Exhibit 10.1

	DRILLING CONTRACT
	between
	VASTAR RESOURCES, INC.
	and
	R&B FALCON DRILLING CO.
	DATED DECEMBER 9, 1998
	for
	“RBS-8D”
	“Deepwater Horizon”
CONTRACT NO. 980249
	D-1-87.1
DISTRIBUTION:
Houston Legal Files - Signed Original
Houston Distribution (2)
Vern Buzard

DRILLING CONTRACT

RBS-8D

SEMISUBMERSIBLE DRILLING UNIT

VASTAR RESOURCES, INC.

AND

R&B FALCON DRILLNG CO.

CONTRACT NO. 980249 DATE: DECEMBER 9, 1998

TABLE OF CONTENTS

ARTICLE 1-	TERM	2
ARTICLE 2-	DAYRATES	4
ARTICLE 3-	PERSONNEL AND PAYMENTS	7
ARTICLE 4-	OTHER PAYMENTS	8
ARTICLE 5-	DRILLING UNIT MODIFICATIONS	9
ARTICLE 6-	OTHER REIMBURSEMENTS	9
ARTICLE 7-	MATERIALS, SUPPLIES, EQUIPMENT, AND SERVICES TO BE FURNISHED BY CONTRACTOR	10
ARTICLE 8-	MATERIALS, SUPPLIES, EQUIPMENT, AND SERVICES TO BE FURNISHED BY COMPANY	11
ARTICLE 9-	PAYMENTS	11
ARTICLE 10-	PAYMENT OF CLAIMS	12
ARTICLE 11-	TAXES AND FEES	13
ARTICLE 12-	COMPANY’S RIGHT TO QUESTION INVOICES AND AUDIT	14
ARTICLE 13-	DEPTH	14
ARTICLE 14-	DRILLING UNIT	14
ARTICLE 15-	PERFORMANCE OF DRILLING OPERATIONS	16
ARTICLE 16-	INSPECTION OF MATERIALS	18
ARTICLE 17-	SAFETY	18
ARTICLE 18-	PERFORMANCE OF THE WORK	19
ARTICLE 19-	RECORDS TO BE FURNISHED BY CONTRACTOR	21
ARTICLE 20-	INSURANCE	22
ARTICLE 21-	INDEMNITY FOR PERSONAL INJURY OR DEATH	22
ARTICLE 22-	RESPONSIBILITY FOR LOSS OF OR DAMAGE TO THE EQUIPMENT	22
ARTICLE 23-	LOSS OF HOLE OR RESERVOIR	24
ARTICLE 24-	POLLUTION	25
ARTICLE 25-	INDEMNITY OBLIGATION	26
ARTICLE 26-	LAWS, RULES, AND REGULATIONS	27
ARTICLE 27-	TERMINATION	28
ARTICLE 28-	FORCE MAJEURE	29
ARTICLE 29-	CONFIDENTIAL INFORMATION, LICENSE AND PATENT INDEMNITY	30
ARTICLE 30-	ASSIGNMENT OF CONTRACT	32
ARTICLE 31-	INGRESS AND EGRESS OF LOCATION	33
ARTICLE 32-	COMPANY POLICIES	33
ARTICLE 33-	NOTICES	34
ARTICLE 34-	CONSEQUENTIAL DAMAGES	35
ARTICLE 35-	WAIVERS AND ENTIRE CONTRACT	35

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TABLE OF CONTENTS (cont.)

EXHIBIT A:	Dayrates	Tab A
EXHIBIT B-1:	Drilling Unit Specifications	Tab B
EXHIBIT B-2:	Material Equipment List	Tab B
EXHIBIT B-3:	Consumable Material and Equipment List	Tab B
EXHIBIT C:	Insurance Requirements	Tab C
EXHIBIT D:	Safety,Health, and Environmental Management System	Tab D
EXHIBIT E:	Termination Payment Schedule	Tab E
EXHIBIT F-1:	Rig Manning	Tab F
EXHIBIT F-2:	Cost of Additional Personnel	Tab F
EXHIBIT G:	Vessel/Equipment Performance/Acceptance Test	Tab G
EXHIBIT H:	Project Execution Plan	Tab H

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DRILLING CONTRACT

THIS CONTRACT (“CONTRACT”) is made and entered into this 9th day of December, 1998, by and between Vastar Resources, Inc., a Delaware Corporation, hereinafter referred to as “COMPANY” and R&B Falcon Drilling Co., (“CONTRACTOR”), and shall be effective upon execution by both COMPANY and CONTRACTOR (the date when so effective, shall be referred to herein as the (“Effective Date”). COMPANY and CONTRACTOR are sometimes herein individually referred to as a “Party” and collectively referred to as the “Parties.”

RECITALS

Whereas CONTRACTOR shall cause to be built, a semisubmersible drilling unit, “Drilling Unit”. Whereas COMPANY desires to engage the services of CONTRACTOR, its Drilling Unit, and its equipment and all necessary crews for drilling, completing, testing, and remedial operations and support operations on a well or wells in the federal waters of the Gulf of Mexico, hereinafter referred to as “Operations” or “Work”.

Whereas this CONTRACT and the attached exhibits establishes the terms and conditions contained in this document entitled “DRILLING CONTRACT” and the attached exhibits:

Exhibit A:	Dayrates
Exhibit B-1:	Drilling Unit Specifications
Exhibit B-2:	Material Equipment List
Exhibit B-3:	Consumable Material and Equipment List
Exhibit C:	Insurance Requirements
Exhibit D:	Safety, Health, and Environmental Management System
Exhibit E:	Termination Payment Schedules
Exhibit F-1:	Rig Manning
Exhibit F-2:	Cost of Additional Personnel
Exhibit G:	Vessel/Equipment Performance/Acceptance Test
Exhibit H:	Project Execution Plan

NOW, THEREFORE, COMPANY and CONTRACTOR, for and in consideration of the mutual covenants and agreements contained herein and good and valuable consideration paid by COMPANY to CONTRACTOR, the receipt and sufficiency of which are acknowledged by CONTRACTOR, the Parties hereby agree as follows:

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ARTICLE 1

TERM

1.1EFFECTIVE DATE AND DURATION

1.1.1This CONTRACT shall remain in full force and effect for three (3) years (the “Initial Contract Term”). The Initial Contract Term shall begin on the Commencement Date. The term of this CONTRACT from its Effective Date through its Initial Contract Term and all Extension Periods shall be herein referred to as the “Contract Period.”

1.1.2With a three (3) year Initial Contract Term, COMPANY has the option (the “Extension Option”) to extend this CONTRACT for five (5) consecutive one (1) year periods (each such extension period shall be herein referred to as an “Extension Period”) beginning at the end of the Initial Contract Term. Each Extension Option must be exercised by COMPANY by written notice to CONTRACTOR nine (9) months before the end of the Initial Contract Term or the previous Extension Period, as the case may be. This CONTRACT, as it may have been amended as of the date on which COMPANY exercises any Extension Option, shall be extended for one (1) year with further Extension Options available to COMPANY, as provided herein and the various rates shall be mutually agreed in writing. COMPANY shall also have the option within twenty-four (24) months of the Effective Date to exercise any of the one-year options at the three (3) year rate. In addition, this CONTRACT may be extended for any additional period by any other method or manner as the Parties may mutually agree in writing.

1.1.3COMPANY has the option from the Effective Date up to and including one (1) year after the Commencement Date, to convert this CONTRACT to a five (5) year term (“5 Year Option”). If the 5-Year Option is exercised within six (6) months from the Effective Date, then the five (5) year rate in Exhibit A shall apply. If the 5 Year Option is exercised from six (6) months of the Effective Date to one (1) year from the Effective Date, then the five (5) year rate in Exhibit A plus five thousand dollars ($5,000.00) shall apply. If the 5 Year Option is exercised from one (1) year after the Effective Date to the Commencement Date, then the five (5) year rate in Exhibit A plus seven thousand five hundred dollars ($7,500.00) shall apply. If the option is exercised from the Commencement Date to the end of the first contract year, the five (5) year rate in Exhibit A plus ten thousand dollars ($10,000.00) shall apply from that date forward and any portion of the first contract year shall become part of the five (5) year commitment.

1.1.4If COMPANY exercises the 5 Year Option, then COMPANY has the option, (the “Extension Option”) under the five (5) year Initial Contract Term to extend this CONTRACT for three (3) consecutive one (1) year periods (each such extension period shall be herein referred to as an “Extension Period”) beginning at the end of the Initial Contract Term. Each Extension Option must be exercised by COMPANY by written notice to CONTRACTOR at least nine (9) months before the end of the Initial Contract Term or the previous Extension Period, as the case may be. This CONTRACT, as it may have been amended as of the date on which CONTRACTOR exercises any Extension Option, shall be extended for one (1) year with further Extension Options available to COMPANY as provided herein and the various rates shall be

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mutually agreed in writing. In addition, this CONTRACT may be extended for any additional period by any other method or as the Parties may mutually agree in writing.

1.1.5If the Initial Contract Term or any Extension Period of this CONTRACT expires while COMPANY has work in progress on any well or any other operations conducted with respect to a well with the objective of satisfying the well producibility criteria of 30 C.F.R. § 250.11 (1988), then COMPANY shall have the right to have the work in progress on such well or operation completed to COMPANY’S satisfaction under the terms and provisions of this CONTRACT and the term of this CONTRACT shall be deemed to be extended for the period of time required to complete such work.

1.2COMMENCEMENT DATE

“Commencement Date” means the date and hour that the last of the following conditions has been satisfied: (i) all requirements in Exhibit G and all governmental and regulatory certifications and inspections required of the CONTRACTOR have been obtained, (ii) CONTRACTOR’S full crew is aboard, (iii) the Drilling Unit has cleared customs and other formalities, (iv) the Drilling Unit and CONTRACTOR’S full crew is in all respects ready to commence and sustain continued drilling operations during the Contract Period and (v) the Drilling Unit has arrived at the COMPANY’S first location or an alternative location, if requested by COMPANY. The Parties shall cooperate in the loading of any COMPANY’S drilling equipment and materials to minimize any delay in the Commencement Date. In the event that, despite the Parties’ best efforts, the loading of COMPANY’S drilling equipment and materials cause a delay in the Commencement Date the CONTRACTOR shall be paid at the Standby and Moving Rate for any such delay. Notwithstanding the foregoing, however, COMPANY may require or allow the Drilling Unit to commence Work at an earlier date in which case such earlier date shall be the Commencement Date and in such event any of the above requirements for the Commencement Date which have not been satisfied shall be deemed satisfied.

The Parties agree that delivery of the Drilling Unit to the U.S. Gulf of Mexico is desired to occur twenty seven (27) months from the Effective Date, with COMPANY agreeing to take delivery as much as three (3) months sooner (“Delivery Date”).

If the Drilling Unit is not delivered to the Gulf of Mexico by thirty (30) months from the Effective Date, then COMPANY shall invoice CONTRACTOR every thirty (30) thirty days after the start of the late delivery charges a sum calculated at a rate of five thousand dollars ($5,000.00)per day during the first six (6) months of the late delivery and then at a rate of ten thousand dollars ($10,000.00) per day for each day until the Drilling Unit is delivered to the Gulf of Mexico with the total amount of such payment not to exceed one million five hundred thousand dollars ($1,500,000.00) for the late delivery of the Drilling Unit.

1.3COMPLETION OF CONTRACT

1.3.1Upon completion of this CONTRACT, if CONTRACTOR has no other Work for the Drilling Unit, COMPANY shall provide for tow, if required, of the Drilling Unit to, and securing

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in, the anchorage area at Galveston, Texas, or a mutually agreed point of no greater distance from its location of the last Work under this CONTRACT and at applicable dayrates.

1.3.2Subject to Article 27.4, upon completion of this CONTRACT, if CONTRACTOR has other Work for the Drilling Unit, COMPANY shall have no further responsibility hereunder when all of COMPANY’S equipment has been offloaded, the well secured, and the Drilling Unit is ready to get underway.

ARTICLE 2

DAYRATES

2.1GENERAL

COMPANY shall pay CONTRACTOR for work performed, services rendered, and materials, equipment, supplies, and personnel furnished by CONTRACTOR at the rates specified in Exhibit A. The period of time for which each rate shall be applicable shall be computed from and to the nearest half (1/2) hour. Subject to Article 2.3, the rates as specified in Exhibit A shall apply during the entire Initial Contract Term. The rates are based on CONTRACTOR’S operations being conducted on a seven (7) day week and a twenty-four (24) hour work day.

2.2DAYRATES

Each of the dayrate classifications is as follows:

2.2.1Moving Rate

a)From the moment operations are commenced to release the first mooring line or move the Drilling Unit off location at a drilling location and until the Drilling Unit is properly positioned at COMPANY’S next drilling location, and the Drilling Unit is ready to commence operations.

b)From the moment operations are commenced to release the first mooring line or move the Drilling Unit off location at COMPANY’S final drilling location hereunder until this Contract terminates.

2.2.2Operating Rate commences at the time of the Commencement Date, time the Drilling Unit is, properly positioned, anchors tested, if any, at drilling draft at the location to be drilled and the Drilling Unit is ready to commence operations and continues until CONTRACTOR has completed operations at the location and the Drilling Unit has been released by COMPANY to move to the next location pursuant to Article 2.2.1(a).

2.2.3Stand-by Rate with Crews applies while the Drilling Unit is on location with full crews waiting for COMPANY’S orders, and shall be payable during any period of time when CONTRACTOR’S crew is aboard the Drilling Unit and drilling, testing or completion operations hereunder are suspended, as a result of COMPANY’S instructions, COMPANY’S failure to issue

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instructions, the mechanical failure of COMPANY’S items, or the failure of COMPANY to timely provide COMPANY’S items or furnish those services set forth in Exhibit B-3.

2.2.4Stand-by Rate without Crews applies while the Drilling Unit is on location without crews. This rate shall commence seventy-two (72) hours after notification by COMPANY to CONTRACTOR to release crews.

2.2.5(a)Mechanical Downtime applies in the event operations during the term of this CONTRACT are shut down (“Mechanical Downtime”) for inspection, repair or replacement of any surface or subsurface equipment including, but not limited to CONTRACTOR’S items described in Exhibit B, including station keeping equipment, mooring equipment, anchors, chains, shackles, pendent lines, buoys, the riser, slip joint, choke and kill lines, flexible hoses, hydraulic hoses, guidelines, subsea BOP, and BOP control system. CONTRACTOR shall be allowed a maximum of twenty-four (24) hours per calendar month Mechanical Downtime with a maximum accumulation of twelve (12) days; thereafter the dayrate reduces to zero (0). Mechanical Downtime shall commence immediately upon suspension of well operations and shall continue until completion of the inspection, repair or replacement of the equipment and operations are at the point in well operations prior to suspension. If COMPANY elects to proceed with an alternative operation, then Mechanical Downtime shall cease at the point in well operations where the alternative operation commences. Article 2.2.5(a) shall not apply to the time required to repair or replace CONTRACTOR’S choke manifolds, blowout preventors, and drill string, if the damage or destruction to the equipment is caused by exposure to unusually corrosive or otherwise destructive elements not normally encountered which are introduced into the drilling fluid from subsurface formations or the use of corrosive additives in the fluid. Article 2.2.5(a) shall not apply to normal maintenance, including, without limitation, cutting and/or slipping the drill line, which time shall be limited to 1 hour plus up to thirty (30) minutes per day (fifteen (15) hours per month maximum) for top drive maintenance. Any mobilization and/or demobilization and associated cost required to repair the Drilling Unit under Article 2.2.5(a) will be at CONTRACTOR’S expense. CONTRACTOR shall not be entitled to any compensation for Mechanical Downtime allowance not consumed during this CONTRACT.

2.2.5(b)Performance Downtime applies in the event operations during the term of this CONTRACT are shut down (“Performance Downtime”) for the following reasons (i) CONTRACTOR, CONTRACTOR’S Personnel (as hereinafter defined), or the Drilling Unit should be incapable, incompetent, negligent, unreliable, or consistently poor in performance of the Work, (ii) the equipment listed in Exhibit B is incapable of being operated at the rated specifications in Exhibit B for sustained operation or (iii) CONTRACTOR fails to fulfill any of its obligations under this Contract. In the event of COMPANY’S dissatisfaction with any items identified in (i), (ii) and (iii), Performance Downtime shall commence when COMPANY provides CONTRACTOR with written notice as to the circumstances of its dissatisfaction and work in progress is suspended and shall continue based on the following remedies. If work in progress is suspended, then Article 2.2.5(a) shall apply. CONTRACTOR shall be allowed five (5) days, from the written notice, to commence good faith efforts to remedy such circumstances. During the remedy period, the Operating Rate shall be reduced to the Standby-rate Without

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Crews. In the event such circumstances are not remedied to COMPANY’S satisfaction within thirty (30) days, from the written notice, the Operating Rate shall be reduced to zero (0) dollars.

2.2.6Hurricane Evacuation Rate applies when all of the crews have been transported to shore. This rate shall include the cost of room and board for all of CONTRACTOR’S personnel including catering personnel and any other of CONTRACTOR’S subcontractor personnel. If COMPANY elects to release CONTRACTOR’S crew, then the Standby Rate Without Crew shall be applicable from the time CONTRACTOR is notified by COMPANY until the CONTRACTOR’S crew returns to the Drilling Unit.

2.2.7Stack Rate applies when the Drilling Unit has arrived and secured at the nearest safe harbor or stack location in the Gulf of Mexico as designated by CONTRACTOR. The Moving Rate shall apply immediately before the Stack Rate commences. The Stack Rate will continue until the unit is ready to get underway at which time the Moving Rate shall apply, or until the CONTRACT expires pursuant to Article 1.

2.3ADJUSTMENTS IN DAYRATES

2.3.1The dayrates set forth in Exhibit A shall remain unadjusted during the Initial Contract Term of this CONTRACT, except for rate changes as described in Article 2.3.2, Article 3, Article 4, Article 5,Article 6, and Article 30.3.

2.3.2The dayrates set forth in Exhibit A shall be revised to reflect the change in costs from the Effective Date if the costs of any of the items hereafter listed shall vary in an amount equal to or greater than five percent (5%) from the costs thereof not earlier than the Commencement Date and not more frequent than one (1) year after the date of any revision pursuant to this Article 2.3.2.

a.Labor costs, including all benefits, of CONTRACTOR’S personnel listed in Exhibit F;

b.CONTRACTOR’S cost of catering;

c.CONTRACTOR’S cost of spare parts and supplies vary and that the parties shall use the United States Department of Labor’s Producer Price Index Commodity Code No. 1191.02 - Oil Field and Gas Field Drilling Machinery - to determine what extent a price variance has occurred in said spare parts and supplies.

d.Cost of insurance not based solely on CONTRACTOR’S loss or claim record.

CONTRACTOR must show documented proof for any dayrate adjustments due to changes in CONTRACTOR’S cost of labor, insurance or catering. CONTRACTOR shall provide COMPANY with the base figures for the items specified in Article 2.3.2a.,b.,c., and d., thirty (30) days after the Effective Date. Base figures from which such revisions (either upward or downward) will be determined for the items in this Article 2.3.2 shall be provided by CONTRACTOR sixty (60) days prior to the estimated Commencement Date. These base figures

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shall be agreed upon by both parties and approved in writing by COMPANY prior to the Commencement Date.

