resource Volumes for Block 1 Prospects
4.5.12. Block 1 Prospects Development Concept
The development concept for the Block 1 prospects is based on the similarities with Buffalo-Giraffe for the heavier oil prospects and Warthog for the lighter oil prospects. The following features were included for the development concepts of these prospects:
• Allowance to vary the well numbers (and consequently plateau rate) in the low, medium and high cases to reflect uncertainty in the degree of fill of the prospects.
• Pro-rating of profiles based on the Contingent Resources in Block 1
• 5% downtime factor.
Injectors Producers Plateau Rate Water Steam (stb/d) Warthog North P90 2 1 — 8,000 P50 6 2 — 20,000 P10 10 3 — 35,000 Buffalo East P90 25 — 37 50,000 P50 45 — 66 90,000 P10 82 — 120 164,000 Crocodile P90 1 — 1 1,800 P50 3 — 4 5,500 P10 5 — 6 10,000 Crocodile East P90 13 — 20 7,000 P50 23 — 34 16,000 P10 50 — 75 32,000 Leopard P90 2 — 3 4,000 P50 6 — 9 12,000 P10 11 — 16 22,000
116 Injectors Producers Plateau Rate Water Steam (stb/d) Kob P90 1 1 — 2,000 P50 1 1 — 3,000 P10 1 1 — 4,000
Table 4-19: Well Count and Production Plateau Assumptions for Block 1 Prospects
4.5.13. Block 1 Prospects Production Forecasts
Based on the ultimate recovery discussed in Table 4-18 and the forecast assumptions mentioned in the previous section, production forecasts were generated by means of decline curves. They are presented graphically in Figure 4-28 to Figure 4-33. The quoted rates are yearly averages, without the 5% downtime assumptions. The downtime assumptions are included in the cumulatives. It is noted that some P10 forecasts, particularly for Buffalo East and Crocodile East have very long tails, which is thought to be realistic for giant fields.
40
35
30
25
20
15
10 Annual Average Oil Rate (Mbopd)
5
0 2010 2015 2020 2025 2030 2035 2040 2045 2050
1P Case 2P Case 3P Case
Figure 4-28: RPS Production Profiles for Warthog North Prospect
117 180
160
140
120
100
80
60
40 Annual Average Oil Rate (Mbopd) 20
0 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 2065 2070 2075 2080
1P Case 2P Case 3P Case
Figure 4-29: RPS Production Profiles for Buffalo East Prospect
12
10
8
6
4 Annual Average Oil Rate (Mbopd) 2
0 20102020 2030 2040 2050 2060 2070 2080 1P Case 2P Case 3P Case
Figure 4-30: RPS Production Profiles for Crocodile Prospect
118 120
100
80
60
40 Annual Average Oil Rate (Mbopd) 20
0 20102020 2030 2040 2050 2060 2070 2080 1P Case 2P Case 3P Case
Figure 4-31: RPS Production Profiles for Crocodile East Prospect
25
20
15
10
Annual Average Oil Rate (Mbopd) 5
0 2010 2020 2030 2040 2050 2060 2070 2080 1P Case 2P Case 3P Case
Figure 4-32: RPS Production Profiles for Leopard Prospect
119 5
4
4
3
3
2
2
1 Annual Average Oil Rate (Mbopd)
1
0 2010 2015 2020 2025 2030 2035 2040 2045 2050 1P Case 2P Case 3P Case
Figure 4-33: RPS Production Profiles for Kob Prospect
4.5.14. Block 1 Facilities and Cost Assumptions
The Buffalo-Giraffe discovery has relatively heavy, viscous oil whereas the oil in Warthog is lighter. The Buffalo East, Leopard, Crocodile and Crocodile East prospects are assumed to have oil that is similar to Buffalo-Giraffe whereas the Warthog North and Kob prospects are assumed to have oil similar to Warthog.
The light oil could blend easily with the heavier crudes. As discussed above, alkaline water flooding or steam flooding of the heavy oil reservoirs and a continuously heated export pipeline will be required to evacuate these resources.
CAPEX
Development of Block 1 prospects will require an onshore Central Processing Facility (CPF) or hub with flowlines from each of the fields. Export of heated crude will be via a 1,300km pipeline to Mombasa. The costs of the pipeline and storage are treated as a tariff in the valuation.
No early production scheme is considered for these prospects as it has been assumed by RPS-Energy that the capacity will be taken by oil from Kingfisher. For valuation purposes, no consideration has been given by RPS-Energy to the Tanzanian export route or to a local refinery. Due to the range of size of the discoveries and prospects, RPS has developed a range of estimated CAPEX as a function of throughput from each. Generally, CAPEX has been taken from estimates made for Heritage, which RPS has reviewed. A contingency allowance of 20% has been included. As an example the CAPEX for the 80,000 stb/d case where steam flood is required is estimated at US$350 MM of which the steam generation plant accounts for about US$70 MM. Indirects and the contingency are added to this.
Drilling costs are based on individual well costs of US£4 MM. Buffalo-Giraffe is expected to require over 100 wells to achieve 85,000 stb/d plateau with the assistance of jet pumps or ESP’s.
OPEX
Operating costs are similarly treated to Kingfisher North and Lake Albert prospects but a steam generation levy of 15% of gross production is applied in line with the Heritage study.
120 5. KURDISTAN—MIRAN BLOCK
The Miran Block in Kurdistan lies within the western part of the High Folded Zone of Iraq and measures some 70 km by 15 km, elongated in a NW-SE direction. Field mapping and seismic data has indicated the sub-surface presence of a large anticlinorium formed by two sub-parallel anticlines, separated by the NNW-SSE trending Tasluja Ridge which has prominent topographic expression down the centre of the Block. The Miran West and Miran East structures lie either side of the Tasluja Ridge and were formed by mid-Tertiary compression which culminated with late stage thrusting during the Late Miocene. These anticlines have been covered by Quaternary and Recent deposits and now lack surface expression. The absence of a wide syncline between Miran West and Miran East reflects the partial thrusting of the latter over the former.
Faulting, both parallel (longitudinal) and orthogonal (transverse) to the fold axes, has been recognised from the seismic data and faults of this type partly delimit both the Miran West and Miran East structures. Results from analogue fields (e.g. Taq Taq) demonstrate that fracturing associated with this faulting can impart significant amounts of fracture porosity to otherwise essentially tight formations.
One well has been drilled on Miran West. Heritage advise that a second well, Miran West-2, will spud in 4Q 2009 and a third, Miran West-3, will be drilled in mid 2010 depending on the success of production test programmes in Miran West-1 and -2. A well on Miran East-1 is planned for 1Q 2010.
5.1. AVAILABLE DATA
Since the last RPS report Heritage has acquired some 300 km of 2D seismic by shooting 12 lines over Miran and drilled and carried out initial testing of the Miran West well.
5.2. MIRAN WEST
Miran West-1 was spudded in late 2008. This is the first well drilled on the Miran West structure and was drilled as a vertical exploration well with primary targets of the Shiranish, Kometan and Qamchuqua Formations (Figure 5-1).
Figure 5-1: Seismic Line HEML-08-05 through Miran West-1
121 The first oil shows (dead oil) were encountered in the Upper Palaeocene claystones of the Kolosh Fm between +575 and +166 m TVD amsl. The first live oil shows were noted at +155 m TVD amsl in the Upper Cretaceous (Late Maastrichtian) sandstones and marls of the Tanjero Fm. The quality of the shows improved within the argillaceous limestones of the Coniacian—Maastrichtian Shiranish Fm over the interval +109 to +25 m TVD amsl.
Severe lost circulation problems were encountered at about 410 m TVDSS in the Kometan Fm. Several gunk plugs and a large amount of loss circulation material was required to prevent further loss. Once circulation had been re-established it was reported that “a large volume of oil was circulated out of hole from trip at 1,375 m MD” (500 m TVDSS), and “>200bbl oil circulated out of hole after a bit trip from 1,452 m” (577 m TVDSS). In addition oil was “constantly present across shakers from 1,420 m to 1,688 m MD” (545 m to 813 m TVDSS). From this evidence it can be concluded that an open fracture system charged with oil had been penetrated. No further live oil shows were reported below 1,680 m MD (805 m TVDSS).
The well became slightly deviated below this point, penetrating a thrust fault at about 1,967 m MD (1,087 m TVDSS). High gas levels were associated with the interval across this thrust. Thereafter, low levels of gas, but no further oil shows, were recorded in the interval to a TD of 2,935 m (2,045 m TVDSS).
A full suite of standard wireline logs were acquired (Figure 5-2) including XRMI image logs, analysis of which confirmed the presence of open fractures in the up-hole section. Heritage has interpreted these wireline data and identifies minimal matrix porosity throughout the well section. RPS has reviewed and endorsed this interpretation. None of the 43 attempted RFT pressure readings proved any permeability.
Source: Heritage
Figure 5-2: Miran West-1 Reservoir Section
122 Quantification of the fracture porosity present In Miran West-1 is currently uncertain and for subsequent STOIIP calculations reliance has been placed on analogue information from the nearby Taq Taq field provided by Heritage. Eleven wells have been drilled on Taq Taq and core material is available on which SCAL analyses have been undertaken.
5.2.1. Miran West-1 Drill Stem Tests
Five DSTs have been run in Miran West-1 (Table 5-1). DSTs #1 to #4 were unsuccessful and only one DST recovered oil to surface. Heritage believes that the DSTs were unsuccessful due to the drilling loss control material plugging the perforations and impairing reservoir permeability. Heritage plans to re-test the intervals tested by DST #3 and #4 in August 2009 with deeper perforations and after acidizing the reservoir. Fluid samples from the initial tests were contaminated rendering their analyses suspect. Fresh analyses will be completed with new samples
DST Depth (m MD) Depth (m, TVDSS) DST #5A, 5B, 5C, 5D 720 – 950 -155 - 75 DST #4 1,215 - 1,275 340 - 400 DST #3 1,334 - 1,390 459 - 515 DST #2 1,430 - 1,655 555 - 780 DST #1 1,943 - 2,150 1,065 - 1,268
Table 5-1: DSTs in Miran West-1
DST 5 was perforated underbalanced with a diesel cushion. After an initial build-up the well was opened to clean up. Coiled tubing and nitrogen were used to unload the diesel and it was reported that “a small amount of 27º API oil was recovered”. Analysis of the pressure gauges indicated that the well would not flow naturally due to the lack of downhole pressure. The test string was re-dressed (DST #5B) and the well was lifted using coiled tubing and nitrogen. Flow rates were determined to be about 35-70 stb/d with very little associated gas (GOR <10scf/stb). DST #5C was a misrun due to the packer getting hung-up during the trip in the hole. DST #5D included a jet pump and the well was flowed for 12 hours. After four hours of clean-up the reported flow rate was 620 stb/d on 1/2” choke, with BS&W at 10%. After 3 hours shut-in, the well was flowed for a further two hours on a 1” choke with the initial flowrate of 1,000 stb/d falling to 500 stb/d with a water cut of between 20 and 30%.
RPS understands that subsequent oil analyses have shown the gravity of the oil in Miran to be in the region of 15º API.
5.3. STRUCTURAL INTERPRETATION
Seismic data quality is considered to be good. Heritage’s seismic interpretation was reviewed by RPS and is considered valid (Figure 5-1). The interpretation and mapping prepared by Heritage is considered robust and representative of the Miran structures (Figure 5-3). The formation tops shown on the Miran West-1 completion log are considered valid. Depth conversion is limited by the single velocity control point. The Top Tanjero surface was depth converted using the average velocity derived from the Miran West-1 well.
RPS built a simple structural model in Petrel for Miran West using a series of structure maps at various reservoir levels. These were created by isopaching down from the Top Tanjero surface using the thicknesses observed in the Miran West-1 well. Control on the position of the critical thrust was limited but the depth at which Miran West-1 intersected the thrust provided some control.
A simple but essentially unconstrained Petrel model was also built for the Miran East structure.
123 Source: Heritage
Figure 5-3: Operator’s Top Tanjero (Near Top Shiranish) Depth Map
5.4. OIL WATER CONTACTS
Petrophysical interpretation does not provide evidence of a water contact. As noted above, hydrocarbon shows of variable quality are noted throughout the well. RPS consider that the inferred low, mid and high case oil-water contacts defined by Heritage for Miran West are reasonable at this early stage of exploration.
Low case: 200 m TVDSS = base of upper fractured zone
Mid case: 800 m TVDSS = base of lower fractured zone
High case: 1,400 m TVDSS = structural spill point on Top Tanjero mapping horizon
However, the results of the pending re-testing in Miran West-1 may result in a revision to these contacts.
