· Odebrecht Oil & Gas ILLUSTRATIVE COUNTERPROPOSAL FROM BONDHOLDERS MAR C H 2 4 , 2 0 1 6 | PR IVILEGED & CONFIDENT IAL | DRAF T | SUBJECT TO FRE 4 0 8 | FOR SET T LEMENT DISCUSSION

Odebrecht Oil & Gas I L L U S T R AT I V E C O U N T E R P R O P O S AL F R O M B O N D H O L D E R S

M A R C H 2 4 , 2 0 1 6 | P R I V I L E G E D & C O N F I D E N T I A L | D R A F T | S U B J E C T T O F R E 4 0 8 | F O R S E T T L E M E N T D I S C U S S I O N P U R P O S E S O N L Y | P R E P A R E D A T T H E R E Q U E S T O F C O U N S E L P R E S E N T A T I O N O R I G I N A L L Y M A D E O N T H E D A T E I N D I C A T E D A N D H A S N O T B E E N U P D A T E D T O R E F L E C T R E C E N T D E V E L O P M E N T S O R O N G O I N G D I S C U S S I O N S . M O R E O V E R , I N L I G H T O F O N G O I N G N E G O T I A T I O N S W I T H P E T R O B R A S T H A T I N V O L V E T H E C H A R T E R A N D S E R V I C E S A G R E E M E N T S S U P P O R T I N G T H E S E B O N D S , T H E C O N T E N T O F T H I S P R E S E N T A T I O N I S N O L O N G E R R E L E V A N T .

PRIVILEGED & CONFIDENTIAL | DRAFT | SUBJECT TO FRE 408 | FOR SETTLEMENT DISCUSSION PURPOSES ONLY | PREPARED AT THE REQUEST OF COUNSEL

Summary Illustrative Counterproposal from Bondholders

2

2021 Notes 2022 Notes

Transaction Structure

Exchange of both classes of notes for new notes with amended terms (as described below) All revenues (charter + services) to flow through the respective project structures Modify but do not collapse current structures, and enhance collateral package as described below Eliminate exchange rate caps and modify OpEx caps to allow structures to fund all expenses (i.e., OpEx +

CapEx) up to levels TBD based on the Company’s business plan and industry standards(1)

Minimum participation level: [95]%, depending on implementation structure(2)

Assumed Transaction Effective Date [April 1, 2016]

Principal Starting balance of: $1,178mm(3) (no discount) Starting balance of: $2,010mm(3) (no discount)

Amortization

Fixed $25mm per annum, paid quarterly, beginning as

of the closing date 2016: None 2017: $5mm per annum, paid quarterly 2018 until maturity: $15mm per annum, paid

quarterly

Excess Cash Flow Sweep

86% of excess cash flow after interest and fixed amortization applied to variable amortization

14% of excess cash flow after interest and fixed amortization provided to Odebrecht Oil & Gas (“ParentCo”) to allow it to remain a viable entity (the “ParentCo ECF Sweep”) in exchange for a new Relief Revolving Note

74% of excess cash flow after interest and fixed amortization applied to variable amortization

26% of excess cash flow after interest and fixed amortization provided to ParentCo in exchange for a new Relief Revolving Note

Holders reserve the right to change the relative contributions of ECF sweep between the 2021 and 2022 structures

ParentCo ECF Sweep tested quarterly; not subject to carryforward or carryback structuring

Drydock Accrual Reserve Funded with $2.0mm / quarter, starting at closing Funded with $3.0mm / quarter, starting at closing

Interest Rate 7.00% cash interest (payable quarterly) 1.00% PIK interest (payable quarterly)

7.00% cash interest (payable quarterly) 1.00% PIK interest (payable quarterly)

(1) Additional due diligence and benchmarking of company’s OpEx and CapEx will be required (2) Holders to consider possible early tender fee payable in cash or in kind (3) Starting balances as of March 31, 2016 after accounting for scheduled amortization payments made in December 2015 and March 2016



3


Maturity(1) No change (remains June 30, 2021) No change (remains October 1, 2022)

New Relief Revolving Loan Facility

In consideration for the ParentCo ECF Sweep, OOG parent to enter into a revolving loan facility (“Relief Revolving Loan Facility”) with Noteholders whereby each ParentCo ECF Sweep payment is deemed to be a draw on the Relief Revolving Loan Facility

The Relief Revolving Loan Facility will bear interest at the same rate (cash or PIK, as applicable) as the restructured Bank Debt, will have the same maturity, and will have a claim on OOG cash flows (including those from Libra, CDI, PLSVs, MSO, and any other ParentCo cash flows) that is senior to (both in terms of payment maturity and security) the Bank Debt

Expense Cap Relief

In consideration of amending the existing OpEx and CapEx caps and exchange rate limitations, any such relief shall constitute a claim in the restructuring of OOG

Subject to certain conditions including terms for the restructuring of existing OOG debt on satisfactory terms, such claim may be exchanged, in whole or in part, for a new debt instrument and / or equity or equity-linked instruments at OOG

Security

All cash outstanding at the assumed closing date shall remain within the respective structure All existing collateral remains in place. First priority lien on substantially all of the assets of the respective

project entities enforceable in Brazil and offshore, including but not limited to the drilling rigs, cash collateral, interests in the charter and services agreements and accounts receivable; lien on equity in structures

The drilling rigs include the ODN I, ODN II, ODN Tay IV, Norbe VI, Norbe VIII, and Norbe IX All LCs related to the 2021 and 2022 assets to remain outstanding Guarantee by, and first priority lien over the shares of, intermediate holding company that holds the equity

of the companies that are obligors under the 2021 and 2022 notes Contractual obligation of ParentCo (i) in favor of 2021 holders not to allow more debt to be incurred at

2022 project companies and (ii) in favor of 2022 holders not to allow more debt to be incurred at 2021 project companies, in each case in connection with refinancing or otherwise

(1) Condition precedent: ParentCo level debt facilities shall be restructured such that no ParentCo debt maturities shall occur within six months of the last maturity of new notes



4


ParentCo Capital Structure and Debt Service Relief

As a condition precedent to the restructuring of the 2021 notes and 2022 notes, the ParentCo level debt shall be restructured on terms and conditions satisfactory to the holders

The Company will renegotiate the terms of the Delba III financing such that it will not be required to make any further contributions to the Delba III structure

Petrobras Cancellations

Proposal assumes no further cancellations beyond the ODN Tay IV, no rate reductions or contractual penalties imposed by Petrobras in a manner inconsistent with normal past practice, and no material adverse developments in connection with Lava Jato

Proposal assumes that ODN I, ODN II, and any other rig in the 2021 and 2022 structures will continue to receive the contractual dayrate plus bonus (i.e. 100% of the contracted dayrate) if and when on idle at the direction of Petrobras

Require any amounts recovered (whether sale

proceeds or from Petrobras) with respect to the ODN Tay IV or any other vessel to amortize the notes secured by such vessel

ODN Tay IV

[ODN Tay IV to be scrapped](1)

Limit ODN Tay IV expenses to the aggregate amount requested through [May 2016] (inclusive of those expenses necessary to move the rig from Brazilian waters to [TBD], as approved by the 2022 Noteholders)

(1) Alternative options may be discussed

Confidential

Project Orion JV AND OTHER PROJECTS MODEL CASH FLOWS

March 6, 2016*

*Presentation originally made on the date indicated and, except as specifically noted, has not been updated to reflect recent developments or ongoing discussions.

Confidential

1

JV and Other Projects Model Cash Flows

Note: Subject to assumptions; actual results may differ. (1) Cash flows after financing include costs incurred by OOG.

Consolidated: JV and Other Projects

($USD in 000s) 2016 2017 2018 2019 2020 2021 2022

Charter and service revenue received $469,723 $613,712 $552,958 $522,253 $571,562 $579,263 $556,854

Opex (243,795) (214,942) (210,185) (192,781) (197,644) (200,502) (199,203)

Capex (588,694) (34,972) (9,109) (19,712) (5,348) (49,858) (13,054)

Operating cash flow ($362,766) $363,798 $333,664 $309,760 $368,570 $328,904 $344,596

Debt issuance 450,912 142,766 315,000 – – – –Debt amortization (119,547) (263,058) (505,731) (133,752) (203,822) (190,298) (189,534)

Interest paid (82,817) (95,655) (83,855) (77,357) (73,139) (61,306) (50,318)

Cash Flows after Financing (1) ($114,218) $147,850 $59,078 $98,652 $91,609 $77,300 $104,744

Cash Flows to OOG $37,438 $35,581 $29,372 $41,786 $32,801 $72,659 $48,659

Confidential

2

JV and Other Projects OOG Consolidated Model Cash Flows

Note: Subject to assumptions; actual results may differ.

Consolidated: JV and Other Projects

($USD in 000s) 2016 2017 2018 2019 2020 2021 2022

Cash Flow from A $15,412 $7,821 $3,874 $11,081 $2,806 $12,302 $3,442

Cash Flow from B 1,491 18,310 21,600 22,576 22,057 52,596 37,628

Cash Flow from C 20,536 9,450 3,898 8,130 7,939 7,761 7,589

Cash Flow from D – – – – – – –

Unallocated Project Costs (12,715) (11,672) (11,406) (11,405) (11,406) (11,406) (11,406)

Total JV and Other Projects Cash Flows $24,723 $23,909 $17,966 $30,381 $21,395 $61,253 $37,253

Confidential

This document contains highly confidential information and is solely for informational purposes. You should not rely upon or use it to form the definitive basis for any decision or action whatsoever, with respect to any proposed transaction or otherwise. You and your affiliates and agents must hold this document and any oral information provided in connection with this document, as well as any information derived by you from the information contained herein, in strict confidence and may not communicate, reproduce or disclose it to any other person, or refer to it publicly, in whole or in part at any time except with our prior written consent. If you are not the intended recipient of this document, please delete and destroy all copies immediately.

This document is “as is” and is based, in part, on information obtained from other sources. Our use of such information does not imply that we have independently verified or necessarily agree with any of such information, and we have assumed and relied upon the accuracy and completeness of such information for purposes of this document. Neither we nor any of our affiliates or agents, make any representation or warranty, express or implied, in relation to the accuracy or completeness of the information contained in this document or any oral information provided in connection herewith, or any data it generates and expressly disclaim any and all liability (whether direct or indirect, in contract, tort or otherwise) in relation to any of such information or any errors or omissions therein. Any views or terms contained herein are preliminary, and are based on financial, economic, market and other conditions prevailing as of the date of this document and are subject to change. We undertake no obligations or responsibility to update any of the information contained in this document. Past performance does not guarantee or predict future performance.

This document does not constitute an offer to sell or the solicitation of an offer to buy any security, nor does it constitute an offer or commitment to lend, syndicate or arrange a financing, underwrite or purchase or act as an agent or advisor or in any other capacity with respect to any transaction, or commit capital, or to participate in any trading strategies, and does not constitute legal, regulatory, accounting or tax advice to the recipient. This document does not constitute and should not be considered as any form of financial opinion or recommendation by us or any of our affiliates. This document is not a research report nor should it be construed as such.

This document may include information from the S&P Capital IQ Platform Service. Such information is subject to the following: “Copyright © 2015, S&P Capital IQ (and its affiliates, as applicable). This may contain information obtained from third parties, including ratings from credit ratings agencies such as Standard & Poor’s. Reproduction and distribution of third party content in any form is prohibited except with the prior written permission of the related third party. Third party content providers do not guarantee the accuracy, completeness, timeliness or availability of any information, including ratings, and are not responsible for any errors or omissions (negligent or otherwise), regardless of the cause, or for the results obtained from the use of such content. THIRD PARTY CONTENT PROVIDERS GIVE NO EXPRESS OR IMPLIED WARRANTIES, INCLUDING, BUT NOT LIMITED TO, ANY WARRANTIES OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE OR USE. THIRD PARTY CONTENT PROVIDERS SHALL NOT BE LIABLE FOR ANY DIRECT, INDIRECT, INCIDENTAL, EXEMPLARY, COMPENSATORY, PUNITIVE, SPECIAL OR CONSEQUENTIAL DAMAGES, COSTS, EXPENSES, LEGAL FEES, OR LOSSES (INCLUDING LOST INCOME OR PROFITS AND OPPORTUNITY COSTS OR LOSSES CAUSED BY NEGLIGENCE) IN CONNECTION WITH ANY USE OF THEIR CONTENT, INCLUDING RATINGS. Credit ratings are statements of opinions and are not statements of fact or recommendations to purchase, hold or sell securities. They do not address the suitability of securities or the suitability of securities for investment purposes, and should not be relied on as investment advice.”

Copyright © 2016, PJT Partners LP (and its affiliates, as applicable). 3

Confidential

Project Orion TAY IV UPDATE

March 2016*


Confidential

Tay IV Update

> The Company is currently asking for an extension for ODN Tay IV to remain in Brazil

‒ Therefore, the Company is continuing to perform analyses to determine the best path forward

> However, if Tay IV leaves Açu Port in Brazil at the end of April, the cost to keep the vessel in Acu Port is projected to be ~$56k / day (not including the payments for previously incurred expenses)

> The cost to transfer Tay IV to Tenerife is projected to be $4 million (cost projected to be paid partially in April and partially in May), and the cost to cold stack at Tenerife is projected to be $4 million (cost projected to be paid partially in September and partially in October)

> From May until October 2016, it is projected to cost ~$44k / day of OPEX to maintain the vessel

> Once cold-stacked, the maintenance cost is projected to be $17k / day

> Additional detail is provided below

1

Warm Stack Tenerife Cold stack Tenerife

Labor Payroll 10.500

20.391

2.298

4.605

Crew Change / Training / Other 1.184 679

Catering 833 120

Repairs & Maintenance 4.600 574

Material Logistics 1.014 150

Other Costs 2.260 784

SHIPYARD COSTS 9.132

9.132

1.919

1.919 Energy 7.940 -

Logistics 1.192 1.919

Rig Insurance 14.894 14.894 10.476 10.476

Insurance Excluding Payroll 10.476 10.476

Deferred Rig Insurance Payment 4.418 0.000

TOTAL COSTS WITH

OVERHEAD 44.418 44.418 17.000 17.000

Confidential

Tay IV Update (Cont’d)

> Tay IV’s annual insurance costs total $3,734,006 and breaks down as follows:

2

Hull & Machinery Increased Value Loss of Hire Protection &

Indemnity Comprehensive General Liability

TOTAL

ODN TAY IV $2,404,081 $189,121 $854,404 $257,000 $29,400 $3,734,006

Confidential

Tay IV Update (Cont’d)

> The cost of demobilizing Tay IV is projected to cost $14.123 million in 2016

> The breakdown of these expenses is provided below:

3

Demobilization costs - ODN IV US$ 000k Description

Debit Notes (Discounted Jan-Feb) $2,578 These are payments that Petrobras will discount (relates to past performance)

Services measured but not paid 1,617 Maintenance performed on a rig

PO open - measurement 667 Outstanding invoice for payment

Material ordered and not paid 8,046 Material/supplies that have been contracted (some already delivered)

Estimated expenses related to employees' dismissals 214 Layoffs (estimate)

Estimated fines to terminate contracts before the maturity 1,000 Early termination penalties (estimate)

TOTAL $14,123

Confidential






Confidential Settlement Communication Subject to FRE 408

Project Orion DISCUSSION MATERIALS

February 29, 2016*

The cap relief requested in connection with this presentation was granted by holders only with respect to the months of March and April. Please see the Notice to the Market issued by the Company on March 31, 2016. *Presentation originally made on the date indicated and, except as specifically noted, has not been updated to reflect recent developments or ongoing discussions.


1

Agenda

> Market Update

> Amendment to Caps

> Libra Update


I. Market Update

2


$0

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

mai-15 jun-15 ago-15 out-15 nov-15 jan-16 mar-16

Historical Dayrate (DW e UDW) | US$k/d

Estimated UDW cash breakeven | US$k/d

Source: Rigzone database

Source: DNB

Source: Reports from banks and webcasts from drillers for the full year 2015 results

Messages from FY 2015 Earnings Season > Analysts are reviewing their forecasts - all increasingly pessimistic:

‒ DNB: “While we currently have less visibility for 2018 and incremental demand could materialize, our forecast oversupply of 89 UDW rigs by end-2017 supports our view that 2018 could also prove very challenging for the industry.”

‒ Wells Fargo: “With another UDW contract cancellation this week on the Development Driller I, ESV highlighting the likelihood of cancellation by PBR on the ENSCO 6001, and ORIG apparently bidding at or below cash break even costs for a 3-well job in Norway with the Leiv Eiriksson, offshore fundamentals seem to be deteriorating at a faster pace than our recently revised (and already quite negative) outlook.”

‒ DNB: “(…) we believe there may be more ‘blend and extend’ deals, pure renegotiations, and we could see some rigs released early. We would expect such events primarily in West Africa and other countries with NOC exposure (Brazil, Mexico, and Saudi Arabia).”

> With challenges mounting, commercial aggressiveness, refinancing, cash costs reduction are in the spotlight.

‒ Wells Fargo: “With discussions over blend and extend and/or cancellations picking up and more data points suggesting bid activity at or below break-even levels, our sense is that “panic mode” is starting to set in for some drillers, and some are adopting the mind-set that losing a little money near term (on a less than cash break even rate) is better than losing even more money long term on cold stacking a floater and potentially losing the rig forever.”