2.3.3If, at the request of COMPANY, it becomes necessary for CONTRACTOR to change the work schedule of its personnel or change the location of its Homeport or area of operations, which impacts the CONTRACTOR’S actual cost, the daily rates set out in Appendix A shall be adjusted accordingly, with appropriate back up data.

2.3.4CONTRACTOR shall be responsible for costs and expenses incurred by CONTRACTOR in complying with any law, regulation, or ruling of a government, governmental agency, or regulatory authority having jurisdiction over the operations of the Drilling Unit to the extent that the law, regulation, or ruling has changed or been imposed subsequent to the Commencement Date. Where compliance with the changed law, regulation, or ruling results in modifications of the Drilling Unit or the purchase of equipment which change CONTRACTOR’S cost, the dayrates shall be adjusted with the additional direct cost and expenses amortized over the life of the Drilling Unit. The increased dayrates shall become effective upon completion of the modifications, and the Drilling Unit commences operations. CONTRACTOR shall be solely responsible for mobilization and demobilization and associated cost; during such time the dayrate shall be zero (0) dollars.

ARTICLE 3

PERSONNEL AND PAYMENTS

3.1PERSONNEL CLASSIFICATIONS, NUMBERS AND REPRESENTATION

3.1.1CONTRACTOR shall furnish, at its sole expense, personnel in the numbers and classifications as set forth in Exhibit F.

3.1.2During any period of time that CONTRACTOR fails to provide on the Drilling Unit the numbers or classifications of personnel specified in Exhibit F, the rate being paid the CONTRACTOR shall be reduced by the overtime hourly rate for the absent crew member(s) as specified in Exhibit F. This reduced rate shall commence on the second day of the crew shortage.

3.1.3The number of personnel to be furnished by CONTRACTOR under the terms hereof as specified in Exhibit F may be increased or decreased by mutual consent of COMPANY and CONTRACTOR, in which case the rates set forth in Article 2 shall be increased or decreased by an amount equal to the change in CONTRACTOR’S cost.

3.1.4CONTRACTOR represents that all of CONTRACTOR’S personnel shall be fully qualified, trained, competent, able bodied and fit for their respective assignments and shall have complied with all necessary laws and regulations in connection therewith. The minimum standard for qualification and training is set forth in Exhibit F. CONTRACTOR shall be able to communicate verbally and in writing by means of a common language at all times.

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3.2OVERTIME COMPENSATION

3.2.1COMPANY shall pay CONTRACTOR for overtime work of personnel employed by CONTRACTOR who are required to work in excess of their regularly scheduled hours, when requested by COMPANY, at the rates specified in Exhibit F.

3.2.2In the event the departure of the crews from the drilling site is delayed more than two (2) hours after the normal scheduled departure time due to delays in the transportation schedule which are not caused by the negligence or fault of CONTRACTOR, COMPANY shall pay CONTRACTOR for time in excess of two (2) hours at the hourly overtime rate for each employee as specified in Exhibit F.

3.2.3In the event that the time of transportation of crews between the Drilling Unit and the shorebase or between the shorebase and Drilling Unit is in excess of two (2) hours for each one-way trip, which are not the result of the negligence or other fault of CONTRACTOR, COMPANY shall pay CONTRACTOR for time in excess of two (2) hours for each trip at the hourly overtime rate for each employee as specified in Exhibit F.

ARTICLE 4

OTHER PAYMENTS

4.1CHANGE IN HOMEPORT OF OPERATIONS

The Homeport of operations for the Drilling Unit under this CONTRACTis any Gulf of Mexico port between and inclusive of Corpus Christi, TX and Pascagoula, MS.

4.2EXCESS MEALS AND LODGINGS

COMPANY shall pay CONTRACTOR for the cost of meals and lodging for COMPANY’S personnel and subcontractors (other than CONTRACTOR) that are in excess of ten (10) people per day calculated over a period of one (1) calendar month at CONTRACTOR’S actual cost.

4.3ANCHOR HANDLING AND TOWING VESSEL CHARGES

COMPANY shall pay all anchor handling and towing vessel charges if required, for movement of the Drilling Unit.

4.4OTHER CHARGES

COMPANY shall pay CONTRACTOR for other charges as per Article 6, Article 7, and Article 8.

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ARTICLE 5

DRILLING UNIT MODIFICATIONS

5.1PRE-COMMENCEMENT

Any modification to the Drilling Unit before the Commencement Date shall be pursuant to Exhibit H.

5.1.1POST-COMMENCEMENT DATE

Any modification to the Drilling Unit after the Commencement Date shall be as agreed in a separate written agreement. In the event the Drilling Unit is taken out of service or placed into shelter or harbor for COMPANY requested modifications, the rate that shall be payable per day, or pro rata for any part of a day during which such activity occurs shall be Standby Rate, which shall be payable for the period of time beginning when the Drilling Unit ceases operations to move off the drilling or well location until it moves back to location and commences full operations; provided, however, that if the Drilling Unit has changed locations, CONTRACTOR shall be credited at the Moving Rate for the time that would otherwise have been spent moving to the new location. In such case, the related modification costs and harbor expenses including, but not limited to, customs or other duties or imposts, harbor tugs if required, demurrage, wharfage, harbor and port fees and dues, landing, pilotage, lighterage, stevedoring, customs agent fees, anchor handling, any tow in and out, fuel, and canal charges, if applicable will be paid by COMPANY in a mutually agreed adjustment to the daily rates

ARTICLE 6

OTHER REIMBURSEMENTS

6.1LICENSES AND PERMITS

CONTRACTOR shall be responsible for all licenses, permits, or other authorization which are required to be obtained by CONTRACTOR subsequent to the Commencement Date. COMPANY agrees to reimburse CONTRACTOR for all cost associated with licenses, permits or other authorization which are required to be obtained by CONTRACTOR should COMPANY designate a location outside the federal waters of the Gulf of Mexico. COMPANY will obtain any required licenses, permits or authorizations which are required to be obtained by COMPANY.

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ARTICLE 7

MATERIALS, SUPPLIES, EQUIPMENT, AND SERVICES

TO BE FURNISHED BY CONTRACTOR

7.1MATERIALS, SUPPLIES, EQUIPMENT, & SERVICES

7.1.1CONTRACTOR shall furnish and maintain at its sole expense all items designated in Exhibit B under the heading FURNISHED BY CONTRACTOR. Any additional items not specifically mentioned elsewhere in this CONTRACT and found necessary to perform work shall be furnished by COMPANY at its sole expense.

7.1.2All items of equipment, materials, supplies, services, and service personnel required for operations hereunder that are to be FURNISHED BY CONTRACTOR as specified in Exhibit B may be furnished by COMPANY upon the mutual consent of COMPANY and CONTRACTOR and billed to CONTRACTOR at actual invoice cost less all cash discounts obtained by COMPANY plus a five (5) percent handling charge plus applicable taxes if taxes are applied to the cost reimbursement. A copy of invoice(s) for equipment, materials, supplies, services, and service personnel shall accompany COMPANY’S invoice to CONTRACTOR and must have the signature of CONTRACTOR’S representative for reimbursement to COMPANY.

7.1.3All items of equipment, materials, supplies, services, and service personnel required for operations hereunder that are to be FURNISHED BY CONTRACTOR AND REIMBURSED BY COMPANY as specified in Exhibit B are to be billed to COMPANY at actual invoice cost less all cash discounts obtained by CONTRACTOR plus a five (5) percent handling charge. A copy of invoice(s) for equipment, materials, supplies, services, and service personnel shall accompany CONTRACTOR’S invoice to COMPANY and must have the signature of COMPANY’S representative’s for reimbursement to CONTRACTOR.

7.1.4Any equipment, materials, or supplies purchased by COMPANY for the account of CONTRACTOR pursuant to Articles 7.1.2 and 7.1.3. above shall thereafter become the property of COMPANY unless agreed to by the Parties.

7.1.5CONTRACTOR shall provide at CONTRACTOR’S expense a drill pipe and drill collar inspection in accordance with API-IADC Standards prior to the Commencement Date. All of the drill pipe and drill collars shall be new. The costs of subsequent drill pipe and drill collar inspections during the term of this CONTRACT shall be borne by the COMPANY or CONTRACTOR as provided in Exhibit B.

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ARTICLE 8

MATERIALS, SUPPLIES, EQUIPMENT, AND SERVICES

TO BE FURNISHED BY COMPANY

8.1MATERIALS, SUPPLIES, EQUIPMENT, & SERVICES

8.1.1COMPANY shall furnish and maintain at its sole expense all items designated in Exhibit B hereof under the heading “FURNISHED BY VASTAR”.

8.1.2All items of equipment, materials, supplies, services, and service personnel required for operations hereunder that are to be “FURNISHED BY VASTAR” as specified in Exhibit B may be furnished by CONTRACTOR upon the mutual consent of COMPANY and CONTRACTOR and billed to COMPANY at actual invoice cost less all cash discounts obtained by CONTRACTOR plus a five (5) percent handling charge plus applicable tax gross up if taxes are applied to the cost reimbursement. A copy of invoice(s) for equipment, materials, supplies, services, and service personnel shall accompany CONTRACTOR’S invoice to COMPANY and must have COMPANY’S representative’s signature for reimbursement to CONTRACTOR.

8.1.3Any equipment, materials, or supplies purchased by CONTRACTOR for the account of COMPANY pursuant to Article 8.1.2 above shall thereafter become the property of COMPANY.

ARTICLE 9

PAYMENTS

9.1TIME OF PAYMENT

COMPANY shall make payments under this CONTRACT in U.S. currency in accordance with the terms of Article 2, Article 3, Article 4, Article 5,Article 6, Article 7, and Article 8 of this CONTRACT, on or before the last working day of the month following the receipt of a valid invoice form CONTRACTOR if received within five (5) calendar days after the month being invoiced If COMPANY receives an invoice after five (5) calendar days from the end of the month being invoiced then the payment will be due twenty (20) working days after receipt of the invoice. Thereafter, valid and undisputed amounts remaining due and unpaid shall earn simple interest at the rate of one and one-half percent (1 1/2%) per month. Should COMPANY question any item of an invoice, COMPANY may withhold payment of the amount in question, without interest, until the matter is resolved between the Parties, but COMPANY shall pay promptly the amount not in question. COMPANY shall have the right to set off any undisputed and liquidated amount payable by COMPANY to CONTRACTOR under this CONTRACT or under any instrument executed in connection herewith against any amount payable by CONTRACTOR to COMPANY under this CONTRACT.

9.2IDENTIFICATION OF CHARGES

All invoices must reference charges by block name and number and well number (e.g., Viosca Knoll Blk. 1001 No. 1). OCS numbers or state numbers are not acceptable references.

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9.3PLACE OF INVOICE PRESENTATION

Invoices, accompanied by copies of the original vouchers or such records, receipts, or other evidence as may be requested by COMPANY to support the invoices rendered, shall be sent to COMPANY’S office in Houston, Texas at the address below on or before the tenth (10th) of each month next succeeding the month during which the Work was performed or the expense incurred. The invoices to COMPANY should be directed as follows:

Vastar Resources, Inc.

P.O. Box 219275

Houston, TX 77218-9275

ATTN: DRILLING INVOICES

9.4PLACE OF PAYMENT

All payments shall be directed to CONTRACTOR as follows:

Wells Fargo Bank

1000 Louisiana

Houston, TX 77002

Account Number

ABA Number

SWIFT Number

ARTICLE 10

PAYMENT OF CLAIMS

10.1CLAIMS

CONTRACTORshall pay all claims for equipment, labor, materials, services, and supplies to be furnished by it hereunder and shall allow no lien or charge resulting from such claims to be fixed upon any well lease or other property of COMPANY. CONTRACTOR shall protect, release, defend, indemnify, and hold harmless COMPANY from and against all such claims and liens. COMPANY may, at its option, pay and discharge any (i) amounts secured by such liens or (ii) overdue charges for CONTRACTOR’S equipment, labor, materials, services, and supplies under this CONTRACT and may thereupon deduct the amount or amounts so paid by COMPANY from any sums due, or which thereafter become due, to CONTRACTOR hereunder.

10.2NOTICE OF CLAIMS

CONTRACTOR shall promptly give COMPANY notice in writing of any claim made or proceeding commenced against CONTRACTOR for which CONTRACTOR claims to be entitled to indemnification under this CONTRACT. CONTRACTOR shall confer with COMPANY concerning the defense of any such claim proceeding, shall permit COMPANY to be represented by counsel in defense thereof, and shall not effect settlement of, nor compromise, any such claim or proceeding without COMPANY’S written consent.

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COMPANY shall promptly give CONTRACTOR notice in writing of any claim made or proceeding commenced against COMPANY for which COMPANY claims to be entitled to indemnification under this CONTRACT. COMPANY shall confer with CONTRACTOR concerning the defense of any such claim proceeding, shall permit COMPANY to be represented by counsel in defense thereof, and shall not effect settlement of, nor compromise, any such claim or proceeding without CONTRACTOR’S written consent.

ARTICLE 11

TAXES AND FEES

11.1TAXES AND FEES ON DRILLING UNIT, CREW, AND OPERATIONS

CONTRACTOR shall be responsible for, pay, and protect, release, defend, indemnify and hold harmless COMPANY from all taxes, including, income taxes of whatsoever kind, and any addition, penalty, interest, or similar item imposed with respect to such taxes, levies, customs charges, duties, fees, or other charges of whatsoever kind without contribution or indemnity from COMPANY whatsoever which may be levied by any national, territorial possession, state, provincial, local, or municipal government, authority, or other agency having jurisdiction over the Operating Area on, in connection with, or related to the Drilling Unit, its crew, its equipment, and any and all materials, equipment, or operations in performance of this CONTRACT. Notwithstanding any other provision of this CONTRACT, COMPANY shall bear ultimate liability for any end user taxes such as, but not limited to, value added taxes and sales taxes imposed on COMPANY or which CONTRACTOR is required by law to collect. COMPANY and CONTRACTOR will make payments in accordance with the laws and regulations governing these taxes.

11.2PAYROLL TAXES

CONTRACTOR shall make all necessary reports and pay all taxes, licenses, and fees levied or assessed on CONTRACTOR in connection with or incident to the performance of this CONTRACT by any governmental agency having jurisdiction over the Operating Area for unemployment compensation insurance, old age benefits, social security, or any other taxes upon the wages or salaries paid by CONTRACTOR, its agents, employees, and representatives. CONTRACTOR shall require the same agreement of, and be liable for any breach of the agreement by, any of its subcontractors.

11.3TAXES PAID BY COMPANY

CONTRACTOR shall reimburse COMPANY on demand for all the taxes or governmental charges, state or federal, outlined in Articles 11.1 and 11.2, which COMPANY may be required or deems necessary to pay on account of CONTRACTOR or its employees or subcontractors. At its election, COMPANY is authorized to deduct all sums so paid for the taxes and governmental charges from any money due CONTRACTOR hereunder and provide official tax receipts within sixty (60) days.

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ARTICLE 12

COMPANY’S RIGHT TO QUESTION INVOICES AND AUDIT

12.1QUESTION INVOICES

Payment of any invoice shall not prejudice the right of COMPANY to question the propriety of any charges therein, provided that COMPANY, within four (4) years after the date of the invoice in question, shall deliver to CONTRACTOR written notice of objections to any item or items, the propriety of which it questions, specifying the reasons for the objections. Should COMPANY so notify CONTRACTOR, adjustments shall be made as the propriety or impropriety of the item may be mutually determined.

12.2AUDIT

CONTRACTOR shall maintain a complete and correct set of records pertaining to all aspects of this CONTRACT, including the performance hereof by CONTRACTOR. If any payment provided for hereunder is to be made on the basis of CONTRACTOR’S cost, COMPANY shall have the Drilling Unit to inspect and audit any and all records relating to the cost any time during the term of this CONTRACT and up to a period of four (4) years after the recorded date of the record in question, provided that CONTRACTOR shall have the right to exclude any trade secrets, formulas, or processes from the inspection and audit. Should the results of any audit so require, the Parties will make appropriate adjustments or payments.

ARTICLE 13

DEPTH

13.1DEPTH

The depth of each well to be drilled hereunder will be specified by COMPANY, which COMPANY may amend from time to time. The depth so specified is hereinafter referred to as the “Contract Depth”, subject to the right of COMPANY to direct, at any time, a stoppage of Work at a lesser depth.

ARTICLE 14

DRILLING UNIT

14.1REPRESENTATION OF DRILLING UNIT

The Drilling Unit shall be fully equipped as specified in Exhibit B and shall meet the requirements of Exhibit G, and shall be adequate to drill and complete wells in the Operating Area to the depths as specified in Article 14.2 hereof and in water depths as specified in Article l4.3. CONTRACTOR represents that the Drilling Unit satisfies all requirements of Articles 14.1.1, 14.4 and 14.6, and is capable of operating to its full capacity as rated by the

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manufacturer. CONTRACTOR shall maintain the Drilling Unit at optimal operating condition, in accordance with good oilfield practices throughout the duration of the CONTRACT.

14.1.1CONTRACTOR represents that (i) the Drilling Unit and related equipment shall be in a condition to permit its continuous and efficient operation during the Contract Period, subject to required periods of maintenance, repair, drydocking and inspection by regulatory bodies and classification societies, (ii) it will diligently perform the Work in a good workmanlike manner consistent with applicable industry standards and practices, (iii) it will use sound technical principles where applicable, (iv) it will perform the Work in compliance with this Contract, (v) it will furnish material and equipment in good condition to sufficiently meet the applicable CONTRACT requirements and good oilfield practices and (vi) where mutually agreed, it will furnish used material and equipment, fit for the intended use. CONTRACTOR shall bear any cost incurred in placing the Drilling Unit in a condition to function continuously and efficiently during the entire Contract Period. CONTRACTOR agrees to ensure that the Drilling Unit and all equipment and materials furnished by CONTRACTOR are adequately maintained and in such condition as to permit their continuous and efficient operation. CONTRACTOR shall appropriately protect and secure all COMPANY’S equipment and materials placed in its care. CONTRACTOR also agrees to carry out visual inspection on, and make available to COMPANY to test any of CONTRACTOR’S equipment in the manner prescribed by COMPANY.

Notwithstanding the foregoing, CONTRACTOR shall carry out, at CONTRACTOR’S expense, a full and detailed inspection of its drill pipe, drill collars, bottom hole assemblies and other down-hole and surface drilling equipment in accordance with Exhibit B prior to commencing the Work. COMPANY reserves the right to ensure that such inspection is carried out satisfactorily and, accordingly, shall have access to all related inspection reports. CONTRACTOR shall give COMPANY three weeks notice of inspection in order that COMPANY may have a third person witness the inspections to ensure they are carried out in accordance with Exhibit G.