The contacts for the Miran East structure are also considered reasonable, i.e.
Low case: 500 m TVDSS = spill point to SE
High case: 950 m TVDSS = sealing fault to NW, lower spill point to SE.
5.5. IN PLACE VOLUMES
A probabilistic approach was taken for the volumetric estimations using Logicom’s REP™ stochastic modelling program.
GRVs for each segment and above each contact, of the Tanjero, Shiranish, Kometan and Qamchuqua reservoirs, were calculated from the Petrel model, based on the Heritage seismic interpretation and mapping of the Tanjero horizon and the isochore values.
124 The Tanjero and Shiranish intervals were considered to be part of the same reservoir interval and were therefore summed. To allow for uncertainty in the picking, interval velocities, depth conversion and contact level, RPS adjusted the measured Petrel value by plus and minus 15% to produce a range of GRVs for both Miran West and Miran East. Normal distributions were applied using the low case and high values as the P90 and P10 input values respectively.
Drilling results from Miran West-1 indicate that fracture porosity is present, but its quantification remains uncertain. As a result Heritage provided analogue data from the nearby Taq Taq field (located 25 km to the Northeast) and these data have been incorporated in the RPS volumetric estimates. The Taq Taq data indicate that the Kometan and Qamchuqua intervals are significantly more fractured than the Shiranish (Figure 5-4).
Figure 5-4: Analogue Fracture Porosity Values from the Taq Taq Field
The low and high values from Figure 5-4 were entered as P90 and P10 values in REP with either a normal (Shiranish and Kometan) or lognormal distribution (Qamchuqua) to generate the best P50 value).
Reservoir P90 P50 P10 Distribution Shiranish 0.1 0.21 0.31 Normal Kometan 0.37 0.7 1.03 Normal Qamchuqua 0.45 0.74 1.21 Lognormal
Table 5-2 Fracture Porosity Ranges in Miran West and Miran East
It is considered possible that fracture porosity could be encountered anywhere within the relevant GRV and that any matrix porosity will be ineffective. Based on these assumptions no reduction for N:G has been applied.
Open, oil-filled fractures often have low water saturations. The Heritage estimates of between 2 and 10% were reasonable and these values were used as the P90 and P10 REP inputs to define a normal distribution (clipped at 0%).
The hydrocarbons tested in Miran West-1 have a very low gas-oil ratio and consequently the formation volume factor (Boi) is very low. The minimum / maximum values of 1.05 / 1.10 rb/stb used by Heritage were considered reasonable and these were used as end members (P1 / P99) for a normal distribution in REP.
125 To account for the variations in fracture porosity in the different reservoirs, separate REP runs were made for each reservoir segment. These were then stochastically consolidated within REP.
5.5.1.1. Miran West
Based on the test results to date from Miran West-1 RPS considers that only the volumes down to 200 m TVDSS, tested by DST 5, can be considered as discovered according to PRMS and hence Contingent Resources. The range of estimated STOIIP to this depth is shown in Table 5-3.
STOIIP (MMstb) P90 P50 P10 Mean 83 141 205 143
Table 5-3: Miran West STOIIP (zone above 200 m TVDSS successfully tested)
RPS considers that the remaining volumes between 200 and 1,400 m TVDSS, over which the test results (DST#1 – #4) are ambiguous, should be considered as Prospective Resources with an associated GPoS of 85%. The range of estimated STOIIP below 200 m TVDSS is shown in Table 5-4.
STOIIP (MMstb) P90 P50 P10 Mean GPoS 759 2,278 4,616 2,507 85%
Table 5-4: Miran West STOIIP (zones below 200 m TVDSS—not successfully tested)
The resulting stochastically consolidated P90-P50-P10 risked in-place volumes are 182 – 2,131 – 4,603 MMstb, respectively.
Clearly, if the results of the imminent DSTs over deeper intervals prove the presence of moveable hydrocarbons in the deeper zones, some of this volume can be moved from Prospective to Contingent Resources.
5.5.1.2. Miran East
Miran East is undrilled and therefore a Prospective Resource. The range of STOIIP estimated for Miran East is shown in Table 5-5.
STOIIP (MMstb) P90 P50 P10 Mean GPoS 141 602 1,637 788 36%
Table 5-5: Miran East STOIIP
5.6. RESERVOIR ENGINEERING
5.6.1. Miran West Recovery Factor and Resources
As discussed above, the Miran West-1 discovery well tested several intervals, but only the topmost interval in the Shiranish formation (DST#5), tested oil to surface. Pumping proved to be necessary to get oil to surface due to the high surface elevation of the well. Despite shows, DSTs in the deeper intervals did not bring oil to surface and it is believed that a prolonged clean-up is required as large quantities of mud were lost over these intervals.
An undersized jet pump was used for DST#5 and the well could only be produced under a small drawdown. Production test analysis estimated a PI of 66 stb/d per psi. Build-up analysis proved to be inconclusive due to liquid segregation.
No significant matrix porosity could be interpreted and recovery is expected from the fracture system only. Not much evidence exists on ultimate recovery factors on these fracture only systems. RPS has investigated this by a quick literature search and a phenomenological simulation study.
126 Two recent SPE articles on recovery factor evidence for fractured carbonates were found SPE 84459 and SPE 8459012,13 (2003). Most of the evidence presented is for Type II and III carbonate reservoirs, which both have storage capacity in the matrix. There is no evidence presented for fracture-only reservoirs (Type I). The closest analogues are Type II reservoirs (low poroperm matrix). SPE 84590 suggests most Type II reservoirs have recovery factor in the range 20 to 30%. This is based on 20 reservoirs and includes both waterfloods as well as primary recovery. An extended dataset of 35 reservoirs is presented in SPE 84459, which has a slightly higher mean recovery factor of 31% (Figure 5-5).
Both articles emphasize the importance of mobility ratio and correct rate control. An example from the Yanling field (16 cP oil) which was produced with water-injection and very high rates achieved a recovery factor of only 19.5%. In contrast the Casablanca field (7 cP oil) was carefully rate-controlled and achieved a recovery of 47.5% with a strong aquifer.
RPS also reviewed possible fractured basement analogues and found a study on a fractured basement field in Yemen which had water injection and for which ultimate recovery factors of 35% were quoted.
Figure 5-5: Recovery Factor Evidence for Type II Fractured Reservoirs (from SPE84459)
In addition to research into analogues, RPS has undertaken a mechanistic dual porosity simulation model using
Eclipse software and varied a number of key parameters, such as oil viscosity, aquifer strength and Sorw. Heritage reports that the oil tested in DST #5 is 15º to 27o API, but viscosity measurements are not available as yet. Simulations have therefore been undertaken using a range of 18, 50 and 100 cP in-situ oil viscosity (it is noted that 100 cP is close to the viscosity derived from correlations, when using 15º API and 10 scf/bbl GOR).
Recovery factors, derived from simulation were in general higher than the evidence from analogues, although it is realised that the provided analogues are type II carbonate reservoirs. Combining the recovery factor range from analogues with the simulation results, RPS Energy arrives at a 40-50-60% range for the recovery factor.
Resources were calculated by applying the recovery factor range deterministically to the P90, P50 and P10 STOIIPs. Only the zones above 200 m TVDSS can be classified as Contingent Resources (see Table 5-6). The remaining volume is considered to be Prospective Resources and is tabulated in Table 5-7.
12 SPE 84459, Quantification of Uncertainty in Recovery Factor Efficiency Predictions: Lessons learned from 250 Mature Carbonate Fields by S. Qing-Sun and R. Sloan
13 SPE 84590, Controls on Recovery Factor in Fractured Reservoirs: Lessons learned from 100 Fractured Reservoirs by J. Allan and S. Qing-Sun.
127 STOIIP (MMstb) Contingent Resources (MMstb)
P90 P50 P10 1C 2C 3C 83 141 205 33 71 123
Table 5-6: STOIIP and Contingent Resources above 200 m TVDSS for Miran West (100% Basis)
STOIIP (MMstb) Contingent Resources (MMstb)
P90 P50 P10 1C 2C 3C 759 2278 4616 303 1134 2767
Table 5-7: STOIIP and Prospective Resources below 200 m TVDSS for Miran West (100% Basis)
PRMS requires the CoD to be estimated for Contingent Resources. RPS judges the CoD for the Contingent Resources in Miran West to be about 25%. At this early stage of appraisal RPS classify the volumes as Contingent Resources—Development Unclarified.
As a basis for production forecasting RPS has stochastically consolidated the STOIIP for the zone above 200 m TVDSS with the risked STOIIP for the zones below 200 m TVDSS (GPoS of 85%) to produce an estimate of risked STOIIP for the whole structure. Risked resources were calculated by applying the recovery factor range deterministically to the P90, P50 and P10 STOIIPs. The results are given in Table 5-8.
STOIIP (MMstb)1 Risked Resources (MMstb)1 P90 P50 P10 P90 P50 P10 182 2,131 4603 73 1,067 2,762
Note1. Stochastically consolidated risked STOIIP and recoverable resources
Table 5-8: STOIIP and Total Risked Resources for Miran West (100% Basis)
5.6.2. Miran West Development Concept
In the conceptual field development plan provided by Heritage it is stated that Miran might lie on a huge regional aquifer. Inspection of the available maps revealed a number of likely sealing faults and inspection of the logs from Miran West-1 indicates a considerable reduction in fracture occurrence towards the base of the well. RPS considers that the aquifer size of the fracture-only reservoir in Miran is limited and that water injection should be scheduled to achieve reasonable recovery factors. RPS understands that water injection is planned in the Taq-Taq field, which is used as the nearest analogue for Miran. It is noted that there is a potential scarcity of water in this area and therefore the water injection was limited to 200,000 bwpd. A similar injector:producer ratio has been assumed than the Taq-Taq field (0.4 injector/producer).
For the Contingent Resources, based on a water contact at 200 m TVDSS, the number of wells was fixed for the low, medium and high cases. A total of 30 producers, with a well spacing of approximately 800 m, and 12 water injectors were assumed in this case. The oil production rate was capped at 5,000 stb/d per well for the mid case, to prevent excessive coning. For the low and high cases maximum well rates of 4,000 and 6,000 stb/d were assumed, respectively.
For the total Miran West field, the number of producing wells was allowed to vary to reflect uncertainty in the OWC. The 172 producing wells, assumed by Heritage for the mid case of Miran East and West together, have been pro-rated over Heritage’s P50 STOIIP, yielding 118 and 54 wells for Miran West and East respectively. The well numbers were varied for the P90 and P10 cases. The P90 case assumed 49 wells and the P10 case 184 wells. The number of injectors was assumed to be 40% of the number of producers. Oil production was capped at 15,000 stb/d per well for the mid case, to prevent excessive coning. For the low and high cases maximum well rates of 10,000 and 20,000 stb/d were assumed, respectively.
128 Some pre-production was assumed from three wells up to a maximum of 15,000 stb/d. This was assumed to occur from mid 2010 onwards. It is assumed that as of January 2014 full production facilities will be available. Pre-drilling of the required wells is assumed to take place from 2011 with a flexible number of rigs and is assumed to continue beyond 2014.
The forecast assumptions are summarised as follows (Table 5-9):
Well Max Field Max Producers Injectors (stb/d) (stb/d) Contingent Resources (above 200 m TVDSS) P90 30 12 4,000 88,000 P50 30 12 5,000 120,000 P10 30 12 6,000 150,000 Total Resources (including risked Prospective Resources) P90 49 20 10,000 190,000 P50 118 47 15,000 670,000 P10 184 74 20,000 906,000
Table 5-9: Well Count and Production Plateau Assumptions for Miran West
The drilling time is estimated to be between 30 and 45 days depending on the depth of the well. Rig move, completion and hook-up are estimated at an additional total of 16 days for all cases.
5.6.3. Production Forecasts
Production forecasts were generated from decline curves, using a single well as a building block. The notional phasing of the wells was based on assumptions in the drilling and completion times and the number of rigs employed. In order to maintain voidage balance, five producers were alternated with two injectors for the notional drilling sequence.
In addition to recovery factor, the duration of the forecasts was varied for the low, medium and high cases. From reservoir simulation results, the effect of time proved to be an important aspect. In contrast with the 25 years assumed in Heritage’s Development Concept, RPS simulator forecasts suggest much longer field life. This is particularly true for the total Miran West forecasts. The P90, P50 and P10 well forecasts were allowed to last 40, 60 and 100 years, respectively, before the recovery factor was achieved. This is considered realistic given the size of the field. It is noted that other giant fractured carbonate fields in the region such as Kirkuk and Gachsaran have been producing for almost a century.