‒ Seadrill: “In the face of the severe downturn in our industry our priorities for 2016 are to conserve cash and address our financing needs.”

‒ Ensco: “(…) uncertainty regarding the timing and degree rebalancing in the oil markets has caused our customers to announce further reductions in capital expenditures, the results of which is to push out the likely duration of the down cycle for the offshore drilling sector.”

3


II. Amendment to Caps

4


Situation Overview

The Company has completed a revised near-term forecast and determine the amount of relief needed under the existing expense caps to extend the runway necessary to complete restructuring negotiations by June 2016.

> At the February 3rd meeting in New York, it was agreed by both the Company and ad hoc group that parties would negotiate relief under the expense caps of the 2021 Senior Notes and 2022 Senior Notes (‘21 and ‘22 Notes) documents

‒ Goal to improve ability of assets to self-fund while a comprehensive transaction is negotiated and executed for the ‘21 and ‘22 Notes as well as OOG parent-level debt

> OOG has finalized revisions to its near-term forecast at the ‘21 and ‘22 Assets as well as OOG

‒ Includes detailed input from treasury department to refine near-term cash needs

> Based on current expense caps, OOG would be required to fund significant cash shortfalls through June 2016

‒ Funding of approximately $30 million and $26 million for the ‘21 and ‘22 Assets, respectively

> Without relief, OOG will not be able to negotiate a restructuring of its liabilities and all creditors and stakeholders will be put at significant risk of a judicial recovery

> OOG has prepared an analysis of the existing caps and the relief required to allow OOG to continue as a going concern in the near-term period

5


Cash Flows of ‘21 and ‘22 Assets (Under Existing Expense Caps) > Existing indentures only allow for a fixed amount of expenses to be funded monthly from revenues at

the ‘21 and ‘22 Assets

> Based on these existing caps, approximately $56 million of operating expenses incremental to the cap as well as capex are required to be funded by OOG

> Detail to the calculations can be found on page 16 and page 25 of the appendix

6

$56 million Total shortfall to be funded by OOG over four-month period

2022 Asset Cash Flow($ in US 000s) March April May June 4 Month Total

Forecast Opex + Capex $16,142 $16,722 $34,106 $21,465 $88,434

Current Capped Expense 14,629 16,066 15,641 16,047 62,383

Surplus / (Shortfall) ($1,512) ($656) ($18,465) ($5,418) ($26,051)

2021 Asset Cash Flow($ in US 000s) March April May June 4 Month Total

Forecast Opex + Capex $10,407 $9,995 $15,699 $15,016 $51,117

Current Capped Expense 4,685 5,725 5,389 5,431 21,230

Surplus / (Shortfall) ($5,722) ($4,270) ($10,310) ($9,585) ($29,887)


2022 - Revised Caps

7

> Below is a summary of proposed increases in caps to allow for full funding with a level of cushion

> Detail to the calculations can be found on pages 15-23 of the appendix

($ in US 000s)

ODN I & II Mar-16 Apr-16 May-16 Jun-16

Total Opex $7,866 $8,095 $12,134 $11,145

Forecast Capex 94 400 1,058 1,058

Total Forecast Opex and Capex $7,959 $8,496 $13,192 $12,203

Plus: Cushion (10%) 796 850 1,319 1,220

Revised Opex and Capex Cap (To be Transferred in Prior Period) $8,755 $9,345 $14,511 $13,423

Difference Between Revised and Existing Cap $1,529 $1,012 $6,324 $5,028

Day Transferred 2/29/16 3/31/16 4/30/16 5/31/16

Memo: Implied Dayrate

Operating Days 29 31 30 31

Forecasted Dayrate (Opex Only + 10% Cushion) (in $USD) $298 $287 $445 $395

Tay IV Mar-16 Apr-16 May-16 Jun-16

Total Opex(1) $2,920 $2,796 $13,174 $2,024

Forecast Capex 63 139 531 531


Plus: Cushion (10%) 298 293 1,371 256


Difference Between Revised and Existing Cap ($836) ($1,525) $10,428 ($2,030)

Day Transferred 2/29/16 3/31/16 4/30/16 5/31/16




(1) The May opex figure for Tay IV assumes that the vessel is mobilized and towed for a cost of $11 million. After that, it is assumed that the vessel is cold-stacked.


2022 - Revised Caps (Cont’d)

8

($ in US 000s)

Norbe VI Mar-16 Apr-16 May-16 Jun-16

Total Opex $5,199 $5,291 $5,731 $5,230

Forecast Capex – – 1,477 1,477


Plus: Cushion (10%) 520 529 721 671



Day Transferred 2/29/16 3/31/16 4/30/16 5/31/16







2021 - Revised Caps

9



($ in US 000s)

Norbe VIII Mar-16 Apr-16 May-16 Jun-16

Total Opex $5,092 $5,102 $6,491 $6,093

Forecast Capex – – 468 468


Plus: Cushion (10%) 509 510 696 656



Day Transferred 2/29/16 3/31/16 4/30/16 5/31/16




Norbe IX Mar-16 Apr-16 May-16 Jun-16

Total Opex $5,315 $4,893 $6,299 $6,014



Plus: Cushion (10%) 532 489 874 846



Day Transferred 2/29/16 3/31/16 4/30/16 5/31/16





Pro Forma OOG Net Cash Flows (with Amended Caps)

10

Note: Actual operating results and cash positions differ from those forecasted in February. Note: the O&M transfers for 2021 and 2022 assets occur at the end of the month, so there is a brief timing mismatch between when the funds are transferred and when the expenses are paid.

> Below is a summary of pro forma OOG cash flows assuming the caps are changed in February

Summary OOG Holding - US$ millions Feb-16 Mar-16 Apr-16 May-16 Jun-16

Cash Flow from 2022 Assets $(2.1) $0.6 $17.4 $(12.6) $(5.1)

Cash Flow from 2021 Assets 2.7 (0.4) 5.7 (0.7) (2.5)

Cash Flow from A (0.0) (0.3) (0.5) (0.2) (0.2)

Cash Flow from B (0.7) (0.9) 1.8 (0.4) (0.4)

Cash Flow from C (1.6) 0.2 (0.1) 4.0 0.5

Cash Flow from D (0.7) (1.2) (1.0) 2.8 -

Unallocated Project Costs (0.7) (0.1) (0.2) (2.7) 3.5

Subtotal Cash Flow from Projects $(3.1) $(2.2) $23.2 $(9.9) $(4.2)

Interest / Swap Payments (0.2) (18.0) (0.2) (2.5) (12.0)

Amortization (0.0) (0.0) (0.0) (0.0) (3.3)

LCs (2021s, 2022s, Other) (11.5) (0.0) (0.0) (1.6) (0.1)

Equity Issuance / Dividends to Shareholders - - - - -

Total Net Cash Flows $(14.8) $(20.2) $22.9 $(14.0) $(19.7)

Beginning Cash Balance $67.3 $52.5 $32.3 $55.2 $41.2

Ending Cash Balance 52.5 32.3 55.2 41.2 21.6

Memo (Assuming Funding Continues Under Existing Caps from OOG):

Ending Cash Balance Assuming Existing Caps $40.5 $15.2 $9.1 ($19.5) ($31.5)


III. Libra Update

11


Libra Update

> Libra project costs total approximately US$1 billion, and as of Jan 31st, 2016, we have invested 28% of the total costs

> The Libra put option deadline was originally on February 12th, 2016, and the Company and Teekay agreed to extend the notice date to March 11th, if the put option is exercised then payment shall occur on April 11th, 2016

> The put option is for up to 25% of Libra (50% of OOG’s 50% stake in Libra) as detailed below:

‒ On the Put Option Notice Exercise Date, the Parties shall calculate the Put Option Consideration as defined below:

o The Put Option Consideration equals:

(a) = USD 24,111,354 minus Released Cash Collateral in consideration for 15% Put Option Shares (as the number of Shares may be varied by the operation of Clause 7.4) purchased by the Buyer;

(b) = USD 32,148,471 minus Released Cash Collateral in consideration for 20% Put Option Shares (as the number of Shares may be varied by the operation of Clause 7.4) purchased by the Buyer; or

(c) = USD 40,185,589 minus Released Cash Collateral in consideration for 25% Put Option Shares (as the number of Shares may be varied by the operation of Clause 7.4) purchased by the Buyer.

> Net cash to OOG in exercise would be approximately US$40.2 million in a 25% Put Option Shares scenario, payable in April

> If exercised, dividends to OOG from the Libra project would be reduced accordingly

Note: The option expired on April 25, 2016. 12


Libra Update (Cont’d)

Call Option

> If exercised, OOG has a call option to purchase back the stake sold to Teekay, whose deadline is late August 2017, but payable in early January 2018

> On the Call Option Notice Exercise Date, the Parties shall calculate the Call Option Consideration as defined below:

‒ (a) = USD 24,111,354 adjusted at 20% per annum from the Put Option Date until the Call Option Date plus US$7,500,000 in consideration for 15% Call Option Shares (as the number of Shares may have been varied by the operation of Clause 7.4) purchased by the Seller;

‒ (b) = USD 32,148,471 adjusted at 20% per annum from the Put Option Date until the Call Option Date plus US$7,500,000 in consideration for 20% Call Option Shares (as the number of Shares may have been varied by the operation of Clause 7.4) purchased by the Seller; or

‒ (c) = USD 40,185,589 adjusted at 20% per annum from the Put Option Date until the Call Option Date plus US$7,500,000 in consideration for 25% Call Option Shares (as the number of Shares may have been varied by the operation of Clause 7.4) purchased by the Seller.

13


IV.Appendix

14


A. 2022 Structure Caps

15


Current Cap Structure (2022 Structure) > The current cap structure requires substantial cash outlay from the Parent in the coming months

(1) The May opex figure for Tay IV assumes that the vessel is mobilized and towed for a cost of $11 million. After that, it is assumed that the vessel is cold-stacked. 16

($ in USD 000s)


Forecast Opex $7,866 $8,095 $12,134 $11,145

Forecast Capex 94 400 1,058 1,058

Total Forecast Opex + Capex $7,959 $8,496 $13,192 $12,203

Current Cap for Prior Month (USD per day) $318 $318 $318 $318

Forecasted Current Cap for Prior Month (USD per day) (Adjusted for 2:1) 249 269 273 271

Days in Prior Month (funds transferred on last day of prior month) 29 31 30 31

Current Cap (USD amount) $7,226 $8,333 $8,188 $8,395

Surplus / (Shortfall to be borne by Parent) ($733) ($163) ($5,005) ($3,808)


Forecast Opex(1) $2,920 $2,796 $13,174 $2,024

Forecast Capex 63 139 531 531






Surplus / (Shortfall to be borne by Parent) $1,134 $1,819 ($9,057) $2,286


Forecast Opex $5,199 $5,291 $5,731 $5,230







Surplus / (Shortfall to be borne by Parent) ($1,913) ($2,312) ($4,403) ($3,896)

Cumulative 2022s Mar-16 Apr-16 May-16 Jun-16

Forecast Opex $15,985 $16,182 $31,039 $18,399

Forecast Capex 157 540 3,066 3,066






Surplus / (Shortfall to be borne by Parent) ($1,512) ($656) ($18,465) ($5,418)

Cumulative ($1,512) ($2,168) ($20,633) ($26,051)


Projected Opex (2022 Structure)

(1) “Suppliers / Other” includes insurance costs. 17

($ in US 000s)


Payroll $1,843 $1,822 $2,852 $2,760

Suppliers / Other(1) 5,125 5,424 5,100 6,301

Restructuring Costs 409 443 3,772 1,687

TAC 489 406 410 397

Total Opex $7,866 $8,095 $12,134 $11,145

Tay IV

Payroll $554 $551 – –

Suppliers / Other(1) 2,162 2,023 288 1,181

Demobilization + Tow Costs – – 11,000 –Restructuring Costs 204 222 1,886 843

TAC – – – –Total Opex $2,920 $2,796 $13,174 $2,024

Norbe VI

Payroll $1,046 $1,032 $1,371 $1,326

Suppliers / Other(1) 3,704 3,834 2,269 2,861

Restructuring Costs 204 222 1,886 843

TAC 244 203 205 198

Total Opex $5,199 $5,291 $5,731 $5,230


B. 2022 Structure Cash Flows

18


2022 Consolidated Cash Flows (with Amended Caps)

19

Consolidated

($ in USD 000s) 02/2016 03/2016 04/2016 05/2016 06/2016

Offshore Proceeds Acct

Beginning Cash 8,270 46,185 10,275 13,217 21,525

Cash Inflows

Net Charter $27,644 $27,063 $25,381 $26,225 $26,854

Services (Net of Taxes) 3,820 3,636 3,381 3,547 3,649

Insurance Proceeds 22,593 – – – –Transfer from Offshore Debt Service Reserve Account – 4,550 – – –Total Cash Inflows $54,057 $35,249 $28,762 $29,773 $30,504

Cash Outflows

Debt Service

Principal $– ($31,878) $– $– ($29,560)

Interest – (34,283) – – (33,748)

Total Debt Service $– ($66,161) $– $– ($63,308)

Opex + Capex (16,142) (16,722) (34,106) (21,465) (16,339)

Other – (2,232) – – –Total Cash Outflows ($16,142) ($85,115) ($34,106) ($21,465) ($79,647)

Ending Cash (Pre I/C Transfers and Reserve Accounts) $46,185 ($3,681) $4,932 $21,525 ($27,619)

Sinking Fund Transfer $0 $13,956 $8,286 $0 $0

Ending Cash $46,185 $10,275 $13,217 $21,525 ($27,619)

Memo: Reserve Account Balances

Sinking Fund Balance $22,241 $8,286 $– $– $–Loss Proceeds Balance 25,897 25,897 25,897 25,897 25,897

Debt Service Reserve Accounts 8,346 3,796 3,796 3,796 3,796

O&M Service Reserve Accounts 3,668 5,900 5,900 5,900 5,900

Subtotal 60,153 43,879 35,593 35,593 35,593


2022 Cash Flows – ODN I (with Amended Caps)

20

($ in USD 000s) 02/2016 03/2016 04/2016 05/2016 06/2016

Offshore Proceeds Acct (USD '000)

Beginning Cash - 6,652 1,250 2,456 6,208

Cash Inflows

Net Charter $10,125 $10,256 $9,627 $10,035 $10,245

Services (Net of Taxes) 507 582 541 621 638

Total Cash Inflows $10,631 $10,839 $10,168 $10,656 $10,883

Cash Outflows

Debt Service

Principal - (8,029) - - (7,140)

Interest - (8,489) - - (8,354)


Opex + Capex (3,980) (4,248) (6,596) (6,101) (4,915)

Other - (558) - - -

Total Cash Outflows (3,980) (21,324) (6,596) (6,101) (20,409)

Ending Cash (Pre I/C Transfers and Reserve Accounts) 6,652 (3,833) 4,822 7,011 (3,318)

I/C Transfers

Cash Available / (Cash Needed) 6,652 (3,833) 4,822 7,011 (3,318)

Transfers to:

Tay IV – – (2,366) (802) –ODN II – – – – –Norbe VI – – – – –

Subtotal $– $– ($2,366) ($802) $–Transfers from:

Norbe VI – – – – –ODN II – – – – –Tay IV – 5,084 – – –Sinking Fund – – – – –

Subtotal $– $5,084 $– $– $–(Cash Transferred) / Cash Received – 5,084 (2,366) (802) –Ending Cash (Post I/C and Sinking Fund Transfers) $6,652 $1,250 $2,456 $6,208 ($3,318)


2022 Cash Flows – ODN II (with Amended Caps)

21

($ in USD 000s) 02/2016 03/2016 04/2016 05/2016 06/2016


Beginning Cash 8,270 14,922 7,189 10,761 15,316

Cash Inflows

Net Charter $10,125 $10,256 $9,627 $10,035 $10,245



Cash Outflows

Debt Service

Principal $– ($8,029) $– $– ($7,140)

Interest – (8,489) – – (8,354)


Opex + Capex (3,980) (4,248) (6,596) (6,101) (4,915)

Others - (558) - - -

Total Cash Outflows ($3,980) ($21,324) ($6,596) ($6,101) ($20,409)

Ending Cash (Pre I/C Transfers and Reserve Accounts) $14,922 $4,437 $10,761 $15,316 $5,790

I/C Transfers

Cash Available / (Cash Needed) 14,922 4,437 10,761 15,316 5,790

Transfers to:

Tay IV – (2,331) – – (5,790)

ODN I – – – – –Norbe VI – – – – –

Subtotal $– ($2,331) $– $– ($5,790)

Transfers from:

Norbe VI – – – – –ODN I – – – – –Tay IV – 5,084 – – –Sinking Fund – – – – –

Subtotal $– $5,084 $– $– $–(Cash Transferred) / Cash Received – 2,752 – – (5,790)

Ending Cash (Post I/C and Sinking Fund Transfers) $14,922 $7,189 $10,761 $15,316 $–