14.1.2COMPANY shall have the right before the Commencement Date to inspect and reject for sound reasons any part of the Drilling Unit not meeting the requirements of this Contract; provided, however, such right shall not in any way relieve CONTRACTOR of its own obligations, including, without limitation, the obligation to inspect and maintain the Drilling Unit and related equipment in efficient operating condition. COMPANY shall have access and the right to review all commissioning, testing, and acceptance documents pertaining to the Drilling Unit. Unless waived by COMPANY, the Commencement Date shall not occur prior to the date on which CONTRACTOR has satisfactorily remedied any defect.

14.2MAXIMUM DRILLING DEPTH RATING

CONTRACTOR represents that the Drilling Unit is mechanically capable of drilling wells to the depth specified in Exhibit B-1.

14.3MAXIMUM WATER DEPTH RATING

CONTRACTOR represents that the Drilling Unit is mechanically capable of drilling wells in water depths and during environmental conditions, as specified in Exhibit B-I.

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14.4TECHNOLOGY

CONTRACTOR and COMPANY agree to explore the latest technologies, including riserless drilling, in an effort to incorporate same into the construction and operation of the Drilling Unit. CONTRACTOR shall make such technology available to COMPANY as soon as CONTRACTOR has the right to install and use such technology on its commercial drilling units, subject to any existing third party contracts as of the Commencement Date. Such installation shall be done pursuant to Article 5.

14.5APPLICABLE LAWS

Subject to Article 2.3.4, CONTRACTOR represents that during the Contract Period, the Drilling Unit is outfitted, conformed, and equipped to meet all applicable laws, rules, requirements, and regulations promulgated by the U.S. Coast Guard, the U.S. Environmental Protection Agency, the United States of America Department of the Interior as well as any other agency, bureau, or department of the U.S. federal, territorial possession, state, municipal, or local governments, any political subdivisions thereof, having jurisdiction over the operations in U. S. federal waters.

14.6SAFETY OF PORT

COMPANY does not and shall not be deemed to warrant the safety of any port, place, berth, dock, anchorage, location, or submarine line and shall be under no liability in respect thereof, except as specifically provided for under Article 31.

14.7OPERATING AREA

The Drilling Unit shall be capable of operating year around in the federal waters of the U. S. Gulf of Mexico. Additionally, the Drilling Unit will be designed to allow for operations in other areas of U. S. federal waters, offshore West Africa and the United Kingdom and other areas of the world, all subject to modifications and outfitting required by the controlling jurisdictions of each different operating area and to the operating limits set forth in Exhibit “G”.

ARTICLE 15

PERFORMANCE OF DRILLING OPERATIONS

15.1OPERATIONS OF DRILLING UNIT

CONTRACTOR shall be solely responsible for the operation of the Drilling Unit, including, without limitation, supervising moving operations, and the positioning of the Drilling Unit on drilling locations as required by COMPANY, as well as such operations on board the Drilling Unit as may be necessary or desirable for the safety of the Drilling Unit.

15.2PREVENTION OF FIRE AND BLOWOUTS

CONTRACTOR shall maintain well control equipment in accordance with good oilfield practices at all times and shall use all reasonable means to control and prevent fire and blowouts and to protect the hole and all other property of the COMPANY. CONTRACTOR shall use the blowout prevention equipment specified in Exhibit B hereof on all strings of casing unless otherwise directed by COMPANY. CONTRACTOR shall pressure test the blowout prevention

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devices as often as instructed by COMPANY, usually once every seven (7) days, and shall function test the blowout prevention devices by opening and closing to assure operating condition at each trip for a bit change. CONTRACTOR shall record the results of all the tests on the Daily Drilling Report Form defined in Section 19.1 hereof. CONTRACTOR shall use kelly sub protectors and drill pipe protectors. In any event, CONTRACTOR, at a minimum, shall use, test, and maintain blowout prevention equipment in accordance with all applicable governmental rules, regulations, and orders then in effect.

15.3 DEVIATION OF THE HOLE

CONTRACTOR shall use precaution in accordance with good oilfield practices in the Area of Operations, to drill a hole which will not deviate excessively from the limits specified by COMPANY. CONTRACTOR shall run angle and directional measuring devices acceptable to, and at the intervals directed by COMPANY. CONTRACTOR shall record the results of the deviation survey on the Daily Drilling Report Form.

15.4 DRILL PIPE MEASUREMENT

CONTRACTOR shall measure the total length of drill pipe in service with a steel tape before setting casing or liner, before logging, after reaching final depth, and whenever requested by COMPANY and shall promptly enter all the measurements on the Daily Drilling Report Form.

15.5 CASING PROGRAM

The casing program shall be as specified by COMPANY.

15.6 MUD PROGRAM

CONTRACTOR shall use all reasonable care to make and maintain drilling mud having weight, viscosity, water loss, and other characteristics to satisfy the requirements as specified by COMPANY. CONTRACTOR shall exercise due diligence to prevent the well from blowing out, and to enable the efficient drilling, logging, and testing of all formations without caving or formation contamination. While drilling, CONTRACTOR shall test drilling mud for weight, viscosity, water loss, and other necessary characteristics as instructed by COMPANY and shall record the results of the tests and the material volume usage on the Daily Drilling Report Form.

15.7COMPLETION OR ABANDONMENT OF WELLS

CONTRACTOR shall perform all work necessary to tube, equip, and complete or abandon each well in the manner specified by COMPANY.

15.8SAMPLES

CONTRACTOR shall save and preserve for COMPANY samples of formations penetrated, and properly prepare and label COMPANY’S containers. COMPANY shall designate the sampling frequency.

15.9CORING

CONTRACTOR shall core at the depths which COMPANY shall specify and shall deliver all cores in COMPANY’S containers, properly labeled, to COMPANY and shall not allow any third

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person access to the cores or to the samples referred to in Article 15.8, or to any core or sample data, without COMPANY’S consent.

15.10 FORMATION TESTS

If during the course of drilling CONTRACTOR encounters evidence of oil or gas, or other hydrocarbon substances, then CONTRACTOR shall immediately notify COMPANY, and should COMPANY desire a test to determine the productivity of any formation so encountered then, CONTRACTOR shall make such a test if it is feasible under existing conditions.

15.11 ANCHOR HANDLING AND TOWING

COMPANY shall supply any required anchor handling and towing vessels to move the Drilling Unit between locations.

ARTICLE 16

INSPECTION OF MATERIALS

16.1 INSPECTION BY CONTRACTOR

CONTRACTOR shall carefully perform a visual inspection of all materials and appliances furnished by COMPANY when delivered into CONTRACTOR’S possession and shall notify COMPANY’S representative of any apparent defects so that COMPANY may replace the defective materials or appliances. Upon the termination of this CONTRACT, CONTRACTOR shall return to COMPANY all materials and appliances received by CONTRACTOR from COMPANY or purchased by CONTRACTOR for COMPANY’S account then in CONTRACTOR’S possession.

16.2 INSPECTION BY COMPANY

Excluding the Drilling Unit and its major equipment, COMPANY shall have the right to inspect and reject, for any valid cause, any items furnished by CONTRACTOR in Exhibit B-3. CONTRACTOR at its sole cost, risk and expense shall replace and/or repair the rejected items, or replace them with items free of defects.

ARTICLE 17

SAFETY

17.1 GENERAL

CONTRACTOR shall have the primary responsibility for the safety of all its operations, shall take all measures necessary or proper to protect the personnel and facilities and, in addition, shall observe all safety rules and regulations of any governmental agency having jurisdiction over operations conducted hereunder. CONTRACTOR shall place the highest priority on safety while performing the work. CONTRACTOR shall also observe all of COMPANY’S safety rules and guidelines as set forth in “Safety and Health Manual” of Vastar Resources, Inc., and the requirements contained in Exhibit D. The CONTRACTOR may also have its own safety manual

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and when CONTRACTOR’S and COMPANY’S safety manuals conflict, CONTRACTOR’S safety manual shall control.

17.2 UNDER TOW

At all times during movement of the Drilling Unit between locations, CONTRACTOR shall have full responsibility for control of the Drilling Unit and shall have final authority regarding the safety and operation of the Drilling Unit, associated equipment, and personnel on board.

17.3 SAFETY EQUIPMENT

CONTRACTOR shall furnish any needed personal protection equipment that CONTRACTOR’S personnel may require in order to safely perform CONTRACTOR’S obligations under this CONTRACT.

17.4 EMERGENCY EVACUATION PLAN

The CONTRACTOR shall furnish COMPANY with information regarding the Emergency Evacuation Plan (“EEP”) for the CONTRACTOR’S Drilling Unit. The information supplied shall include station bills, a list of fire fighting equipment, list of emergency crafts onboard, and all other information required to describe the EEP in order to meet federal regulations in 46 C.F.R. 109 for MODU’s. The COMPANY shall submit as part of the COMPANY’S EEP, information and/or data as required by 33 C.F.R. 146.2 10.

ARTICLE 18

PERFORMANCE OF THE WORK

18.1 INDEPENDENT CONTRACTOR RELATIONSHIP

In performing the work set forth in this CONTRACT, CONTRACTOR shall act at all times as an independent contractor. Unless otherwise mutually agreed, CONTRACTOR shall not make any commitment or incur any charges or expense in the name of COMPANY. CONTRACTOR expressly agrees, acknowledges and stipulates that neither this CONTRACT nor the performance of CONTRACTOR’S obligations or duties hereunder shall ever result in CONTRACTOR, or anyone employed by CONTRACTOR, being i) an employee, agent, servant, or representative of COMPANY, or ii) entitled to any benefits from COMPANY, including without limitation, pension, profit sharing or accident, health, medical, life or disability insurance benefits or coverage, to which employees of COMPANY may be entitled. The sole and only compensation to which CONTRACTOR shall be entitled to under this CONTRACT are the payments provided for herein. COMPANY shall have no direction or control of CONTRACTOR or its employees and agents except in the results to be obtained. The actual performance and superintendence of all work hereunder shall be by CONTRACTOR, but the work shall meet the approval of COMPANY and be subject to the general right of inspection herein provided in order for COMPANY to secure the satisfactory completion of the work.

18.2 COMPANY’S REPRESENTATIVE

COMPANY shall be entitled to designate a representative(s), who shall at all times have complete access to the Drilling Unit for the purpose of observing or inspecting operations

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performed by CONTRACTOR in order to determine whether, in COMPANY’S sole opinion, CONTRACTOR has complied with the terms and conditions of this CONTRACT. The representative(s) shall be empowered to act for COMPANY in all matters relating to CONTRACTOR’S daily performance of the work. CONTRACTOR shall cooperate at all times with and render reasonable assistance to the representative(s) of COMPANY or representative(s) of any of COMPANY’S other contractor(s).

18.3 DISCIPLINE

CONTRACTOR shall maintain at all times strict discipline and good order among its employees. Should COMPANY determine, for just cause, that the conduct of any of CONTRACTOR’S personnel is detrimental to COMPANY’S interest, COMPANY shall notify CONTRACTOR in writing of the reasons for requesting removal of such personnel and CONTRACTOR shall replace the personnel at CONTRACTOR’S expense.

18.4 TAKEOVER BY COMPANY

In the event that CONTRACTOR shall fail to take proper steps to supply properly skilled workmen or tools, machinery or appliances for the performance of the work on any well hereunder, or shall otherwise neglect or willfully discontinue or delay commencement of the work to be performed on any such well, for a period of five (5) consecutive days after notice by COMPANY, then COMPANY shall have the right, by giving CONTRACTOR notice of its intention to do so, to take possession of the well, and the supervision and control of the drilling equipment and tools, machinery and appliances of CONTRACTOR and drill the well to completion or otherwise complete the work on said well. CONTRACTOR shall continue to have custody of and be solely responsible for its Drilling Unit and the locating and maintaining of it, and COMPANY or its representatives shall have supervision and control of such facilities only to the extent of the drilling or other operations involved. Following any such taking of possession by COMPANY, whether COMPANY is successful or unsuccessful in completing the well, or restoring same to production, the actual incremental cost directly related to the assumed operations to COMPANY (with no allowance to CONTRACTOR, other than dayrate, for the use of its drilling equipment and tools, machinery and appliances), shall be deducted from the applicable dayrate during such period and the balance, if any, paid to CONTRACTOR. COMPANY shall be liable for the return of such drilling equipment and tools, machinery and appliances to CONTRACTOR in as good condition as when received, natural wear and weathering, accidental loss or breakage excepted.

COMPANY SHALL INDEMNIFY, DEFEND AND HOLD CONTRACTOR HARMLESS FROM AND AGAINST ANY AND ALL LOSS, COST, CLAIM OR CAUSE OF ACTION ARISING DIRECTLY OR INDIRECTLY FROM COMPANY’S SUPERVISION OF CONTRACTOR’S DRILLING EQUIPMENT AND TOOLS DURING THAT PERIOD OF TIME IN WHICH COMPANY HAS TAKEN OVER SUPERVISION AND CONTROL OF CONTRACTOR’S DRILLING EQUIPMENT AND TOOLS. THE LIABILITY PROVISIONS HEREOF AND CONTRACTOR’S INDEMNITY OBLIGATIONS HEREUNDER SHALL REMAIN IN FULL FORCE AND EFFECT AS TO ANY AND ALL DAMAGE, LOSS, COST, CLAIM OR CAUSE OF ACTION

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ARISING DIRECTLY OR INDIRECTLY PRIOR TO COMPANY’S TAKEOVER OF CONTRACTOR’S DRILLING EQUIPMENT AND TOOLS OR AFTER SUCH DRILLING EQUIPMENT AND TOOLS ARE RETURNED TO THE POSSESSION OF CONTRACTOR. During such a takeover, COMPANY shall obtain insurance coverage with the same coverages as the insurance required to be carried by CONTRACTOR, naming CONTRACTOR and endorsed to waive subrogation.

18.5 CHANGE OF SUPERVISORY PERSONNEL

CONTRACTOR shall notify OPERATOR of any proposed change in supervisory personnel prior to the proposed change.

ARTICLE 19

RECORDS TO BE FURNISHED BY CONTRACTOR

19.1 DAILY DRILLING REPORTS

CONTRACTOR shall keep and furnish to COMPANY one (1) copy of the Daily Drilling Report Form showing the depth of the hole, formation penetrated, and any other data required by COMPANY or governmental authority. CONTRACTOR shall supply the report on the standard API-IADC Report Form. When CONTRACTOR prepares such form, it shall be referred to as the “Daily Drilling Report Form”.

19.2 ACCIDENT REPORTS

CONTRACTOR shall report to COMPANY, as soon as possible, all accidents or occurrences resulting in injuries to CONTRACTOR’S employees or to any third parties, as well as any damage to property of third persons, arising out of or during the course of operations of CONTRACTOR or its subcontractors. CONTRACTOR shall furnish COMPANY with a copy of all reports made by CONTRACTOR to its insurer or to others as requested by COMPANY of the accidents and occurrences.

19.3 DELIVERY TICKETS

CONTRACTOR shall furnish to COMPANY delivery tickets covering any materials or supplies furnished to CONTRACTOR by vendors for which COMPANY is obligated to reimburse CONTRACTOR. These shall be turned in to COMPANY’S representative as received with the Daily Drilling Report Form. The quantity, description, and condition of materials and supplies so furnished shall be verified and checked by CONTRACTOR. The delivery tickets shall be properly certified as to receipt by CONTRACTOR and must have COMPANY’S representative’s signature for reimbursement to CONTRACTOR.

19.4 LOGS

CONTRACTOR shall diligently maintain navigational logs, equipment maintenance, and testing logs, and such other logs and documentation designated by COMPANY. Any maintained log or documentation shall not create any additional burden on CONTRACTOR that is not already required elsewhere in this CONTRACT. CONTRACTOR shall provide a copy of any log upon COMPANY’S request.

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ARTICLE 20

INSURANCE

20.1 INSURANCE

Without limiting the indemnity obligation or liabilities of CONTRACTOR or its insurer, at all times during the term of this CONTRACT, CONTRACTOR shall maintain insurance covering the operations to be performed under this CONTRACT as set forth in Exhibit C.

ARTICLE 21

INDEMNITY FOR PERSONAL INJURY OR DEATH

21.1 CONTRACTOR’S PERSONNEL

CONTRACTOR SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS COMPANY FROM AND AGAINST ALL CLAIMS, DEMANDS AND CAUSES OF ACTION ASSERTED BY CONTRACTOR, CONTRACTOR’S SUBSIDIARIES AND AFFILIATED COMPANIES, CONTRACTORS OF ANY SUCH PARTIES, AND THEIR RESPECTIVE OFFICERS, DIRECTORS, AGENTS, INVITEES, EMPLOYEES AND ANY OF THEIR RELATIVES FOR PERSONAL INJURY (INCLUDING BODILY INJURY), ILLNESS, OR DEATH, THAT ARISE OUT OF OR ARE RELATED TO WORK PERFORMED HEREUNDER.

21.2 COMPANY’S PERSONNEL

COMPANY SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS CONTRACTOR FROM AND AGAINST ALL CLAIMS, DEMANDS AND CAUSES OF ACTION ASSERTED BY COMPANY, COMPANY’S SUBSIDIARIES, CO-OWNERS AND JOINT VENTURERS (IF ANY), CONTRACTORS OF ANY SUCH PARTIES (EXCEPT CONTRACTOR, AS SET FORTH IN ARTICLE 21.1 HEREOF), AND THEIR RESPECTIVE OFFICERS, DIRECTORS, AGENTS, INVITEES, EMPLOYEES AND ANY OF THEIR RELATIVES FOR PERSONAL INJURY (INCLUDING BODILY INJURY), ILLNESS, OR DEATH, THAT ARISE OUT OF OR ARE RELATED TO WORK PERFORMED HEREUNDER.

ARTICLE 22

RESPONSIBILITY FOR LOSS OF OR DAMAGE TO THE EQUIPMENT

22.1 CONTRACTOR’S DRILLING UNIT

EXCEPT AS SPECIFICALLY PROVIDED FOR IN ARTICLE 22.3, CONTRACTOR SHALL ASSUME ALL RISK OF LOSS OF OR DAMAGE TO AND SHALL PROTECT,

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RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS COMPANY FROM AND AGAINST ANY AND ALL CLAIMS FOR LOSS OF OR DAMAGE TO (INCLUDING SALVAGE OR REMOVAL COSTS) ITS DRILLING UNIT AND EQUIPMENT.

FOR PURPOSES OF THIS ARTICLE 22, ALL EQUIPMENT BELONGING TO CONTRACTOR’S PARENT, SUBSIDIARIES, AFFILIATES, SUBCONTRACTORS, PARTNERS, JOINT VENTURERS, EMPLOYEES, OR AGENTS SHALL BE CONSIDERED TO BE CONTRACTOR’S EQUIPMENT.

22.2 USE OF CONTRACTOR’S EQUIPMENT

COMPANY shall have unrestricted right to use all of CONTRACTOR’S equipment provided under this CONTRACT during such times as COMPANY or both COMPANY and CONTRACTOR are engaged in bringing a well being drilled under this CONTRACT under control, provided however, that such use, in CONTRACTOR’S sole opinion, does not endanger CONTRACTOR’S personnel or the Drilling Unit.