129 The single well forecasts are summarised in Figure 5-6. The Miran West Contingent Resources forecasts are summarised in Figure 5-7 The forecasts for the total Miran West structure including the unproven volume are shown in Figure 5-8.
25000 15
20000 12
15000 9 Mid Rate (stb/d) High Rate (stb/d)
10000 Low Rate (stb/d) 6 Mid Cum (MMstb) High Cum (MMstb)
Annual Average Oil Rate (bopd) Low Cum (MMstb) 5000 3 Cumulative Oil Production (MMbbl)
0 0 2011 2021 2031 2041 2051 2061 2071 2081 2091 2101 2111
Figure 5-6: RPS Single Well Profiles for Miran West
150
140000 140
130
120000 120
110
100000 100
P90 Production Rate 90
80000 P50 Production Rate 80 P10 Production Rate P90 Cumulative 70 P50 Cumulative 60000 60 P10 Cumulative 50 Annual Average Oil Rate (bopd) 40000 40 Cumulative Oil Production (MMbbl)
30
20000 20
10
0 0 01-2010 06-2015 12-2020 06-2026 11-2031 05-2037 11-2042
Figure 5-7: RPS Forecasts for Contingent Resources in Miran West (OWC at 200 m TVDSS)
130 900000 3000
800000
2500 P90 Production Rate 700000 P50 Production Rate P10 Production Rate 600000 P90 Cumulative 2000 P50 Cumulative P10 Cumulative 500000
1500
400000
300000 1000 Annual Average Oil Rate (bopd) Cumulative Oil Production (MMbbl)
200000
500
100000
0 0 01-2010 09-2023 05-2037 01-2051 10-2064 06-2078 02-2092 10-2105
Figure 5-8: RPS Production Forecast for All Resources in Miran West (Contingent plus Risked Prospective Resources)
5.7. MIRAN EAST
5.7.1. Recovery Factor and Resources
The same rationale as described for Miran West was followed for the Miran East prospect. It is expected that similar uncertainties exist for this prospect and the recovery factor range was therefore maintained similar to that of Miran West: 40-50-60%. Again resources were determined by multiplication of the recovery factor range and the stochastically determined STOIIP range (Table 5-10).
STOIIP (MMstb) Prospective Resources (MMstb) P90 P50 P10 P90 P50 P10 141 602 1,637 56 301 982
Table 5-10: STOIIP and Prospective Resources for Miran East (100% Basis)
5.7.2. Development Concept
A similar rationale is followed for the Miran East development. It is assumed that no interference will exist between the Miran West and East developments. Miran East will therefore be developed as a stand-alone field with its own drilling rig and processing plant, although Heritage has a assumed a common facility for both fields. The only exception is that no early production has been assumed for valuation purposes.
The well numbers for the mid-case were 54 producers and 36 injectors. Well numbers for the P90 and P10 cases were varied up and down, mainly as a result of contact uncertainties. A similar well rate range was adopted as for Miran West.
131 The Miran East prospect is scheduled to commence production in 2014.
Well Max Producers Injectors (stb/d) P90 38 15 10,000 P50 54 22 15,000 P10 65 26 20,000
Table 5-11: Well Count and Production Plateau Assumptions for Miran East
5.7.3. Production Forecasts
Production forecasts for Miran East were generated along the same lines as Miran West, allowing a long field life (40, 60 and 100 years respectively for P90, P50 and P10), a ramp-up period dependent on the number of drilling rigs and a pre-drill period of up to three years. These are shown in Figure 5-9.
500000 1000
450000 900
400000 800 P90 Production Rate P50 Production Rate 350000 700 P10 Production Rate P90 Cumulative 300000 P50 Cumulative 600 P10 Cumulative
250000 500
200000 400 Annual Average Oil Rate (bopd)
150000 300 Cumulative Oil Production (MMbbl)
100000 200
50000 100
0 0 01-2010 09-2023 05-2037 01-2051 10-2064 06-2078 02-2092 10-2105
Figure 5-9: RPS Production Forecasts for Miran-East
5.8. FACILITIES AND COST ESTIMATES
For valuation of the extremely large development of Miran West and Miran East nine cases have been generated to cover the P10, P50 and P90 scenarios.
The Miran Field is located some 12 km west of the city of Sulaimaniah in Northern Iraq. Heritage has opted for an EPS in the form of trucking to the Khurmala trucking station which is tied into the Kirkuk-Ceyhan pipeline system. The early production facility could be available in 2Q 2010. It will be pre-fabricated and modularised for ease of transportation and installation. These facilities are quoted at circa US$10 MM including transportation and can operate independently whilst the main production plant is constructed. It is envisaged that the EPS will run from 2Q 2010 to 4Q 2013.
132 5.8.1. Capital Expenditure
CAPEX has been estimated for each of the resource cases with throughputs ranging from 30,000 stb/d to 680,000 stb/d. The cost estimates have been based on recent Heritage studies together with RPS in-house data and data from Questor™. CAPEX for the processing plant in the smaller cases is estimated at US$60 MM and rises to US$700 MM for the consolidated cases. Flowline costs are dependent on well count. Costs of the export pipelines to a tie-in point have been varied with expected throughput for each case. The Kirkuk-Ceyhan pipeline is currently seen as the main evacuation method with a purported 500,000 stb/d spare capacity. Other routes are being considered including the old Iraq-Syria-Lebanon pipeline system. Approximately US$300 MM has been allocated for the pipeline tie-in.
Indirect costs (design engineering, project management, insurances, etc) have been added at 20% of the base CAPEX cost with a further contingency allowance of 20% applied to both the base and indirect costs.
Typical well costs for the region are US$7.5 MM/well for a 60-day duration well. The number of wells has been varied in accordance with resource size. Up to five rigs may be required to drill up to 300 wells in the high cases and 50 wells in the low cases. Approximately 29% of the well count is for water injectors.
5.8.2. Operating Costs
Heritage estimates of OPEX for the early production scheme have been endorsed by RPS. Trucking costs are estimated at US$6.50 per stb and there is US$2 MM per annum fixed OPEX and US$5 per stb variable OPEX. These OPEX estimates are assumed to apply for the 3-4 year period of the EPS.
Fixed OPEX for the main processing plant are applied to each case. OPEX ranges from US$15MM for the lowside cases to US$90MM for the upside cases. In addition, a variable OPEX of US$1 per stb is applied in line with the Heritage’s report “Miran field development concept” (June 2009). Workover costs are included at US$5 MM every three years.
5.8.3. Abandonment Costs
ABANDEX costs vary according to plant size and well count. Plant removal and reinstatement is estimated at US$20 MM for the lowside case of 30,000 stb/d and US$130 MM for the highside case of 680,000 stb/d. In addition well abandonment costs at an estimated US$400,000 per well have been included.
133 6. ECONOMICS
6.1. VALUATION ASSUMPTIONS
6.1.1. General
The effective date of this report is 30/06/2009 and this has been used as the discount date for the valuation. All values are post-tax and have been expressed over a range of discount rates. An annual inflation rate of 2% has been assumed and is applied to both costs and revenues.
6.1.2. Oil Prices
The valuation has been based on the RPS long term forecast for Brent (long term price of $80/bbl in REAL 2009$) as shown Table 6-1 and Figure 6-1. A Low Price Case ($60/bbl in REAL 2009$) and High Price Case ($100/bbl in REAL 2009$) are also shown in the Table in Money of the Day (MOD) and have been used for price sensitivity purposes.
Low Price Case Base Price Case High Price Case (US$/bbl, MOD) (US$/bbl, MOD) (US$/bbl, MOD) 2009(6) 55.00 65.00 75.00 2010 61.20 72.00 84.00 2011 62.40 78.00 93.00 2012 63.60 84.00 102.00 2013 65.00 86.00 108.00 2014 66.24 88.00 110.41 2015 67.57 90.09 112.62 2016 68.92 91.89 114.87 2017 70.30 93.73 117.17 2018 71.71 95.61 119.51 2019 73.14 97.52 121.90 2020 74.60 99.47 124.34 2021 76.09 101.46 126.82 2022 onwards + 2% p.a. + 2% p.a. + 2% p.a.
Table 6-1: RPS Forecast Price Cases
134 RPS Brent Oil Price Forecast 190 180 170 160 150 140 130 120 110 100 90 80
Brent (US$/bbl) 70 60 50 Forecast price (US$ MOD) 40 30 20 Forecast price (US$ 2009) 10 0
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 2048
Figure 6-1: RPS Base Forecast Price
This forecast price was used as the basis for all other price forecasts required for the valuation. These prices are summarised in Table 6-2. Details of how each price deck was derived can be found in the sections below for each asset.
Russia Uganda Kurdistan Urals Export Kingfisher Block 1 Kirkuk Blend Domestic South heavy oil Blend Year US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl 2009(6) 52.25 34.53 59.61 59.36 62.40 2010 58.14 38.42 66.77 66.52 69.12 2011 59.28 39.17 72.91 72.66 74.88 2012 60.42 39.93 79.04 78.79 80.64 2013 61.75 40.80 81.09 80.84 82.56 2014 62.93 41.59 83.13 82.88 84.48 2015 64.19 42.42 85.27 85.02 86.49 2016 65.48 43.27 87.12 86.87 88.22 2017+ +2%pa +2%pa +2%pa +2%pa +2%pa
Table 6-2: Table of Base Case Forecast Prices
6.2. VALUATION METHODOLOGY
6.2.1. Reserves
1P, 2P and 3P reserves were valued using spreadsheet-based discounted cashflow models. Each model was based on the applicable contract terms and a forecast of future production and costs.
135 6.2.2. Contingent and Prospective Resources
Contingent Resources have been assigned to:
• Kingfisher in Block 3A, Uganda;
• Buffalo/Giraffe and Warthog in Block 1, Uganda;
• Miran West (down to 200 TVDSS), Kurdistan
The (1C, 2C and 3C) contingent resources in Kingfisher and Miran were valued in a similar manner as the reserves, using spreadsheet-based discounted cash flow models. Each model was based on the applicable contract terms and a forecast of future production and costs.
The Block 1 contingent resources and all prospective resources in Blocks 1 and 3A were valued using a Monte Carlo simulation model. The Monte Carlo model simulates all possible outcomes of the Uganda drilling programme based on the GPoS of each prospect and its range of recoverable resources. The result of the simulation is a massive array of discovered resources and resulting NPV10 net to Heritage. Each set of values in the array represents one possible combination of success and failure of the drilling programme with corresponding discovered oil volumes. For each realisation or success scenario in the Monte Carlo simulation the model generates a forecast production profile that matches the volume of oil resources discovered as well as development cost profiles. This input data is used to generate a value of the discovered resources using a detailed cash flow model that is embedded into the simulation model. This approach was considered necessary as a large proportion of the total development costs are shared infrastructure costs (processing facilities and export pipelines). The scale of investment in infrastructure is dependent on the total level of success in both Blocks.
The value of each outcome from the simulation is weighted based on the relative probability of the outcome occurring. These relative probabilities are based on the risks assigned to each prospect. The “true” expected value of the drilling programme or EMV simply represents the probability weighted average value of all possible outcomes of the drilling programme. The range in possible values of the drilling programme and the mean of these values is displayed as a reverse cumulative distribution of NPV10.
The prospective resources in Miran West were valued by consolidating the contingent and prospective resources into a total resources estimate for the whole of Miran West. A P90, P50 and P10 development case with forecast costs and production was constructed and valued. Using these cases an expected value for the whole field was calculated. The expected value of the contingent resources alone was then subtracted form the whole field expected value to give the expected value of the prospective resources.
6.3. RUSSIA—ZAPADNO CHUMPASSKOYE
6.3.1. Fiscal Regime and Contract Terms
The Zapadno Chumpasskoye licence is due to expire in September 2024. The main commercial terms are:
Crude Oil Export Duty
Urals Urals Rate (US$/tonne) (US$/bbl) <109.5 <15 0 109.5 – 146.0 15 – 20 0.35 * (P – 15) 146.0 – 182.5 20 – 25 1.75 + 0.45 * (P – 20) >182,5 >25 4.00 + 0.65 * (P – 25) P = average quarterly price of Urals Blend (US$/bbl)
136 VAT 18 per cent. on domestic sales Mineral Extraction Tax (MET) Oil MET = 419 Roubles / tonne * Cp Where Cp = (P – 15) * (R / 261) P = average quarterly price of Urals Blend (US$/bbl) R = average quarterly exchange rate for US$/Rouble Tax base—Revenue less VAT, excise tax, custom duties, transportation costs and insurance costs Property Tax 2.2 per cent. Tax base—Cumulative CAPEX (drilling & facilities) less depreciation Income / Profits Tax 20.0% Tax base—Revenue less OPEX, depreciation, interest, exchange rate losses and losses on re-evaluation. Depreciation: Facilities: 7-10 years Drilling: 10-15 years Pipelines: 20-25 years Loss carry forward – 10 years
6.3.2. Price Assumptions
Heritage has assumed that the gross field production will be split between export (via Black Sea) and domestic sales in the proportion 35% / 65% respectively. The export price has been based on the Urals (Mediterranean) price. This has been derived from the Brent forecast using a relationship based on an analysis of historical prices (see figure below). A 5% discount to Brent has been assumed for the valuation. The domestic price was assumed to be 56% of the Urals price.