2022 Cash Flows – Norbe VI (with Amended Caps)

22

($ in US 000s) 02/2016 03/2016 04/2016 05/2016 06/2016


Beginning Cash – 5,001 1,836 – –

Cash Inflows

Net Charter $7,395 $6,550 $6,128 $6,155 $6,365


Transfer from Offshore Debt Service Reserve Account - 4,550 - - -


Cash Outflows

Debt Service

Principal - (6,251) - - (6,000)

Interest - (8,478) - - (8,372)


Opex + Capex (5,199) (5,291) (7,208) (6,707) (5,484)

Other - (558) - - -


Ending Cash (Pre I/C Transfers) $5,001 ($2,004) $3,053 $1,753 ($11,119)

I/C Transfers

Cash Available / (Cash Needed) 5,001 (2,004) 3,053 1,753 (11,119)

Transfers to:

Tay IV – – (3,053) (1,753) –ODN I – – – – –ODN II – – – – –

Subtotal $– $– ($3,053) ($1,753) $–Transfers from:

Tay IV – 3,840 – – –ODN I – – – – –ODN II – – – – –Sinking Fund – – – – –

Subtotal $– $3,840 $– $– $–(Cash Transferred) / Cash Received – 3,840 (3,053) (1,753) –Ending Cash (Post I/C and Sinking Fund Transfers) $5,001 $1,836 $– $– ($11,119)


2022 Cash Flows – ODN Tay IV (with Amended Caps)

23

($ in USD 000s) 02/2016 03/2016 04/2016 05/2016 06/2016

Offshore Proceeds Acct

Beginning Cash - 19,609 - - -

Cash Inflows

Net Charter $– $– $– $– $–Services (Net of Taxes) – – – – –Insurance Proceeds 22,593 – – – –Total Cash Inflows $22,593 $– $– $– $–

Cash Outflows

Debt Service

Principal $– ($9,570) $– $– ($9,280)

Interest – (8,827) – – (8,669)


Opex + Capex (2,984) (2,935) (13,705) (2,555) (1,024)

Other - (558) - - -


Ending Cash (Pre I/C Transfers and Reserve Accounts) $19,609 ($2,280) ($13,705) ($2,555) ($18,972)

I/C Transfers

Cash Available / (Cash Needed) 19,609 (2,280) (13,705) (2,555) (18,972)

Transfers to:

Norbe VI – (3,840) – – –ODN I – (5,084) – – –ODN II – (5,084) – – –

Subtotal $– ($14,007) $– $– $–Transfers from:

Norbe VI – – 3,053 1,753 –ODN I – – 2,366 802 –ODN II – 2,331 – – 5,790

Sinking Fund – 13,956 8,286 – –Subtotal $– $16,287 $13,705 $2,555 $5,790

(Cash Transferred) / Cash Received – 2,280 13,705 2,555 5,790

Ending Cash (Post I/C and Sinking Fund Transfers) $19,609 $– $– $– ($13,182)


C. 2021 Structure Caps

24


Current Cap Structure (2021 Structure) > The current cap structure requires substantial cash outlay from the Parent in the coming months

25

($ in USD 000s)


Forecast Opex $5,092 $5,102 $6,491 $6,093

Forecast Capex – – 468 468








Forecast Opex $5,315 $4,893 $6,299 $6,014








Cumulative 2021s Mar-16 Apr-16 May-16 Jun-16

Forecast Opex $10,407 $9,995 $12,789 $12,107







Cumulative ($5,722) ($9,992) ($20,302) ($29,887)


Projected Opex (2021 Structure)

26

($ in US 000s)


Payroll $955 $938 $1,420 $1,374

Suppliers / Other(1) 3,688 3,739 2,980 3,677


TAC 244 203 205 198

Total Opex $5,092 $5,102 $6,491 $6,093

Norbe IX

Payroll $1,041 $1,027 $1,481 $1,433

Suppliers / Other(1) 3,825 3,442 2,727 3,539


TAC 244 203 205 198

Total Opex $5,315 $4,893 $6,299 $6,014

(1) “Suppliers / Other” includes insurance costs.


2021 Consolidated Cash Flows (with Amended Caps)

27

($ in USD 000s) 02/2016 03/2016 04/2016 05/2016 06/2016

Offshore Receipts Acct

Beginning Cash Position $15,075 $36,494 $46,843 $53,490 $61,256

Cash Inflows $31,826 $20,344 $22,346 $22,782 $24,140

Charter 30,131 19,251 21,152 21,437 22,704


Cash Outflows ($10,407) ($9,995) ($15,699) ($15,016) ($102,367)

Debt Service - - - - (89,886)

New SOISA Caps (10,407) (9,995) (15,699) (15,016) (12,481)

Other - - - - -

Ending Cash (Pre I/C Transfers and Reserve Accounts) $36,494 $46,843 $53,490 $61,256 ($16,972)

Memo: Reserve Account Balances

Mobilization Fee Accounts $11,736 $11,736 $11,736 $11,736 $11,736

Debt Service Reserve Accounts 11,193 11,193 11,193 11,193 11,193

O&M Service Reserve Accounts - - - - -

Subtotal $22,928 $22,928 $22,928 $22,928 $22,928


2021 Cash Flows – Norbe VIII (with Amended Caps)

28

($ in USD 000s) 02/2016 03/2016 04/2016 05/2016 06/2016


Beginning Cash $7,549 $15,042 $18,709 $23,271 $28,922

Cash Inflows $12,585 $8,769 $11,521 $12,211 $12,469

Charter 11,903 8,298 10,906 11,486 11,723


Interest Accrued

Cash Outflows ($5,092) ($5,102) ($6,959) ($6,561) ($50,451)

Debt Service – – – – (45,172)

New SOISA Caps (5,092) (5,102) (6,959) (6,561) (5,279)

Other – – – – –



2021 Cash Flows – Norbe IX (with Amended Caps)

29

($ in USD 000s) 02/2016 03/2016 04/2016 05/2016 06/2016


Beginning Cash Position $7,526 $21,452 $28,134 $30,218 $32,334

Cash Inflows $19,241 $11,575 $10,824 $10,571 $11,670

Charter 18,228 10,953 10,246 9,951 10,981

Services (Net of Taxes) 1,014 622 578 620 689

Interest Accrued

Cash Outflows ($5,315) ($4,893) ($8,740) ($8,455) ($51,916)

Debt Service - - - - (44,714)

New SOISA Caps (5,315) (4,893) (8,740) (8,455) (7,203)

Other - - - - -


Confidential

Project Orion AMENDED OPERATING AND CAPITAL EXPENSE CAPS

March 6, 2016

Confidential

Historical and Projected Daily Opex (2022 Structure)

Note: Historical daily opex numbers are on an accrual basis, and there are some costs incurred in 2015 that are paid in 2016. 1

($ in US 000s)

Norbe VI 2014 2015 2016

Labor Payroll $63 $56 $44

Crew Change/Training 8 6 6

Catering 5 4 4

Repairs & Maintenance 42 17 23

Opex Project – 46 19

Logistics 7 14 9

Rig Insurance 10 9 9

Other Costs 6 6 10

Onshore Support + TAC 21 14 15

Total Opex / Day $163 $173 $138

Restructuring Costs – – 9

Total Opex (Incl. Restructuring Costs) $163 $173 $148

ODN I / II 2014 2015 2016



Catering 11 9 8



Logistics 24 24 19


Other Costs 12 9 11


Total Opex / Day $310 $288 $269



Confidential

Historical and Projected Daily Opex (2022 Structure) (Cont’d)


($ in US 000s)

Tay IV 2014 2015 2016



Catering 6 4 1



Logistics 12 13 1


Other Costs 10 13 14

Onshore Support + TAC 21 14 –Demobilization cost – – 39

Transfer to Tenerife – – 11

Cold stack process – – 11

Total Opex / Day $171 $147 $101



Confidential

Historical and Projected Daily Opex (2021 Structure)


($ in US 000s)

Norbe VIII 2014 2015 2016



Catering 6 4 4



Logistics 25 11 9


Other Costs 19 4 6


Total Opex / Day $230 $150 $147



Norbe IX 2014 2015 2016



Catering 6 4 4



Logistics 8 9 9


Other Costs 7 6 6


Total Opex / Day $153 $143 $147



Confidential

I. Revised Caps

4

Confidential

A. 2022 Revised Caps

5

Confidential

2022 – Revised Caps (Dollar Amount)

(1) Transfer will occur at the end of the month with the amounts established under the new caps. 6

($ in US 000s)


Salary $1,140 $1,103 $1,140 $1,103

Bonus – – 800 –

Crew Change/Training 180 174 180 174

Catering 117 114 117 114

Repairs & Maintenance 883 1,197 779 569

Opex Project 914 1,240 807 589

Logistics 426 578 376 275

Rig Insurance 86 688 – 688

Other Costs 218 211 218 211

Onshore Support + TAC 490 440 467 435

Total Opex $4,454 $5,745 $4,885 $4,159

Total Opex per Day $144 $192 $158 $139


Total Opex (Incl. Restructuring Costs) $4,592 $5,967 $6,771 $5,147

Total Opex (Incl. Restructuring Costs) per Day $148 $199 $218 $172

MPD – – – –

Fleet spare – – – 163

Operational capex – – – 257

Constrction capex – – – –

5-year SPS 1,044 – 862 1,245

Forecast Capex $1,044 $– $862 $1,665


Total Forecast Opex and Capex per Day $182 $199 $246 $227

Plus: Cushion (10%) 564 597 763 681

Revised Opex and Capex Cap (To be Transferred at end of Current Month)(1)$6,200 $6,564 $8,396 $7,494

Revised Opex and Capex Cap per Day (To be Transferred at end of Current Month) $200 $219 $271 $250

Confidential

2022 – Revised Caps (Dollar Amount) (Cont’d)

7

($ in US 000s)

ODN I / II Mar-16 Apr-16 May-16 Jun-16

Salary $2,383 $2,306 $2,383 $2,306

Bonus – – 1,600 –


Catering 235 227 235 227

Repairs & Maintenance 1,093 507 1,643 1,138

Opex Project 975 429 1,447 997

Logistics 526 238 798 549

Rig Insurance 171 1,363 – 1,551

Other Costs 318 308 318 308


Total Opex $7,041 $6,606 $9,716 $8,295


Restructuring Costs 275 443 3,772 1,978



MPD – – – –

Fleet spare 837 418 316 543



5-year SPS – – – –

Forecast Capex $837 $418 $316 $712



Plus: Cushion (10%) 815 747 1,380 1,098



(1) Transfer will occur at the end of the month with the amounts established under the new caps.

Confidential


8

($ in US 000s)


Salary $326 $315 $326 $315

Bonus – – – –


Catering 26 25 26 25

Repairs & Maintenance 143 138 143 138

Opex Project – – – –

Logistics 31 30 31 30


Other Costs 845 818 353 342

Onshore Support + TAC – – – –

Demobilization cost 1,882 1,436 1,314 1,363

Transfer to Tenerife – 1,200 2,800 –

Cold stack process – – – –

Total Opex $3,380 $4,904 $5,029 $3,123




Total Opex (Incl. Restructuring Costs) $113 $171 $223 $137

MPD – – – –

Fleet spare – – – –

Operational capex – – – –

Constrction capex 838 325 208 237

5-year SPS – – – –

Forecast Capex $838 $325 $208 $237



Plus: Cushion (10%) 436 545 712 435

Revised Opex and Capex Cap (To be Transferred at end of Current Month) (1)$4,791 $5,996 $7,836 $4,783



Confidential

B. 2021 Revised Caps

9

Confidential

2021 – Revised Caps (Dollar Amount)

10

($ in US 000s)


Salary $1,186 $1,147 $1,186 $1,147

Bonus – – 800 –


Catering 117 114 117 114

Repairs & Maintenance 1,133 723 649 569

Opex Project 2,017 1,291 1,161 1,019

Logistics 552 350 314 275


Other Costs 167 161 167 161


Total Opex $6,099 $5,252 $5,060 $4,772





MPD – – – –

Fleet spare – – – –

Operational capex – – – –


5-year SPS 1,487 4,218 1,012 716

Adjustment for Capex Not Paid using Caps (1,487) (3,511) – –

Forecast Capex $– $707 $1,012 $716



Plus: Cushion (10%) 624 618 796 648




Confidential


11

($ in US 000s)


Salary $1,242 $1,202 $1,242 $1,202

Bonus – – 800 –


Catering 117 114 117 114

Repairs & Maintenance 1,212 686 743 569

Opex Project 1,982 1,126 1,219 936

Logistics 591 332 360 275


Other Costs 176 171 176 171


Total Opex $6,075 $5,013 $5,305 $4,730





MPD – – – –

Fleet spare – – – 92



5-year SPS 1,689 634 1,043 1,819

Adjustment for Capex Not Paid using Caps (467) – – –

Forecast Capex $1,222 $634 $1,043 $2,096



Plus: Cushion (10%) 743 587 823 781




Confidential






Company Profile September 2015

Norbe IX

Management Presentation

February 2016*

Norbe IX Drillship



2 2

Agenda

OOG Operation

Capital Structure Considerations


3

Operating Performance Overview

• OOG’s management team has made significant progress over the last two years in improving operating

performance

• As of January 28, 2016, OOG is ranked 4th out of 14 operators according to Petrobras

• Ranked 1st on those operating 3 rigs or more

• OOG’s performance has improved five places since December 2014

• Four of the six individual operating assets are in the top half of performance

• OOG has continued to improve its standing across several metrics:

• Punch list items (compliance items) have declined by 70+% over the last three years (January 2013 to

January 2016)

• Safety indicators (frequency rate of recordable incidents) have declined by 55+% over last three years

(December 2012 to December 2015)

• Operational uptimes have increased each year over last three years (from 80.6% in 2012 to 93.1% in 2015)

• Since December 13th, 2014, OOG has improved from 9th to 4th on the list of competitors regarding a series of

operational initiatives


4

Performance Indicators

9.489.50

9.11

8.86

Dec/14

Dec/15

Dec/12

Dec/13

In Jan/15

9.50

9.23

Average

Maximum

Note: numbers are out of a possible score of 10 (i.e. 9.50 out of 10; the higher the better)


5

Performance Indicators Operational Uptime – 6 rigs (12 month average)

93.1%92.7%

88.7%

80.6%

Dec/15

Dec/13

Dec/12

Dec/14

In Oct/15

Note: Performance score out of a total potential score of 100% (i.e. 80.6% out of 100%; the higher the better). For Dec/15, the Operational Uptime includes 27 days of dockage for N6.

Maximum

Average

95.0%

91.4%%


6

Performance Indicators Downtime Events (# days) – 6 rigs

Note: Dec/15 Op. Uptime considers 27 of docking days (N6)

Unit: # days

149.7 Op. Uptime 93.1%

Op. Uptime 88.7%

Downtime Days

218.1

2015 2013

158.6 Op. Uptime 92.7%

2014

Norbe VI downtime event is under dispute

(18.9 days)

Downtime Days

Downtime Days

Note: Dec/15 Operational Uptime includes 27 of docking days (N6). Lower downtime is better.


7

Performance Indicators Opex – 6 rigs average (annual total)

$178.7

$162.6 $168.5

$147.3

2012 2013 2014 2015

Unit: USD K/day


8 8

Agenda

OOG Operations

Capital Structure

Considerations


9

LCs Guarantees for the Project Bonds Maturity Schedule as of April 25, 2016

• Below is a summary of all outstanding letters of credit that support the ‘21 and ‘22 Notes


Amount

(USD k)

Norbe VIII O&M LC Citibank 19-Dec-16 10.695

Norbe IX O&M LC Citibank 19-Dec-16 10.695

Total O&M 21.390

Norbe VIII DSRA Ins. w/ LC Swiss Re 15-May-16 40.386

Norbe IX DSRA Ins. w/ LC Swiss Re 15-May-16 39.976

Total DSRA 80.363

101.753

248.962 Total '21 + '22

Total LCs 21s

Project Account Type Issuer MaturityAmount

(USD k)

ODN Tay IV O&M LC CA-CIB 24-Jun-16 11.020

ODN I & II O&M Insurance Swiss Re 01-Aug-16 28.152

Norbe VI O&M Insurance Swiss Re 01-Aug-16 14.076

Total O&M 53.248

ODN Tay IV DSRA LC Swiss Re 06-Aug-16 93.961

Bond '22 DSRA Insurance Total DSRA 93.961

147.209 Total LCs 22s

Project Account Type Issuer Maturity

9

10

OOG Debt Overview

Since OOG began operating the 2021 Assets and 2022 Assets, OOG has made significant contributions to fund those assets’ operations

- OOG contributions have been required to continue funding for ongoing operations for the following items:

o Opex requirements above the opex cap (as set in the indentures)

o Capital expenditures

o Equity injections to fund the ramp up of the rigs

o Shortfalls to cover debt service

From bond issuance to December 2015, OOG has funded the aggregate net shortfalls of more than $705 million of operating expenses, capital expenditures, debt service and downtime/non schedule stoppages

Approximate OOG Funding to Date

(USD$ in k)

2021 Structure 2010 2011 2012 2013 2014 2015

Dividends $– $64,116 $32,135 $21,306 $31,877 $20,911

Equity Injections – (284,528) (40,368) (47,453) (76,021) (59,304)

Net Equity Investment $– ($220,411) ($8,233) ($26,147) ($44,144) ($38,393)

2022 Structure

Dividends including Reimbursements $– $– $20,486 $319,661 $179,495 $72,713

Equity Injections (40,994) (104,896) (197,949) (245,465) (131,513) (128,791)

Net Equity Investment ($40,994) ($104,896) ($177,462) $74,196 $47,982 ($56,078)

Total Net Equity Investment ($40,994) ($325,307) ($185,695) $48,049 $3,838 ($94,471)

Allocated Interest Costs – (4,251) (11,982) (27,094) (30,981) (36,389)

Corporate Funding Requirements ($40,994) ($329,558) ($197,676) $20,955 ($27,144) ($130,860)

Cumulative Net Equity Investment ($40,994) ($370,552) ($568,229) ($547,274) ($574,418) ($705,278)


11

OOG Debt Costs & Maintenance Issues

Main Causes Main Effects

Labor Costs During 2010-2014, high oil prices (over US$100/bbl) encouraged Upstream Capex growth. As a result, global drilling companies expanded their fleet quickly. During this period, Petrobras announced the pre-salt discoveries and an aggressive expansion of its drilling fleet.