22.3 CONTRACTOR’S IN HOLE-EQUIPMENT

COMPANY SHALL ASSUME ALL RISK OF LOSS OF OR DAMAGE TO CONTRACTOR’S IN-HOLE, SUBSEA AND MOORING EQUIPMENT WHEN THE EQUIPMENT IS IN THE HOLE OR IN USE BELOW THE SURFACE OF THE WATER TO THE EXTENT CONTRACTOR’S INSURANCE DOES NOT COMPENSATE CONTRACTOR, REGARDLESS OF WHEN OR HOW THE DESTRUCTION OR DAMAGE OCCURS, UNLESS SAID LOSS OF OR DAMAGE IS A RESULT OF CONTRACTOR’S SOLE NEGLIGENCE, GROSS NEGLIGENCE OR WILLFUL MISCONDUCT, IN WHICH CASE CONTRACTOR IS SOLELY RESPONSIBLE FOR ALL LOSS OF OR DAMAGE. FOR PURPOSES OF THIS SECTION 22.3, ALL EQUIPMENT BELONGING TO CONTRACTOR’S SUBCONTRACTORS, PARTNERS, JOINT VENTURERS, EMPLOYEES, OR AGENTS SHALL BE CONSIDERED TO BE CONTRACTOR’S EQUIPMENT. COMPANY’S RESPONSIBILITY FOR LOSS OF CONTRACTOR’S INHOLE, SUBSEA AND MOORING EQUIPMENT IS LIMITED TO CONTRACTOR’S CIF REPLACEMENT COST LESS DEPRECIATION AT THE RATE OF THREE-FOURTHS OF ONE PERCENT (0.75%) PER MONTH OF USE UNDER THIS CONTRACT.

COMPANY SHALL ASSUME THE RISK OF LOSS FOR AND PROTECT, RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS CONTRACTOR FOR DAMAGE TO OR DESTRUCTION OF CONTRACTOR’S CHOKE MANIFOLDS, BLOWOUT PREVENTORS, AND DRILL STRING CAUSED BY EXPOSURE TO UNUSUALLY CORROSIVE OR OTHERWISE DESTRUCTIVE ELEMENTS NOT NORMALLY ENCOUNTERED WHICH ARE INTRODUCED INTO THE DRILLING FLUID FROM SUBSURFACE FORMATIONS OR THE USE OF CORROSIVE ADDITIVES IN THE FLUID, UNLESS SAID LOSS OF OR DAMAGE IS A RESULT OF CONTRACTOR’S NEGLIGENCE, GROSS NEGLIGENCE OR WILLFUL MISCONDUCT IN WHICH CASE CONTRACTOR IS SOLELY RESPONSIBLE FOR ALL LOSS OR DAMAGE.

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22.4 COMPANY’S EQUIPMENT

COMPANY SHALL ASSUME THE RISK OF LOSS FOR AND PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD HARMLESS CONTRACTOR FROM AND AGAINST ANY AND ALL CLAIMS FOR LOSS OF OR DAMAGE TO COMPANY’S EQUIPMENT AND PROPERTY. FOR THE PURPOSE OF THIS ARTICLE 22 ONLY, ALL EQUIPMENT AND PROPERTY BELONGING TO COMPANY’S PARENT, SUBSIDIARIES, AFFILIATES, CONTRACTORS (OTHER THAN CONTRACTOR) SUBCONTRACTORS, PARTNERS, JOINT VENTURERS, EMPLOYEES, OR AGENTS SHALL BE CONSIDERED TO BE COMPANY’S EQUIPMENT.

22.5 RESPONSIBILITY DURING MOBILIZATION FROM KOREA

CONTRACTOR SHALL ASSUME FULL RESPONSIBILITY FOR AND SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD HARMLESS COMPANY AND ITS’ JOINT OWNERS HARMLESS FROM AND AGAINST ANY LOSS, CLAIM, DAMAGE, FINE, PENALTY, DEMAND OR LIABILITY, FOR POLLUTION OR PROPERTY DAMAGE, WITHOUT MONETARY LIMITATIONS, MADE BY ANY ENTITY OR PERSON WHILE THE DRILLING UNIT IS MOBILIZING FROM KOREA TO THE GULF OF MEXICO PRIOR TO THE COMMENCMENT DATE.

ARTICLE 23

LOSS OF HOLE OR RESERVOIR

23.1 LOSS OR DAMAGE TO THE HOLE

SHOULD THE HOLE BE LOST OR DAMAGED, THE LOSS OR DAMAGE WILL BE BORNE BY COMPANY AND COMPANY SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD HARMLESS CONTRACTOR FROM AND AGAINST ALL CLAIMS FOR LOSS OF OR DAMAGE TO THE HOLE. NOTWITHSTANDING THE PREVIOUS SENTENCE, IF THE HOLE IS LOST OR DAMAGED DUE TO CONTRACTOR’S NEGLIGENCE, GROSS NEGLIGENCE, WILLFUL MISCONDUCT OR ITS AGENTS’, OR SUBCONTRACTORS OR THEIR FAILURE TO COMPLY WITH COMPANY’S INSTRUCTIONS, THEN AS CONTRACTOR’S SOLE LIABILITY, CONTRACTOR SHALL BE OBLIGATED AT COMPANY’S ELECTION TO REDRILL THE HOLE TO THE POINT AT WHICH THE HOLE WAS LOST AT EIGHTY PERCENT (80%) OF THE OPERATING RATE BUT OTHERWISE SUBJECT TO THIS DRILLING CONTRACT.

23.2 COST OF CONTROL OF BLOWOUT OR CRATER

IN THE EVENT ANY WELL BEING DRILLED HEREUNDER SHALL BLOWOUT, CRATER OR CONTROL BE LOST FROM ANY CAUSE, COMPANY SHALL BEAR THE ENTIRE COST AND EXPENSE OF KILLING THE WELL OR OF OTHERWISE BRINGING THE WELL UNDER CONTROL AND SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD HARMLESS CONTRACTOR FROM AND

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AGAINST ALL CLAIMS, SUITS, DEMANDS, AND CAUSES OF ACTION FOR COSTS ACTUALLY INCURRED IN CONTROLLING THE WELL.

23.3 UNDERGROUND DAMAGE

COMPANY SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD HARMLESS CONTRACTOR FOR ANY AND ALL CLAIMS ON ACCOUNT OF (I) INJURY TO, DESTRUCTION OF, LOSS, OR IMPAIRMENT OF ANY PROPERTY RIGHT IN OR TO OIL, GAS, OR OTHER MINERAL SUBSTANCES OR WATER, IF AT THE TIME OF THE ACT OR OMISSION CAUSING THE INJURY, DESTRUCTION, LOSS, OR IMPAIRMENT, THE SUBSTANCE HAD NOT BEEN REDUCED TO PHYSICAL POSSESSION ABOVE THE SURFACE OF THE EARTH, OR (II) ANY LOSS OR DAMAGE TO ANY FORMATION, STRATA, OR RESERVOIR BENEATH THE SURFACE OF THE EARTH.

ARTICLE 24

POLLUTION

24.1 CONTRACTOR RESPONSIBILITY

CONTRACTOR SHALL ASSUME FULL RESPONSIBILITY FOR AND SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD COMPANY AND ITS JOINT OWNERS HARMLESS FROM AND AGAINST ANY LOSS, DAMAGE, EXPENSE, CLAIM, FINE, PENALTY, DEMAND, OR LIABILITY FOR POLLUTION OR CONTAMINATION, INCLUDING CONTROL AND REMOVAL THEREOF, ORIGINATING ON OR ABOVE THE SURFACE OF THE LAND OR WATER, FROM SPILLS, LEAKS, OR DISCHARGES OF FUELS, LUBRICANTS, MOTOR OILS, PIPE DOPE, PAINTS, SOLVENTS, BALLAST, AIR EMISSIONS, BILGE SLUDGE, GARBAGE, OR ANY OTHER LIQUID OR SOLID WHATSOEVER IN POSSESSION AND CONTROL OF CONTRACTOR AND WITHOUT REGARD TO NEGLIGENCE OF ANY PARTY OR PARTIES AND SPECIFICALLY WITHOUT REGARD TO WHETHER THE SPILL, LEAK, OR DISCHARGE IS CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE OR OTHER FAULT OF COMPANY, ITS CONTRACTORS, (OTHER THAN CONTRACTOR) PARTNERS, JOINT VENTURERS, EMPLOYEES, OR AGENTS. IN ADDITION TO THE ABOVE, CONTRACTOR TO A LIMIT OF FIFTEEN MILLION DOLLARES (US$ 15,000,000.00) PER OCCURANCE, SHALL RELEASE INDEMNIFY AND DEFEND COMPANY FOR CLAIMS FOR LOSS OR DAMAGE TO THIRD PARTIES ARISING FROM POLLUTION IN ANY WAY CAUSED BY THE DRILLING UNIT WHILE IT IS OFF THE DRILLING LOCATION, WHILE UNDERWAY OR DURING DRIVE OFF OR DRIFT OFF FROM THE DRILLING LOCATION.

24.2 COMPANY RESPONSIBILITY

COMPANY SHALL ASSUME FULL RESPONSIBILITY FOR AND SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD CONTRACTOR HARMLESS FROM AND AGAINST ANY LOSS, DAMAGE, EXPENSE, CLAIM, FINE, PENALTY,

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DEMAND, OR LIABILITY FOR POLLUTION OR CONTAMINATION, INCLUDING CONTROL AND REMOVAL THEREOF, ARISING OUT OF OR CONNECTED WITH OPERATIONS UNDER THIS CONTRACT HEREUNDER AND NOT ASSUMED BY CONTRACTOR IN ARTICLE 24.1 ABOVE, WITHOUT REGARD FOR NEGLIGENCE OF ANY PARTY OR PARTIES AND SPECIFICALLY WITHOUT REGARD FOR WHETHER THE POLLUTION OR CONTAMINATION IS CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE OR FAULT OF CONTRACTOR.

24.3 CLEAN UP OPERATIONS

Initiation of clean up operations by either Party shall not be an admission or assumption of liability by such initiating Party or Parties.

ARTICLE 25

INDEMNITY OBLIGATION

25.1 INDEMNITY OBLIGATION

EXCEPT TO THE EXTENT ANY SUCH OBLIGATION IS SPECIFICALLY LIMITED TO CERTAIN CAUSES ELSEWHERE IN THIS CONTRACT, THE PARTIES INTEND AND AGREE THAT THE PHRASE “SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS” MEANS THAT THE INDEMNIFYING PARTY SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD HARMLESS THE INDEMNIFIED PARTY OR PARTIES FROM AND AGAINST ANY AND ALL CLAIMS, DEMANDS, CAUSES OF ACTION, DAMAGES, COSTS, EXPENSES (INCLUDING REASONABLE ATTORNEYS FEES), JUDGMENTS AND AWARDS OF ANY KIND OR CHARACTER, WITHOUT LIMIT AND WITHOUT REGARD TO THE CAUSE OR CAUSES THEREOF, INCLUDING PREEXISTING CONDITIONS, WHETHER SUCH CONDITIONS BE PATENT OR LATENT, THE UNSEAWORTHINESS OF ANY VESSEL OR VESSELS (INCLUDING THE DRILLING UNIT), BREACH OF REPRESENTATION OR WARRANTY, EXPRESSED OR IMPLIED, BREACH OF CONTRACT, STRICT LIABILITY, TORT, OR THE NEGLIGENCE OF ANY PERSON OR PERSONS, INCLUDING THAT OF THE INDEMNIFIED PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, ACTIVE, PASSIVE OR GROSS OR ANY OTHER THEORY OF LEGAL LIABILITY AND WITHOUT REGARD TO WHETHER THE CLAIM AGAINST THE INDEMNITEE IS THE RESULT OF AN INDEMNIFICATION AGREEMENT WITH A THIRD PARTY.

25.2 BENEFIT OF INDEMNITIES

TO THE EXTENT A PARTY IS ENTITLED TO INDEMNIFICATION IN ARTICLES 21, 22, 23, AND 24, SUCH PARTY’S PARENT, SUBSIDIARIES, AFFILIATES, CO-OWNERS AND JOINT VENTURERS (IF ANY), AND THEIR RESPECTIVE OFFICERS, DIRECTORS, AGENTS AND EMPLOYEES, THE DRILLING UNIT AND ITS LEGAL AND BENEFICAL OWNERS, IN REM OR IN PERSONAM SHALL ALSO BE ENTITLED TO SUCH INDEMNIFICATION AND DEFENSE THEREUNDER. ANY

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SUCH PERSON SO ENTITLED TO INDEMNIFICATION AND DEFENSE UNDER THIS ARTICLE 25.2 ARE HEREINAFTER REFERRED TO AS AN “EXTENDED BENEFICIARY OF INDEMNIFICATIONS.

25.3 Third Party Beneficiaries

Except as otherwise specifically agreed nothing in this Contract shall be construed or applied so as to permit any person or entity not a direct signatory party hereto (except for a successor or permitted assignee of such direct signatory party) to enforce or seek damages against either signatory party hereto for any breach of this Contract. The definition of CONTRACTOR and COMPANY herein shall not be construed to enable or entitle any person or entity other than the signatory parties hereto or a successor or permitted assignee of such a signatory party to directly sue or seek relief against the other signatory party hereto except to the extent that any Extended Beneficiary of Indemnification (as defined in Article 25.2) shall be expressly permitted to enforce such rights of indemnification against the indemnitor. Except for any EXTENDED BENEFICIARY OF INDEMNIFICATION, no persons or entities are intended to be or become third party beneficiaries of this contract.

ARTICLE 26

LAWS, RULES, AND REGULATIONS

26.1 LAWS, RULES AND REGULATIONS

CONTRACTOR and COMPANY shall comply with all governmental laws, rules, and regulations or orders which are now or hereafter shall become applicable to its operations covered by this CONTRACT or arising out of the performance of such operations.

26.2 EQUAL OPPORTUNITY CLAUSE

To the extent applicable and in connection with the performance of work under this CONTRACT, CONTRACTOR agrees to comply with the following Equal Employment Opportunity and/or Affirmative Action requirements and all other similar requirements as the same are enacted or become applicable to the CONTRACT: Section 202 of Executive Order 11246, as amended by Executive Order 11375, relating to equal employment opportunities, the implementing rules and regulations of the Secretary of Labor and all contract clauses and requirements which are applicable and set forth therein are incorporated herein by specific reference. In particular, CONTRACTOR hereby certifies that it does not maintain segregated facilities. In making this certification, CONTRACTOR incorporates each and all of the provisions of the approved form of certification contained in 41 C.F.R. Section 60-1.8(b) the same as if such provisions were fully set forth herein and signed by CONTRACTOR. Sections 503 and 504 of the Rehabilitation Act of 1973 and Title IV of the Vietnam Era Veterans Readjustment Assistance Act of 1974 relating to employment and advancement of employment of qualified handicapped individuals, disabled veterans and veterans of the Vietnam Era, the implementing rules and regulations of the Secretary of Labor and all contract clauses and requirements which are applicable and set forth therein are incorporated herein by specific reference pursuant to 41 C.F.R. Section 60-741.22 and 41 C.F.R. Section 60-250.22.

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26.3 CERTIFICATE OF FINANCIAL RESPONSIBILITY

COMPANY, in cooperation with the CONTRACTOR, shall obtain, at COMPANY’S expense, and maintain evidence of a Certificate of Financial Responsibility from the U.S. Coast Guard covering the Drilling Unit as required by 33 C.F.R. Part 135 and the Outer Continental Shelf Lands Act of 1978. COMPANY will file for the certificate before the well is spud and will coordinate the filing with COMPANY. A copy of filed certificate shall be furnished to CONTRACTOR prior to spud and CONTRACTOR must maintain a copy on the Drilling Unit.

ARTICLE 27

TERMINATION

27.1 TERMINATION BY COMPANY

27.1.1 COMPANY shall have the option to terminate this CONTRACT subject only to (i) payment of amounts earned by CONTRACTOR before termination, and demobilization of the Drilling Unit pursuant to Article 1.3 and (ii) payment of the Lump Sum set forth in Exhibit E. Terminating pursuant to Article 27.1.1 does not limit any other right of termination which COMPANY may have. The termination shall not affect any right or obligation which accrued prior to the termination.

27.1.2 In the event the shipyard where the Drilling Unit is being constructed fails or is unable to deliver the Drilling Unit within the time limits and operational specifications of its contract with CONTRACTOR such that CONTRACTOR has the ability to terminate the construction contract, CONTRACTOR shall so advise COMPANY in writing.

If COMPANY desires to accept the Drilling Unit with later delivery or reduced operational specifications, then COMPANY shall so notify CONTRACTOR within a reasonable time following COMPANY’S receipt of notice under this Article, and upon timely receipt of notice by CONTRACTOR, CONTRACTOR shall not terminate the construction contract and this CONTRACT shall be suitably amended to reflect the later delivery and the reduced operational specifications in Exhibit G, with all other terms and conditions remaining in full force and effect. If such later delivery or reduced operational specifications result in a claim by CONTRACTOR against the Drilling Unit constructor, any net savings to CONTRACTOR as a result of such claim shall be credited to COMPANY against CONTRACTOR’S invoices or remitted to COMPANY as COMPANY shall direct.

If COMPANY does not desire to accept the Drilling Unit with such later delivery or reduced operational specifications, then COMPANY shall so notify CONTRACTOR within a reasonable time following COMPANY’S receipt of notice under this Article, and upon timely receipt of such notice by CONTRACTOR, this CONTRACT shall terminate and COMPANY shall have no obligations under Exhibit E.

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27.2 TERMINATION BY CONTRACTOR

CONTRACTOR may cancel this CONTRACT for non-payment of its invoices for services under this CONTRACT, except for portions of the invoices which COMPANY may dispute in good faith. However, CONTRACTOR may cancel under this Article no sooner than one hundred and twenty (120) days after payment was due and only after giving ninety (90) days notice thereof, during which period COMPANY shall have the opportunity to correct the breach.

27.3 LOSS OF DRILLING UNIT

In the event of actual or constructive total loss of the Drilling Unit (as determined by CONTRACTOR’S underwriters), termination shall be immediate with neither CONTRACTOR nor CONTRACTOR’S underwriters having any recourse against COMPANY, or obligations pursuant to Exhibit E, except for CONTRACTOR’S claim to amounts CONTRACTOR earned up to the date of such loss. Contractor shall be responsible for any removal or salvage costs.

27.4 PROVISION AFTER EXPIRATION OF CONTRACT

Notwithstanding the termination of this CONTRACT, COMPANY and CONTRACTOR shall continue to be bound by the provisions of this CONTRACT that reasonably require some action or forbearance after the expiration of the term of this CONTRACT.