Figure 6-2: Plot of Brent vs. URALS (Mediterranean)—1997 to June 2009
137 6.3.3. Transportation Costs
Estimates of the transportation costs for export via the Transneft pipeline system were provided by Heritage. A figure of US$5.65/bbl was used for export costs. Domestic sales are assumed to be at the Transneft custody point and as such any transportation costs are built into the domestic price.
6.3.4. Exchange rate and Tax Losses
A constant exchange rate of 33 Roubles to the US $ was assumed for the valuation. The total tax loss carry forward at 30/06/2009 of US$14.377 MM was included in the valuation as a deduction against future profits tax liabilities. In addition, US$17.577 MM was included as the total undepreciated sunk costs. These sums were provided by Heritage.
6.3.5. Valuation Summary
Although the licence expiry date is 2024, the value and reserves have been reported up to their economic limit on the assumption that the licence will be extended to allow full economic recovery of all the reserves. The valuation includes the cost of abandonment of the wells and all facilities, which has been estimated to be US$25.0 MM, US$40.0 MM and US$55.0 MM (in 2009 US$) for the 1P, 2P and 3P cases, respectively.
Economic Post-Tax Net Present Value Limit (US$ Million, MOD) Discount Rate 0.0% 5.0% 7.5% 10.0% 15.0% Proved Reserves (1P) 2030 238 128 90 60 18 Proved plus Probable Reserves (2P) 2031 844 503 388 298 174 Proved plus Probable plus Possible Reserves (3P) 2034 3,005 1,624 1,225 935 560
Table 6-3: Zapadno Chumpasskoye Post-Tax Valuation (Net Heritage Share)
Zapadno Chumpasskoye reserves are summarised in Table 6-4, below.
Heritage Net Heritage Net Entitlement Gross Working Reserves at Remaining Interest Base Case Price Reserves Reserves Forecast (MMstb) (MMstb) (MMstb) Proved Reserves (1P) 24.7 23.4 23.4 Proved plus Probable Reserves (2P) 63.4 60.3 60.3 Proved plus Probable plus Possible Reserves (3P) 172.6 164.0 164.0
Table 6-4: Zapadno Chumpasskoye Reserves Summary
6.3.6. Sensitivity to Oil Price
Sensitivity of the NPV10 of the future net revenue in Zapadno Chumpasskoye to changes in oil price is shown in Table 6-5.
Net Present Value10 of Future Net Revenue (US$ Million, MOD) Price Case 1P 2P 3P Low Price ($60) 9 177 635 Base Price ($80) 60 298 935 High Price ($100) 110 419 1,238
Table 6-5: Sensitivity of Zapadno Chumpasskoye NPV10 to Oil Price
138 6.4. UGANDA—BLOCKS 1 AND 3A
6.4.1. Fiscal Regime and Contract Terms
Block 1 and Block 3 Production Sharing Agreements were signed in July and September 2004 respectively. The exploration period in Block 1 is 7 years in duration and is subdivided into three sub-periods of 3 years, 2 years and 2 years. The exploration period in Block 3A on the other hand is 6 years in duration and is subdivided into three sub-periods of 2 years, 2 years and 2 years with the option of a second sub-period of 2 years. The development period in both contracts lasts for an initial 25 years and can be extended for an additional 5 years.
In April 2006 Addendum’s to the Block 1 and Block 3A contracts were signed. The commercial terms relating to Cost Recovery and Profit Sharing in Block 3A were revised with respect to the first oilfield to be developed.
RPS has seen the fiscal terms, the work programme and expenditure commitments of the executed PSA but are not permitted to disclose these terms under Government-imposed confidentiality.
The commercial structure of the PSCs are in our opinion very similar to standard PSCs with the Contractor’s entitlement revenue comprising of Cost Oil (defined as a maximum percentage of the net revenue) and Profit Oil (shared between the Contractor and the Government based on tranches of average daily production rates). A royalty payment is due under the contract on gross production, related to the level of average daily production, and net revenue is defined as the gross revenue less royalty. The Contractor’s is liable to Income Tax based on its share of Profit Oil and Cost Oil less deductions. The Government may participate in any future development at a level of up to 15% at the point of first production, but is required to make any repayment to the Contractor out of its share of future cost oil for costs incurred up to that point.
The corporation tax rate of 30% has been applied to all values quoted below.
6.4.2. Price Assumptions
New crude oils, such as Kingfisher, tend to trade at prices in common with the value of the products produced from them and the difference in cost of processing. Relative prices tend to reflect the variance in physical properties of the various grades. The Kingfisher crude oil will therefore tend to price at a value that reflects its yield of products or at a differential to already traded crude of similar quality. The Kingfisher crude is also a waxy crude and as such will tend to compete in markets where similar crudes such as Indonesian grades trade. The main markets will likely be Asia, and its value will be set by refining economics based on Singapore product prices and / or tagged to Asian marker crude grades such as Tapis & Minas.
The crude is 31.5° API, with very low Sulphur (0.11%) but with a high pour point (45°C) and wax content (30% w/w). It is also very low TAN (0.08 mg KOH/g). Its basic physical characteristics are similar to Indonesian Minas, to Chinese Daqing and to one of the few East African grades, Sudanese Nile Blend.
A quick first cut analysis has been made of its likely worth based on a TBP from samples received in February 2009. In quality and location, Kingfisher most resembles Sudanese Nile Blend, which trades FOB Indian Ocean at typically Minas OGSP—$5.0/bbl. Therefore, Kingfisher is expected to price in a similar manner with a differential to Minas that reflects its quality relative to that of Nile Blend. The TBP curve for Kingfisher shows it has a greater residue yield than Nile Blend. If distillate prices stay higher value than residual prices, Kingfisher will have a lower refining value than Nile Blend. New crudes also tend to be discounted for the first 6-9 months of their introduction, until such a time as traders and refiners become familiar with its quality. Kingfisher is likely therefore to attract a new crude discount of some $1.00/bbl until it becomes established. Concerted marketing of the crude through trading houses and brokers would be a fundamental way of quickly removing such a penalty.
In summary our first cut analysis would suggest that Kingfisher should be priced at constant differential of -$6.20 below Minas. Minas has been referenced to the Heritage Brent forecast, and is assumed to trade at a small premium to Brent.
This differential has been applied to all the other Block 3A resources and also to Block 1, with the exception of Buffalo/Giraffe, Buffalo East, Crocodile East and Leopard. The Buffalo and Giraffe crude samples have a lower
139 API, i.e. higher density, but lower wax content, resulting in a lower pour point. Because of its higher density and higher yields of heavier products, it is likely to be discounted further than Kingfisher. No assay of the oil is available, but on the basis of the PVT data available it is estimated that the Block 1 heavy oil will attract a further discount to Kingfisher of -$0.25/bbl. In practice this heavier crude will be blended with the Kingfisher type crude but the impact on the price of the blend has not been considered.
For the purposes of the valuation we have priced Kingfisher and all similar crudes at around a discount of -$6.20 to Minas and the heavier Block 1 crudes at around a discount of -$6.45.
6.4.3. Sunk Costs
The unrecovered costs (gross) at 30/06/2009 for both Blocks are:
• Block 1 US$48.7 MM
• Block 3A US$229.0 MM (of which US$181 MM is cost recoverable and US$47 MM are tax deductible and relate to Block 3)
These sums were provided by Heritage.
6.4.4. Valuation Summary
The valuation of Blocks 1 and 3A is more complex than for Russia and Kurdistan because of the mix of Contingent and Prospective resources and due to the sharing of common infrastructure costs. As a result the valuation has been undertaken using a Monte Carlo simulation model that was set up to simulate all possible combinations of success and failure as well as incorporating the uncertainty in recoverable resources. The valuation was broken down into 3 phases which are:
• Phase 1—development of Contingent Resources in Kingfisher South from an onshore location adjacent to the field and export of the production initially by truck to Jinja and then by rail to Mombasa. The trucking of early production is replaced in 2013/14 by a dedicated pipeline from Lake Albert to Hoima and then from Hoima to Jinja. This allows field production to ramp up to the full capacity of the rail export route (40,000 bopd) The Hoima to Jinja pipeline represents the 1st phase of a main export pipeline which will eventually join Hoima to Mombasa. This line and the Lake Albert to Hoima line will be oversized to accommodate the expected production from Block 1 and further production from Block 3A in the event of further exploration success;
• Phase 2—development of the Contingent and successful Prospective Resources in Block 1. All resources under development are tied back to a common central processing facility (CPF) via dedicated flowlines. The CPF is scaled to match the total plateau production of the resources under development. All production is then piped via a dedicated 3rd party pipeline from Block 1 to Hoima to join the main 3rd party export pipeline to Mombasa. The pipeline from Block 1 to Hoima is scaled to match the plateau production level of all the resources under development. It is assumed that the extension of the main export pipeline from Jinja to Mombasa will be available from 2016. The main export pipeline will also be scaled to the combined plateau rate of all resources under development in both Blocks 3A and 1.
• Phase 3—development of the Contingent Resources in Kingfisher North that could not be reached from an onshore location in Phase1, plus successful Prospective Resources in prospects beneath Lake Albert. All these lake prospects will be drilled from a dedicated jack-up rig and developed through a well tower tied back sub-sea to a common CPF located onshore adjacent to the Kingfisher South processing facilities. All production will be exported via the dedicated 3rd party pipeline to Hoima (built to export the Kingfisher South production in Phase 1) where it will join the main export pipeline to Mombasa and together with the production from Block 1.
140 6.4.5. Third Party Pipeline Tariffs
The PSCs in Uganda require the Contractor to establish an independent pipeline company to handle any export and for this company to charge the upstream contractors a tariff that provides for a fair and reasonable return on the investment needed to establish such export routes. This tariff, payable by the upstream contractors, can be charged to the PSC account for cost recovery purposes as an operating cost. In addition the truck and rail export is also charged to the PSCs as a tariff.
These tariffs have been estimated using a simple cashflow model incorporating capital and operating cost estimates for the establishment and operation of these export routes. In each case a tariff necessary to generate a 10% after tax rate of return has been computed and this has been used in the PSC cashflow modelling. A summary of the tariffs is;
6.4.5.1. Phase 1
Trucking Tariff (Lake Albert to Jinja)—$8.0 /bbl plus an estimated $0.5/bbl for heating at Jinja, payable for the years 2011, 2012 and 2013
Pipeline Tariff (Lake Albert to Hoima)—variable tariff based on required pipeline capacity (at 100,000 bopd $0.47 /bbl) payable from 2013/2014.
Pipeline Tariff (Hoima—Jinja)—variable tariff based on required pipeline capacity (at 200,000 bopd $3.10 /bbl) payable from 2013/14.
Rail Tariff—$9.3 /bbl plus $1.0 /bbl for heating in Mombasa. The tariff has been computed based on the assumption that the rail route is fully used for 15 years at a rate of 40,000 bopd after the initial trucking build-up period.
6.4.5.2. Phase 2/3
Pipeline Tariff (Block 1 to Hoima)—variable tariff based on required pipeline capacity (at 100,000 bopd $0.50 /bbl). The tariff has been computed based on the assumption that the pipeline is operational for 25 years;
Pipeline Tariff (Block 3A to Hoima)—variable tariff based on required pipeline capacity (at 100,000 bopd $0.47 /bbl). The tariff has been computed based on the assumption that the pipeline is operational for 25 years;
Export Pipeline Tariff (Hoima to Mombasa)—variable tariff based on the total required pipeline capacity (at 200,000 bopd $12.4 /bbl). The tariff has been computed based on the assumption that the pipeline is operational for 25 years.
6.4.6. Capital Costs
6.4.6.1. Kingfisher South
Drilling CAPEX was estimated using the drilling programme required to support the 1C (P90), 2C (P50) and 3C (P10) production forecasts that match the reported recoverable Contingent Resource volumes. Three producers were assumed to be conversions of existing wells.