When the rigs that were awarded by Petrobras’ in 2006 and 2008 started operations, payroll began increasing considerably above global inflation and especially in Brazil – where local content rules put pressure in a small specialized workforce pool.

Suppliers Led by the Upstream growth, specialized equipment suppliers began increasing their prices throughout the period and started to subcontract equipment parts throughout the world without proper supervision.

As a result, even with increased lead-times, suppliers constantly delivered with delays and with quality problems, premature failures and many downtime and claims.

Maintenance Costs The Macondo accident has raised a new standard that now requires stricter maintenance rules regarding well control equipment. Thus, demand for subsea parts and services has inflated the costs in the market.

After disasters like the Macondo, the Chevron oil spill, the fire in Cidade de São Mateus FPSO, the ANP (a Brazilian Regulator) has increased the requirements related to technical inspections.

The maintenance plan also includes an increased budget for preventative maintenance in order to reduce downtime.

Tax Importation Regime Changes in REPETRO rules (imposed in Dec/2013) removed tax breaks for equipment with cost below US$25k, which has contributed to a cost-increased in importation

Exchange Rate The Project Exchange Rate Cap of 2:1 does not reflect the current exchange rate scenario of ~4:1


• Below is a summary of cost and maintenance issues that have impacted funding needs

12

6

101

76

156

26 28 27 27

0

20

40

60

80

100

120

140

160

180

200

Short-Term 2016 2017 2018 2019 2020 2021 2022 ≥ 2023

US

D m

illi

on

Perpetual Bond Corporate Debt

550

OOG Debt Schedule Confidential Settlement Communication Subject to FRE 408

13

Appendix


14

Historical Data Background

• From 2004 to 2014, Oil and Drilling companies were impacted by the growth in oil prices and upstream capex

• While revenues increased, margins declined resulting in the same level of EBITDA

Source: Companies data/Thomson Reuters. 1) Includes the majors BP, Chevron, Exxon, Shell and Total. 2) Includes drillers operating since 2004 (Diamond, Ensco, Noble, Odfjell and Transocean).

-

100,000

200,000

300,000

400,000Revenues

10.0%

12.0%

14.0%

16.0%

18.0%

20.0%EBITDA Margin

-

1,000

2,000

3,000

4,000

5,000

Revenues

0.0%

20.0%

40.0%

60.0%

EBITDA Margin

Oil Co’s¹ Drillers²

USD MM

USD MM


15

Historical Data Background

• The below report from IHS addresses the pressure on costs as Odebrecht was ramping up its operations

Source: IHS. Press release and chart freely available on https://www.ihs.com/info/cera/ihsindexes/


16

147

193

169

123

127

118

118

131

Opex Per Rig per Day¹ Rigs Considered

• 6 Ultra-deepwater

• 12 Ultra-deepwater • 7 Deepwater • 9 Midwater

• 18 Ultra-deepwater • 5 Deepwater • 3 Midwater

• 17 Floaters • 14 Jack-ups

• 23 Floaters • 21 Jack-ups

• 37 UDW e Deepwater • 17 Midwater • 10 Jack-ups

Location

• Brazil

• Global

• Global

• Global • No operation in Africa

• Global

• Global

Avg Opex: 141 MM

Performance Indicators Opex Benchmark

Source: Companies data/Thomson Reuters; Odebrecht analysis. 1) Odebrecht’s data is FY15. Other companies’ data is 3Q15 and calculated as follows: (Operating costs + SG&A) ÷ Active Fleet ÷ 273 days (9 months).



• Mexico and Nigeria

• Angola, Norway, Brazil and West Africa

High Spec Rigs Comparable Players

• The data available for comparison between daily opex of the rigs should be considered as only a proxy since they are not precise due to the following issues:

Geographic location of the rigs

Portfolio of rigs (Water depth, weather conditions)

Methodology/Capitalization of asset maintenance and other expenses


17

Historical Opex of each Vessel

When the ‘21 Notes were issued (Nov ‘10), the expectation was that the synergies from operating the fleet would reduce

costs over time. After operations began, OOG faced constantly increasing costs. This assumption was addressed when the

22’s Notes were issued (Aug ‘13)

(USD$ 000s per Day) 2011 2012 2013 2014 Dec15 Dec15 YTD

2022 Assets

ODN I

Personnel Costs N/A N/A $84 $77 $67 $68

Repairs, Maintenance, Logistics N/A N/A 26 31 23 26

Other Costs N/A N/A 49 52 44 58

Total N/A N/A $159 $161 $134 $152

ODN II




Total N/A N/A $145 $150 $114 $136

Norbe VI




Total N/A N/A $161 $163 $189 $173

Tay IV


Repairs, Maintenance, Logistics N/A N/A 109 50 (6) 44


Total N/A N/A $228 $171 $92 $148

2021 Assets

Norbe VIII

Personnel Costs $81 $87 $86 $85 $58 $67

Repairs, Maintenance, Logistics 39 39 41 94 69 54

Other Costs 28 52 53 52 36 29

Total $148 $179 $179 $231 $163 $150

Norbe IX

Personnel Costs $82 $85 $83 $79 $66 $69


Other Costs 29 50 50 39 37 30

Total $124 $173 $160 $153 $149 $143


18

Historical Capex of each Vessel

Historical Capex to Date

(USD$ in k)

2022 Assets 2011 2012 2013 2014 2015

ODN I & II $– $16,314 $19,940 $17,718 $30,914

Norbe VI 2,626 5,454 1,621 8,788 29,937

Tay IV – – 20,255 31,431 35,160

Total $2,626 $21,768 $41,816 $57,937 $96,012

2021 Assets

Norbe VIII $– $– $328 $2,814 $3,879

Norbe IX – 0 1,628 7,153 5,848

Total $– $0 $1,956 $9,967 $9,727

Important capex information:

2014: ODN I&II – 70% came from the Managed Pressure Drilling (“MPD”) Norbe VI – 75% came from the MPD ODN Tay IV – 70% came from (unscheduled) stoppage

2015: ODN I&II – 70% came from the MPD Norbe VI – 40% came from the MPD, 32% from (scheduled) stoppage ODN Tay IV – 80% came from (unscheduled) stoppage,

Notes: Construction costs: overall, these are acceptance costs disbursed after the rig started operations Fleet spare: main equipments such as riser, top drive, BOP and etc Operational capex: specific costs such as pendency with Petrobras


19

Historical Financial and Cash Flow of each Vessel

Onshore Revenue Acct (BRL '000) 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15

Initial Balance - - - - - - - -

Project Revenues 23.787 23.399 23.749 26.411 24.079 19.850 28.857 15.132

Net Service 23.787 23.399 23.749 26.411 24.079 19.850 28.857 15.132

Outflow (23.787) (23.399) (23.749) (26.411) (24.079) (19.850) (28.857) (15.132)

O&M Expenses under opex allowance (23.787) (23.399) (23.749) (26.411) (24.079) (19.850) (28.857) (15.132)

Final Balance - - - - - - - -

Offshore Proceeds Acct (USD '000) 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15

Initial Balance 6.564 6.206 4.684 4.498 6.524 1 6.541 6.590

Project Revenues 19.352 17.415 16.876 21.887 13.289 22.665 26.275 12.775

Charter 19.352 17.415 16.876 20.295 13.288 20.285 19.275 12.314

I/L ODN Tay IV - - - - - 2.380 - -

I/L ODN I GmbH - - - - - - - 461

Outflow (19.709) (18.937) (17.063) (19.860) (19.812) (16.125) (26.226) (19.365)

Debt Service (13.923) (12.730) (14.307) (14.610) (14.840) (14.125) (14.747) (14.737)

Amounts Transferred to O&M Service Accounts (1.500) (1.500) (1.500) (1.500) (1.000) (2.000) (1.500) (1.500)

I/L ODN Tay IV - - - (3.750) - - (9.979) (2.974)

Transfers to other Accounts (371) - - - - - - -

Transfer to Offshore Distribution Holding Acct (3.915) (4.708) (1.256) - (3.972) - - -

Final Balance 6.206 4.684 4.498 6.524 1 6.541 6.590 (0)

Offshore Distribution Holding Acct (USD '000) 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15

Initial Balance - - - 1.256 1.256 5.228 5.228 -

Project Revenues 3.915 4.708 1.256 - 3.972 - - -

Transfer from Offshore Proceeds Acct 3.915 4.708 1.256 - 3.972 - - -

Outflow (3.915) (4.708) - - - - (5.228) -

Transfer to Offshore Distribution Acct (3.915) (4.708) - - - - (5.228) -

Final Balance - - 1.256 1.256 5.228 5.228 - -

Norbe VI


20


ODN I GmbH Onshore Revenue Acct (BRL '000) 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15

Initial Balance 0 - - - - - - - -

Project Revenues 15.072 9.895 7.229 9.023 12.358 11.953 12.331 10.993 12.121

Net Service 15.051 9.827 7.229 9.023 12.358 11.953 12.331 10.993 12.121

Payment adjustment from Petrobras 21 67 - - - - - - -

Outflow (15.089) (9.895) (7.229) (9.023) (12.358) (11.953) (12.331) (10.993) (12.121)

O&M Expenses under opex allowance (15.089) (9.895) (7.229) (9.023) (12.358) (11.953) (12.331) (10.993) (12.121)

Final Balance - - - - - - - - -

ODN I GmbH Offshore Proceeds Acct (USD '000) 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15

Initial Balance - 15.207 15.219 5.774 16.192 13.916 13.041 21.517 16.312


Charter 102.673 60.379 51.861 53.370 64.280 63.457 56.247 58.939 61.140

Payment adjustment from Petrobras - 371 - 326 - - - - -

DSME - - - - - - 3.500 671 -

Equity Contribution for Debt Service/SOISA - - - 8.905 - - - - -

Transfer from Debt Service Reserve Account - - - - - - - - 2.454

Outflow (87.465) (60.738) (61.306) (52.182) (66.555) (64.332) (51.271) (64.815) (77.076)

Debt Service (44.939) (35.177) (28.794) (30.936) (31.214) (33.294) (30.696) (33.435) (33.918)

Amounts Transferred to O&M Service Accounts (30.530) (19.003) (21.834) (21.247) (18.436) (19.576) (18.541) (13.287) (20.658)

I/L ODN Tay IV - - - - - - - (4.977) (21.732)

I/L Norbe VI - - - - - - - - (461)

Transfer to Debt Service Reserve Account - - - - - - (1.526) (928) -

Transfer to O&M Service Reserve Account - - - - - - - - (306)

Transfer to Offshore Distribution Holding Acct (11.997) (6.557) (10.678) - (16.905) (11.462) (508) (12.188) -

Final Balance 15.207 15.219 5.774 16.192 13.916 13.041 21.517 16.312 2.831

ODN I GmbH Offshore Distribution Holding Account - USD 000 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15

Initial Balance - - - - - 16.905 28.367 28.876 -

Project Revenues 11.997 6.557 10.678 - 16.905 11.462 508 12.188 -

Transfer from Offshore Proceeds Acct 11.997 6.557 10.678 - 16.905 11.462 508 12.188 -

Outflow (11.997) (6.557) (10.678) - - - - (41.064) -

Transfer to Offshore Distribution Acct (11.997) (6.557) (10.678) - - - - (41.064) -

Final Balance - - - - 16.905 28.367 28.876 - -

ODN I GmbH


21


ODN Tay IV

ODN Tay IV Onshore Revenue Acct (BRL '000) 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15

Initial Balance - - - - - - -

Project Revenues - - 1.115 2.713 5.909 - -

Net Service - - 1.115 2.713 5.478 - -

Payment adjustment from Petrobras - - - - 430 - -

Outflow - - (1.115) (2.713) (5.909) - -

O&M Expenses under opex allowance - - (1.115) (2.713) (5.909) - -

Final Balance - - - - - - -

ODN Tay IV Offshore Proceeds Acct (USD '000) 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15

Initial Balance - - 0 5.781 5.031 4.380 0

Project Revenues 36.516 30.188 35.152 28.926 26.819 14.956 32.480

Charter 36.516 611 20.549 28.926 26.819 - -

I/L Norbe VI - - 3.750 - - 9.979 2.974

I/L ODN I GmbH - - - - - 4.977 21.732

Equity Contribution for Debt Service/SOISA - 25.798 10.854 - - - -

Transfer from Loss Proceeds and Compensation Account - 3.780 - - - - -

Transfer from Sinking Fund - - - - - - 7.774

Outflow (36.516) (30.188) (29.371) (29.677) (27.470) (19.335) (32.480)

Debt Service (16.791) (16.924) (17.218) (17.120) (9.653) (17.052) (17.848)

Amounts Transferred to O&M Service Accounts (15.088) (13.265) (12.152) (11.624) (9.733) (2.284) (14.563)

I/L Norbe VI - - - - (2.380) - -

Transfer to O&M Service Reserve Account - - - - - - (69)

Transfer to Offshore Distribution Holding Acct (4.636) - - (933) (5.705) - -

Final Balance - 0 5.781 5.031 4.380 0 0

ODN Tay IV Offshore Distribution Holding Account - USD '000 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15

Initial Balance - - - - 933 6.638 -

Project Revenues 4.636 - - 933 5.705 - -

Transfer from Offshore Proceeds Acct 4.636 - - 933 5.705 - -

Outflow (4.636) - - - - (6.638) -

Transfer to Offshore Distribution Acct (4.636) - - - - (6.638) -

Final Balance - - - 933 6.638 - -


22


Norbe VIII

Dates 2S11 1S12 2S12 1S13 2S13 1S14 2S14 1S15 2S15

USD 000



Outflows (92.501) (53.993) (66.862) (65.445) (53.880) (54.812) (61.599) (64.675) (68.724)

Debt Service (39.010) (30.993) (38.292) (41.583) (40.984) (40.386) (39.788) (42.959) (46.010)

SOISA (18.165) (20.559) (16.425) (16.527) (12.896) (13.194) (12.411) (10.846) (11.619)

Dividends (Distr. Holding Acc) (35.325) (2.441) (12.144) (7.334) - (1.232) (9.400) (10.871) (11.095)

Dates 2S11 1S12 2S12 1S13 2S13 1S14 2S14 1S15 2S15

BRL 000

Onshore Proceeds and Service Acct


OOG O&M Service Accounts (4.161) (9.144) (6.784) (7.733) (10.530) (11.378) (17.497) (17.426) (15.856)

Dates 2S11 1S12 2S12 1S13 2S13 1S14 2S14 1S15 2S15

USD 000



Outflows (74.687) (58.886) (64.839) (61.479) (56.990) (64.533) (66.184) (65.168) (61.232)

Debt Service (38.615) (30.679) (37.904) (41.161) (40.569) (39.976) (39.384) (42.523) (45.543)

SOISA (7.282) (20.122) (17.470) (15.771) (15.739) (16.171) (13.941) (12.605) (13.025)

Dividends (Distr. Holding Acc) (28.791) (8.085) (9.465) (4.547) (9.425) (8.386) (12.858) (10.040) (2.664)

Dates 2S11 1S12 2S12 1S13 2S13 1S14 2S14 1S15 2S15

BRL 000

Onshore Proceeds and Service Acct

Project Revenues - 9.993 11.840 9.537 10.922 8.778 12.631 15.091 11.959

OOG O&M Service Accounts - (9.993) (11.840) (9.537) (10.922) (8.778) (12.631) (15.091) (11.959)

Norbe IX


23

Forecasted Opex of each Vessel (21’s)

Note: Opex data shown above is based on accrual accounting. Additionally, unlike the forecast in the business plan, the data above is not (i) adjusted for inflation nor (ii) reduced by the social security tax that results from the credit generated by Petrobras deductions of the Services Agreement. Actual results may differ from forecasts.