ARTICLE 28

FORCE MAJEURE

28.1 FORCE MAJEURE

The term Force Majeure as used in this Article 28 shall mean acts of God, adverse sea or weather conditions beyond the design operating perimeters of the Drilling Unit including wind, sea and current, earthquakes, flood, war, civil disturbances, strikes, lockouts or other industrial disturbances by persons other than employees of CONTRACTOR, governmentally imposed rules, regulations or moratoriums or any other cause whatsoever, whether similar or dissimilar to the causes herein enumerated, not within the reasonable control of either Party which, through the exercise of due diligence said party is unable to foresee or overcome. In no event shall the term Force Majeure include normal, reasonably foreseeable, or reasonably avoidable operational delays or strikes, lockouts or other industrial disturbances by employees of CONTRACTOR. In the event that either Party hereto is rendered unable, wholly or in part, by Force Majeure to carry out its obligations under this CONTRACT, it is agreed that such Party shall give notice and details of the Force Majeure in writing to the other Party as promptly as possible after its occurrence. In such cases, the obligations of the Party giving the notice shall be suspended during the continuance of any inability so caused, except that COMPANY shall be obligated to pay to CONTRACTOR the applicable Dayrates. Should a condition of Force Majeure continue for more than thirty (30) consecutive days, this CONTRACT may be immediately terminated at the option of COMPANY by delivering written notice thereof to CONTRACTOR.

Except for its obligation to make payments of monies hereunder, neither Party to this CONTRACT shall be considered in default in performance of such obligations hereunder to the

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extent that the performance of such obligations, or any of them is delayed or prevented by Force Majeure.

ARTICLE 29

CONFIDENTIAL INFORMATION, LICENSE AND PATENT INDEMNITY

29.1 CONFIDENTIAL INFORMATION

29.1.1 CONTRACTOR agrees to hold in confidence, and not disclose to any third party or use for any purpose other than performance of the work, all or any part of the well information (including the location and type of operations performed), logs, cores, core data, cuttings, maps, data, plans, reports, manuscripts, procedures, schedules, drawings, specifications, results, models, computer programs, or any product which is: a) received or ascertained by CONTRACTOR directly or indirectly from COMPANY, its licensors or other contractors; or b) otherwise acquired by CONTRACTOR, its employees, representatives, or subcontractors in connection with, as a result of, or incident to performance of the work (“INFORMATION”). CONTRACTOR shall secure prior written agreements from its subcontractors, and suppliers who will be engaged in the performance of the Work, or may be exposed to INFORMATION ensuring their compliance with the provisions of Article 29. Nothing herein contained should preclude CONTRACTOR from providing INFORMATION required by any governmental authority.

29.1.2 CONTRACTOR shall not use COMPANY’S name or COMPANY’S affiliate’s name in any promotional materials, or make any publicity release regarding the Work or INFORMATION hereunder except as may be required by law, regulation or rule of any governmental entity or stock exchange without first obtaining the written approval of COMPANY.

29.1.3 CONTRACTOR agrees to comply with all the laws and regulations governing the export of INFORMATION from the United States.

29.1.4 Any other warranty, representation, limitation, or indemnification provision of this CONTRACT shall not affect the obligations of Article 29.

29.1.5 All INFORMATION, whether completed or not, shall be the property of COMPANY for its copying, use, modification, distribution, or disclosure without accounting, in whatever way COMPANY may determine, notwithstanding copyright or other restrictive legends placed thereon by CONTRACTOR, its employees, its subcontractors, or its suppliers. All INFORMATION shall be turned over to COMPANY promptly at COMPANY’S request or at the termination of operations.

29.2.2 CONTRACTOR agrees to grant, and hereby grants to COMPANY an irrevocable, paid up, nonexclusive worldwide license to make, use, sell, copy, modify, disclose, distribute, and license under any and all patent, copyright, trade secret and other proprietary rights owned or controlled by CONTRACTOR, its parent or subsidiaries, to the extent needed for making, using,

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selling, or licensing equipment, materials, or other goods according to INFORMATION supplied by CONTRACTOR or to produce, copy, distribute, and use copyrighted materials based on using such INFORMATION.

29.3 PATENT INDEMNITIES

29.3.1 CONTRACTOR SHALL PROTECT, DEFEND, INDEMNIFY AND HOLD HARMLESS COMPANY AGAINST LOSS OR DAMAGE ARISING OUT OF ANY CLAIM OR SUIT FOR MISAPPROPRIATION OF TRADE SECRET OR FOR PATENT, COPYRIGHT OR OTHER PROPRIETARY RIGHT INFRINGEMENT ARISING OUT OF INCIDENT TO OR IN CONNECTION WITH (A) PERFORMANCE OF THE WORK BY CONTRACTOR, OR (B) COMPANY’S POSSESSION, USE OR SALE OF GOODS, EQUIPMENT OR MATERIALS FURNISHED BY CONTRACTOR, OR (C) COMPANY’S PRODUCTION OF COPYRIGHTED WORKS INCORPORATING OR PREPARED ACCORDING TO DOCUMENTS OR OTHER TANGIBLE MATERIALS FURNISHED BY CONTRACTOR, AND COMPANY’S POSSESSION, MODIFICATION, USE, SALE, DISTRIBUTION, COPYING OR LICENSING OF SUCH DOCUMENTS, MATERIALS OR WORKS. COMPANY shall promptly notify CONTRACTOR of any such claim or suit and afford CONTRACTOR an opportunity at CONTRACTOR’S expense to undertake the defense of any such suit, provided that COMPANY, at its election, may join in such defense at its expense. If CONTRACTOR refuses or fails to defend such suit, CONTRACTOR shall reimburse COMPANY in full for COMPANY’S costs and expenses in the defense of such suit including attorneys’ fees. CONTRACTOR shall pay promptly any judgments or decrees which may be entered against COMPANY in such suit, and in the event of the grant of injunctive relief, CONTRACTOR shall provide non-violating INFORMATION, equipment, and/or material equal in value and efficiency and failing so to do, shall pay COMPANY all damages suffered by reason of such failure.

29.3.2 COMPANY SHALL PROTECT, DEFEND, INDEMNIFY AND HOLD HARMLESS CONTRACTOR AGAINST LOSS OR DAMAGE ARISING OUT OF ANY CLAIM OR SUIT FOR MISAPPROPRIATION OF TRADE SECRET OR FOR PATENT, COPYRIGHT OR OTHER PROPRIETARY RIGHT INFRINGEMENT ARISING OUT OF INCIDENT TO OR IN CONNECTION WITH (A) CONTRACTOR”S POSSESSION, USE OF EQUIPMENT OR MATERIALS FURNISHED BY COMPANY IN ACCORDANCE WITH EXHIBIT B-3, OR (B) CONTRACTOR’S PRODUCTION OF COPYRIGHTED WORKS INCORPORATING OR PREPARED ACCORDING TO DOCUMENTS OR OTHER TANGIBLE MATERIALS FURNISHED BY COMPANY, AND CONTRACTOR’S POSSESSION, MODIFICATION, USE, SALE, DISTRIBUTION, COPYING OR LICENSING OF SUCH DOCUMENTS, MATERIALS OR WORKS. CONTRACTOR shall promptly notify COMPANY of any such claim or suit and afford COMPANY an opportunity at COMPANY’S expense to undertake the defense of any such suit, provided that CONTRACTOR, at its election, may join in such defense at its expense. If COMPANY refuses or fails to defend such suit, COMPANY shall reimburse CONTRACTOR in full for CONTRACTOR”S costs and expenses in the defense of such suit including attorneys’ fees. COMPANY shall pay promptly any judgments or decrees entered against CONTRACTOR in such suit.

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ARTICLE 30

ASSIGNMENT OF CONTRACT

30.1 ASSIGNMENT BY CONTRACTOR

CONTRACTOR shall not sublease or assign this CONTRACT, other than to its parent company or an affiliate or subsidiary thereof, without first obtaining the written consent of COMPANY. Such consent shall not be unreasonably withheld. COMPANY may require CONTRACTOR or its parent, subsidiaries or affiliates to issue a performance guarantee in a mutually agreeable form.

30.2 ASSIGNMENT BY COMPANY

30.2.1 COMPANY shall have the right to assign this CONTRACT to Atlantic Richfield Company, its divisions, subsidiaries (whether wholly or partially owned by Atlantic Richfield Company) and affiliates. CONTRACTOR shall look exclusively to the assignee of COMPANY for any matter during the period of assignment in the event of any such assignment by COMPANY. The time the Drilling Unit is operating for the assignee shall count towards the Contract Period.

30.2.2 Subject to Article 30.2.1, COMPANY shall have the right to assign its rights and obligations hereunder, in whole or in part, to third persons for wells within the Gulf of Mexico, with written consent of CONTRACTOR, and such consent shall not be unreasonably withheld. In the event of any such assignment under this Article 30.2.2 to a third party with CONTRACTOR’S written consent, COMPANY shall thereafter have no liability for any matter or operations hereunder and shall have no further responsibility to CONTRACTOR or other person hereunder during the time the right is assigned. CONTRACTOR shall look exclusively to the assignee of COMPANY for any matter during the period of assignment in the event of any such assignment by COMPANY. The time the Drilling Unit is operating for the assignee shall count toward the Contract Period.

30.2.3 COMPANY shall have the right to assign its rights and obligations hereunder, in whole or in part, to third parties for wells within the Gulf of Mexico, without the consent of CONTRACTOR. In the event of any such assignment under this Article 30.2.3, COMPANY shall provide written notice to CONTRACTOR prior to the use of the Drilling Unit on behalf of the assignee. In the event of such an assignment, COMPANY shall remain fully liable and responsible to CONTRACTOR for complete performance of all terms, conditions, and obligations imposed by this CONTRACT. The time the Drilling Unit is operating for the assignee shall count toward the Contract Period.

30.3 ASSIGNMENT OUTSIDE OF OPERATING AREA

In the event any assignment being contemplated under the provisions of this Article 30 is to involve operations outside of the Operating Area (as defined in Article 14.6), the dayrates provided for herein shall be adjusted to reflect any documented increases or decreases in CONTRACTOR’S cost of operations, including but not limited to taxes and fees in Article 11.

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ARTICLE 31

INGRESS AND EGRESS OF LOCATION

31.1 INGRESS AND EGRESS OF LOCATION

31.1.1 COMPANY shall provide CONTRACTOR with rights of ingress and egress to the well location and provide any related drilling permits or licenses for the performance by CONTRACTOR of all Work.

31.1.2 COMPANY makes no warranty or representation, express or implied, and hereby disclaims all such warranties or representations as to any conditions with respect to any port, place, dock, anchorage, access route, location, or submarine line relating to the Work, except at the well location.

ARTICLE 32

COMPANY’S POLICIES

32.1 UNAUTHORIZED PERSONS ON JOB SITES

Only (i) CONTRACTOR’S authorized employees or subcontractors, (ii) other authorized employees and persons, including invitees, authorized by COMPANY, or (iii) representatives of governmental agencies will be permitted to enter any job site where Work is to be performed under this CONTRACT. CONTRACTOR is obligated to take such steps as are reasonably necessary to prevent unauthorized persons from entering a job site.

32.2 DRUGS, FIREARMS, AND SEARCHES

CONTRACTOR shall abide by and help enforce COMPANY’S policy regarding drugs, firearms, and alcohol. The policy is as follows: The use, possession, or transportation of firearms, alcoholic beverages, illegal drugs, narcotics, or other controlled or dangerous substances, and unauthorized drugs for which a person does not have a current prescription, while on COMPANY’S Premises is prohibited. The term “COMPANY’S Premises” is used in its broadest sense to include all work locations, buildings, structures, installations, Drilling Unit, and all other facilities, both onshore and offshore, including the point of embarkation and debarkation for all boats, planes, and helicopters owned or controlled by COMPANY or one of its affiliated companies or otherwise being utilized for COMPANY’S business for transportation of persons to and from these facilities.

To ensure compliance with this policy, COMPANY may require CONTRACTOR, upon written request, to conduct unannounced periodic inspections of all individuals and their personal effects while on COMPANY’S Premises. Violation of this policy or refusal to submit to an inspection by COMPANY’S or CONTRACTOR’S personnel could result in disciplinary action up to and including discharge will be cause for immediate removal of the individual from COMPANY’S Premises.

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ARTICLE 33

NOTICES

33.1NOTICES

Any notice provided or permitted to be given under this CONTRACT shall be in writing, and may be served by personal delivery or by depositing same in the mail, addressed to the Party to be notified, postage prepaid, and registered or certified with a return receipt requested. Notice deposited in the mail in the manner described above shall be deemed to have been given and received on the date of the delivery as shown on the return receipt. Notice served in any other manner shall be deemed to have been given and received only if and when actually received by the addressee (except that notice given by telecopier shall be deemed given and received upon receipt only if received during normal business hours and if received other than during normal business hours shall be deemed received as of the opening of business on the next Business Day (for purposes of this CONTRACT, the term “Business Day”) shall mean any day except a Saturday, Sunday or other day on which commercial banks in Houston, Texas are required or authorized by law to be closed). For purposes of notice, the addresses of the Parties shall be as follows:

33.2FOR COMPANY

Vastar Resources, Inc.

15375 Memorial Drive

Houston, TX 77079

ATTN: Don Weisinger

FAX: (281) 584-6810 or 6670

TELEPHONE: (281) 584-6021

33.3FOR CONTRACTOR

R&B Falcon Drilling Co.

901 Threadneedle

Houston, TX 77079-2911

ATTN: President

FAX: (281)496-4363

TELPHONE: (281)496-5000

33.4ORAL NOTICES

Notices may be given orally only with respect to minor questions involved in the immediate drilling of any well concerned.

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ARTICLE 34

CONSEQUENTIAL DAMAGES

34.1 CONSEQUENTIAL DAMAGES

Neither Party shall be liable to the other for incidental special, indirect, statutory, exemplary, punitive, or consequential damages suffered by such party resulting from or arising out of this CONTRACT, including, without limitation, loss of profits, or business interruptions however they may be caused.

ARTICLE 35

WAIVERS AND ENTIRE CONTRACT

35.1 WAIVERS

None of the terms and conditions of this CONTRACT shall be deemed waived by either Party unless the waiver is executed in writing and then only by the duly authorized agents or representative of that Party. The failure of either Party to execute any right of termination shall not act as a waiver of any right of that Party provided hereunder. No waiver of the provisions of this CONTRACT shall be deemed or shall constitute a waiver of any other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.

35.2 ENTIRE CONTRACT

This CONTRACT, including all exhibits attached hereto and made a part hereof by this reference, constitute the entire agreement between the Parties with respect to the subject matter hereof and thereof and supersede all prior agreements, understandings, negotiations, discussions and commitments, whether oral or written with respect to same. The right of either Party to require strict adherence to the terms hereof and performance hereunder will not be affected by any previous waiver of course of dealing. Neither this CONTRACT nor any supplement, amendment, alteration, modification, or waiver will be binding on a Party unless signed by duly authorized agents or representatives of CONTRACTOR and COMPANY, or in the case of termination, by the duly authorized agents or representatives of the Party seeking termination. In the event of conflict between the terms and conditions of the text of this CONTRACT and those in any of the Exhibits, the terms and conditions of the text of this CONTRACT shall prevail.

35.3 GOVERNING LAW

This CONTRACT shall be construed and the relations between the parties determined in accordance with the General Maritime Law of the United States of America, not including, however, any of its conflicts of law rules which would direct or refer to the laws of another jurisdiction.

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35.4 ARBITRATION

Any controversy or claim arising out of or relating to this CONTRACT, or the breach thereof, which cannot be resolved satisfactorily between the parties, shall be settled by arbitration in Houston, Texas, in accordance with the rules of the American Arbitration Association Commercial Disputes. If no agreement can be reached by the Parties on discovery disputes, then the Federal Rules of Civil Procedure shall govern and judgement upon the award rendered by the arbitrator(s) may be entered in any court of competent jurisdiction.

IN WITNESS WHEREOF, the parties hereto have executed this CONTRACT on the 9th day of December, 1998.

R&B Falcon Drilling Co.			Vastar Resources, Inc.
BY:	/s/ Paul B. Loyd, Jr.		By	/s/ Charles D. Davidson
	Paul B. Loyd, Jr.			Charles D. Davidson
TITLE:		Attorney-in-Fact	TITLE:	President and CEO
		(Chairman R&B Falcon Corporation)

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EXHIBIT A

DAYRATES

	RATES PER 24 HOUR DAY
	Three (3) Year Option	Five (5) Year Option
Operating Rate	$199,950.00 per day	$189,200.00 per day
Moving Rate	$199,950.00 per day	$189,200.00 per day
Standby Rate With Crews	$199,950.00 per day	$189,200.00 per day
Standby Rate Without Crews	$199,950.00 per day less documented cost savings	$189,200.00 per day less documented cost savings
Stack Rate With Crews	$199,950.00 per day less documented cost savings	$189,200.00 per day less documented cost savings
Stack Rate Without Crews	$199,950.00 per day less documented cost savings	$189,200.00 per day less documented cost savings
Equipment Repair Rate	$ -0- per day	$ -0- per day
Hurricane Evacuation Rate	Standby Rates without crews plus documented expenses of evacuated crew	Standby Rates without crews plus documented expenses of evacuated crew

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EXHIBIT B-1

Drilling Unit Specifications

GENERAL DESCRIPTION, DIMENSIONS & CRITERIA

General Description

The RBS8D is a 5th generation, harsh environment, dynamically positioned semi-submersible, suitable for worldwide operations in up to 10,000’ water depth.

The vessel has twin “dog-bone”-shaped lower hulls, four (4) columns, canted in the transverse plane, each with a Column Outer Belt (COB) at the drilling draft, two (2) transverse horizontal, four (4) diagonal horizontal braces, and a watertight rectangular box-type upper hull.

Designed for harsh environments, the vessel features variable deck & column loads (per 1.2.4 of this document), very low motions, and high specification drilling systems, with machinery spaces and two-level quarters for 130 personnel.

Eight 5.5 MW azimuth thrusters plus six 7 MW engines provide reliable and redundant DPS-3 station keeping ability.

Principal Dimensions

	Metric Units	U.S. Units
Overall Structure
Length (overall)	120.7 m	396.00 ft.
Breadth (overall)	78.0 m	255.91 ft.
Upper Hull
Length	81.5 m	267.40 ft.
Breadth	61.0 m	200.13 ft.
Depth	8.5 m	27.89 ft.
Main Deck
Length	84.1 m	275.93 ft.
Breadth	61.0 m	200.13 ft.
Pontoons (two each)
Length	114.0 m	373.96 ft.
Breadth (amidship)	13.4 m	43.96 ft.
Breadth (ends)	16.5 m	54.13 ft.
Depth	9.10 m	29.86 ft.
Corner Radius	3.00 m	9.84 ft.
Transverse Distance (c. to c.)	61.5 m	201.77 ft.

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Columns (four each)
Horizontal Section (Lx B)
	17.0 m x l6.5 m (@ WL	)	55.8 ft. x 54.l ft.
	14.0 m x 16.5 m (bottom	)	45.93 ft. x 54.13 ft.
Corner Radius	3.00 m		9.84 ft.
Vertical Height	23.9 m		78.41 ft.
Longitudinal Distance (c. to c.)	60.0 m		196.85 ft.
Transverse Distance (c. to c.) at Top	46.00 m		150.92 ft.
at Bottom	61.5 m		201.77 ft.
Transverse Braces (two each)
Length	45.0 m		147.64 ft.
Breadth	6.0 m		19.68 ft.
Depth	3.00 m		9.84 ft.
Corner Radius	0.60 m		1.97 ft.
Longitudinal Distance (c. to c.)	68.0 m		223.10 ft.
Centerline Elevation	1.5 m		4.92 ft.
Diagonal Braces (four each)
Diameter	3.0 m		9.84 ft.
Centerline Elevation	1.5 m		4.92 ft.
Elevations
Drill Floor	46.0 m		150.92 ft.
Main Deck (at sides)	41.5 m		136.15 ft.
Second Deck	38.0 m		124.67 ft.
Third Deck (Inner bottom Top)	34.5 m		113.19 ft.
Upper Hull Bottom	33.0 m		108.27 ft.
Lower Hull Top	9.1 m		29.86 ft.
Draft
Operating Condition (G.O.M.)	23.00 m		75.46 ft.
Severe Storm Condition (G.O.M.)	16.50 m		54.13 ft.
Transit Condition	8.80 m		28.87 ft.