In each case a processing facility with a capacity of 40,000 bopd was included in the CAPEX. To support the rail export, $28 MM was included to cover the purchase of sufficient bitutainers.
6.4.6.2. Block 1 Contingent and Prospective Resources
Field specific costs such as drilling and flow line tie backs to the CPF were estimated for the P90, P50 and P10 cases for each field/prospect.
A shared CPF was included with a capacity sufficient to handle the plateau production rate from the Block. Each pass of the Monte Carlo simulation model generated the need for a different sized CPF and the estimated cost of this CPF was scaled accordingly using a matrix of production rate vs. capital cost.
A shared export pipeline from Block 1 to Hoima is also assumed with sufficient capacity to handle the plateau production rate form the Block as a whole. This was scaled in each pass of the Monte Carlo simulation in the same way as the CPF. This results in a new tariff calculation for each pass of the simulation.
141 6.4.6.3. Block 3A Prospective Resources and remaining Contingent resources in Kingfisher
Field specific costs such as drilling and sub-sea tie backs to an onshore CPF adjacent to the Kingfisher South facilities were estimated for the P90, P50 and P10 cases for each field/prospect. Each prospect was assumed to be developed via a number of 24 slot well head towers. The number of well head towers varied in each pass of the simulation model according to the total resources under development and the number of wells drilled in each successful prospect.
A shared CPF was included with a capacity sufficient to handle the plateau production rate from the Block. Each pass of the Monte Carlo simulation model generated the need for a different sized CPF and the estimated cost of this CPF was scaled accordingly using a matrix of production rate vs. capital cost.
A shared export pipeline from Block 3A to Hoima is also assumed with sufficient capacity to handle the plateau production rate from the Block as a whole. This was scaled in each pass of the Monte Carlo simulation in the same way as the CPF. This results in a new tariff calculation for each pass of the simulation.
6.4.7. Operating Costs
6.4.7.1. Kingfisher South
For the Contingent resources in Kingfisher South, operating costs was estimated in detail for the 1C, 2C and 3C cases.
6.4.7.2. Block 1 Contingent and Prospective Resources
The OPEX was estimated as a block wide total for each pass of the Monte Carlo simulation based on the total production in the Block. This was based on a matrix of production rate vs. annual operating costs. The operating costs take account of the steam flood operations and the occurrence of heavy oil in some prospects.
6.4.7.3. Block 3A Prospective Resources and remaining Contingent Resources in Kingfisher
Block 3A OPEX was estimated in a very similar fashion as Block 1 except for a downward adjustment to account for the lighter oil.
6.4.8. Abandonment Costs
Except for Kingfisher South, where the abandonment costs were estimated for each case, the abandonment liabilities were based on the total capital expenditure within the Block. This varied with every pass of the Monte Carlo simulation.
6.4.9. Valuation Results
6.4.9.1. Block 3A Contingent Resources
The Block 3A Contingent Resources for valuation purposes comprise Kingfisher South only. The Contingent Resources in Kingfisher North have been included in the Prospective Resources valuation as they will be developed offshore together with the Lake Albert prospects. Kingfisher South has been evaluated as a standalone development as described in the section above. The results of the valuation of the 1C, 2C and 3C cases at the Base Case price are summarised in the table below.
Post-Tax Net Present Value Economic Net Heritage Share Limit (US$ Million, MOD) Discount rate 0.0% 5.0% 7.5% 10.0% 15.0% 1C 2029 568 334 255 190 103 2C 2037 1,549 843 635 482 284 3C 2037 2,810 1,353 971 710 389
Table 6-6: Block 3A Contingent Resources Post-Tax Valuation (Net Heritage Share)
142 For the purposes of the valuation all profiles have been truncated in 2048 unless the economic limit has been reached already.
6.4.9.2. Sensitivity to Oil Price
Sensitivity of the NPV10 of the future net revenue in the Block 3A Contingent Resources (Kingfisher South) to changes in oil price is shown in the table below.
Post-Tax Net Present Value Net Heritage Share (US$ Million, MOD) Price Case 1C 2C 3C Low Price ($60) 62 270 421 Base Price ($80) 190 482 710 High Price ($100) 307 688 992
Table 6-7: Sensitivity of Block 3A Contingent Resources NPV10 to Oil Price
6.4.9.3. Block 3A Prospective Resources
In order to value the Prospective Resources correctly it is necessary to consolidate the Prospective Resources with the Block Contingent Resources and compute a total PSC value. The value of the Prospective Resources is the result of subtracting the value of the Contingent Resources from the Total PSC value. This is a consequence of the PSC wide ring fence for royalty, cost recovery, profit sharing and tax. The result of the Monte Carlo simulation is a distribution of possible values for the Contingent Resources on their own and one for the total Block resources Figure 6-3. The total Block value is shown below as a reverse cumulative probability distribution. From this distribution it is possible to extract a P90, P50 and P10 value as well as the expected (or mean) value which is the EMV.
Figure 6-3: Reverse Cumulative Distribution showing Total Value of Block 3A Resources
143 The valuation is summarised in Table 6-8, below.
Post-Tax1 Net Present Value @10% Discount Rate Net Heritage Share (US$ Million, MOD) P90 P50 P10 Expected Value (Mean) Total PSC 222 629 1,292 691 Contingent Resources 190 482 710 464 Prospective Resources 227
The expected value of the Total PSC is the probability weighted mean of the value of all possible outcomes of the Contingent Resources plus the drilling of the Prospective Resources. This is also known as the EMV.
The expected value of the Contingent Resources represents the probability weighted mean value of the resource volume range. This is sometimes known as the ENPV.
The mean of distributions may be added or subtracted arithmetically but the P90, P50 and P10 values are the result of probabilistic addition or subtraction.
Table 6-8: Block 3A Prospective Resource Valuation Summary
6.4.9.4. Block 1 Contingent Resources
The Block 1 Contingent Resources comprise Buffalo/Giraffe plus Warthog and have been evaluated as described in the section above using the Monte Carlo simulation model. The results of the valuation at the Base Case price are summarised in the table below.
Post-Tax Net Present Value Economic Net Heritage Share Limit (US$ Million, MOD) Discount rate 0.0% 5.0% 7.5% 10.0% 15.0% 1C Resources Buffalo/Giraffe 2039 1,207 552 377 257 112 Warthog 2027 121 60 41 25 5 2C Resources Buffalo/Giraffe 2040 3,126 1,383 947 639 312 Warthog 2035 312 168 123 89 47 3C Resources Buffalo/Giraffe 2040 4,703 1,894 1,251 841 385 Warthog 2037 451 246 184 140 78
Table 6-9: Block 1 Contingent Resources Post-Tax Valuation (Net Heritage Share)
For the purposes of the valuation all profiles have been truncated in 2048 unless the economic limit has been reached already.
144 6.4.9.5. Sensitivity to Oil Price
Sensitivity of the NPV10 of the future net revenue in the Block 1 Contingent Resources (Kingfisher South) to changes in oil price is shown in the table below.
Post-Tax Net Present Value Price Case Net Heritage Share (US$ Million, MOD) 1C 2C 3C Buffalo/Giraffe Low Price ($60) 115 331 476 Base Price ($80) 257 639 841 High Price Base ($100) 395 941 1,293 Warthog Low Price ($60) -7 40 73 Base Price ($80) 25 89 140 High Price ($100) 49 137 204
Table 6-10: Sensitivity of Block 1 Contingent Resources NPV10 to Oil Price
6.4.9.6. Block 1 Prospective Resources
In order to value the Prospective Resources correctly it is necessary to consolidate the Prospective Resources with the Contingent Resources and compute a total PSC value. The value of the Prospective Resources is the result of subtracting the value of the Contingent Resources from the Total PSC value. This is a consequence of the PSC wide ring fence for royalty, cost recovery, profit sharing and tax. The result of the Monte Carlo simulation is a distribution of possible values for the Contingent Resources on their own and one for the total Block resources. The total Block value is shown below as a reverse cumulative probability distribution. From this distribution it is possible to extract a P90, P50 and P10 value as well as the expected (or mean) value which is the EMV.
Figure 6-4: Reverse Cumulative Distribution showing Total Value of Block 1 Resources
145 The valuation is summarised in the table below.
Post-Tax Net Present Value @10% Discount Rate Net Heritage Share (US$ Million, MOD) Expected Value P90 P50 P10 (Mean)
Total PSC 410 878 1,382 920
Contingent Resources 329 717 915 662
Prospective Resources 258
The expected value of the Total PSC is the probability weighted mean of the value of all possible outcomes of the Contingent Resources plus the drilling of the Prospective Resources. This is also known as the EMV. The expected value of the Contingent Resources represents the probability weighted mean value of the resource volume range. This is sometimes known as the ENPV. The mean of distributions may be added or subtracted arithmetically but the P90, P50 and P10 values are the result of probabilistic addition or subtraction.
Table 6-11: Block 1 Prospective Resource Valuation Summary
6.5. KURDISTAN—MIRAN BLOCK
6.5.1. Fiscal Regime and Contract Terms
The Miran Block was signed in October 2007. The exploration period is 5 years in duration and is subdivided into an initial sub-period of 3 years with the option of a second sub-period of 2 years. The development period lasts for an initial 20 years and can be extended for an additional 5 years.
The extended details of the Miran PSC are subject to confidentiality agreements. However, RPS Energy confirms that it has had full access to the final, signed copy of PSC under the terms of such agreements and that the commercial terms therein have been built into our economic models. The RPS valuation honours fully these commercial terms.
The commercial structure of the PSC is in our opinion very similar to standard PSCs with the Contractor’s entitlement revenue comprising of Cost Oil (defined as a maximum percentage of the net revenue) and Profit Oil (shared between the Contractor and the Government based on a R factor, the R factor being defined as the ratio of cumulative revenue divided by cumulative costs). A royalty payment is due under the contract on gross production and net revenue is defined as the gross revenue less royalty. As is normal, the Contractor’s Income Tax liability is paid by the Government out of its share of Profit Oil. The Government may participate in any future development at a level of up to 25% at the point when commerciality is declared, but is not required to make any repayment to the Contractor for costs incurred up to that point.
RPS has not taken into account in its cash flows the US$35 MM payment for removal of the obligation to build a refinery that was in the original PSC terms.
146 6.5.2. Price Assumptions
For the purposes of the valuation it was assumed that Miran crude would trade at a similar price as Kirkuk. This crude currently trades around 4% below Brent.
$160
$140
$120
$100
$80
$60
Kirkuk Blend ($/bbl) $40
$20
$0 $0 $20 $40 $60 $80 $100 $120 $140 $160 Brent ($/bbl)
Figure 6-5: Plot of Brent vs. Kirkuk Blend—2008 to June 2009
6.5.3. Sunk Costs
The unrecovered costs (gross) at 30/06/2009 for the Miran Block are $70.2 MM. This sum was provided by Heritage.
6.5.4. Valuation summary
6.5.4.1. Contingent resources
The Contingent Resources in Miran West have been valued separately on a standalone basis and the 1C, 2C and 3C values at the Base Case price are summarised in Table 6-12. These values are unrisked and do not include any chance of development.
Post-Tax Net Present Value Economic Net Heritage Share Limit (US$ Million, MOD) Discount rate 0.0% 5.0% 7.5% 10.0% 15.0% 1C Resources 2028 233 119 79 46 -1 2C Resources 2028 738 455 357 280 169 3C Resources 2035 1,225 751 597 478 308
Table 6-12: Miran West Contingent Resources Post-Tax Valuation (Net Heritage Share)
147 The Miran West Contingent Resources are summarised in Table 6-13.
Heritage Net Heritage Net Entitlement Gross Working Resources at Remaining Interest Base Case Price Resources Resources Forecast (MMstb) (MMstb) (MMstb) 1C Resources 33 25 13 2C Resources 71 53 23 3C Resources 120 90 33
Table 6-13: Miran West Contingent Resources Summary
6.5.4.2. Sensitivity to Oil Price
Sensitivity of the unrisked NPV10 of the future net revenue in the Miran West Contingent Resources to changes in oil price is shown in Table 6-14.
Post-Tax Net Present Value Net Heritage Share (US$ Million, MOD)
Price Case 1C 2C 3C Low Price ($60/bbl real) -89 150 319 Base Price ($80/bbl real) 46 280 478 High Price ($100/bbl real) 149 384 616
Table 6-14: Sensitivity of Miran West Contingent Resources NPV10 to Oil Price
6.5.4.3. Prospective Resources
The prospective resources lie in the deeper section of Miran West and in Miran East. The Miran East value has been calculated on a standalone basis but the Miran West has been valued as part of a consolidated Miran West development. The incremental value of the prospective resources has been determined by subtraction of the Miran West Contingent Resource value. Since it is not statistically valid to subtract P90, P50 or P10 numbers arithmetically the only prospective value quoted is for the mean. The valuation at the Base Case price is summarised in the table below.