2016 2017 2018 2019 2020 2021

(USD$ 000s per Year)

2021 Assets

Norbe VIII

Personnel Costs $20,278 $21,144 $21,944 $22,739 $23,584 $24,318

Repairs, Maintenance, Logistics 6,943 7,215 7,460 7,704 7,961 8,189

Other Costs 26,977 21,199 19,445 22,356 27,935 28,768

Total $54,198 $49,558 $48,849 $52,798 $59,480 $61,274

Norbe IX

Personnel Costs $20,993 $21,859 $22,651 $23,439 $24,275 $25,006

Repairs, Maintenance, Logistics 6,943 7,217 7,464 7,710 7,970 8,200

Other Costs 25,979 21,424 21,498 22,069 28,768 29,644

Total $53,915 $50,501 $51,613 $53,219 $61,013 $62,850


24

Forecasted Opex of each Vessel (22’s)

2016 2017 2018 2019 2020 2021 2022

(USD$ 000s per Year)

2022 Assets

ODN I

Personnel Costs $20,834 $21,700 $22,493 $23,282 $24,119 $24,850 $25,555

Repairs, Maintenance, Logistics 6,943 7,209 7,446 7,682 7,931 8,153 8,369

Other Costs 22,147 28,257 20,803 23,109 25,608 26,323 26,444

Total $49,924 $57,166 $50,741 $54,073 $57,658 $59,326 $60,369

ODN II

Personnel Costs $19,870 $20,732 $21,532 $22,326 $23,172 $23,903 $24,605


Other Costs 21,335 24,090 22,367 23,930 24,902 25,592 25,693

Total $48,148 $52,033 $51,348 $53,945 $56,014 $57,660 $58,681

Norbe VI

Personnel Costs $19,694 $20,556 $21,358 $22,154 $23,003 $23,735 $24,437


Other Costs 24,054 20,685 22,177 24,959 29,322 30,207 31,032

Total $50,692 $48,446 $50,971 $54,779 $60,234 $62,069 $63,808

Tay IV

Personnel Costs $13,054 $21,040 $21,854 $22,662 $23,523 $24,266 $24,979

Repairs, Maintenance, Logistics 0 6,278 6,483 6,687 6,902 7,094 7,281

Other Costs 7,006 25,653 16,161 16,714 17,288 17,794 18,285

Total $20,060 $52,972 $44,498 $46,062 $47,712 $49,154 $50,545


Note: Opex data shown above is based on accrual accounting. Additionally, unlike the forecast in the business plan, the data above is not (i) adjusted for inflation nor (ii) reduced by the social security tax that results from the credit generated by Petrobras deductions of the Services Agreement. Actual results may differ from forecasts.

25

Forecasted Capex of each Vessel

US$ in K

Norbe VI 2015 (Sep-Dec) 2016 2017 2018 2019 2020 2021 2022

Total $20,771 $12,818 $7,150 $3,121 $52,620 $9,936 $4,688 $4,688

ODN I 2015 (Sep-Dec) 2016 2017 2018 2019 2020 2021 2022

Total $8,200 $5,539 $11,189 $11,853 $8,009 $3,931 $4,688 $36,018

ODN II 2015 (Sep-Dec) 2016 2017 2018 2019 2020 2021 2022

Total $10,170 $4,449 $16,547 $18,719 $3,804 $927 $4,688 $36,018

ODN Tay IV 2015 (Sep-Dec) 2016 2017 2018 2019 2020 2021 2022

Total $23,530 $4,567 $2,390 $1,526 $2,158 $1,411 $4,688 $22,818

Norbe VIII 2015 (Sep-Dec) 2016 2017 2018 2019 2020 2021 2022

Total $2,378 $11,822 $18,985 $4,467 $4,233 $37,055 $4,688 $4,688

Norbe IX 2015 (Sep-Dec) 2016 2017 2018 2019 2020 2021 2022

Total $1,573 $20,680 $3,943 $3,276 $2,242 $37,293 $4,688 $4,688


Note: Actual results may differ from forecasts.

26

Performance Indicators Downtime Events Classification

Subsea: BOP and Tree Transporters, BOP Controls (Electric), BOP Controls (Hydraulic), BOP Overhead Cranes, BOP Stack, C & K Manifold & Hoses, Diverter System, Marine Riser (inc Slip Joint), Miscellaneous Subsea, Motion Compensator, Tensioners, Riser or Guideline

Drilling: Drawworks, Top Drive (DDM), Wash Pipe Swivel Packing, Saver Sub, Crown/Traveling Block, Pipe Handling VPH - LGA or BRC, Iron Roughneck, HPU, Drilling Controls, Other Drill Floor, Mud Pumps, Mud Process System, CMC

Dynamic Position: DP System/Station Keeping, Thrusters/Thruster controls, Other (If equip not listed)

Power Generation: Power, Prime Movers, Controls, SCR's

Docking Days

Others: Petrobras Dispute, Equipment Failure, Planned PM, Human Error, Instrumentation, Deck Cranes, Anchors, Wires, Chains, Mooring Winches, Riser Handling Crane, Mooring Winches

Note: Actual results may differ from forecasts.



Project Orion PROPOSALS COMPARISON

January 29, 2016*

*Presentation originally made on the date indicated and has not been updated to reflect recent developments or ongoing discussions. Moreover, in light of ongoing negotiations with Petrobras that involve the charter and services agreements supporting these bonds, the content of this presentation is no longer relevant.


Proposal Comparison Summary

1

Company Proposal (January 7) Bondholder Proposal (January 22) Company Proposal (January 29)

2021 Notes 2022 Notes 2021 Notes 2022 Notes 2021 Notes 2022 Notes

Transaction Structure

> Offer to exchange both classes of notes for new notes with amended terms (as described below)

> Existing Notes will be exchanged for (i) New 2021, 2022 Secured Notes (respectively) and (ii) New Convertible Unsecured Notes (each as described below)

> Modify structure to cover opex and capex

> Eliminate LCs, reserve accounts, and exchange rate caps

> Offer to exchange both classes of notes for new notes with amended terms (as described below)

> All revenues (charter + services) to flow through the respective project structures

> Modify but do not collapse current structures, and enhance collateral package as described below

> Eliminate exchange rate caps and modify OpEx caps to allow structures to fund all expenses (i.e., OpEx + CapEx) up to levels TBD based on the Company’s business plan(1)

> Minimum participations: [95]%

> Same as Bondholder Proposal (January 22)

> Same

> Same

> Same

> Minimum participations: [TBD%]

Principal Balance of

Secured Note

> $883 million (75% of principal, remaining 25% converted to New Convertible Unsecured Notes)

> $1,327 million (65% of principal, remaining 35% converted to New Convertible Unsecured Notes)

> Starting balance of: $1,178mm(2) (no discount)

> Starting balance of: $2,041mm(2) (no discount)

> Same

> Same

Fixed Amortization

> $20 million per annum

> $25 million per annum, beginning the later of 1/1/2017 or ODN Tay IV re-charter date

> $25 million per annum

> $20 million per annum, beginning 1/1/2017

> Same > Same

(1) Additional due diligence and benchmarking of company’s OpEx and CapEx will be required. No further obligations from OOG beyond such levels. (2) Starting balances as of March 31, 2016 after accounting for scheduled amortization payments made in December 2015 and March 2016.


Proposal Comparison Summary (Cont’d)

2



Variable Amortization

and Cash Sweeps

> 60% of excess cash flow after interest and fixed amortization (“ECF”)(1) applied to variable amortization

> 40% of ECF provided to Odebrecht Oil & Gas (“ParentCo”) to allow it to remain a viable entity (the “ParentCo ECF Sweep”)

- 30% of such amount held in reserve released to OOG on pro rata basis for the amount of scheduled amortization of existing OOG debt that is reduced

- 70% of such amount is released to OOG to fund OOG debt cash interest payments

> ECF Sweep tested quarterly, subject to carryforward and carryback structuring

> 85% of ECF applied to variable amortization


> ParentCo ECF Sweep tested quarterly; not subject to carryforward or carryback structuring

> 60% of ECF applied to variable amortization



Drydock Accrual Reserve

> $0.75 million per quarter, subject to $10 million cap

> Allow usage on drydock expenses as well as other extraordinary capex items TBN

> $1.50 million per quarter, subject to $20 million cap


> $1.50 million per quarter

> $3.00 million per quarter

> $1.50 million per quarter with a release mechanism TBN


> $3.00 million per quarter with a release mechanism TBN


Interest Rate

> 7% cash interest (quarterly)



> 1% PIK interest (quarterly)


> 1% PIK interest (quarterly)


> 7% cash interest (quarterly). 100% PIK interest in Q2 – Q4 2016

(1) ECF is Unlevered Free Cash Flow less Cash Interest less Fixed Amortization less Drydock Accrual Reserve additions / (releases) less Sinking Fund Account additions / releases.



3



Maturity(1)

> No change (remains June 30, 2021)

> No change (remains October 1, 2022)

> No change (remains June 30, 2021)

> No change (remains October 1, 2022)


> However, maturity shall be extendable by 2 years for a structure provided that certain conditions precedent are met, including, without limitation, that there is (i) before closing, 95% participation in the exchange and (ii) after closing, no default, charter contract coverage at an agreeable rate for 2.5 years after the proposed extended maturity of a given structure, and other conditions to be agreed

> Same as Bondholder Proposal (January 22), subject to confirming exchange participation and mechanics for maturity extension

Reserve Accounts and L/Cs

> Removed / not renewed > Reserve accounts remain in place for benefit of new notes; residual cash remains in accounts at closing

> O&M L/Cs to be increased to provide 6-months of coverage. Debt service L/Cs to remain in place at current amounts (i.e. no reduction). ParentCo and Odebrecht S.A. to guarantee that L/Cs will remain in place and are renewed through full payment of new notes

> Reserve accounts and LCs removed / not renewed

> In addition to the Drydock reserve account, a new Sinking Fund Reserve Account will be funded from project level cash flow(2)

• 2022 Sinking Fund Account capped at $56.4 million

– Max annual reserve contribution capped at $18.8 million

• 2021 Sinking Fund Account capped at $21.4 million

– Max annual reserve contribution capped at $7.1 million

(1) Bondholder proposal condition precedent / Company proposal condition subsequent: ParentCo level debt facilities shall be restructured such that no ParentCo debt maturities shall occur within six months of the last maturity of new notes.

(2) Sinking Fund Reserve Account will be funded with any excess cash flow after interest expense, fixed amortization, and any additions/subtractions from the Drydock Reserve Account.



4

Company Proposal (January 7)

Bondholder Proposal (January 22) Company Proposal (January 29)

2021 Notes

2022 Notes

2021 Notes 2022 Notes 2021 Notes 2022 Notes

Security

> Security package on 2021 and 2022 Secured Notes remains consistent with existing collateral package except for the removal of the LCs and reserve accounts as noted above

> All cash outstanding at the assumed closing date shall remain within the respective structure

> All existing collateral remains in place. First priority lien on substantially all of the assets of the respective project entities enforceable in Brazil and offshore, including but not limited to the drilling rigs, cash collateral, interests in the charter and services agreements and accounts receivable; lien on equity in structures

> The drilling rigs include the ODN I, ODN II, ODN Tay IV, Norbe VI, Norbe VIII, and Norbe IX

> New collateral to be provided in favor of 2021 holders and 2022 holders:

> Lien on service revenues from the Maintenance and Service business (non-project)(1)

> First priority lien on 100% of the equity of OOG GmbH (or a new intermediate holdco to be determined)

> Corporate guarantee by Apicatus Holding GmbH in favor of 2021 holders and 2022 holders

> Contractual obligation of ParentCo (i) in favor of 2021 holders not to allow more debt to be incurred at 2022 project companies and (ii) in favor of 2022 holders not to allow more debt to be incurred at 2021 project companies, in each case in connection with refinancing or otherwise


> Same as Bondholder Proposal (January 22), except for removal of existing reserve accounts

> No new collateral other than new reserve accounts (Drydock RA and Sinking Fund RA)

> All Cash Flows to Parent will remain in escrow until certain conditions are met (please refer to “ParentCo Capital Structure and Debt Service Relief”)

(1) New collateral is subject to further due diligence and understanding of the value of this additional collateral.



5



ParentCo Capital

Structure and Debt Service Relief

> Not explicitly discussed > As a condition precedent to the restructuring of the 2021 notes and 2022 notes, the ParentCo level debt shall be restructured on terms and conditions satisfactory to the holders, which shall include, without limitation, the following:

> No ParentCo debt matures prior to 6 months after the latter to mature of the new 2021 notes or the new 2022 notes

> Acceptable and sustainable interest and other financial costs payment schedule

> Contribution of the ultimate parent company to the debt restructuring of the ParentCo, as capital contribution, guaranty of ParentCo obligations or other means satisfactory to the 2021 and 2022 holders

> Restructuring of the Corporate Debt is a Condition Subsequent

> 100% of the Cash Flow to Parent will be held in escrow and will be released on a pro rata basis, subject to ParentCo’s ability to defer scheduled amortization

> This Proposal shall not be interpreted as supported by Odebrecht S.A. (“ODB”)

• ODB‘s participation and/or support toward a restructuring of OOG, if obtained, depends on further negotiations and the overall evolution of the OOG restructuring



6

Company Proposal (January 7)

Bondholder Proposal (January 22) Company Proposal (January 29)

2021 Notes

2022 Notes

2021 Notes

2022 Notes 2021 Notes 2022 Notes

Petrobras Cancellations

> N/A > Proposal assumes no further cancellations beyond the ODN Tay IV and no material adverse developments in connection with Lava Jato

> Proposal assumes that ODN I, ODN II, and any other rig in the 2021 and 2022 structures will receive the contractual dayrate plus bonus (i.e. 100% of the contracted dayrate) if and when on idle at the direction of Petrobras


> N/A > N/A > N/A > Require any amounts recovered (whether sale proceeds or from Petrobras) with respect to the ODN Tay IV or any other vessel to amortize the notes secured by such vessel

> Limit ODN Tay IV expenses (as and to the extent agreed) to an aggregate of $[TBD] million in monthly layup costs. After this limit has been reached or [TBD] months have passed from the Petrobras termination (whichever comes earlier), if ODN Tay IV has not been re-contracted on terms contemplated by the projections or acceptable by the 2022 holders, any continuing expenses will have to be funded by ParentCo or there will be a reduction in the amount of cash that can be distributed to ParentCo. During such time, ParentCo shall have the option to purchase ODN Tay IV for a minimum price and such other terms satisfactory to the 2022 holders to be included in the definitive documents. In addition, the 2022 holders have the right to force a sale process at or after such time, on terms to be included in the definitive documents

> [Tay IV alternatives to be discussed]

Company Profile September 2015

Norbe IX

Management Presentation

January 2016*

Norbe IX Drillship


2

Agenda

OOG AT A GLANCE

OOG’s ASSETS

MARKET OVERVIEW

OOG SOURCES OF CAPITAL

3

Odebrecht Presence in the Oil & Gas Sector

Odebrecht’s track record in the Brazilian oil & gas services industry

Operations in the offshore segment

Growth opportunities Consolidation of the oilfield services capabilities

Increased exposure to the Oil and Gas sector

Disinvestment of all

shallow and mid water assets by the end of the

decade

1990’s 1970’s to 1980’s 2000’s 2011 - today

Start working in the offshore industry

First Brazilian company to provide offshore drilling services for

Petrobras.

Largest privately owned offshore oil

drilling and exploration fleet

in Brazil by the end of the 1980's, with 8

platforms

FPSO operations in the North Sea joint

venture with Maersk

Service operations in the Campos Basin

Incorporation of Odebrecht Oil & Gas

Contract for Norbe VI

Contracts for Norbe VIII and Norbe IX

2nd round of private placement - Partnership

with Gávea

Increasing drilling portfolio

2010

Contracts for ODN I

and ODN II

Norbe VIII / IX Project Bond

1st round of private

placement - Partnership with

Temasek

Contracts for ODN Delba III and ODN

TAY IV

Strengthening

position in

Production and

Subsea with

Cidade de Itajaí

(50%) and the 2

PLSVs together

with Technip

Contract for

operating 5

rigs to be

built in

Brazil, in

partnership

with Sete

Brasil

Operations of 3 third-party

deepwater rigs

ODN Tay

IV Project

Bond

retap and

Perpetual

Bond

EWT Libra

FPSO

contract

(OOG-TK)

ODN I&II and

Norbe VI

Project Bond

and contract to

operate the

PLSV Polar

Onyx with

Ceona

4

Drilling 80.2%

Production 11.9%

Subsea 3.9%

Maintenance 4.0%

Company Description

Odebrecht Oil & Gas (“OOG”) is the oil field services arm of the Odebrecht Group, one of the largest business conglomerates in Latin America

Created in 2006 to concentrate the oil field services activities of the group and provide integrated, customized solutions for the upstream oil industry

‒ Integrated solutions: project supervision, maintenance and offshore assets operations

‒ Operation and chartering of vessels and offshore drilling rigs ‒ Operation of production and exploration platforms

The Company already has long-term relationships with Petrobras, Conoco Phillips and is well-positioned to expand operations to deal with equally or even more attractive counterparties

1st UDW drilling player in Brazil and 6th worldwide

Shareholder Structure

13.6% 81.4% 5.0%

1 – Does not consolidate Cidade de Itajai, PLSVs and Sete Brasil Assets 2 – LTM EBITDA

Backlog Breakdown

Temasek (Aaa / AAA): Established in 1974, is a sovereign investment fund of the Government of Singapore, with US$ 167bn under management as of March 31, 2014.