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Storage Capacities

(subject to adjustments)

	Metric Units	U.S. Units
Pipe Racks	871 m2	9,376 ft2
Riser (90’ joints)	3,048.5 m	10,000 ft
Total Open Deck	2,005 m2	21,578 ft2
Bulk Cement	232 m3	8,205 ft3
Bulk Barite	387 m3	13,675 ft3
Cement Day Tank	62 m3	2,200 ft3
Barite Day Tank	68 m3	2,400 ft3
Total Bulk Storage	750 m3	26,480 ft3
Sack Storage	10,000 Sx	10,000 Sx
Drilling Mud Deck	750 m3	4,434 bbl.
Drilling Mud (Column)	908 m3	5,710 bbl.
Base Oil	480 m3	3,019 bbl
Column Brine Storage	480 m3	3,019 bbl.
Pontoon Brine Storage *)	3,975 m3	25,000 bbl.
DW-Col.	1,736 m3	10,918 bbl.
DW-pontoons	1424 m3	8,956 bbl.
Fuel Oil	3,468 m3	21,811 bbl
Potable Water	644 m3	4,050 bbl
Helicopter Fuel	TBD	TBD
Refrigeration Storage	45 m2	484 ft.2
Dry Storage	60 m2	646 ft. 2
SWB — pontoons *)	16,308 m3	102,565 bbl
Quarters	130 Persons	130 Persons
Heliport	S-61, Super Puma	S-61, Super Puma

_________________________________________

(*) Note: Pontoon Brine Storage and SWB are interchangeable

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GULF OF MEXICO

METOCEAN DESIGN CRITERIA *)

	OPERATION (DP Mode)	SURVIVAL (transit / future moored)
Condition	Drilling	Moored	Vessel
Item	10 Year Eddy + 10 year Tropical Storm	20Year Tropical + 10 Year Eddy (API Criteria)	100 Year Tropical Storm (ABS/API)
Wind (1 hour)	26.1 m/s (50.8 kn)	30.5 rn/s (59.2 kn)	44.9 m/s (87.2 kn)
Wind (1 min.)	30.9 m/s (60 kn)	36.0 m/s (70 kn)	53.1 m/s (103 kn)
Wind (3 sec.)	35.8 m/s (69.5 kn)	41.7 m/s (81.0 kn)	61.7 m/s (120 kn)
Wave Hgt. Significant	7.9 m (26.0 ft)	9.4 m (31.0 ft)	12.5 m (41.0 ft)
Peak Period	(PMS)	12.0 sec.	15.0 sec.
Wave Height Maximum	14.7 m (48.2 ft)	17.5 m (57.3 ft)	22.0 m (72.2 ft)
Current:
Surface	1.8 m/s, (3.5 kn)	1.8 m/s, (3.5 kn)	1.0 m/s (1.9 kn)
100 ft.	1.7 m/s, (3.4 kn)	1.7 m/s, (3.4 kn)
200 ft.	1.2 m/s (2.4 kn)	1.2 m/s (2.4 kn)
400 ft.	1.0 M/s (2.0 kn)	1.0 m/s (2.0 kn)
1000 ft.	0.5 m/s (1.0 kn)	0.5 m/s (1.0 kn)
2000 ft.	0.3 m/s (0.5 kn)	0.3 m/s (0.5 kn)
Seafloor	0.1 m/s, (0.1 kn)	0.1 m/s, (0.1 kn)

_________________________________________

*) Metocean Design Criteria in the DP mode relate to drilling conditions with all engines (6 x 7.0 MW power) on line and any one thruster down.

4

1.2.4 Variable Drilling Loads (VDL)

DP Mode — No Mooring

Item	Division	Operation Condition	KG (m) (Operating)	Survival Condition	Transit Condition	Remark
		MT	(m)	MT	MT
Light Ship		22,325	26.15	22,325	22,325
VDL (Variable Dlg. Loads)	Upper Hull & Abv.	5,596	37.40	5,596		(note 1)
	Columns	2,057	22.85	2,057
VDL Total	(Dk. + Col.)	7,653	33.49	7,653	7,450
Pontoon Loads: Drill Water, Potable Water, Water, Fuel Oil, Lube Oil, and Ballast Water		17,530	5.57	10,722	2,984
Displacement (MT)		47,509	19.68	40,700	32,759

Future Mooring + Thruster Assist

Item	Division	Operation Condition	KG (m) (Operating)	Survival Condition	Transit Condition	Remark
		MT	(m)	MT	MT
Light Ship		22,325	26.15	22,325	22,325
Mooring Load		2,135	22.00	2,135	1,784
VDL (Variable Dlg. Loads)	Upper Hull & Abv.	5,596	37.40	5,596		(note 1)
	Columns	2,057	22.85	2,057
VDL Total	(Dk. + Col.)	7,653	33.49	7,653	5,696	(note 2)
Pontoon Loads: Drill Water, Potable Water, Water, Fuel Oil, Lube Oil, and Ballast Water		15,395	5.55	8,587	2,984
Displacement (MT)		47,509	20.49	40,700	32,759

_________________________________________

Notes:

1) Variable Drilling Load computation is based on a derrick height of 170 ft. Derrick extension beyond 170 ft will impact max. VDL.

2) Mooring equipment weight of 1,784 MT is included in transit VDL + pontoon load; alternatively, field transit may be conducted at column draft.

5

Classification Society

American Bureau of Shipping

XA1 “Column Stabilized Drilling Unit”, XCDS, (P), DPS-3

Rules and Regulations

·SOLAS, 74 Convention, 78 Protocol with Amendments through 1997

1988 Amendments to the 1974 SOLAS Convention concerning Radio Communications for the Global Maritime Distress and Safety System (GMDSS)

·API /AISC

·OCIMF

·US Coast Guard Requirements

·MARPOL 73 COW, Regulation 13F, etc., (Annexes I, IV, & V) (Oil) IOPP, with the Protocol 1978, and amendments to Annex I and Annex V of 1992.

(refer to section 053 Damage stability)

·IMO Resolutions A.468(XII), “Code on Noise Levels Onboard Ships”, 1981, and USCG NVIC 12-82 as well

·IMO Resolution A.574(XIV), “Recommendations on General Requirements for Electric Navigational Aids”

·IMO MSC/circ. 403, “Draft Guidelines on Navigation Bridge Visibility except field of vision (blind sector).

·IMO MODU Code, 1989 with amendments of 1991 (ABS Statement-of-Fact).

·1966 Loadline Conference and all amendments and IMO Resolutions A.513 (XIII) and A.514 (XIII)

·International Convention on Tonnage Measurement of Ships, 1969, as amended by IMO Resolution A.493 (XII) and Resolution A.494 (XII).

·1972 International Prevention of Collision at sea Convention, including amendments of 1981, 1987, and 1989

·1988 Amendments to the 1974 SOLAS Convention concerning Radio Communications for the Global Maritime Distress and Safety System (GMDSS)

·International Electro Technical Commission (IEC) Publication No. 60092 for electrical installation of ships.

·International Electro Technical Commission (IEC) Publication No. 61892 for Mobile and Fixed Offshore Units - electrical installations,

·U.S.C.G. Regulations for Marine Sanitation Devices (CFR title 33-Part 159)

Registration

The Vessel shall be registered under USA Flag.

6

The estimated Light Ship weight is 22,325 metric tons, the estimated Light Ship VCG is 26.15m above baseline. The approximate breakdown is as follows:

Item	M. Tonnes		L. Tons
HSW	13,603		13,390
BFE	3,433		3,379
OFE	4,619		4,547
<SUBTOTAL>	<21,655	>	<21,316	>
OTHERS	220		218
MARGIN	450		443
TOTAL	22,325		21,977

7

EXHIBIT B-2

MATERIAL EQUIPMENT LIST

TABLE OF CONTENTS

SECTION A - UNIT SPECIFICATIONS
Al	Main Dimensions/Technical Description
A2	Storage Capacities
A3	Propulsion/Thrusters
A4	Operational Capabilities
A5	Variable Loading
A6	Environmental Limits
A7	Mooring System
A8	Marine Loading Hoses
A9	Cranes, Hoists, and Materials Handling
A10	Helicopter Landing Deck
A11	Auxiliary Equipment
SECTION B - GENERAL RIG SPECIFICATIONS
B1	Derrick and Substructure
B2	Drawworks and Associated Equipment
B3	Derrick Hoisting Equipment
B4	Rotating System
SECTION C - POWER SUPPLY SYSTEMS
C1	Rig Power Plant
C2	Emergency Generator
C3	Primary Electric Motors
SECTION D - DRILLSTRING EQUIPMENT
D1	Tubulars
D2	Handling Tools
D3	Fishing Equipment
SECTION E - WELL CONTROL/SUBSEA EQUIPMENT
El	Lower Riser Diverter Assembly
E2	Primary BOP Stack
E3	Primary Lower Marine Riser Package
E4	Annular Gas Handler
E5	Secondary Lower Marine Riser Package
E6	Primary Marine Riser System
E7	Secondary Marine Riser System
E8	Diverter BOP
E9	Subsea Support System
El0	BOP Control System
E11	Subsea Control System
E12	Acoustic Emergency BOP Control System
E13	Subsea Auxiliary Equipment

1

E14	Choke Manifold
E15	Hydraulic BOP Test Pump
E16	Wellhead Running/Retrieving/Testing Tools
SECTION F - MUD SYSTEM/BULK SYSTEM
Fl	High Pressure Mud System
F2	Low Pressure Mud System
F3	Bulk System
SECTION G - CASING/CEMENTING EQUIPMENT
G1	Casing Equipment
G2	Cement Equipment
SECTION H - INSTRUMENTATION/COMMUNICATION
H1	Drilling Instrumentation at Driller’s Position
H2	Drilling Parameter Recorder
H3	Instrumentation at Choke Manifold
H4	Standpipe Pressure Gauge
H5	Deviation Equipment
H6	Calibrated Pressure Gauges
H7	Rig Communication System
H8	Environmental Instrumentation
H9	Additional MODU Specific Instrumentation
H10	Radio Equipment
SECTION I - PRODUCTION TEST EQUIPMENT
11	Burners
12	Burner Booms
13	Lines Required on Burner Booms
14	Sprinkler System
15	Fixed Lines for Well Tesing
16	Power Requirement
SECTION J - WORKOVER TOOLS
SECTION K - ACCOMMODATION
K1	Offices
K2	Living Quarters
SECTION L - SAFETY EQUIPMENT
L1	General Safety Equipment
L2	Gas Detection
L3	Fire Fighting Equipment
L4	Breathing Apparatus
L5	Emergency First Aid Equipment
L6	Helideck Rescue Equipment
L7	Rig Safety Store
L8	Emergency Warning Alarms
L9	Survival Equipment

2

SECTION M - POLLUTION PREVENTION EQUIPMENT
Ml	Sewage Treatment
M2	Garbage Compaction
M3	Garbage Disposal/Grinder
SECTION N - THIRD PARTY EQUIPMENT (SPACE PROVIDED)

3

SECTIONS

A.UNIT SPECIFICATIONS
GENERAL
Unit Name	:	RBS8-D
Rig Type	:	SEMISUBMERSIBLE
Unit/design/shape		IHI - RBF Exploration
Unit flag	:	UNITED STATES
Unit classification	:	ABS
IMO Certification (yes/no)	:	YES
Which code version	:	1989 as ammended 1991
Year of construction	:	2,000
Construction yard	:	HYUNDAI
Type of Positioning system (anchor/dp/c	:	DPS-3
A.1MAIN DIMENSIONS/TECHNICAL
DESCRIPTION
Weight (light ship)	lt:	21,977
Overall width	ft:	255.9
Overall length	ft:	396
Main deck width	ft:	200.1
Main deck length	ft:	275.9
Main deck depth	ft:	27.9
Number of main columns/diameter	No x ft:	4 x 55.8 x 54.1 (WL) 45.9 x 54.1 (Bottom)
Number of small columns/diameter	No x ft	0
Drilling draft/related displacement	ft - lt:	75.5 / 46,767
Transit draft/related displacement	ft - lt:	28.9 / 32,247
Survival draft/related displacement	ft - lt:	54 / 40,064
Moon pool dimensions	ft x ft:	21 X 93
Maximum opening through spider deck	ft - lt:	N/A
Pontoon length	ft - lt:	374
Pontoon breadth (ends / middle)		54.1 / 44.0
Pontoon height	ft - lt:	29.9
Accommodation for maximum no. of persons	:	130
A.2STORAGE CAPACITIES
Fuel	bbls:	21,811
Drilling water	bbls:	19,874
Potable water	bbl:	4050
Active liquid mud (see F.2)	bbl:	4434 (100%)
Mud processing tank (see F.2)	bbl:	450 (100%)
Reserve liquid mud (see F.2)	bbl:	5710 (100%)
Bulk bentonite/barite (see F.3)	cu ft:	13,675 (100%)
Bulk cement (see F.3)	cu ft:	11000 (100%)
Sack storage	No. or ft2:	10000 sxs
Pipe racks area	ft2:	9,376
Load bearing capacity	lb/ft2:	500
Riser racks area	ft:	10,000
Load bearing capacity	lb/ft2:	300
Miscellaneous storage area	ft2:	See Drawing
Brine storage (Column)	bbls:	3019 (100%)

4

Brine storage (Pontoon)	bbls:	25,000 (100%)
Base oil mud storage	bbls:	3019 (100%)
Ballast system	bbls:	102,565
A.3PROPULSION/THRUSTERS
Thrusters\Type (azimuth/in line)	:	AZIMUTH - FULL 360
Quantity	:	8
Location (aft, opposite corners, 4 corners	:	FOUR CORNERS
Driven by electric motor (yes/no)	:	YES - VARIABLE SPEED DRIVE
Make/type	:	Kamewa
Power output (HP ea)	:	6633
Propeller type (fixed/variable pitch)	:	FIXED
Nozzled (yes/no)	:	YES
Thruster power (HP total)	:	53064
DP SYSTEM	:
		Class III Dynamic Positioning System in accordance with ABS DPS-3 requirements and recommendations. System to consist of a main triple redundant dynamic positioning system and shall accept inputs from the team selected and proven state of the art Acoustic Positioning System, two differential GPS (DGPS) based on correction signal inputs from different sources, (3) three gyrocompass, (3) three vertical reference units with redundant feeds to the DP system, and three wind sensors, as well as operator input and input from the ERA (Electrical Riser Angle) system. The system shall be powered from a redundant UPS. A single dynamic positioning system of similar design as the main DP system, will accept inputs from the APS, the two DGPS’s, the ERA system, one gyrocompass, one vertical reference unit, and one wind sensor. The system contains the Power Management System and is interfaced with the Integrated Alarm and Control System. The system shall be powered from a dedicated UPS.
Position reference	:	HYDRO ACOUSTIC & GLOBAL POSITIONING
Integrated Alarm And Control System:		The IACS will operate as the Sys.Control and Data acquisition sys. for the MODU. The IACS will perform several different functions including: Power Management Sys., Machinery Monitoring and Control, Manual Thruster Control and Autopilot, Dynamic Positioning Control, Ballast / Bunker Monitoring and Control, Bulk Storage Sys. Monitoring and Control.
A.4OPERATIONAL CAPABILITIES
Maximum designed water depth capability	ft:	10000
Outfitted max. water depth capability	ft:	8000
Normal min. water depth cpability	ft:	250
Drilling depth capability (rated)	ft:	30000
Transit speed towed (historical avg)	knots:	4.5

5

Transit speed self propelled (historical avg)	knots:	7.5
A.5VARIABLE LOADING (VL)
Transit VL	mt	See B-1
Drilling VL	mt	See B-1
Survival VL	mt	See B-1
A.6ENVIRONMENTAL LIMITS
Drilling (including station keeping)		See Exhibit B-1
Air gap	ft:	32.8
Sign. Wave Height	ft:	26
Max. wave height	ft:	48.2
Spec. peak period	sec:	PMS
Max. wind velocity	knots:	60 ( 1 min.)
Max. current velocity	knots:	See B-1
Max. heave	ft:	N/A
Max. pitch	degrees:	N/A
Max. roll	degrees:	N/A
Survival (excluding station keeping)
Air gap	ft:	54.2
Sig. Wave height	ft:	41
Max. wave height	ft:	72.2
Spec. peak period	sec:	15
Max. wind velocity	knots:	103 ( 1 min.)
Max. current velocity	knots:	1.9
Max. heave	ft:	N/A
Max. pitch	degrees:	N/A
Max. roll	degrees:	N/A
Transit (field move)
Air gap	ft:	79.4
Max. wave height	ft:	30-40
Max. wave period	sec:	8-12
Max. wind velocity	knots:	60-70
Max. current velocity	knots:	2-3
Max. heave	ft:	N/A
Max. pitch	degrees:	N/A
Max. roll	degrees:	N/A
A.7MOORING SYSTEM		MOD’S REQ’D FOR THE FUTURE INSTALLATION OF OPERATOR FURNISHED CHAIN WINDLASSES WILL BE PERFORMED DURING THE CONSTRUCTION PHASE AT THE SHIPYARD INCLUDING FOUNDATIONS / PRIMARY PIPING & WIRING.
A.7.1ANCHOR WINCHES
Quantity	no.:	N/A
Make
Type (electric/hydraulic/diesel)	:
Rated pull	mt
Speed low gear	ft/m:

6

Test load	:
Control locations (local/remote/both)	:
Emergency release (type/location)	:
A.7.2FAIRLEADS		Foundations to be installed in shipyard
Quantity	no:
Make	:
Free rotating range	degrees:
A.7.3ANCHORS		Company Supplied
A.7.3.1ANCHORS - Primary		Company Supplied
A.7.3.2ANCHORS - Spare		Company Supplied
A.7.4ANCHOR LINES		Company Supplied to be installed at later date
A.7.5ANCHOR LINE RUNNING / RETRIE’		N/A
A.7.5.1PENNANT LINES		N/A
A.7.5.2ANCHOR BUOYS		N/A
A.7.5.3CHASER		N/A
A.7.6TOWING GEAR
Towing bridle size	inches:	Installation of a tow bridle will be evaluated by the team.
Hook-up system	:
Rating	lt:
Power required for infield tow	bollard pull lt:	N/A
Power required for ocean tow	bollard pull lt:	N/A
Spare bridle	yes/no:	yes
A.7.7SUPPLY VESSEL MOORING LINES	:
Quantity	no.:	4
System	mt:	TO BE EVALUATED BY TEAM
Rating	lt:	TBA
A.8MARINE LOADING HOSES
Location of loading manifolds (port/stbd	:	BOTH
A.8.1POTABLE WATER HOSE
Quantity	no.:	2 x 150’
Size	inch:	3
Make/Type	:	TBA
Color coding	yes/no:	YES
Make/Type/Connection		TBA
A.8.2DRILLING WATER HOSE
Quantity	no.:	2 x 150’
Size	inch:	4
Make/Type	:	TBA
Color coding	yes/no:	YES
Make/Type connection	:	TBA
A.8.3GAS OIL HOSE
Quantity	no.:	2 x 150’
Size	inch:	4