Post-Tax Net Present Value @10% Discount Rate Net Heritage Share (US$ Million, MOD) Expected Value P90 P50 P10 (Mean) Miran West Total Field 228 3,971 8,431 3,920 Miran West Contingent Resources 46 280 478 275 Miran West Prospective Resources 3,645 Miran East Prospective Resources 119 964 3,085 479 Total Prospective Resources 4,125 The expected value of Miran East is the probability weighted mean of the value of all possible outcomes for this prospect including the chance of a dry hole (1-36% = 74%). This is also known as the EMV. The expected value of Miran West Contingent Resources, since they already discovered, represents the probability weighted mean value of the resource volume range. This is sometimes known as the ENPV. This ENPV does not incorporate any chance of development. The expected value of the total Miran West field is based on the ENPV of the Contingent Resources plus the risked value of the additional Prospective Resources which includes a choice of success of 85%. The mean of distributions may be added or subtracted arithmetically but the P90, P50 and P10 values can only be calculated by probabilistic addition or subtraction.
Table 6-15: Miran Field Post Tax NPV10
148 APPENDIX A: GLOSSARY OF TECHNICAL TERMS
1P Proved 2P Proved plus Probable 3P Proved plus Probable plus Possible AAPG American Association of Petroleum Geologists API American Petroleum Institute B Billion Barg gauge pressure in Bar Bbls Barrels Bopd barrels of oil per day
Bo(g)i initial formation volume factor for oil (or gas) Bscf billion standard cubic feet Btu British Thermal Units
(i/n)Cn (isomeric or normal) hydrocarbon of the general form CnH2n+2
C1 C1H4 , methane
C3 C3H8 , propane
C4 C4H10 , butane
C7(+) C7H16 , heptane (plus, meaning heptane and all heavier fractions)) CGR Condensate: Gas Ratio
CO2 carbon dioxide CVD Constant Volume Depletion (a laboratory experiment) DST drill stem test Entitlement Volumes the volumes of oil and/or gas which a Contractor receives under the terms of a PSA EoS Equation of State FBHP flowing bottom hole pressure FFD Full Field Development Ft Feet
FVF Formation Volume Factor (also: Boi) FWHP flowing well head pressure G&A General & Administrative GIIP Gas Initially In Place GPoS Geological Probability of Success GOC Gas-oil contact GOR Gas: Oil Ratio GRV gross rock volume
H2S hydrogen sulphide LPG Liquefied Petroleum Gas—in this context means either Butane or Propane or both
k(e) (effective) permeability Kg Kilogram Km Kilometre
149 M Metres M Thousand MD measured depth mD permeability in milli-Darcies MM Million Mbbls thousand barrels MMBtu/d millions of British Thermal Units per day MMbwpd million barrels of water per day MMscfd or MMscf/d millions of standard cubit feet per day MMstb million stock tank barrels Money of the Day calculated allowing for the effect of inflation MPa Mega Pascal
N2 Nitrogen N:G Net to gross ratio NIOC National Iranian Oil Company OWC oil-water contact PI Productivity Index (stb/d/psi) p(b/r) (bubble point or reservoir) pressure PSC / PSA Production Sharing Contract / Production Sharing Agreement psi(a/g) pounds per square inch (absolute/gauge) PTA Pressure transient analysis PVT Pressure, Volume & Temperature RF Recovery Factor
Rsi Solution GOR
Rw Water resistivity S Skin, a measure of damage derived from well test analysis Scf standard cubic feet measured at 14.7 pounds per square inch and 60° F SPE Society of Petroleum Engineers STOIIP Stock Tank Oil Initially In Place
Sw Water Saturation TD Total Depth
Tr Reservoir temperature TVD True vertical depth TVDSS true vertical depth (sub-sea) URR Ultimate recoverable reserves (before economic cut-off) VCL Volume of clay VRR Voidage replacement ratio VSH Volume of shale WHFP Wellhead Flowing Pressure Working Interest Share (of reserves) calculated by multiplying the Gross estimate by the Contractor’s Working Interest in a Production Sharing Contract WPC World Petroleum Congress
150 Ωm Ohm-metre ω Omega, a measure of fracture storage λ Lambda, a measure of matrix-fracture flow ρ o. Oil density
μo Oil viscosity
151 APPENDIX B: SPE/WPC/AAPG/SPEE RESERVE/RESOURCE DEFINITIONS
The following is extracted from the SPE/WPC/AAPG/SPEE PRMS 2007 using the section numbering and spelling from PRMS.
1.0 Basic Principles and Definitions
The estimation of petroleum resource quantities involves the interpretation of volumes and values that have an inherent degree of uncertainty. These quantities are associated with development projects at various stages of design and implementation. Use of a consistent classification system enhances comparisons between projects, groups of projects, and total company portfolios according to forecast production profiles and recoveries. Such a system must consider both technical and commercial factors that impact the project’s economic feasibility, its productive life, and its related cash flows.
1.1 Petroleum Resources Classification Framework
Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, or solid phase. Petroleum may also contain non-hydrocarbons, common examples of which are carbon dioxide, nitrogen, hydrogen sulfide and sulfur. In rare cases, non-hydrocarbon content could be greater than 50%.
The term “resources” as used herein is intended to encompass all quantities of petroleum naturally occurring on or within the Earth’s crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered “conventional” or “unconventional.”
Figure 1-1 is a graphical representation of the SPE/WPC/AAPG/SPEE resources classification system. The system defines the major recoverable resources classes: Production, Reserves, Contingent Resources, and Prospective Resources, as well as Unrecoverable petroleum.
Figure 1-1: Resources Classification Framework.
152 The “Range of Uncertainty” reflects a range of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the “Chance of Commerciality, that is, the chance that the project that will be developed and reach commercial producing status. The following definitions apply to the major subdivisions within the resources classification:
TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”).
DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production.
PRODUCTION is the cumulative quantity of petroleum that has been recovered at a given date. While all recoverable resources are estimated and production is measured in terms of the sales product specifications, raw production (sales plus non-sales) quantities are also measured and required to support engineering analyses based on reservoir voidage.
Multiple development projects may be applied to each known accumulation, and each project will recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided into Commercial and Sub-Commercial, with the estimated recoverable quantities being classified as Reserves and Contingent Resources respectively, as defined below.
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 sub-classified based on project maturity and/or characterized by development and production status.
CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources 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 their economic status.
UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered.
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.
UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in-Place quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
153 Estimated Ultimate Recovery (EUR) is not a resources category, but a term that may be applied to any accumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be potentially recoverable under defined technical and commercial conditions plus those quantities already produced (total of recoverable resources).
1.2 Project-Based Resources Evaluations
The resources evaluation process consists of identifying a recovery project, or projects, associated with a petroleum accumulation(s), estimating the quantities of Petroleum Initially-in-Place, estimating that portion of those in-place quantities that can be recovered by each project, and classifying the project(s) based on its maturity status or chance of commerciality.
This concept of a project-based classification system is further clarified by examining the primary data sources contributing to an evaluation of net recoverable resources (see Figure 1-2) that may be described as follows:
Net RESERVOIR Recoverable PROJECT (in-place volumes) Resources (production/cash flow)
Entitlement
PROPERTY (ownership/contract terms)
Figure 1-2: Resources Evaluation Data Sources
• The Reservoir (accumulation): Key attributes include the types and quantities of Petroleum Initially-in-Place and the fluid and rock properties that affect petroleum recovery.
• The Project: Each project applied to a specific reservoir development generates a unique production and cash flow schedule. The time integration of these schedules taken to the project’s technical, economic, or contractual limit defines the estimated recoverable resources and associated future net cash flow projections for each project. The ratio of EUR to Total Initially-in-Place quantities defines the ultimate recovery efficiency for the development project(s). A project may be defined at various levels and stages of maturity; it may include one or many wells and associated production and processing facilities. One project may develop many reservoirs, or many projects may be applied to one reservoir.
• The Property (lease or license area): Each property may have unique associated contractual rights and obligations including the fiscal terms. Such information allows definition of each participant’s share of produced quantities (entitlement) and share of investments, expenses, and revenues for each recovery project and the reservoir to which it is applied. One property may encompass many reservoirs, or one reservoir may span several different properties. A property may contain both discovered and undiscovered accumulations.
In context of this data relationship, “project” is the primary element considered in this resources classification, and net recoverable resources are the incremental quantities derived from each project. Project represents the link between the petroleum accumulation and the decision-making process. A project may, for example, constitute the development of a single reservoir or field, or an incremental development for a producing field, or the integrated development of several fields and associated facilities with a common ownership. In general, an individual project will represent the level at which a decision is made whether or not to proceed (i.e., spend more money) and there should be an associated range of estimated recoverable quantities for that project.
154 An accumulation or potential accumulation of petroleum may be subject to several separate and distinct projects that are at different stages of exploration or development. Thus, an accumulation may have recoverable quantities in several resource classes simultaneously.
In order to assign recoverable resources of any class, a development plan needs to be defined consisting of one or more projects. Even for Prospective Resources, the estimates of recoverable quantities must be stated in terms of the sales products derived from a development program assuming successful discovery and commercial development. Given the major uncertainties involved at this early stage, the development program will not be of the detail expected in later stages of maturity. In most cases, recovery efficiency may be largely based on analogous projects. In-place quantities for which a feasible project cannot be defined using current, or reasonably forecast improvements in, technology are classified as Unrecoverable.
Not all technically feasible development plans will be commercial. The commercial viability of a development project is dependent on a forecast of the conditions that will exist during the time period encompassed by the project’s activities. “Conditions” include technological, economic, legal, environmental, social, and governmental factors. While economic factors can be summarized as forecast costs and product prices, the underlying influences include, but are not limited to, market conditions, transportation and processing infrastructure, fiscal terms, and taxes.
The resource quantities being estimated are those volumes producible from a project as measured according to delivery specifications at the point of sale or custody transfer. The cumulative production from the evaluation date forward to cessation of production is the remaining recoverable quantity. The sum of the associated annual net cash flows yields the estimated future net revenue. When the cash flows are discounted according to a defined discount rate and time period, the summation of the discounted cash flows is termed net present value (NPV) of the project.