Gávea Investimentos: Founded in 2003, is a Brazilian asset management firm co-owned by JP Morgan Asset Management, that manages equity, mutual and hedge funds. Currently has an equity portfolio of 18 companies in its private equity arm and R$ 17.1bn (approximately US$ 5.7bn) under management as of April 2015.

Total Backlog: US$ 10.1bn (as of June 30, 2015) *

Consolidated Financial Highlights1

US$ MM 2011 2012 2013 2014 Q2 14 Q2 15 1H 15

Income Statement

Net Revenue 371 691 988 1,187 297 296 581

Growth (%) n/a 86.48% 42.91% 20.14% n/a 0% 6%

EBITDA 80 273 475 505 116 160 307

EBITDA Margin (%) 21.6% 39.5% 48.1% 42.5% 39.1% 54.1% 52.8%

Net Income (2) (22) (34) (75) (12) 57 57

Net Margin (%) -0.5% -3.2% -3.4% -6.3% -4.0% 19.3% 9.8%

Balance Sheet

Total Assets 4,904 6,160 6,044 6,205 6,492 6,141 6,141

Total Fixed Assets 4,143 5,193 5,153 5,041 5,078 5,011 5,011

Cash 474 431 298 475 742 364 364

Cash and Equivalents 462 390 212 331 690 148 148

Short-Term Investments

12 41 86 144 52 216 216

Total Debt 3,616 4,683 4,564 4,809 5,048 4,674 4,674

Shareholders' Equity 1,173 1,269 1,211 1,121 1,164 1,169 1,169

Consolidated Net Debt/ EBITDA

39.3x 15.6x 9.0x 8.6x 8.1x² 7.4x² 7.4x²

OOG at a glance

* Excluding ODN Tay IV

http://www.google.com.br/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&docid=qbaVh8HGJ0_buM&tbnid=ByzeKFFsmDgRUM:&ved=0CAUQjRw&url=http://www.odebrecht.com/en/businesses-and-interests/odebrecht-oil-and-gas&ei=5vhzUrKeLpLd4APi9oHwAw&bvm=bv.55819444,d.cWc&psig=AFQjCNH19WxhsInhBwV7VdYRNuor36h8iw&ust=1383418466544478

5

Chartering, operation of Pipe Laying Support Vessels; Subsea, Umbilical, Riser and Flowline projects; equipment manufacture and installation.

Chartering and operation of Floating Production, Storage and Offloading units.

Integrity Management Services, Inspection, Offshore Asset Installation, Maintenance and Engineering.

Chartering and drilling operations of ultra-deepwater rigs.

Integrated solutions for the Upstream Oil and Gas industry

Odebrecht Oil & Gas provides integrated solutions for the upstream oil industry in Brazil and around the world. Our history began in the 70s through Odebrecht’s Group experience. Today we are able to serve our customers throughout their entire business cycle, from engineering and design to the operation of offshore rigs, including new challenges in ultra-deepwater and pre-salt drilling. Our business segments are:

6

Fleet

ODN II*

ODN I*

ODN Delba III* ODN Tay IV

Norbe VIII* Norbe VI* Norbe IX*

FPSO North Sea Producer*

FPSO Cidade de Itajaí*

PLSV TOP Coral do Atlântico*

PLSV TOP Estrela do Mar*

Drilling – Composed of 100% ultra-deepwater rigs (Backlog: US$8.1bn) Production (Backlog: US$1.2bn)

Subsea (Backlog: US$0.4bn)

OOG is the Largest Offshore Brazilian Company in Oil Field Services

Associated investments totaling US$6 billion1

Ondina

Pituba Boipeba Interlagos Botinas

1 – Including Sete Brasil and FPSO Pioneiro de Libra EPC contracts values

* In operation ** Commercial Operation Date

COD**: Aug/2016

COD: Jun/2017 COD: Oct/2018 COD: Jun/2019 COD: Feb/2020

FPSO Pioneiro de Libra

COD: Dec/2016

Currently evaluating redeployment alternatives

7

Agenda

OOG AT A GLANCE

OOG’s ASSETS

MARKET OVERVIEW


Drilling Charter & Operation of Deepwater rigs with

state of the art assets

Norbe VI

9 * In operation. 1 As of Oct 2015 2 Day rate at bid date (Oct/11) 3December 11th onwards

Vessel Type

Water

Depth (ft)

Operational

in

Contract

Period

Contractor/

Day Rate 1

Shipyard

Ownership

Drilling Fleet of Latest Technology Vessels

Norbe

VI*

ODN

Tay IV*

ODN Delba

III*

Norbe

VIII*

Norbe

IX*

ODN

I*

ODN

II*

Semi-sub Semi-sub Semi-sub Drillship Drillship Drillship Drillship

7,874 7,874 7,874 10,000 10,000 10,000 10,000

3Q2011 1Q2013 3Q2012 3Q2011 4Q2011 3Q2012 3Q2012

7 years 7 years 10 years 10 years 10 years 10 years

PBR/317 PBR/336 PBR/410 PBR/385 PBR/360 PBR/360

GPC/SBM Astican /

Keppel Fels GPC/SBM DSME DSME DSME DSME

100% Owned 100%

Owned(3) 47% Owned 100% Owned 100% Owned 60% Owned 60% Owned

Ondina

Drillship

10,000

3Q2016

15 years

PBR/5402

Enseada

15% Owned

Pituba

Drillship

10,000

2Q2017

15 years

PBR/5402

Enseada

15% Owned

Boipeba

Drillship

10,000

4Q2018

15 years

PBR/5412

Enseada

15% Owned

Interlagos

Drillship

10,000

2Q2019

15 years

PBR/5412

Enseada

15% Owned

Botinas

Semi-sub

10,000

1Q2020

15 years

PBR/5342

Enseada

15% Owned

Note: Sete assets reflect the original configuration of the project, which is now being revisited

10

PB Contracts: Day Rates and Bonuses

As of Oct/15 Drilling Units

Rig Charter (US$ per

day) Services (BRL per day) Bonus

Uptime Threshold to

receive Bonus

Norbe VI 210,460 410,365 Up to 15% 90.15%

Norbe VIII 380,878 110,730 Up to 10% 93.01%

Norbe IX 357,836 104,031 Up to 10% 93.01%

ODN I 335,070 97,412 Up to 10% 93.01%

ODN II 335,070 97,412 Up to 10% 93.01%

ODN Tay IV 345,060 89,675 Up to 15% 90.15%

11

Norbe VI UDW Semi sub

Drilling capacity (water depth – m) 2,400

Year of Construction 2010

Tenor of Contract with Petrobras 7 years

Builder SBM

Operational Start up July 2011

12

Norbe VIII & IX UDW Drillships




Builder DSME

Operational Start up Aug-11/Nov-11

13

Rigs not originally awarded to OOG - ODNs

Delba Marítima, a Brazilian maritime service company, was awarded 6 rig contracts by Petrobras from 2006 to 2008. OOG acquired controlling ownership of four of these rigs. ODN I and II were acquired in 2010 and ODN Delba III and ODN Tay IV in 2011.

The rigs are operated by OOG.

OOG contributed with 100% of the equity portion for ODN I, II and IV and is in title of aprox. 100% of the economic interest on these 3 assets.

The operation fee related to the first seven-year Delba III contract was replaced for OOG’s initial participation in the project.

Delba will pay the loan related to their equity contribution with dividends.

14

ODN I & II UDW Drillships




Builder DSME

Operational Start up Sep-12 / Aug-12

15

ODN Delba III UDW Semi sub

Currently drilling at Búzios Field, Santos Basin Drilling capacity (water depth – m) 2,400



Builder SBM

Operational Start up August 2012

16

ODN Tay IV UDW Semi sub


Year of Upgrade 2012

Builder Keppel Fels

Operational Start up March 2013

17

• Failure to comply with or improper compliance with contractual clauses, specs or timeframes;

• Interruption of the Charter without cause or prior communication to Petrobras;

• Total or partial assignment or subcontracting of the Charter Agreement without prior consent, as well as partnership, merger, split-off, split-up, total, or partial takeover of the Project Company without prior notification of Petrobras;

• Repeated flawed performance, provided that the aggregate value of fines has reached 10% of the Agreement value;

• Declaration of bankruptcy, dissolution or alteration of the corporate structure or modification of the corporate purpose, which according to Petrobras, adversely affects the performance of the charter;

• Failure by the Operator to present adequate assurances to Petrobras, at Petrobras discretion, after approval of the Operator judicial or extrajudicial reorganization;

• Suspension of the Charter determined by the competent authorities to have been caused by the Project Company, which will be liable for any increase in costs resulting therefrom and for losses and damages that Petrobras incurs in consequence thereof;

• Delay in the beginning of the Charter period for more than 365 days;

• Termination of the Services Agreement;

• If the time for which Petrobras is exempt from Charter payments due to performance incidents amounts to a total of 30% of any 6-month period;

• If the Project Company remains under the repair rate for an aggregate period of 30% of any 6-month period;

• Shutdown of operations for over 60 days, for reasons imputable to the Project Company, except in the case of shutdown due to fortuitous or force majeure cases.

• Delay of payments due by Petrobras exceeding 90 days, except in the case of public calamity, serious public disturbance or war;

• Non-clearance by Petrobras of the location for the performance of the Charter; and

• Termination of the Services Agreement.

Termination by Odebrecht Oil &

Gas

PB Contracts: Termination Provisions

Termination by Petrobras

18

Key Facts:

– OOG has 15% of the charter contracts and 100%

of the service contracts for 5 rigs (which will

represent an equity contribution of approximately

US$150 million over the next 7 years) to be

delivered from 2016 to 2020

– Service contracts are Cost Plus

– Petrobras has 9,36% of SETE Brasil (4,36%

indirectly)

– More than US$80bn in backlog with 15 year

contracts

– Deliveries of the 29 vessels: from 2015 to 2020

– Local content: 55% to 65%

– Project being restructured for going concern

purposes

Source: Sete Brasil.

DRILLSHIPS

Company Operator # of

Units Yard Location

Sete Brasil

Etesco/OAS 5 Rio Grande (3) /

Enseada (2)

Rio Grande do

Sul / Bahia

Odebrecht 4 Enseada Bahia

Seadrill 3 Jurong Espírito Santo

Odfjell/Galvão

Engenharia 3 Jurong Espírito Santo

Petrobras 6 Atlântico Sul (EAS) Pernambuco

1 Jurong Espírito Santo

SEMISUBMERSIBLES

Company Operator # of

Units Yard Location

Sete Brasil

Queiroz

Galvão 3

Brasfels Rio de Janeiro Petroserv 2

Odebrecht 1

Sete Brasil


http://www.setebr.com/index.php

19

Ondina Drilling BV Drillship COD: Aug/2016

85%

15%

100%

Pituba Drilling BV Drillship COD: Jun/2017

Boipeba Drilling BV Drillship COD: Oct/2018

Interlagos Drilling BV Drillship COD: Jun/2019

Botinas Drilling BV Semi-sub COD: Feb/2020

Sete Brasil


http://www.setebr.com/index.php

http://www.petrobras.com.br/pt/

http://www.petrobras.com.br/pt/

Subsea Installation of subsea infrastructure

21

PLSVs TOP Coral do Atlântico & TOP Estrela do Mar

Operating capacity (water depth – m) 3,000

Laying Tower Tension Capacity 550t

Year of Construction 2014 / 2014

Tenor of Contract with Petrobras 5 + 5 years

Builder DSME

Operational Start up Oct-14 / Dec-14

TOP Coral do Atlantico: Started operations on October 19, 2014 TOP Estrela do Mar: Started operations on December 3, 2014

Production Charter & Operation of Production Vessels

FPSO Cidade de Itajai

23

Operates in the Bauna e Piracaba Field, Santos Basin

Production capacity (bpd) 80,000

Storage capacity 650,000

Year of Conversion 2012

Tenor of Contract with Petrobras 9 + 6x 1 years

Shipyard Jurong

Operational Start up Feb/13

24

Agenda

OOG AT A GLANCE

OOG’s ASSETS

MARKET OVERVIEW


25

Petrobras 2015-2019 Business Plan

Source: Petrobras Business Plan 2015-2019.

Petrobras’ Strategic Plan for 2015-2019 comprises total investments of US$130.3 billion

Divestments of US$57.7bn (US$15.1bn in 205-2016 and US$42.6bn in 2017-2018)

Increased focus on E&P spending; 83% of the plan is E&P, versus 70% in the previous years as the largest cuts are in non-upstream areas

Of the US$108.6bn to be invested in E&P, 82% is for production development and 10% is for exploration

On Oct 5, 2015 Petrobras announced a US$11bn capex cut in 2015 (US$3bn) and 2016 (US$8bn), but it is not clear in which areas

2015 – 2019 Budget Split (US$ billion, %) Petrobras 5-year plan budgets over time (US$ billion)

CAGR 10%

Source: Petrobras Business Plan 2012/2016.

$108.60bn, 83%

$12.80bn, 10%

$6.30bn, 5%

$2.60bn, 2%

E&P & Intl

Downstream & Distribution

Gas & Energy

Other Areas$54.0bn

$87.0bn

$112.0bn

$174.0bn

$224.0bn $225.0bn

$236.5bn $236.7bn

$220.6bn

$130.3bn

26 Sources: Pareto Securities Equity Research.

Older deepwater and midwater rigs are being taken out of the market

Rig count in Brazil down from 80 to 41 (in operation), from the peak in 2012

Brazil rig market is now 20% of the global demand, from above 30% in 2012

Brazil Rig Count – June 2015

Brazil Rig Count (in Operation)

27

Worldwide 2014/15 Fixtures – UDW Rigs

Contract Length (Months)*

Da

y R

ate

s (

US

D k

/d

ay)

Sources: DNB Markets, Rigzone, company data.

* For contracts determined in number of wells, it was assumed an average of 3 months per well.

Prior to the oil cycle down turn, companies would engage in backlog for day rate, exchanging higher rates and shorter contracts for lower rates and longer contracts

With the down turn, drillers seem to agree with low day rates and short contracts so as to keep the rig working until the market recovers

RIG: Transocean

SDRL: Seadrill

ESV: Ensco

ORIG: Ocean Rig

NE: Noble

DO: Diamond

ODL: Odfjell

QGOG: Queiroz Galvao

NE

RIG

RIG

ESV

ODL

NE

ODL ORIG

DO

NE

Grupo R

SDRL

DO

DO

DO

RIG

ORIG

RIG

QGOG

200

250

300

350

400

450

500

550

600

650

0 5 10 15 20 25 30 35 40 45

28

Trend line shows the trade-off between shorter contracts with higher rates vs. longer contracts with lower day rates

Water depth ranges from 6,600ft to 12,000ft (UDW rigs)

Contract start dates range from Feb/2010 to Aug/2015

Contract length ranges from 1 to 10 years

Da

y R

ate

s (

US

D k

/d

ay)

Contract Ending Dates

Petrobras UDW Day Rates in Brazil (≥6,600ft)

Excluding Victoria 10000 and Carolina drillships

0

100

200

300

400

500

600

700

2014 2016 2017 2019 2020 2021 2023

Others

OOG

Linear (Others)

Linear (OOG)

Short term / high cost

Long term / low cost

Sources: Rigzone, Seadrill / Transocean / Noble / Diamond Offshore public data.

29

Fixture date Owner Off taker

Day rate (USD 000s) Tenor Units

Water depth (k ft)

Oct 15 Noble Talos 206 2-mo Danny Adkins 12

Jun15 Transocean Exxon/ENI 395/300 3-mo

ext/45d

Deepwater Champion (‘10)/Sedco Express

(‘00) 10/6.6

Jun15 Noble Deep Gulf

Energy 317 2-mo ext

Dany Adkins (‘99/upgd. ‘09)

12

Jun15 Ensco Total 585 1-yr ext Ensco DS-7 (‘13) 10

Jun15 Odfjell Statoil 301.4 13 wells Deepsea Atlantic (‘09) 10

May15 Transocean Lukoil 315 100-day

ext GSF Development

Driller II (‘05) 7.5

May15 Odfjell VietGazprom 255 140 days Deepsea Metro I (‘11) 10

May05 Ocean Rig Vitol Energy 295 1 well Olympia (‘11) 10

May15 Diamond Apache 350 1.5yr Ocean Monarch (‘74/upgd. ‘08)

10

Apr15 Grupo R Pemex 365/365 1-yr ext/1-

yr ext Bicentenario

(‘10)/Centenario (‘10) 10/10

Fixed Contract Fixed Contract Extension at Mutually Agreed Price

Sources: DNB Markets, Rigzone, company data.

OOG Day Rates Still Below PBR Average

OOG Average Daily Rates for Drilling Units: US$ 361.2k/day

Current Day Rate

(US$ 000s)* 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

Norbe VI $316.8

ODN Delba III $335.5

Norbe VIII $409.6

Norbe IX $384.8

ODN I $360.3

ODN II $360.3

Recent Market Tenders

* Service Contracts translated to USD at R$3.8589 (October 30, 2015)

Fixture date Owner Off taker

Day rate (USD 000s) Tenor Units

Water depth (k ft)

Feb15 Seadrill Petrobras 500/500 3yrs W. Tellus (‘13)/W.