7

Make/Type			:		TBA
Color coding			yes/no:		yes
Make/Type connection			:		TBA
PRESSURE RATING			p.s.i		150 wp
A.8.4MUD CHEMICAL HOSE
Quantity			no.:		2 x 150’
Size			inch:		5
Make/Type			:		TBA
Color coding			yes/no:		YES
Make/Type connection			:		TBA
A.8.5CEMENT HOSE
Quantity			no.:		2 x 150’
Size			inch:		5
Make/ Type			:		TBA
Color coding			yes/no:		YES
Make/Type connection			:		TBA
A.8.6BASE OIL HOSE
Quantity			no.:		2 x 150’
Size			inch:		4
Make/Type			:		TBA
Color coding			yes/no:		YES
Make/Type connection			:		TBA
Pressure Rating					150 psi wp
A.8.7BRINE HOSE
Quantity			no.:		2 x 150’
Size			inch:		4
Make/Type			:		TBA
Color coding			yes/no:		YES
Make/Type connection			:		TBA
A. 9CRANES, HOISTS, AND MATERIALS HANDLING
A. 9.1CRANES, REVOLVING, MAIN
Quantity			no.:		2
Specification (API, etc.)					ABS /US-DEN
Make			:		LIEBHERR
Type			:		PEDESTAL
Location (stbd, port, aft, frwd)			:		PORT & STBD
Maximum rated capacity (main hook)			mt		100
Maximum rated capacity (whip hook)			mt		15
Boom length			ft:		150
Line length (no Boom			ft:		1893
Main Hoist			ft:		1920
Whip line			ft:		475
Maximum capacity and hoisting speeds
				Radius	Metric
Main Hoist	Platform Lift	4 lines		Meters	Tons
				6.6	92

8

10		92
			11	92
			15	84.7
			20	71.8
			25	62.8
			30	55.6
			35	47.2
			40	39.7
			45	33.8
			48	31.1
				No Load
			Radius	Metric
Main Hoist	Seastate Lift	4 lines	Meters	Tons
			6.6	51.5
			10	46
			11	44.8
			15	40.7
			20	36.8
			25	33.5
			30	30.6
			35	26.4
			40	22.4
			45	19.4
			48	18
				No load
			Radius	Metric
Main Hoist	Platform Lift	2 lines	Meters	Tons
			6.6	50
			10	50
			11	50
			15	50
			20	50
			25	50
			30	50
			35	47.2
			40	39.7
			45	33.8
			48	31.1
				No load
			Radius	Metric
Main Hoist	Seastate Lift	2 lines	Meters	Tons
			6.6	31.9
			10	31.9
			11	31.9
			15	31.9
			20	31.9
			25	31.9
			30	30.6

9

35		26.4
			40	22.4
			45	19.4
			48	18
				No Load
			Radius	Metric
			Meters	Tons
Whip Line	Platform Lift		51	15
	Seastate lift		51	10
				No Load
Hook load indicator automatically corrected for boom angle			yes/no:	YES
Alarm (audible, visual, both)			:	BOTH
Automatic brake			yes/no:	YES
Safety latch on hooks			yes/no:	YES
Crown saver (limit switch)			yes/no:	YES
Boom illumination			yes/no:	YES
Baskets for personnel transfer			no.:	2
A. 9.2CRANES, REVOLVING, SECONDARY
Quantity			no.:	1
Specification (API, etc.)			:	API
Make			:	OUT REACH
Type			:	KNUCKLEBOOM
Location (stbd, port, aft, frwd)			:	FORWARD
Maximum rated capacity (main hook)			lt:	3.57
Maximum rated capacity (whip hook)			lt:	N/A
Boom length			ft:	68
Line length (nominal)			ft:	N/A
A. 9.3FORKLIFTS
Quantity			no.:	1
Make/Type			:	TBA
Rated capacity			lt:	TBA
Explosion proof			yes/no:	YES
A. 9.4MONORAIL OVERHEAD CRANES
Quantity			no.:	1
Make			:	MARITIME HYDRAULICS
Type			:	GANTRY TYPE
Rated capacity			mt	36
Location			:	AFT RISER DECK
A. 9.5BOP HANDLING SYSTEM
Make/Type				HYDRALIFT BRIDGE CRANE
Rated capacity (5 Ram Stack =551,300 lbs (250mt)) 310 T
BOP CARRIER
Make/Type				Hydralift “C” Cart complete with false rotary deck.
Rated Capacity				310 Tons

10

A. 9.6AIR HOISTS/DERRICK WINCHES
A. 9.6.1RIG FLOOR WINCHES (Non man-riding)
Quantity	no.:	4
Make	:	INGERSAL RAND
Type	:	HYDRAULIC
Rated capacity	st:	5.5
Wire diameter	inch:	0.75
Automatic brakes	yes/no:	YES
Overload protection	yes/no:	NO
Automatic spooling	yes/no:	YES
A. 9.6.2MONKEY BOARD WORK WINCH
Quantity	no.:	1
Make	:	IR
Type	:
Rated capacity	st:	0.25
Wire diameter	yes/no:	3/8”
Automatic brakes	yes/no:	YES
Overload protection	yes/no:	NO
A. 9.6.3RIG FLOOR “MAN-RIDING” WINCH
Quantity	no.:	2
Make	:	Ingersoll Rand
Type	:	Hydraulic
Rated capacity	st:	0.25
Wire diameter/non-twist wire	inch:	3/8”
Automatic brakes	yes/no:	Yes
Overload protection	yes/no:	No
Automatic spooling	yes/no:	Yes
Certified for man-riding	yes/no:	Yes
A. 9.6.4UTILITY WINCH (i.e. Deck Winch)		N/A
A. 9.6.5CELLAR DECK WINCH
Quantity	no.:	4
Make	:	Ingersoll Rand
Type	:	Air
Rated capacity	st:	5.5
Wire diameter	inch:	.75
Automatic brakes	yes/no:	No
Overload protection	yes/no:	No
Automatic spooling	yes/no:	Yes
Man -riding	:	2
A.10HELICOPTER LANDING DECK
Location		PORT/FWD. MAIN DECK
Dimensions	ft. x ft.:	72.8 X 72.8
Perimeter safety net	yes/no:	YES
Load capacity	lt:	9.15

11

Designed for helicopter type				:	SIKORSKY S-61
Tie down points				yes/no:	YES
Covered by foam fire system (See L.36)				yes/no:	YES
A.10.1HELICOPTER REFUELING SYSTEM
Fuel storage capacity			U.S. gals:		1440
Jettisonable				yes/no:	NO
Fuel transport containers				qty:	2
Volume (ea)				:	720
Covered by foam fire system (See L.3.5)				yes/no:	YES
A.11AUXILIARY EQUIPMENT
A.11.1WATER DISTILLATION
Quantity				no.:	4
Make/Type					Alfa Laval or equivalent
Capacity (each/total)	cu. ft./day:				26 Metric Ton each (Depending on engine utilization)
A.11.2BROILERS					N/A
A.11.3AIR CONDITIONING
Quantity				no.:	5
Make/Type				:
Capacity (total system)				tons:
A.11.4ELECTRIC WELDING SETS
Quantity				no.:	3
Current capacity				amp:	400
Make/Type				:	Lincoln S-7046 SAE 400
A.11.5HIGH PRESSURE CLEANER
Quantity				no.:	1
Make/Type				:	Weatherford
Electric/pneumatic				:	Electric
Max delivered pressure				psi:	2700
Ring Main		yes/no			Yes
Outlets		Number			6
B.GENERAL RIG SPECIFICATIONS
B.1DERRICK AND SUBSTRUCTURE
B.1.1.DERRICK/MAST
Make/Type				:	DRECO
Rated for wind speed:
With full set back				knots:	100
With no set back				knots:	100
Height				ft:	210 estimated. Final height to be evaluated by Dreco.
Dimensions of base				ft x ft:	48X48
Dimensions of crown				ft x ft:	18x18
Gross nominal capacity				st.:	1250
Maximum Number of lines				no.:	14

12

Ladders with safety cages and rests	yes/no:	yes
Platform for crown sheave access	yes/no:	yes
Counter balance, system for rig tongs and pipe spinning tong	yes/no:	yes
Lighting system explosion proof	yes/no:	yes
(adjustable fingers on the right hand side can have any one of the casing below racked back at any one time, but not all)		Unit is capable of field transiting with 238 stands of drillpipe without exceeding rated design loads of derrick.
Make/Type	:	Varco
Racking platform total capacity with 5-1	ft:	31,000 (nominal)
Fixed Fingers (on left side of derrick) - u	ft:	20000 (nominal)
Adjustable fingers (on right side) - 7” Ca	ft:	11000 (nominal)
or
Adjustable fingers (on right side) - 9-5/8	ft:	11000 (nominal)
or
Adjustable fingers (on right side) - 13-3/	ft:	9500 (nominal)
Racking platform capacity of 8” - 9” DC	no.:	8
Auxiliary Derrick (Moonpool)
Make / Type		Dreco
Capacity		300 Tons
B.1.3 AUTOMATIC PIPE RACKER
Make/Type	:	2 - Varco PRS-6 Pipe Rackers
		Pipe racker on forward side to be capable of handling 20”, 16”, 13-3/8”, 11-3/4”, 9-7/8”, 7-5/8”, and 7” casing
B.1.4 CASING STABBING BOARD
Make/Type	:	Dreco / Hyd.
Adjustable from/to height above R/table	ft/ft:	Adjustable Casing Stabbing Basket - 45’ reach
Auxiliary Pipe Handler (Moonpool)
Make / Type		National
B.1.5 SUBSTRUCTURE
Make/Type	:	H.H.I
Height	ft :	14.75’
Width	ft:	80
Length	ft:	71
Setback capacity	st:	1000
Hookload	st	1000
Simultaneous setback-hookload capacity	st:	2000
Tensioner capacity	st	1750
Clear height below R/table beams (from	ft:	29.5
B.1.6 WEATHER PROOFING
Rig floor windbreaks height	ft:	10
Derrickman windbreaks height	ft:	15

13

B.1.7 DERRICK TV CAMERA SYSTEM
Camera located at	:	Monkey Board/ Crown
Make/Type	:	Color
Zoom/Pan/Tilt-function	yes/no:	yes
Monitor located at	:	Driller’s House
B.2 DRAWWORKS AND ASSOCIATED EQUIPMENT
B.2.1 DRAWWORKS
Make/Type	:	Dreco/Hitec
Drum type	:	Lebus Grooving, 2” drill line
Spinning cathead type	:	Refer D 2.1.7
Breakout cathead type	:	N/A
Crown block safety device	:	YES
Make	:
Model	:
Rated input power continuous	hp:	6900
Rated input power maximum	hp:	8400
Drum Diameter	inches:	73.5
Maximum line pull 14 lines	st:	1000
Maximum line pull 12 Lines
Maximum line pull 10 lines	st:	600
Maximum line pull 8 lines	st:
Independent fresh water cooling system for
drawworks	yes/no:	yes
B.2.2 DRAWWORKS POWER
Number of electric motors	no.:	8
Make	:	General Electric
Model	:	GEB 22A1
Output power continuous	hp:	1150
Output power intermittent (max.)	hp:	1400
B.2.3 AUXILIARY BRAKE
Make	:	Hitec
Model	:	Regenerative AC braking,
Independent back-up system type	:	Failsafe disc brakes
B.2.4 SANDLINE		NA
B.2.5 AUTOMATIC DRILLER
Make/Type	:	Hitec
AUXILIARY DRAWWORKS (Moonpool)
Make / Type		National / AC
Lift Capacity		300 Tons
Input HP		1,000

14

B.3 DERRICK HOISTING EQUIPMENT
B.3.1 CROWN BLOCK
Make/Type	:	Dreco
Rated capacity	st:	1000
No. of sheaves	no.:	7
Sheave diameter	inches:	72
Sheave grooved for line size	inches:	2
AUXILIARY CROWN BLOCK (Moonpool)
Make / Type		Dreco
Rated Capacity		300 Tons
B.3.2 TRAVELING BLOCK
Make/Type	:	Dreco
Rated capacity	st:	1000
No. of sheaves	no.:	7
Sheave diameter	inches:	72
Sheave grooved for line size	inch:	2
AUXILIARY TRAVELING BLOCK
Make / Type		Dreco
Rated Capacity		300 Tons
B.3.3 HOOK		N/A
Make/Type	:
Rated capacity	st:
Complete with spring assembly/hook loc	yes/no:
B.3.4 SWIVEL
Make/Type	:	None
Rated capacity	st:
Test/working pressure	psi/psi:
Gooseneck and washpipe minimum ID >	yes/no:
Left hand pin connection size	inches:
Access fitting for wireline entry on top o	yes/no:
B.3.5 DRILLING LINE
Diameter	inch:	2”
Type	:	6 x 26 EIPS, IWRC
Length (original)	ft:	12500
Support frame for drum/cover	yes/no:	yes
Drilling line drum power driven	yes/no:	yes
Spare reel drilling line	yes/no:	no
Location (rig, shore, etc.)	:
B.3.6 ANCHOR DEAD LINE
Make/Type	:	Dreco
Weight sensor	yes/no:	yes
B.3.7 DRILL STRING MOTION COMPENSATOR
Make/Type	:	Hitec ASA Active Heave Comp.
Stroke	ft:	14.5

15

Capacity - compensated	st:			500
Capacity - locked	st:			1000
B.3.8 BLOCK GUIDANCE SYSTEM
Make/Type	:			DRECO
B.3.9 RETRACTION SYSTEM FOR TRAVELING BLOCK
Make/Type		:		Varco/Retrac. Dolly
B.4 ROTATING SYSTEM
B.4.1 ROTARY TABLE
Make/Type		:		Varco
Maximum opening		inches:		60
Rated capacity		st:		1000
Static load capacity		st:		1000
Rotating load capacity		st @ rpm:		TBA
Two speed gearbox		yes/no:		No
Max RPM @t Max Torque		RPM/ Ft lbs		17/48000
Emergency chain drive		yes/no:		no
Driven by an independent electric motor		yes/no:		No
Electric motor type/make		:		Hydraulic x 4
Maximum continuous torque		ft/lbs:		48000
Drip pan/mud collection system		yes/no:		yes
B 4.2 ROTARY TABLE ADAPTER BUSHING
Size		“	60 1/2 x 49 1/2
Quanity		:		1
Size		“	49 1/2 x 37 1/2
Quanty		:
B.4.3 MASTER BUSHING
Make/Type		:		Varco MPCH
Size		inch:		37-1/2
Inset Bushings		#’s		3,2,1
B.4.4 KELLY BUSHING
B.4.5 TOP DRIVE
Make		:		National or Varco
Type (electric/hydraulic)		:		Electric
Rated capacity		st:		1000 or 750 (if 750 parking system to be supplied)
Test/working pressure		psi/psi:		11250 / 7500
Remote operated kelly cock		yes/no:		YES
If driven by electric motor
Make/Type		:		GE GEB-20AC
Output power		hp:		1150
Output torque		ft lbs:		Per Manufacturers rating
Max Torque @ Max RPM		Ft lb/s RPM		Per Manufacturers rating
Two speed gearbox		yes/no:		No
Maximum rotary speed		rpm:		270
Cooling system type		:		AIR

16

B.4.6 TOP DRIVE MAKEOUT/BREAKOUT SYSTEM
Make	:	National or Varco
Model	:
Type	:	HYDRAULIC
Max. breakout torque that can be applied	ft/lbs:	100000
B.4.7 RAISED BACKUP SYSTEM
Make	:	Varco
Model	:	RBS 4
Torque rating	:	100,000 Ft Lb
Vertical Travel	:	10 Ft
Pipe range	:	4 3/4” to 8 1/4”
C. POWER SUPPLY SYSTEMS
C.1 RIG POWER PLANT
C.1.1 DIESEL ENGINES
Quantity	no.:	6
Make/Type	:	18V32
Maximum continuous power	hp:	7290
At rotation speed of	rpm:	720
Equipped with spark arrestors	yes/no:	YES
Mufflers installed	yes/no:	YES
Total fuel consumption, drilling (average	bbl/day:	Av 375. Estimate only, based on GOM weather and will vary depending on operations
C.1.2 DC - GENERATOR	Type:	N/A
C.1.3 AC-GENERATOR
Quantity	no.:	6
Make/Type	:	TBA
Continuous power	kw:	7000
At rotation speed of	rpm:	720
Output volts	volts:	42,000 kw
Quantity	no.:
Make/Type	:
Continuous power	kw:
At rotation speed of	rpm:
Output volts	volts:
C.1.4 VARIABLE FREQUENCY DRIVES
Number of Inverters	no.:	19 INVERTERS
Make/Type	:	TBA
Maximum continuous power (total)	kw:	15130 KW
Output volts	volts:	0-600AC
C.1.5 TRANSFORMER SYSTEM
Quantity	no.:	8 THRUSTER TRANSFORMERS
Make/Type	:	TBA
Continuous power (each)	KVA:	5000 KVA

17

Output volts	volts:	2300
Frequency	Hz:	60
Quantity	no.:	6 DRILLING TRANSFORMERS
Make/Type	:	TBA
Continuous power (each)	KVA:	2500
Output volts	volts:	600
Frequency	Hz:	60
C.1.6 EMERGENCY SHUTDOWN
Emer. shutdown switches for complete power sys.		CENTRAL CONTROL ROOM
(AC and DC), located at the following points	:	RIG FLOOR
		ENGINE CONTROL ROOM
C.1.7 AUXILIARY POWER SUPPLY
Power supply for a mud logging unit	yes/no:	YES
Power supply available:
Output volts	volts:	480
Frequency	Hz:	60
Current	amps:	100
Phase	single/three	THREE
C.1.8 COMPRESSED AIR SYSTEMS
Air Compressors - High Pressure:
Quantity	no:	2
Make	:	Hamworthy
Model	:	w1234
Rated capacity	cu ft/hr:	65 cfm
Working press	psi:	5000
Prime mover (electric/diesel)	hp:	Electrical
Continuous power	hp:	60
Air dryers
Quantity	no.:	2
Make/Type	:	Hamworthy Regenerative Tower (Dual)
Rated Capacity	cu ft/min:
Air Compressors - Medium Pressure (rig air):
Quantity	no:	3
Make	:	Gardner Denver
Model	:	EGQSP Rotary Screw
Rated capacity	cu ft/hr:	750 SCFM
Working press	psi:	125 psi
Prime mover (electric/diesel)	hp:	Electric
Continuous power	hp:	200
Air dryers
Quantity	no.:	3
Make/Type	:	Dessicant Domnick Hunter / DX110 Heatless
Rated Capacity	cu ft/min:	1080 scfm
Air Compressors - Low Pressure (bulk air):		None - Reducing Stations
Quantity	no:	2
Make	:	Kimray
Model	:	Reducing Valve / Back Pressure Valve ABY / AAU 3”
Rated capacity	cu ft/hr:	10,600 Each
Working press	psi:	60