155 PART VII—DEFINITIONS
The following definitions apply throughout this document, except in Parts III, IV and VI of this document, unless the context otherwise requires:
“ABCA” the Business Corporations Act (Alberta), as amended
“Act” the Companies (Jersey) Law 1991, and the regulations promulgated thereunder as each may be amended from time to time
“Adopted IFRS” International Financial Reporting Standards as adopted for use in the European Union
“Alberta CallCo” 1381890 Alberta ULC, a wholly-owned subsidiary of the Company incorporated under the laws of Alberta
“Arrangement Agreement” the agreement entered into in connection with the Plan of Arrangement between the Company, DutchCo and Alberta CallCo on 22 February 2008
“Articles” the articles of association of the Company, as amended
“Beneficiaries” the registered holders (other than the Company and its affiliates) of the Exchangeable Shares
“Board” or “Directors” the directors of the Company as at the date of this document whose names are set out on page 36 of this document
“Block 3 JOA” the joint operating agreement in respect of the former Block 3, Uganda, as described in Section 5 of Part I of this document
“Business Day” means any day on which commercial banks are generally open for business in Jersey and Calgary, Alberta other than a Saturday, a Sunday or a day observed as a holiday in Jersey or in Calgary, Alberta under the laws of Canada or any jurisdiction therein
“Companies Act” the U.K. Companies Act 1985, as amended
“Company” or “Heritage” Heritage Oil Plc, a company incorporated in Jersey on 6 February 2008 as Heritage Oil Limited, with company number 99922 and whose registered address is Ordnance House, 31 Pier Road, St Helier, JE4 8PW, Jersey, Channel Islands. On 18 June 2009, the name of the Company was changed to Heritage Oil Plc
“Completion” means completion of the Disposal
“Computershare” Computershare Investor Services (Jersey) Limited
“Computershare Canada” means Computershare Trust Company of Canada
“Continuing Group” means the Heritage Group, excluding the Disposed Assets, following Completion
“CREST” the computerised settlement system operated by CRESTCO to facilitate the transfer of title to shares in uncertificated form
“CRESTCO” Euroclear U.K. and Ireland Limited
156 “Deferred Consideration” the deferred consideration of up to $150 million payable in respect of the sale of the Disposed Assets, as described in Section 4 of Part I of this document
“Disclosure and Transparency Rules” the Disclosure and Transparency Rules published by the FSA from time to time
“Disposal” the proposed disposal of the Disposed Assets pursuant to (i) the Disposal Agreement, or in the alternative (ii) a disposal agreement to be entered into with Tullow (and/or its wholly-owned affiliate) on the same terms and conditions as the Disposal Agreement in the event after the date of this document Tullow delivers to the Heritage Group a valid Pre-Emption Notice
“Disposal Agreement” the conditional asset disposal agreement dated 18 December 2009 between the Company, HOGL, and Eni International, as described in Section 4 of Part I of this document and Section 5.1(i) of Part V of this document
“Disposed Assets” all of the Heritage Group’s unencumbered and undivided 50 per cent. interest in the Block 1 and Block 3A licences in Uganda under the respective PSCs and under the Block 3 JOA, including all of the Heritage Group’s rights and obligations in respect of the operatorship thereof, and the whole of the issued share capital of HOGL(U), a company incorporated in Uganda being a wholly-owned subsidiary of the Company
“DutchCo” Heritage Coöperatief U.A., a wholly-owned subsidiary of the Company, incorporated under the laws of the Netherlands
“DRC” the Democratic Republic of Congo
“Energy Africa” Energy Africa Uganda Limited, now renamed Tullow Uganda Limited
“Eni” Eni S.p.A. or its affiliates (including Eni International where appropriate)
“Eni International” Eni International B.V., a company incorporated under the laws of the Netherlands, being a wholly-owned subsidiary of Eni
“Exchangeable Shares” the exchangeable shares of HOC
“Existing Ordinary Shares” 284,527,830 Ordinary Shares in issue as at 18 December 2009, being the latest practicable date prior to the date of this document
“Existing Exchangeable Shares” 3,024,108 Exchangeable Shares in issue with a voting right as at 18 December 2009, being the latest practicable date prior to the date of this document
“Form of Proxy” the form of proxy for use at the General Meeting
“FSA” or “Financial Services the U.K Financial Services Authority in its capacity as the competent Authority” authority for the purposes of Part VI of FSMA and in the exercise of its functions in respect of admission to the Official List otherwise than in accordance with Part VI of FSMA
157 “FSMA” the Financial Services and Markets Act 2000, as amended
“General Meeting” the general meeting of the Company to be held on 25 January 2010, to be convened by the Notice set out at the end of this document (including any adjournment thereof)
“Heritage Group” the Company and its subsidiary companies as at the date of this document
“HOGL” Heritage Oil & Gas Limited, a company incorporated under the laws of the Commonwealth of the Bahamas, being a wholly-owned subsidiary of the Company
“HOGL(U)” Heritage Oil & Gas (U) Limited, a company incorporated under the laws of Uganda, being a wholly-owned subsidiary of the Company
“HOC” Heritage Oil Corporation, a company incorporated under the laws of Alberta, being a wholly-owned subsidiary of the Company
“HOC Common Shares” the Common Shares of HOC
“Iraq” the Republic of Iraq
“ISIN” International Security Identification Number
“JOA” joint operating agreement
“J.P. Morgan Cazenove” J.P. Morgan Cazenove Limited
“Kurdistan” the Kurdistan Region of Iraq, being a semi-autonomous federal region within Iraq
“Listing” the admission of Ordinary Shares and Exchangeable Shares to the Official List and to trading on the London Stock Exchange’s main market for listed securities which became effective on or around 31 March 2008
“Listing Rules” the listing rules of the FSA
“London Stock Exchange” or “LSE” London Stock Exchange plc
“LTIP” the 2008 Long Term Incentive Plan approved by shareholders of the Company in June 2008
“Main Market” the Main Market of the London Stock Exchange
“Major Shareholder” Albion Energy Limited, a company incorporated under the laws of the Commonwealth of Barbados
“Memorandum” the memorandum of association of the Company
“New Companies Act” the U.K. Companies Act 2006, as amended
“Official List” the Official List of the UKLA
“Option” an option to acquire Ordinary Shares pursuant to the Scheme
158 “Ordinary Shares” ordinary shares of no par value in the capital of the Company
“Plan of Arrangement” the Court approved reorganisation of the share capital of HOC in connection with the Listing, pursuant to Article 193 of the ABCA where all of the existing HOC Common Shares were converted to Ordinary Shares and Exchangeable Shares
“Pre-Emption Notice” the notice to Heritage pursuant to which Tullow may exercise the Pre-Emption Right
“Pre-Emption Right” the right of Tullow to acquire the Disposal Assets, as described in Section 5 of Part I of this document.
“PRMS” SPE/WPC/AAPG/SPEE 2007 Petroleum Resource Management System
“PSC” production sharing contract
“Regulations” Companies (Uncertificated Securities) (Jersey) Order 1999 of Jersey
“Replacement Stock Option Scheme” the Company’s stock option scheme dated 18 March 2008 or “Scheme” “Reporting Accountants” in respect of matters relating to the United Kingdom and Jersey, KPMG Audit Plc
“Resolutions” the resolutions to be proposed at the General Meeting
“Retraction Request” request by a holder of Exchangeable Shares for redemption of such Exchangeable Shares
“RPS” RPS Energy
“RPS Report” the mineral experts’ report prepared by RPS setting out the Heritage Group’s statement of reserves data and other oil and gas information in respect of the material assets of the Heritage, including the Disposed Assets, effective 30 June 2009, prepared in accordance with PRMS and reproduced in its entirety at Part VI of this document
“SeaDragon” SeaDragon Offshore Limited
“Shareholders” holders of Ordinary Shares or the holder of the Special Voting Share from time to time
“Special Voting Share” the special voting share in the Company issued to the Trustee
“Support Agreement” the agreement entered into on 17 March 2008 between the Company, DutchCo, Alberta CallCo and HOC described in Section 5.1(c) of Part V of this document
“Transfer Agent” means Computershare Trust Company of Canada or such other person as may from time to time be appointed by HOC as the registrar and transfer agent for the Exchangeable Shares
“Trustee” means Computershare Canada and, subject to the provisions of Article 9 of the Voting and Exchange Trust Agreement, includes any successor trustee
159 “TSX” the Toronto Stock Exchange
“Tullow” Tullow Oil plc or its affiliates (including Tullow Uganda Limited, where appropriate)
“Uganda” the Republic of Uganda
“U.K.” or “United Kingdom” the United Kingdom of Great Britain and Northern Ireland
“UKLA” the U.K. Listing Authority, being the FSA acting in its capacity as the competent authority for listing under Part VI of FSMA
“U.S.” or “United States” the United States of America, its territories and possessions, any state of the United States of America and the District of Columbia and all other areas subject to its jurisdiction
“Voting and Exchange Trust a voting and exchange trust agreement entered into by the Company, Agreement” HOC, Alberta CallCo and the Trustee, on 27 February 2008
“Voting Share Capital” the Existing Ordinary Shares and the Existing Exchangeable Shares
160 PART VIII—GLOSSARY
The following definitions apply throughout this document, unless the context otherwise requires:
“API” a specific gravity scale developed by the American Petroleum Institute for measuring the relative density of various petroleum liquids, expressed in degrees
“bbl” barrel
“bbls” barrels
“bbls/d” or “bopd” barrels per day
“Bcf” billion cubic feet
“boe” barrels of oil equivalent(1)
“boe/d” or boepd” barrels of oil equivalent per day
“condensate” low density, high API hydrocarbon liquids that are present in natural gas fields where it condensates out of the raw gas if the temperature is reduced to below the hydrocarbon dew point temperature of the raw gas
“Contingent Resources” those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingent Resources are a class of discovered recoverable resources as defined in the PRMS
“Gj” gigajoules
“LPG” liquid petroleum gas
“Mbbls” thousand barrels
“MMbbls” million barrels
“Mboe” thousands of barrels of oil equivalent
“MMboe” millions of barrels of oil equivalent
“Mcf” thousand cubic feet
“Mcf/d” thousand cubic feet per day
“MMBtu” million British thermal units
“MMcf” million cubic feet
“MMcf/d” million cubic feet per day
“MMstb” million stock tank barrels
“NGLs” natural gas liquids
161 “Petroleum” any mineral, oil or relative hydrocarbon (including condensate and natural gas liquids) and natural gas existing in its natural condition in strata (but not including coal or bituminous shale or other stratified deposits from which oil can be extracted by destructive distillation)
“Possible Reserves” as defined in the PRMS, an incremental category of estimated recoverable volumes associated with a defined degree of uncertainty. Possible reserves are those additional reserves which analysis and geoscience and engineering data suggest are less likely to be recovered than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible Reserves (3P) which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10 per cent. probability that the actual quantities recovered will equal or exceed the 3P estimate
“Probable Reserves” as defined in the PRMS, an incremental category of estimated recoverable volumes associated with a defined degree of uncertainty. Probable Reserves are those additional reserves that are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context when probabilistic methods are used, there should be at least a 50 per cent. probability that the actual quantities recovered will equal or exceed the 2P estimate
“Prospective Resources” those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations as defined in the PRMS
“Proved Reserves” as defined in the PRMS, an incremental category of estimated recoverable volumes associated with a defined degree of uncertainty. Proved Reserves are those quantities of petroleum, which by analysis and geoscience, 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. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 per cent. probability that the actual quantities recovered will equal or exceed estimate. Often referred to as a 1P, also as “Proven”
“psi” pounds per square inch
“psia” pounds per square inch absolute
“SPE” Society of Petroleum Engineers
“WPC” World Petroleum Council
“WTI” West Texas Intermediate
Note
(1): Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf : 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
162 CONVERSION
The following table sets forth standard conversions from Standard Imperial Units to the International System of Units (or metric units).
To Convert From To Multiply By boe...... Mcf 6 Mcf...... Cubic metres 28.174 Cubic metres ...... Cubic feet 35.494 bbls ...... Cubic metres 0.159 Cubic metres ...... bbls oil 6.290 Feet ...... Metres 0.305 Metres ...... Feet 3.281 Miles ...... Kilometres 1.609 Kilometres ...... Miles 0.621 Acres ...... Hectares 0.405
163 HERITAGE OIL PLC
Incorporated in Jersey under the Companies (Jersey) Law 1991, as amended, with registered number 99922
NOTICE OF GENERAL MEETING
NOTICE IS HEREBY GIVEN that a GENERAL MEETING of Heritage Oil Plc (the “Company”) will be held at 22 Grenville Street, St Helier, JE4 8PX, Jersey, Channel Islands on 25 January 2010 at 3:00 p.m. for the purpose of considering and, if thought fit, passing the following resolutions.
You will be asked to consider and vote on resolutions 1 and 2 below, which will be proposed as an ordinary resolution and a special resolution, respectively.
ORDINARY RESOLUTION
1. THAT the proposed disposal by the Company of its entire interests in Block 1 and Block 3A, and certain other assets, in Uganda as described in the circular to holders of Ordinary Shares in the Company and holders of Exchangeable Shares in Heritage Oil Corporation dated 21 December 2009 (the “Circular”) and (i) on the terms and subject to the conditions of the agreement for the disposal dated 18 December 2009 between the Company, Heritage Oil & Gas Limited and Eni International B.V. (the “Disposal Agreement”) or, in the alternative, (ii) on the terms and subject to the conditions of an agreement for the disposal to be entered into between the Company, Heritage Oil & Gas Limited and Tullow Oil plc (“Tullow”) and/or a wholly-owned affiliate of Tullow (which shall contain the same terms and conditions as the Disposal Agreement, save that Tullow shall be the purchaser instead of Eni International B.V.) (as described in the Circular), be and is hereby approved, and the directors of the Company (or a duly authorised committee thereof) are authorised to do or procure to be done all such acts and things on behalf of the Company and any of its subsidiaries as they consider necessary or expedient for the purpose of giving effect to either proposed disposal and this Resolution 1 and to carry the same into effect with such modifications, variations, revisions, waivers or amendments as the directors of the Company (or a duly authorised committee thereof) may in their absolute discretion think fit, provided such modifications, variations, revisions, waivers or amendments are not of a material nature.