Carina (‘14) 12/12

Jan15 Noble Shell 456 1 well Bully II (‘11) 10

Oct14 Diamond Petrobras

567/455 3yrs Ocean Courage (‘09) 10

440/445 3yrs Ocean Valor (‘09) 10

310 3yrs Ocean Baroness

(‘73/’02) 6.5

(moored)

Oct14 Ocean Rig Petrobras 505/505 3yrs Corcovado

(’11)/Mykonos(‘11) 10/10

May14 Transocean Petrobras 440 3yrs Dhirubhai Deepwater

KG 1 (‘09) 12

May14 QGOG Petrobras 530 3yrs Brava Star (‘15) 12

30

Petrobras UDW Day Rates in Brazil (≥6,600ft)

Sources: Rigzone, Seadrill / Transocean / Noble / Diamond Offshore public data.

Rig Name Operator Water Depth (ft) Day Rate (US$/d) Contract Start Tenor (yr) Status

Vitoria 10000 Schahin 10,000 n/a 3/11/2011 10 - West Orion Seadrill 10,000 586,000 7/19/2010 6 - Brava Star Queiroz Galvao 12,000 545,303 8/15/2015 3 - Ocean Rig Corcovado Ocean Rig 10,000 502,283 5/15/2015 3 Renewed for 3 years at 502k/d Ocean Rig Mykonos Ocean Rig 10,000 502,283 3/22/2015 3 Renewed for 3 years at 502k/d West Tellus Seadrill 12,000 466,000 4/23/2015 3 - Gold Star QGOG Constellation 9,000 470,776 3/20/2015 3 - West Carina Seadrill 12,000 457,000 6/22/2015 3 - Ocean Courage Diamond Offshore 10,000 455,000 2/25/2015 3 Extended for 875 days at 380k/d, to start in late Feb 2016

Ocean Valor Diamond Offshore 10,000 455,000 1/9/2011 3 3-year extension (previous contract ended in Sep/15)

Carolina Petroserv 10,000 n/a 11/28/2011 10 - Petrobras 10000 Transocean 12,000 419,000 2/1/2011 8.5 - Etesco Takatsugu J Etesco 10,000 437,000 4/28/12 10 - Laguna Star QGOG Constellation 10,000 421,431 11/20/2012 6 - SSV Victoria Petroserv 10,000 473,000 2/17/2010 7 - Alpha Star QGOG Constellation 9,000 430,348 7/11/2011 6 - Amaralina Star QGOG Constellation 10,000 421,431 9/19/2012 6 - Dhirubhai Deepwater KG1 Transocean 12,000 397,000 12/31/2014 3 - Sevan Driller Seadrill 10,000 411,000 5/21/2010 6 - Norbe VIII Odebrecht 10,000 409,600 8/02/2011 10 - Sevan Brasil Seadrill 10,000 383,000 7/24/2012 6 - Norbe IX Odebrecht 10,000 384,800 11/03/2011 10 - ODN I Odebrecht 10,000 360,300 9/13/2012 10 - ODN II Odebrecht 10,000 360,300 8/28/2012 10 - Deepwater Navigator Transocean 7,200 361,000 5/1/2011 5 - Lone Star QGOG Constellation 7,900 382,461 3/31/2011 7 - Paragon DPDS3 Paragon Offshore 7,200 347,000 12/4/2013 4 - ODN Delba III Odebrecht 8,000 335,500 8/10/2012 7 - Norbe VI Odebrecht 8,000 316,800 7/25/2011 7.7 - Aban Abraham Etesco 6,600 261,774 6/8/2011 5 - Noble Dave Beard Noble 10,000 235,000 3/18/2015 1.1 Renewed for 1.1 year at 235k/d

31 Sources: Companies’ reports

Rig Name Water Depth (ft) October 2014 October 2015

Ocean Courage 10,000

Contract extended from Feb 2015 to Feb 2018 Day rate reduced from USD 567k to USD 455k

(starting in Oct 2015)

Contract extended from Feb 2018 to Jul 2020 Day rate reduced from USD 455k to USD 380k

(starting in Feb 2018)

Ocean Alliance 5,300 No adjustments

Contract early terminated in Oct 2015 Original date: Jun 2016 Day rate: USD 367k

Ocean Clipper 8,000 No adjustments Contract early terminated in Oct 2015

Original date: Dec 2015 Day rate: USD 312.6k

Rig Name Water Depth (ft) November 2015

Sedco 706 6,500 Contract extended from Sep 2016 to Sep 2018 Day rate reduced from USD 277k to USD 275k

Deepwater Navigator 7,200

Contract to be early terminated in Dec 2015 Original date: Feb 2016 Day rate: USD 361k

Transocean Driller 3,000

Contract to be early terminated in Jun 2016 Original date: Jul 2016 Day rate: USD 256k

Diamond Offshore

Transocean

Recent renegotiations / terminations of contracts in Brazil

32

Agenda

OOG AT A GLANCE

OOG’s ASSETS


33

Project Finance Project Bond Project Finance Restructuring

Project Bond

Amount

Average life @ issuance

Cidade de Itajaí*

ODN I & II and Norbe VI

ODN Tay IV ODN Delba III

US$1.69 bn

• Coupon: 6.75%

6.9

US$593 m

• Original:US$488 m

• Additional: US$105 m

9.8

Syndicate of 11 banks and of the Inter-American Development Bank (IDB)

6.5

B2 Moody’s B+ Fitch B+ S&P

US$300 m

6.4

Club deal of 6 banks

Maturity Oct 2022 Dec 2018 Oct 2022 Nov 2021

Structured Finance

Project Finance

PLSVs*

7.5

Mar 2020 / Mar 2027

Syndicate of 8 banks

US$546 m

• Banks: US$438 m

• ECAs: US$108 m

B2 Moody’s B+ Fitch B+ S&P

* For 100% of the project

US$580 m

• Coupon: 6.625%

Cross collateralized

Outstanding in June/15

Project Bond

Norbe VIII & Norbe IX

US$1.5 bn

• Coupon: 6.35%

8.0

B2 Moody’s BB- Fitch

Jun 2021

US$1.230 bn US$1.553 bn US$ 550 m US$494 m US$239 m US$528 m

Project Finance

Libra*

Club deal of 7 banks

US$804 m

-

Mar 2027

7.2

34

Norbe VIII & IX – Project Bond

Key Terms Contracts with Petrobras Summary

• The charter and services contracts have a 10-year tenor, with an option to be extended by another 10-years. Current contract expires in July 2021 for Norbe VIII and October 2021 for Norbe IX.

• The contract daily rate is denominated 90% in USD and 10% in BRL.

Financing Security Package

• First priority lien on drillships

• Assignment of cash flows from Charter and Service Agreements, insurance proceeds

• Pledge of receivables accounts and shares

• Insurances

• Debt Service Coverage Ratio 1.10x for two consecutive semesters or 1.20x for four consecutive semesters.

• 3-month O&M Reserve Account.

• 6-month Debt Service Reserve account

• Balloon retention account starting in June 2018

Issuer: Odebrecht Drilling Norbe VIII/IX Ltd.

Guarantors: Odebrecht Drilling Norbe VIII LLC and Odebrecht Drilling Norbe IX LLC

Ownership: 100% OOG

Original Amount:

USD 1,500 MM

Outstanding balance:

USD 1,275 MM

Maturity: June 2021

Coupon: 6.35%

Debt Service: Semi-annual (Jun, Dec)

Balloon: 30.0% Gross / 16.2% Net

35

Cash Waterfall Structure – 21s

6th

Monthly Onshore Proceeds

Account

O&M Monthly

Expense Amount

Offshore Proceeds

Account

(Charterer)

3rd

Brazil

Offshore

Opex Payment

(OOSL)

Services Reserve Account

(3-month Opex)

Debt Service Reserve Account

(6-month Debt Service)

Offshore Retention Account

Distribution Account

4th

5th

7th

1st (Priority)

Monthly

Note Debt Service Account

(Payment of Obligations)

2nd

Offshore Mobilization

Fee Account

20%

(aprox.

US$12MM)

Monthly

Semi Annual

Charter Payments

Service Payments

Monthly

Pre-completion Charter Operation Debt Amortization Structure

36

CAP OPEX 21’s

Semester Reference – NORBE VIII

Aug-11 to Jul-12 135

Aug-12 to Jan-14 120

Feb-14 to Jan-16 115

Feb-16 to Jun-21 110

Semester Reference – NORBE IX

Nov-11 to Oct-12 135

Nov-12 to Apr-14 120

May-14 to Apr-16 115

May-16 to Jun-21 110

37

ODN I & II, Norbe VI & Tay – Project Bond

Key Terms Financing Security Package

• First priority lien over the four assets of the guarantors

• Assignment of cash flows from charter and service agreements, insurance proceeds

• Pledge of receivables accounts and shares

• Insurances

• Debt Service Coverage Ratio of 1.10x for four consecutive quarters or 1.15x for eight consecutive quarters

• 3-month O&M Reserve Account

• 6-month Debt Service Reserve account (increased to 12 month under certain circumstances)

• Charter Termination Account starting in September 2016

• Balloon retention account starting in December 2018

Issuer: Odebrecht Offshore Drilling Finance Limited

Guarantors: ODN I GmbH, Odebrecht Drilling Norbe Six GmbH and ODN Tay IV GmbH

Ownership Norbe VI: ODN I&II: ODN Tay IV

100% OOG 60% OOG / 40% Delba 68,5% OOG / 31,5% Delba

Original Amount:

USD 1,690 MM issuance + US$580MM retap for ODN Tay


USD 2,073 MM

Maturity: October 2022

Coupon: 6.75%

Debt Service: Quarterly (Mar, Jun, Sep, Dec)

Balloon: 40.0% Gross / 20.0% Net

38

Cash Waterfall Structure – 22s

Monthly

Onshore Proceeds Account

Offshore Proceeds

Account

Petrobras (Charterer)

3rd

Brazil

Offshore

O&M Service Reserve Account

(3-month Opex)

Debt Service Reserve Account

(6-month Debt Service1) (jointly held)

Offshore Distribution

Holding Account

Offshore Distribution Account

4th

6th

1st (Priority)

Monthly

Note Debt Service Account

(Payment of Obligations) 2nd

Monthly

Quarterly

Charter Payments

Service Payments

Monthly

1st (Priority)

Not Pledged

Pledged, Guarantor Individual Account

Pledged, Guarantor Joint Account Pledged, Issuer Account

O&M Dollar Transfer Amount

OOG O&M Service Account

Payment of O&M Expenses

O&M Service Account

1.15x DSCR Threshold

Additional Reserve Accounts

- Offshore Retention Account - Offshore Charter Termination Account

5th

Offshore Sinking Fund Account

(US$ 30 MM established at issuance)

1- 12-month Debt Service in case of non renewal of the Norbe VI and/or ODN Tay VI

39

CAP OPEX 22’s

40

ODN Delba III – Project Finance

Key Terms Contracts with Petrobras Summary

• The charter and services contracts have a 7-year tenor, with an option to be extended by another 7-years. Current contract expires in August 2019.

• The contract daily rate is denominated 60% in USD and 40% in BRL.

Financing Security Package

• Customary for this type of Financing

Borrower: Delba Drilling International Cooperatie UA

Ownership1: 50.419% OOG / 1.316% Delba / 1.265% Interoil / 47% MPC

Amount: Original Facility: USD 488 MM Additional Facility: USD 112 MM


USD 479,9 MM

Tenor: 4y construction + 7y amortization

Maturity: Tranche A: Dec18 / Tranche B: Sep17

1. As of October 31, 2015

41

Working Capital

Revolving Credit Facility

Amount: US$ 200 Million

Maturity: 3 years (2017)

Financial Cost:

– Libor + 2.50% p.y. (first 18 months)

– Libor + 2.30% p.y. (last 18 months)

Obligor: OOG

Not disbursed

Participating Banks

http://www.google.com.br/imgres?imgurl=http://www.sinfaferj.org.br/images/Logo-Bradesco.gif?766&imgrefurl=http://www.sinfaferj.org.br/page_16.html&h=480&w=640&sz=11&tbnid=Z_7aqsjlw4K3MM:&tbnh=103&tbnw=137&prev=/search?q=bradesco+logo&tbm=isch&tbo=u&zoom=1&q=bradesco+logo&hl=pt-BR&usg=__nOOCIZxgsyinBIOffLLJer6RUJA=&sa=X&ei=cwDMTejFHcvogQe76IzkBQ&ved=0CCUQ9QEwAA

42

2016 debt matures in the 2nd semester of 2016 (USD 25 MM-Bradesco-Aug/2016 and USD 75 MM-BB-Dec/2016).

Corporate Debt Schedule

6

101

76

156

26 28 27 27

0

20

40

60

80

100

120

140

160

180

200

Short-Term 2016 2017 2018 2019 2020 2021 2022 ≥ 2023

US

D m

illi

on

Perpetual Bond Corporate Debt

550

43

144A / Reg S Senior Unsecured Notes Offering Structure

Perpetual with call option at year 10 and every 5 years thereafter Tenor

Reset every 10 years / Step-up of +50% of the initial spread if the bond is not rated IG by 2 agencies at year 10 Coupon Reset / Step-up

USD 400 million / June 10, 2014; USD 150 million / July 01, 2014 Issuance Amount / Date

Odebrecht Oil & Gas Finance Limited Issuer

Odebrecht Oleo e Gas S.A. Guarantor

7.000%, quarterly starting on Sep 17, 2014 Coupon

Perpetual Corporate Bond

Price / Yield 100.00 price at 7.000% yield for the USD 400 million / 103.00 price at 6.586% for the USD 150 million

Spread over 10Y-UST 436.5 bps for the USD 400 million / 402.78 bps for the USD 150 million

44

1st Round 2nd Round

85,7% 14,3%

– On October 22, 2010 Temasek Holdings

acquired a 14.3% ownership interest in

Odebrecht Oil & Gas through a private

placement investment of US$400 million

81,43% 13,57%

Two rounds of private equity in order to finance its growth

Strong and committed long term shareholders with a common goal to strengthen OOG’s position as a preferred service provider for the Upstream Oil & Gas Industry in Brazil

– On October 5, 2011 Gavea Investimentos

acquired a 5% ownership interest in

Odebrecht Oil & Gas through a private

placement investment of US$175 million

5,00%

Equity

http://www.gaveainvest.com.br/tabid/36/language/pt-BR/Default.aspx


Project Orion FINANCIAL FORECAST AND PROPOSAL MATERIALS

January 7, 2016*



I. Introduction

1


Preliminary Observations Challenges related to the cash flow, liquidity and credit of the Drilling Assets are driven by both the existing financing structure as well as the current underlying economics of the Drilling Assets.

> The current operating environment has negatively impacted the expected cash flows and long term value of the assets that secure the 2021 Notes and 2022 Notes (“Drilling Assets”)

‒ ODN Tay IV contract terminated by Petrobras and currently the asset is not producing cash flow

o Termination unexpected by OOG

o Determination of best alternative for ODN Tay IV still in process

o Petrobras aggressively targeting additional contracts in the market

‒ Re-chartering of Norbe VI in 2019 will likely result in lower day rates than originally anticipated

‒ The future value of the Drilling Assets expected to be well below what was originally anticipated at closing of bond offerings

‒ Higher opex than originally expected (specific to 2021 Notes’ assets)

‒ Currency moves have significantly impacted OOG’s funding requirements

> Projected cash flows from the Drilling Assets are expected to be lower than originally anticipated but are still forecast to cover all operating expenses, capital expenditures and interest expense on the 2021 Notes and 2022 Notes; however, cash flow is not sufficient to meet scheduled amortization payments

‒ At issuance, the structures were intended to receive little, if any, support from parent

‒ Over the last five years, OOG has invested more than $300mm in the Drilling Assets through capex and opex overage, net of all dividends received

o Such shortfalls were funded through debt at OOG

‒ Based on the Company’s business plan, operating expenses and capital expenditures will exceed the caps by ~$575 million and ~$425 million, respectively, through the respective maturities of the 2021 / 2022 Notes

‒ Based on current debt balances and estimated residual value of the Drilling Assets, OOG cannot continue funding capex and expected shortfalls in debt amortization payments

o OOG has limited obligation to provide ongoing financial support for the Drilling Assets

2


3

Proposal Development

> Amending the existing ‘21 and ‘ 22 Notes securitization structures will significantly improve the long-term viability of the Drilling Assets

‒ Amending the current financing structure would allow all disbursement requirements, including capex and opex above the current cap, to be borne by the revenues of the Drilling Assets

‒ Viability of the operator is crucial to both the ‘21 and ‘22 Notes

> OOG and its advisors developed a proposal to address the Drilling Assets liquidity and capital structure. The proposal takes into consideration the current operating environment and the Company’s view of asset values as well as concessions based on the feedback provided by Houlihan and Cleary

> The proposal developed by OOG and its advisors seeks:

‒ A sustainable debt structure for the Drilling Assets and ability to refinance at maturity

‒ Incentive for OOG to continue operating the assets

‒ Value to Noteholders in the form of both interest and amortization

‒ Flexibility to deal with uncertainty in re-chartering ODN Tay and renewing Norbe VI in 2019

‒ A viable operating company


II. Financial Forecast

4


Key Assumptions to Forecast

> Key assumptions in the operating forecast for the 2021 and 2022 Notes are:

5

Forecast Approach

> Each asset forecasted on an individual basis

> Presented as two separate consolidations of 2021 Note assets and 2022 Note assets

Daily Charter Rates

> Daily charter and service rate assumptions consistent with dayrates in chartering contracts

o Dayrates increase at contracted rates

> Tay IV assumed to be re-contracted in 2017 at expected/projected market rates

> Norbe VI re-contracted in 2019 at dayrates consistent with existing contracts and with internal projected market rates

Number of Days > Assets assumed to work 365 days a year, except for scheduled maintenance and

usual downtimes already reflected in uptime assumptions

Tax Rate > Actual onshore tax rate is 11.25%, with 22.45% levied on revenue but further

compensated with opex costs

Capex

> Forecasted capex includes special survey costs

> Cash available in drydock accrual reserve account assumed to release in years with special survey costs

Debt Service > Existing debt schedule


6

Changes in Operating Environment

Since the issuance of the 2021 and 2022 Notes, the operating environment for the Company’s assets securing the 2021 and 2022 Notes has changed. Additionally, certain targeted operating metrics have not yet been achieved.