SPECIAL RESOLUTION
2. THAT the Directors be generally and unconditionally authorised:
(a) pursuant to Article 57 of the Companies (Jersey) Law 1991, to make market purchases of ordinary shares of no par value in the capital of the Company (“Ordinary Shares”), provided that:
(i) the maximum number of Ordinary Shares authorised to be purchased is 28,755,194 (representing approximately 10.00 per cent. of the Company’s Voting Share Capital (as defined in the circular to holders of Ordinary Shares in the Company and holders of Exchangeable Shares in Heritage Oil Corporation dated 21 December 2009);
(ii) the minimum price, exclusive of any expenses, which may be paid for an Ordinary Share is £0.01;
(iii) the maximum price, exclusive of any expenses, which may be paid for an Ordinary Share shall be the higher of:
(A) an amount equal to 5 per cent. above the average of the middle market quotations for Ordinary Shares taken from the London Stock Exchange Daily Official List for the five business days immediately preceding the day on which such shares are contracted to be purchased; and
(B) the higher of the price of the last independent trade and the highest current independent bid on the London Stock Exchange Daily Official List at the time that the purchase is carried out, and
164 (iv) the authority hereby conferred shall expire on the conclusion of the annual general meeting of the Company to be held in 2010 (except that the Company may make a contract to purchase Ordinary Shares under this authority before the expiry of this authority, which will or may be executed wholly or partly after the expiry of this authority, and may make purchases of Ordinary Shares in pursuance of any such contract as if such authority had not expired); and
(b) pursuant to Article 58A of the Companies (Jersey) Law 1991, to hold as treasury shares any Ordinary Shares purchased pursuant to the authority conferred by Resolution 2(a) above.
HERITAGE OIL PLC BY ORDER OF THE BOARD Registered office: Michael J. Hibberd Ordnance House, Chairman 31 Pier Road, 21 December 2009 St Helier, JE4 8PW, Jersey, Channel Islands
165 NOTES TO THE NOTICE OF GENERAL MEETING
Entitlement to attend, vote and ask questions
1. The Company, pursuant to Article 40 of the Companies (Uncertified Securities) (Jersey) Order 1999 and the Articles of Association of the Company, specifies that only those persons entered on the register of members of the Company as at 6:00 p.m. on 23 January 2010 shall be entitled to attend and to speak and vote at the meeting in respect of the number of shares registered in their name at that time. Changes to entries on the register of members after 6:00 p.m. on 23 January 2010 shall be disregarded in determining the rights of any person to attend or vote at the General Meeting of the Company (the “General Meeting”). If the meeting is adjourned to a time not more than 48 hours after the specified time applicable to the original meeting, that time will also apply for the purpose of determining the entitlement of members to attend and vote (and for the purpose of determining the number of votes they may cast) at the adjourned meeting. If however, the meeting is adjourned for a longer period then, to be so entitled, members must be entered on the Company’s register of members at the time which is 48 hours before the time fixed for the adjourned meeting, or, if the Company gives notice of the adjourned meeting, at the time specified in that notice.
2. If you are a member of the Company at the time set out in note 1 above, you are, in addition to being entitled to attend and vote at the General Meeting, entitled to put questions to the Company relating to the business being dealt with at the General Meeting. The Company must cause to be answered any such question so put except in certain limited circumstances.
3. The following documents will be available for inspection during normal business hours at the London office of the Company’s U.K. solicitors McCarthy Tétrault at 2nd Floor, 5 Old Bailey, London EC4M 7BA and will be available for inspection at the place of the General Meeting from 2:30 p.m. on the day of the meeting until its conclusion:
• A copy of the Disposal Agreement (as defined in Resolution 1 set out in the Notice of General Meeting to which these Notes are appended).
• copy of the Articles of Association of the Company
This Notice will also be accessible on the Company’s website (www.heritageoilplc.com), together with details of the information contained in note 11 below.
Appointment of proxies
4. If you are a member of the Company at the time set out in note 1 above, you are entitled to appoint a proxy or proxies to exercise all or any of your rights to attend, speak and vote at the meeting instead of you and you should have received a proxy form with this Notice of the General Meeting. You can only appoint a proxy using the procedures set out in these notes and the notes to the proxy form.
5. If you are not a member of the Company but you have been nominated by a member of the Company to enjoy information rights, you do not have a right to appoint any proxies under the procedures set out in this “Appointment of proxies” section.
6. A proxy does not need to be a member of the Company but must attend the General Meeting to represent you. Details on how to appoint the Chairman of the meeting or another person as your proxy using the proxy form are set out in the notes to the proxy form.
7. You may appoint more than one proxy. Further details are set out in the notes to the proxy form.
8. A vote withheld is not a vote in law, which means that the vote will not be counted in the calculation of votes for or against the resolution. If in your proxy form you either select the “Vote withheld” option or if no voting indication is given, your proxy will vote or abstain from voting at his or her discretion. Your proxy will vote (or abstain from voting) as he or she thinks fit in relation to any other matter which is put before the meeting.
166 Appointment of proxy using hard copy proxy form
9. The notes to the proxy form explain how to direct your proxy how to vote on each resolution or withhold their vote.
10. To appoint a proxy using the proxy form, the form must be:
• completed and signed;
• sent or delivered to Computershare Investor Services (Jersey) Limited at Ordnance House, 31 Pier Road, St Helier, JE4 8PW, Jersey; and
• received by Computershare Investor Services (Jersey) Limited no later than 48 hours (or in the case of the proxy form for the Special Voting Share 24 hours) before the time appointed for the General Meeting.
In the case of a member which is a company, the proxy form must be executed under its common seal or signed on its behalf by an officer of the company or an attorney for the company.
Any power of attorney or any other authority under which the proxy form is signed (or a duly certified copy of such power or authority) must be included with the proxy form.
Appointment of proxy electronically
11. CREST members who wish to appoint a proxy or proxies through the CREST electronic proxy appointment service may do so for the meeting or any adjournment(s) thereof by using the procedures in the CREST manual. CREST Personal Members or other CREST sponsored members, and those CREST members who have appointed a voting service provider(s), should refer to their CREST sponsor or voting service provider(s), who will be able to take the appropriate action on their behalf. In order for a proxy appointment or instruction made using the CREST service to be valid, the appropriate CREST message (a “CREST Proxy Instruction”) must be properly authenticated in accordance with Euroclear UK & Ireland Limited’s specifications and must contain the information required for such instructions, as described in the CREST Manual. The message, regardless of whether it constitutes the appointment of a proxy or an amendment to the instruction given to a previously appointed proxy must, in order to be valid, be transmitted so as to be received by the issuer’s agent (ID 3RA50) by no later than 48 hours (or in the case of the proxy form for the Special Voting Share 24 hours) before the time appointed for the General Meeting. For this purpose, the time of receipt will be taken to be the time (as determined by the time stamp applied to the message by the CREST Applications Host) from which the issuer’s agent is able to retrieve the message by enquiry to CREST in the manner prescribed by CREST. After this time any change of instructions to proxies appointed through CREST should be communicated to the appointee through other means.
To appoint one or more proxies or to give an instruction to a proxy (whether previously appointed or otherwise) via the CREST system, CREST messages must be received by the issuer’s agent (ID number 3RA50) not later than 48 hours before the time appointed for holding the meeting. For this purpose, the time of receipt will be taken to be the time (as determined by the timestamp generated by the CREST system) from which the issuer’s agent is able to retrieve the message. The Company may treat as invalid a proxy appointment sent by CREST in the circumstances set out in Article 34 of the Companies (Uncertificated Securities) (Jersey) Order 1999.
CREST members and, where applicable, their CREST sponsors or voting service providers should note that Euroclear UK & Ireland Limited does not make available special procedures in CREST for any particular messages. Normal system timings and limitations will therefore apply in relation to the input of CREST Proxy Instructions. It is the responsibility of the CREST member concerned to take (or, if the CREST member is a CREST personal member or sponsored member or has appointed a voting service provider(s), to procure that his CREST sponsor or voting provider(s) take(s)) such action as shall be necessary to ensure that a message is transmitted by means of the CREST system by any particular time.
167 In this connection CREST members and, where applicable, their CREST sponsors or voting service providers are referred, in particular, to those sections of the CREST Manual concerning practical limitations of the CREST system and timings.
The Company may treat as invalid a CREST Proxy Instruction in the circumstances set out in Article 34 of the Companies (Uncertificated Securities) (Jersey) Order 1999.
Appointment of proxy by joint members
12. In the case of joint holders, where more than one of the joint holders purports to appoint a proxy, only the appointment submitted by the most senior holder will be accepted. Seniority is determined by the order in which the names of the joint holders appear in the Company’s register of members in respect of the joint holding (the first named being the most senior).
Changing proxy instructions
13. To change your proxy instructions simply submit a new proxy appointment using the methods set out above. Note that the cut-off time for receipt of proxy appointments (see above) also applies in relation to amended instructions; any amended proxy appointment received after the relevant cut-off time will be disregarded.
Where you have appointed a proxy using the hard copy proxy form and would like to change the instructions using another hard copy proxy form, please contact Computershare Investor Services (Jersey) Limited at Ordnance House, 31 Pier Road, St Helier, JE4 8PW, Jersey , Channel Islands.
If you submit more than one valid proxy appointment, the appointment received last before the latest time for the receipt of proxies will take precedence.
Termination of proxy appointments
14. In order to revoke a proxy instruction you will need to inform the Company by sending a signed hard- copy clearly stating your intention to revoke your proxy appointment to Computershare Investor Services (Jersey) Limited at Ordnance House, 31 Pier Road, St Helier, JE4 8PW, Jersey, Channel Islands. In the case of a member which is a company, the revocation notice must be executed under its common seal or signed on its behalf by an officer of the company or an attorney for the company. Any power of attorney or any other authority under which the revocation notice is signed (or a duly certified copy of such power or authority) must be included with the revocation notice.
The revocation notice must be received by Computershare Investor Services (Jersey) Limited no later than one hour before the commencement of the General Meeting.
If you attempt to revoke your proxy appointment but the revocation is received after the time specified then your proxy appointment will remain valid.
Corporate representatives
15. In the case of a member which is a company, voting may be facilitated by corporate representatives at the General Meeting, so that:
• Each person duly authorised to act as a corporate representative of a person who is the holder of Ordinary Shares shall be entitled to exercise on behalf of such holder the same powers (in respect of the number of Ordinary Shares held by the relevant holder for which the relevant person is appointed its representative) as such holder of Ordinary Shares could exercise if it were a natural person.
• Each person duly authorised to act as a corporate representative of a person who is the holder of the Special Voting Share shall be entitled to exercise on behalf of such holder the same powers (in respect of the number of votes attaching to the Special Voting Share for which the relevant person is appointed its representative) as the holder of the Special Voting Share could exercise if it were a natural person.
168 • If a corporate member appoints more than one representative (but subject to the voting instructions (if any) given by the member), no representative need cast all the votes used by him in respect of any resolution in the same way as any other representative or any proxy appointed by the member.
• Where a person is authorised to represent a corporate member at the meeting, the directors or the Chairman of the meeting may require him to produce a certified copy of the resolution from which he derives his authority.
• For the avoidance of doubt, any corporate member may by resolution of its directors or other governing body appoint, in addition to the corporate representatives (if any) appointed by it, any number of persons to act as its proxy at the General Meeting in respect of (in relation to a corporate member which is a holder of Ordinary Shares) any Ordinary Shares held by such holder in respect of which no corporate representative is appointed or (in relation to a corporate member which is the holder of the Special Voting Share) any votes attaching to the Special Voting Share in respect of which no corporate representative is appointed.
Issued shares and total voting rights
16. As at 18 December 2009, the Company’s issued share capital comprised 284,527,830 Ordinary Shares of no par value. On a show of hands each member who holds Ordinary Shares and is present in person or by proxy shall have one vote. On a poll, each member who holds Ordinary Shares and is present in person or by proxy shall have one vote for every Ordinary Share of which he, she or it is the holder.
As at 18 December 2009, the Company’s issued share capital comprised one Special Voting Share of no par value which represents a vote for each of the exchangeable shares of no par value of Heritage Oil Corporation which has a voting right in the Company of which there were 3,024,108 as at 18 December 2009. On a show of hands, the holder of the Special Voting Share present in person or by proxy shall have one vote. On a poll, the holder of the Special Voting Share present in person or by proxy shall have the number of votes equal to the number of exchangeable shares with voting rights in issue in the capital of Heritage Oil Corporation at 6:00 p.m. 23 January 2010 (excluding any exchangeable shares held by the Company or its affiliates) which have instructed the holder of the Special Voting Share on how to vote.
Communication
17. Except as provided above, members who have general queries about the General Meeting should contact Computershare Investor Services (Jersey) Limited at Ordnance House, 31 Pier Road, St Helier, JE4 8PW, Jersey, Channel Islands or by telephone on +44 1534 825230.
Entry to General Meeting
18. Members should note that the doors to the General Meeting will open at 2:30 p.m. on the date appointed for the General Meeting.
169 Printed by RR Donnelley 14312