Foreign Exchange

> Cash flow has been negatively impacted by the BRL / USD spot exchange rate moving from approximately 2:1 to 4:1

Operating Expenses and Capital Expenditures

> High demand for offshore drilling resources has impacted the following costs:

‒ Labor costs have increased above inflation from 2011-2015

o Mid 2015 was the only time that costs have started to decline given BRL devaluation

‒ Equipment suppliers have consistently increased their costs between 2011 and 2014

o Discounts being offered following the decline in the price of oil do not compensate for previous price increases

> The Macondo accident has raised a new standard API, inferring stricter maintenance rules related to well control equipment

‒ The demand for subsea parts and services has inflated the costs in the market

‒ With the new standard, Subsea now represents approximately 50% (before was 15%) of the maintenance costs of our rigs

‒ Most Subsea equipment parts are imported so Logistics costs associated with the new subsea standard also increased due to the taxes and freight associated with the imported parts

‒ Petrobras has been more strict on its requirements

> Disasters like the Macondo accident, the Chevron oil spill in Frade, and, more recently, the fire in Cidade de São Mateus FPSO have increased ANP inspections in relation to technical inspections

> Changes in REPETRO rules (imposed in December 2013) removed tax breaks for equipment with cost below US$25k, which also increased importation costs

> Change in taxation on income tax (IRRF) was not absorbed by Petrobras until now

Operational Metrics

> Operational uptimes have been less than original projected, particularly as it relates to ODN Tay IV

The projected continuation of the aforementioned factors will impact forecasted unlevered free cash flow materially


2016 2017 2018 2019 2020 2021

Services Revenue (R$ 000)

Daily Services Rate (Prior Period) $238 $259 $266 $276 $287 $330

Number of Days (Prior Period) 366 365 365 365 341 348

Uptime + Bonus (Prior Period) 96% 97% 100% 100% 99% 99%

Tax Rate (Prior Period) 22% 22% 22% 22% 22% 22%

Services Revenue (R$ 000) (1) $64,942 $71,055 $75,154 $78,008 $75,075 $88,244

Charter Revenue (US$ 000)

Daily Charter Rate (Prior Period) $741 $744 $735 $737 $742 $760

Number of Days (Prior Period) 366 365 365 365 341 348

Uptime + Bonus (Prior Period) 96% 97% 100% 100% 99% 99%

Charter Revenue (US$ in 000) (1) $260,080 $262,885 $267,514 $268,357 $250,199 $262,276

Revenue (in $US) $275,918 $279,231 $284,183 $285,246 $266,069 $280,494

Operating Expenses (103,635) (99,955) (103,765) (112,384) (105,537) (127,425)

Operating Cash Flow $172,283 $179,276 $180,418 $172,861 $160,532 $153,070

Cap Ex (26,148) (19,553) (7,743) (6,475) (74,348) (9,377)

Unlevered Free Cash Flow $146,135 $159,723 $172,675 $166,386 $86,184 $143,693

Interest Expense (73,104) (66,199) (58,579) (50,244) (40,958) (31,194)

Cash Flow After Interest $73,031 $93,524 $114,097 $116,142 $45,227 $112,499

Fixed Amortization (105,000) (120,000) (127,500) (142,500) (150,000) (165,000)

Cash to / (Required from) Parent ($31,969) ($26,476) ($13,403) ($26,358) ($104,773) ($52,501)

Memo:

Total Debt $1,072,500 $952,500 $825,000 $682,500 $532,500 $367,500

Debt / LTM EBITDA 6.2x 5.3x 4.6x 3.9x 3.3x 2.4x

Op Ex Funding

By Service Agreement $15,838 $16,345 $16,669 $16,889 $15,871 $18,218

By Charter Agreement 47,814 46,522 43,704 42,398 36,591 61,541

Structure Cap $63,652 $62,867 $60,373 $59,287 $52,462 $79,759

Op Ex Funded by Parent $39,983 $37,088 $43,391 $53,098 $53,075 $47,665

Cap Ex Funded by Parent 26,148 19,553 7,743 6,475 74,348 9,377

Total Funding by Parent $66,131 $56,641 $51,134 $59,573 $127,423 $57,042

Cumulative Funding by Parent $66,131 $122,772 $173,907 $233,480 $360,903 $417,945

2021 Bond – Status Quo Forecast

7 Note: For illustrative purposes, the analysis assumes that the 2021 Notes are refinanced beyond maturity date with similar terms. Additionally, the analysis shown does not account for the impact of any reserve accounts (e.g. the sinking fund). (1) The consolidated revenue is reduced for days for measurement at 90% daily rate, income tax, and any additional revenue/outflows.


2022 Bond – Status Quo Forecast

Note: For illustrative purposes, the analysis assumes that the 2022 Notes are refinanced beyond maturity date with similar terms. Additionally, the analysis shown does not account for the impact of any reserve accounts (e.g. the sinking fund). (1) The consolidated revenue is reduced for days for measurement at 90% daily rate, income tax, and any additional revenue/outflows.

8

2016 2017 2018 2019 2020 2021 2022

Services Revenue (R$ 000)

Daily Services Rate (Prior Period) $961 $997 $1,038 $1,238 $1,357 $1,411 $1,709

Number of Days (Prior Period) 366 365 363 358 365 365 343

Uptime + Bonus (Prior Period) 65% 95% 97% 97% 97% 97% 92%

Tax Rate (Prior Period) 22% 22% 22% 22% 22% 22% 22%

Services Revenue (R$ 000) (1) $178,444 $267,087 $283,645 $333,214 $372,166 $388,042 $415,799

Charter Revenue (US$ 000)

Daily Charter Rate (Prior Period) $1,290 $1,123 $1,093 $1,125 $1,131 $1,133 $1,289

Number of Days (Prior Period) 366 365 363 358 365 365 343

Uptime + Bonus (Prior Period) 65% 95% 97% 97% 97% 97% 92%

Charter Revenue (US$ in 000) (1) $308,908 $387,944 $384,971 $390,586 $399,894 $401,826 $404,391

Revenue (in $US) $352,423 $449,363 $447,885 $462,732 $478,573 $482,034 $488,372

Operating Expenses (170,991) (207,743) (196,318) (206,123) (221,743) (228,895) (211,650)

Operating Cash Flow $181,432 $241,620 $251,567 $256,608 $256,830 $253,138 $276,723

Cap Ex (27,373) (37,275) (35,219) (66,591) (16,205) (18,753) (99,543)

Unlevered Free Cash Flow $154,059 $204,345 $216,348 $190,017 $240,624 $234,385 $177,180

Interest Expense (134,047) (125,587) (116,813) (107,925) (95,884) (82,623) (57,951)

Cash Flow After Interest $20,012 $78,758 $99,535 $82,092 $144,740 $151,762 $119,229

Fixed Amortization (124,044) (130,282) (123,378) (164,639) (197,270) (206,895) (186,948)

Cash to / (Required from) Parent ($104,032) ($51,524) ($23,843) ($82,547) ($52,530) ($55,133) ($67,719)

Memo:

Total Debt $1,917,412 $1,787,130 $1,663,752 $1,499,113 $1,301,843 $1,094,948 $908,000

Debt / LTM EBITDA 10.6x 7.4x 6.6x 5.8x 5.1x 4.3x 3.3x

Op Ex Funding

By Service Agreement $43,515 $61,419 $62,914 $72,146 $78,679 $80,208 $83,981

By Charter Agreement 87,006 103,512 108,564 90,514 79,178 79,559 78,203

By Entity Transfers 18,819 4,383 – – – – 4,110

Structure Cap $149,340 $169,313 $171,478 $162,659 $157,857 $159,767 $166,294

Op Ex Funded by Parent $21,651 $38,430 $24,840 $43,464 $63,886 $69,128 $45,355

Cap Ex Funded by Parent 27,373 37,275 35,219 66,591 16,205 18,753 99,543

Total Funding by Parent $49,024 $75,705 $60,059 $110,056 $80,092 $87,882 $144,899

Cumulative Funding by Parent $49,024 $124,728 $184,787 $294,842 $374,934 $462,816 $607,714


IV.Legal Update

9


Overview of ODN Tay IV

> The ODN Tay IV Drilling Rig, one of the Vessels securing the Existing Notes, began operating in March 2013 under seven-year charter and services agreements with Petrobras (renewable for up to seven additional years upon mutual agreement of the parties)

> On May 16, 2015, the ODN Tay IV Drilling Rig entered into a planned maintenance dockage in order to change four thrusters

‒ At the direction of Petrobras, the Company invested ~$57 million to overhaul its engines

o Thruster repair: ~$16 million

o Engines and other costs: ~$41 million

‒ The scheduled maintenance was concluded on June 10, 2015

‒ While the rig was back in its location, Petrobras demanded that the rig be subject to a full acceptance test on the main engines

‒ After unsuccessful results on the engine tests, the rig was moved to the Brasfels shipyard in order to undergo a major overhaul of its 13 engines.

> On September 22, 2015, the Company received a letter from Petrobras exercising its alleged right to terminate both the ODN Tay IV Charter Agreement and Services Agreement effective as of such date.

10


Overview of ODN Tay IV (cont.)

> OOG believes that Petrobras had no legal grounds for termination in particular because:

a) Planned maintenance dockage was specifically carried out to change four thrusters

b) Engine performance tests were successfully conducted in March/April 2015

c) Petrobras required new tests and changed the criteria without adequate prior notice

d) Petrobras’ demands were met before the end of the defense period

> Historical economic uptimes for the ODN Tay IV vessel are as follows:

‒ 52% in 2013, 61% in 2014, 46% in 2015 through October (91% uptime from January through May)

> Currently the ODN Tay IV vessel is at the Açu Port, in Brazilian waters, with a reduced crew

> The Company is currently evaluating a range of alternatives for the vessel, including:

‒ Options to re-charter under a short-term contract in Brazil

‒ Options to re-charter under a longer-term contract in Africa

> For forecasting purposes, the ODN Tay IV vessel is assumed to be re-chartered at a market rate

11


Status of Lavo Jato/Petrobras Blacklist

> Mr. Marcelo Odebrecht, the former CEO of Odebrecht S.A., OOG’s parent company, and former chairman of the board of directors of OOG, as well as Mr. Marcio Faria and Mr. Rogerio Araújo, former members of the board of directors of OOG, have been arrested in June 2015 in connection with the Lava Jato investigations, and have been indicted in the Lava Jato investigation in relation to illicit payment made on behalf of other Odebrecht group entities, though not for OOG

> On December 29, 2014, OOG was provisionally blocked (bloqueio cautelar)(or blacklisted) by Petrobras, temporarily prohibiting OOG from bidding for and entering into new contracts with Petrobras

> Petrobras instituted a Committee to Analyze the Application of Sanctions (Comissão para Análise de Aplicação de Sanção), or CAASE, to assess whether certain companies mentioned in the Lava Jato investigations should remain blacklisted and assess potential sanctions

> The investigations by the CAASE were suspended as the Brazilian Federal General Comptroller (Controladoria Geral da Unidão), or CGU, commenced an administrative proceeding to investigate the allegations in order to determine whether any Odebrecht entity may have been a participant in any illicit payment scheme

> An adverse finding by CGU with respect to OOG could ultimately result in monetary fines to the government and restitution due to Petrobras (and OOG would continue on the blacklist)

> Petrobras may or may not remove OOG from the blacklist following a favorable finding by the CGU

> OOG believes that the CGU administrative proceeding will be concluded in the near term with a finding favorable to OOG, and that the CAASE investigation, once resumed, reaches the same conclusion leading to the reversion of the provisional block

Note: On March 8, 2016, Mr. Marcelo Odebrecht, Marcio Faria and Rogerio Araújo have been sentenced to prison for unlawful violations ranging from money laundering, criminal association and bribery. The sentences are subject to appeal. 12


Overview of OOG Obligations

> In addition to ~$1 billion of indebtedness, the OOG parent provides approximately $37 million of guarantees on various letters of credit (“LCs”) at project level entities (other than those related to the 2021 structure and 2022 structure)

‒ ~$102 million and ~$187 million of LCs are outstanding for ‘21s and ‘22s, respectively

> The banks issuing the letters of credit in relation to the ODN Tay IV Operation and Maintenance Reserve Account (in the amount of $12 million) and the ODN Tay IV Debt Service Reserve Account (in the amount of $36 million) have notified the Trustee that they will not renew such letters of credit that expire at the end of February 2016

> OOG has obligations under its other projects, including the Delba III drilling rig, the PLSVs and FPSO Libra

‒ Total obligations of $213 million in aggregate, which includes amounts for funding operating expenses of certain vessels, balloon payments of certain indebtedness and amounts required as base equity contributions for certain projects

13


V. Appendix

14


15

Overview of Vessel Contract Rates > Below are the contract rates utilized in the forecast. Rates are consistent with existing contracts.

(1) Contracted rate until March 2019. Re-contracted rate applies from March 2019 onwards. (2) Current contracted applies through August 2021.

Vessel Contract Rates

2022 Dri l l ing Assets 2016 2017 2018 2019 2020 2021 2022

Service Dayrate (R$ 000's)

ODN I $106 $114 $119 $123 $128 $133 $137

ODN II 106 114 119 123 128 133 137

Norbe VI

Currently Contracted(1)438 478 500

Re-contracted High 530 720 810 840 860

Re-contracted Low 400 550 620 640 660

ODN Tay IV

Re-contracted High – 270 310 320 340 350 420

Re-contracted Low – 210 240 250 260 270 320

Charter Dayrate (USD$ 000s)

ODN I $333 $332 $334 $335 $338 $339 $341

ODN II 333 332 334 335 338 339 341

Norbe VI

Currently Contracted(1)210 210 216

Re-contracted High 230 250 260 260 260

Re-contracted Low 170 190 200 200 200

ODN Tay IV

Re-contracted High – 200 210 210 210 220 250

Re-contracted Low – 150 160 160 160 170 190

2021 Dri l l ing Assets ( 2 )2016 2017 2018 2019 2020 2021 2022

Service Dayrate (R$ 000's)

Norbe VIII $122 $132 $138 $143 $149 $154

Norbe IX 114 123 128 133 138 143

Charter Dayrate (USD$ 000s)

Norbe VIII $381 $381 $384 $385 $388 $389

Norbe IX 358 358 361 362 364 365


Historical Opex by Rig

16

(USD$ 000s per Day)

2022 Assets 2011 2012 2013 2014 Nov15 Nov15 YTD

ODN I




Total N/A N/A $159 $161 $167 $153

ODN II




Total N/A N/A $145 $150 $139 $138

Norbe VI




Total N/A N/A $161 $163 $246 $171

2021 Assets

Norbe VIII

Personnel Costs $81 $87 $86 $85 $66 $67


Other Costs 28 52 53 52 26 28

Total $148 $179 $179 $231 $147 $149

Norbe IX

Personnel Costs $82 $85 $83 $79 $61 $69


Other Costs 29 50 50 39 22 29

Total $124 $173 $160 $153 $148 $143


Cost Reduction Initiatives > Labor Payroll

‒ Labor reduction per rig

‒ Continue the Full Time Equivalents “FTEs” control – related to double shift and resting days control

> Negotiations with the Union (ongoing measure)

> Crew Change

‒ Travel policy revision to only economic class tickets for all crew

‒ Optimize onshore logistics by using minivans and buses

> Repairs & Maintenance

‒ Reduce emergency flights per rig

> Material Logistics

‒ Optimize logistics of material supplies and equipment rentals in the Yard

> OpEx Reduction

‒ Reduce communication costs

> Onshore Base

‒ Target to reduce G&A by reducing number of employees in the onshore base

‒ Reduce price of rental equipment

‒ Unify offices in Macaé in a single building, thus further reducing rent

‒ Reduce service contracts with third parties (ex.: air cond., mobile phones, etc)

‒ Adjust Field Support structure

‒ Engagement of consulting company to analyze and propose optimization on G&A

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Documents

· Odebrecht Oil & Gas ILLUSTRATIVE COUNTERPROPOSAL FROM BONDHOLDERS MAR C H 2 4 , 2 0 1 6 | PR IVILEGED & CONFIDENT IAL | DRAF T | SUBJECT TO FRE 4 0 8 | FOR SET T LEMENT DISCUSSION