18

C.2EMERGENCY GENERATOR - Emergency Generator not required due to power system design
C.2.1ENGINE
AUXILIARY POWER PLANT
C.2.1ENGINE		Data, for Anchored ver.may change for RBS8-D
Quantity	no.:	1
Make/Type	:	CATERPILLAR 3508B
Maximum output	kw:	500
At rotation speed	rpm:	1200
Starting methods (automatic, manual, air	:	AUTOMATIC
Max. angle of operation	degrees:	22.5 PER ABS
C.2.2AC-GENERATOR
Quantity	no.:	1
Make/Type	:	CATERPILLAR SR4
Maximum output	kw:	500
At rotation speed	rpm:	1200
Output volts	volts:	480
Capable of back-feeding to main bus	yes/no:	YES - TO 480V BUS
C.3PRIMARY ELECTRIC MOTORS
C.3.1PROPULSION MOTORS	Type:	See Thruster Motors
C.3.2THRUSTER MOTORS
Quantity	no.:	8
Type (AC/DC)	:	TBA
Power of each	MW	5.5
Total power	MW
D.DRILLSTRING EQUIPMENT
D.1TUBULARS
D.1.1KELLIES
D.1.2TOP DRIVE SAVER SUBS
Quantity	no.:	2
Connection type	:	HT 55
API classification	:	8 C
Protector	yes/no:	No
Quantity	no.:	2
Connection type	:	4 1/2 IF
API classification	:	8 C
Protector	yes/no:	No

19

D.1.3DRILL PIPE
Drill pipe OD	inch:	5.5
Grade	:	S135
Total length	ft:	22000
Range	:	3
Weight	lbs/ft:	21.9 Nonimal
Tensile yield strength Premium	lbs:	621000
Internally plastic coated	yes/no:	Yes,TK-34
Tool joint OD/ID	inch/inch:	71 /4” x 4” provisional
Make up torque	Ftt/lbs	46300
Tool joint pin length	inch:	10
Tapered shoulder tool joints	degree:	18
Connection type	:	HT 55
Type of hardfacing	:	Armacor M
API classification	:	PREMIUM
Thread protectors	yes/no:	Yes
Drill pipe OD	inch:	5
Grade	:	S-135
Total length	ft:	8000
Range	:	3
Weight	lbs/ft:	19.5 Nominal
Tensile yield strength Premium	lbs	560000
Internally plastic coated	yes/no:	Yes TK-34
Tool joint OD/ID	inch/inch:	6 5/8” x 3 1 1/6”
make up Torque	Ft/lbs	32900
Tool joint pin length	inch:	9”
Tapered shoulder tool joints	degree:	18
Connection type	:	4 1/2 “IF
Type of hardfacing	:	Armacor M
API classification	:	PREMIUM
Thread protectors	yes/no:	Yes
Drill pipe OD	inch:	5.5
Grade	:	S-135
Total length	ft:	8000
Range	:	3
Weight	lbs/ft:	38
Tensile yield s Premium	lbs	1170600
Internally plastic coated	yes/no:	Yes
Tool Joint OD/ID	inch/inch:	7 1/8 x 3 3/4 Provisional
Tool joint pin length	inch:	10
Tapered shoulder tool joints	degree:	18
Connection type	:	HT 55
Type of hardfacing	:	Armacor M
API classification	:	Premium
Thread protectors	yes/no:	Yes
D.1.4DRILL PIPE PUP JOINTS ( Integral)
O.D		5.5”
Grade/Yield	:	4145 H Equiv. To 120K

20

Tool joint OD/ID	inch/inch:	7 1/4 x 3 3/4 ”
Weight	LB/FT	40
Connection type		HT-55
Stress relief pin groove	:	No
Boreback on box	:	No
Internally plastic coated	yes/no:	No
Thread protectors	yes/no:	Yes,
Length	ft:	10
Quantity	no:	1
Length	ft:	15
Quantity	no:	2
Length	ft:	20
Quantity		1
O.D	:	5”
Grade/ Yield	:	4145 H equiv to 120 K
Tool joint OD/ID	inch/inch:	6 5/8” x 2 3/4 ”
Grade	:	4145 H Equiv. To 120K
Weight	LB/FT	TBA
Connection type		4 1/2” IF
Stress relief pin groove	:	Yes
Boreback on box	:	Yes
Internally plastic coated	yes/no:	No
Thread protectors	yes/no:	Yes
Length	ft:	10
Quantity	no:	1
Length	ft:	15
Quantity	no:	2
Length	ft:	20
Quantity		1
Thread protectors	yes/no:	yes
D.1.5DRILL PIPE PUP JOINT:	Size:	N/A
D 1.6HEAVY WEIGHT DRILL PIPE (Integral)
Quantity	no.:	30
Nominal size OD	inch:	5”
Weight	lbs/ft:	49.1 Nonimal
Range	:	2
Tool joint OD	inch:	6 5/8”
Tool joint ID	inch:	3 1/16”
Pin Stress relief groove	yes/no	yes
Box , Bore back	yes/no	yes
Type of hardfacing	:	Pinnchrome ( team to review)
Internally plastic coated	yes/no:	No
Connection type	:	4 1/2 IF
Thread protectors	yes/no:	Yes, Bale type
Quantity	no.:	30
Nominal size OD	inch:	5 1/2”
Weight	lbs/ft:	58” Nonimal
Range	:	2

21

Tool joint OD	inch:	7 1/4”
Tool joint ID	inch:	3 3/4”
Pin Stress relief groove	yes/no	No
Box , Bore back	yes/no	No
Type of hardfacing	:	Pinnchrome ( Team to review)
Internally plastic coated	yes/no:	No
Connection type	:	HT 55
Thread protectors	yes/no:	yes, Bale type
D.1.7DRILL COLLARS
Quantity	no.:	15
OD body	inches:	9.5
ID body	inches:	3”
Nominal Length of each joint	ft:	31.5 Nominal
Drill collar body (slick/spiral)	:	SPIRAL
Recess for “zip” elevator	yes/no:	yes
Recess for slips	yes/no:	yes
Stress relief pin groove	yes/no:	YES
Boreback on box	yes/no:	YES
B.S.R		2.72
Connection type	:	7 5/8”reg
Thread protectors	yes/no:	yes, Bale type
Quantity	no.:	15
OD body	inches:	8 1/4”
ID body	inches:	2 13/16”
Nominal Length of each joint	ft:	31.5 Ft Nomimal
Drill collar body (slick/spiral)	:	SPIRAL
Recess for “zip” elevator	yes/no:	yes
Recess for slips	yes/no:	yes
Stress relief pin groove	yes/no:	YES
Boreback on box	yes/no:	YES
B.S.R.		2.93
Connection type	yes/no:	6 5/8” reg
Thread protectors	yes/no:	yes, Bale type
Quantity	no.:	30
OD body	inches:	6 1/2
ID body	inches:	2 1/2”
Nominal Length of each joint	ft:	31.5 Ft Nominal
Drill collar body (slick/spiral)	:	SPIRAL
Recess for “zip” elevator	yes/no:	YES
Recess for slips	yes/no:	YES
Stress relief pin groove	yes/no:	YES
Boreback on box	yes/no:	YES
B.S.R		2.73
Connection type	yes/no:	4 ” IF
Thread protectors	yes/no:	yes, Bale type
D.1.8SHORT DRILL COLLARS		Company Supplied
D.1.9NON-MAGNETIC DRILL COLLARS		Company Supplied
D.1.10CORE BARRELS		Company Supplied

22

D.1.11STABILIZERS		Company Supplied
D.1.12ROLLER REAMERS		Company Supplied
D.1.13SHOCK ABSORBERS (Damping Sub)		Company Supplied
D.1.14DRILLING JARS		Company Supplied
D.1.15INSIDE BOP VALVE
Quantity	no.:	2
Make	:	SMF (provisional)
OD	inch:	TBA
Connection type	:	HT 55
Working pressure rating	psi:	15000
Quantity	no.:	2
Make	:	SMF (provisional)
OD	inch:	6 5/8”
Connection Type		4 1/2 IF
Working Pressure	psi	15000
D.1.16FULL OPENING SAFETY VALVE
Quanty		2
Make	:	SMF ( provisional)
O.D/ I.D	no.:	TBA ( Team to review & advise )
Connection type	:	HT 55
Working Pressure		15000
Quanty		2
Make	:	SMF ( provisional)
O.D/ I.D	no.:	6 5/8” / 2 13/16”
Connection type	:	4 1/2 IF
Working Pressure		15000
D.1.17CIRCULATION HEAD		N/A
D.1.18TOP DRIVE VALVES
Upper
Quantity	no.:	2
Make/Type	:	Varco
Working pressure	psi:	15000
Max. OD body	inch:	TBA
Min. ID body	inch:	TBA
Connection type	:	7 5/8 Reg
Lower
Quantity	no.:	2
Make/Type	:	Varco
Working pressure	psi:	15000
Max. OD body	inch:	TBA
Min. ID body	inch:	TBA
Connection type	:	7 5/8 Reg
D.1.19CIRCULATION SUBS		Company Supplied
D.1.20CUP TYPE TESTERS		Company Supplied
D.1.21PLUG TYPE TESTERS		Company Supplied
D.1.22DROP-IN VALVES		Company Supplied

23

D.1.23NEAR-BIT SUBS (Box-Box)
Quantity	no.:	2
OD size	inch:	9 1/2”
ID size	inch:	3”
Top connection	inch:	7 5/8 Reg
Boreback	Yes/No	Yes
BSR	:	2.25. - 3
Bottom connection	inch:	7 5/8 REG
Boreback	Yes/No	No
Bored for float valve	yes/no:	yes
Float size	inch:	5F-6R
Quantity	no.:	2
OD size	inch:	9 1/2”
ID size	inch:	2 13/16”
Top connection	inch:	7 5/8 REG
Boreback	Yes/No	Yes
BSR	:	2.25 - 3
Bottom connection	inch:	6 5/8 REG
Boreback	Yes/No	No
Bored for float valve	yes/no:	YES
Float size	inch:	5F-6R
Quantity	no.:	2
OD size	inch:	8 1/4”
ID size	inch:	2 13/16”
Top connection	inch:	6 5/8 Reg
Boreback	Yes/No	Yes
BSR	:	2.25 - 3
Bottom connection	inch:	6 5/8 Reg
Boreback	Yes/No	No
Bored for float valve	yes/no:	YES
Float size	inch:	5F-6R
Quantity	no.:	2
OD	inch:	6 1 /2
ID	inch:	2 1/2”
Top connection	inch:	4 1/2 XH
Boreback	Yes/No	Yes
BSR	:	2.25 - 3
Bottom connection	inch:	4 1/2 Reg
Boreback	Yes/No	No
Bored for float valve	yes/no:	YES
Float size	inch:	4 R
D.1.24CROSSOVER SUBS
Quantity	no.:	2
OD size	inch:	8 1/4” x 9 1/2”
Top connection size	inch:	6 5/8 REG
Type (pin/box)	:	BOX
I.D	:	2 13/16”
B.S.R	:	2.25 - 3
Boreback	Yes/No	Yes
Bottom connection size	inch:	7 5/8 REG
Type (pin/box)	:	PIN

24

I.D	:	3”
B.S.R	:	2.25 - 3
Relief Groove	Yes/No	Yes
Quantity	no.:	2
OD size	inch:	7 1/4” x 8 1/4”
Top connection size	inch:	HT 55
Type (pin/box)	:	BOX
ID	inch:	3”
B.S.R	:	2.25 - 3
Boreback	Yes/No	No
Bottom connection size	inch:	6 5/8 Reg
Type (pin/box)	:	PIN
I.D	:	3”
B.S.R	:	2.25 - 3
Relief Groove	Yes/No	Yes
Quantity	no.:	2
OD	inch:	7 1/4” x 6 1/2”
Top connection size	inch:	HT 55
Type (pin/box)	:	BOX
ID	inch:	2 1/2”
B.S.R	:	2.25 - 3
Boreback	Yes/No	No
Bottom connection size	inch:	4 1/2 XH (NC 46)
Type (pin/box)	:	PIN
I.D	:	2 1/2”
B.S.R	:	2.25 - 3
Relief Groove	Yes/No	Yes
Quantity	no.:	2
OD size	inch:	6 1/2” x 8 1/2”
Top connection size	inch:	4 IF (NC 46)
Type (pin/box)	:	BOX
ID	inch:	2 1/2”
B.S.R	:	2.25 - 3
Boreback	Yes/No	Yes
Bottom connection	inch:	6 5/8 Reg
Type (pin/box)	:	PIN
ID	inch:	2 1/2”
B.S.R	:	2.25 - 3
Relief Groove	Yes/No	Yes
Quantity	no.:	2
OD size	inch:	7 1/4 x 6 5/8
Top connection size	inch:	HT55
Type (pin/box)	:	Box
ID size	inch:	2 13/16”
B.S.R	:	2.25 - 3
Boreback	Yes/No	No
Bottom connection size	inch:	4 1/2 IF (NC 50)
Type (pin/box)	:	Pin
ID size	inch:	2 13/16”
B.S.R	:	2.25 - 3
Relief Groove:	Yes/No	Yes
Quantity	no.:	2

25

OD size	inch:	6 5/8 x 6 5/8
Top connection size	inch:	4 1/2 IF (NC 50)
Type (pin/box)	:	Box
ID size	inch:	2 1/2”
B.S.R	:	2.25 - 3
Boreback	Yes/No	Yes
Bottom connection size	inch:	4 IF (NC 46)
Type (pin/box)	:	Pin
ID size	inch:	2 1/2”
B.S.R	:	2.25 - 3
Relief Groove	Yes/No	Yes
Quantity	no.:	2
OD size	inch:	6 5/8 x 8 1/4
Top connection size	inch:	4 1/2 IF
Type (pin/box)	:	Box
ID size	inch:	2 13/16”
B.S.R	:	2.25 - 3
Boreback	Yes/No	YES
Bottom connection size	inch:	6 5/8 Reg
Type (pin/box)	:	Pin
ID size	inch:	2 13/16”
B.S.R	:	2.25 - 3
Relief Groove	Yes/No	Yes
D 1.25 STABBING SUBS - Approximately 9” long
Quantity	no.:	1
OD size	inch:	9.5
ID size	inch:	3
Top connection size	inch:	HT 55
Type (pin/box)	:	Box
Bottom connection size	inch:	7 5/8 Reg
Type (pin/box)	:	PIN
Quantity	no.:	1
OD size	inch:	9.5
Top connection size	inch:	4 1/2 IF
Type (pin/box)	:	Box
ID size	inch:	3
Bottom connection size	inch:	7 5/8 Reg
Type (pin/box)	:	PIN
Quantity	no.:	1
OD size	inch:	8.25
ID size	inch:	2 13 /16
Top connection size	inch:	HT 55
Type (pin/box)	:	BOX
Bottom connection size	inch:	6 5/8 REG
Type (pin/box)	:	PIN
Quantity	no.:	1
OD size	inch:	6.5
ID size	inch:	2.8125
Top connection size	inch:	HT 55
Type (pin/box)	:	BOX
Bottom connection size	inch:	4 IF

26

Type (pin/box)	:	PIN
D.1.26 PUMP IN / TESTING SUBS
Quantity	Pin/Box	1
Connection		HT 55 Box
Union type		2” 1502 Female
Quantity		1
Connection	Pin/Box	HT 55 Pin
Union Type		2” 1502 Female
Quantity		1
Connection	Pin/Box	4 1/2 IF Box
Union type		2” 1502 Female
Quantity		1
Connection	Pin/Box	4 1/2 IF Pin
Union type		2” 1502 Female
Quantity		1
Connection	Pin/Box	7 5/8 Reg Pin
Union Type		2” 1502 Female
D 1.27. SIDE ENTRY SUBS
Quantity		1
Top Connection	Box/Pin	HT 55 Box
Lower connection		HT 55 Pin
Outlet size and type		2” 1502 Female
Quantity		1
Top Connection	Box/Pin	4 1/2 IF Box
Lower connection		4 1/2 IF Pin
Outlet size and type		2” 1502 Female
D.1.28 DRILLING BUMPER SUBS		Company Supplied
D.1.29 HOLE OPENERS		Company Supplied
D.1.30 UNDERREAMERS		Company Supplied
D.2HANDLING TOOLS
D.2.1 DRILL PIPE ELEVATORS
Quantity	:	2
Make	:	Varco
Model	st:	BX 475
Drill Collars inserts 150 Ton		6 1/2” , 8 1/4” , 9 1/2”
Casing inserts 350 Ton	“	Company Supplied
Drill pipe Inserts 500 Ton		5 , 5 1/2”
Elevators 750 Ton		5”, 5-1/2”
BOP handling elevators	st:	1000 Refer E 6.10
D.2.2 DRILL COLLAR ELEVATORS
Size	inch:	N/A
Quantity	no.:
Make	:
Model	:
Rated capacity	st:

27

Size		inch:	N/A
Quantity		no.:
Make		:
Model		:
Rated capacity		st:
Size		inch:	N/A
Quantity		no.:
Make		:
Model		:
Rated capacity		st:
Size		inch:	N/A
Quantity		no.:
Make		:
Model		:
Rated capacity		st:
D.2.3 TUBING ELEVATORS		Type:	Company Supplied
D.2.4 DRILL PIPE HAND SLIPS
Size		inch	5 1/2 ”
Quantity		no.:	1
Make/Type		:	VARCO / SDXL
Size		inch	5
Quantity		no.:	1
Make/Type		:	VARCO / SDXL
D.2.5 POWER SLIPS
Make/Type			Varco PS 30
Quantity			1
Slip assembly	20” to 18 5/8”		1
Slip Assmebly	16 ” to 6 5/8		1
Slip Assembly	2 3/8 to 10 3/4”		1
Insert carriers Drillpipe		:	5 ”, 5 1/2” ,
Insert Carriers Drill collars			6 1/2, 8 1/4,9 1/2
Insert carriers Casing			Company supplied
Die sets for 13 3/8” 9 5/8 & 7” carriers			Company supplied
MOUSEHOLE SLIPS			Varco 18” Power Slips.
D.2.6 DRILL COLLAR SLIPS
Size		inch:	9.5
Quantity		no.:	1
Make/Type		:	VARCO / DCS-L
Size		inch:	8.25
Quantity		no.:	1
Make/Type		:	VARCO / DCS-L
Size		inch:	6.1/2
Quantity		no.:	1
Make/Type		:	VARCO / DCS-R
D.2.7 DRILL COLLAR SAFETY CLAMPS
Quantity		no.:	1

28

Model		MP-L
Range	:	19 3/8” to 4 1/2 “
D.2.8 TUBING SLIPS	:	Company Supplied
D.2.9 TUBING SPIDER	:	Company Supplied
D.2.10 DRILL COLLAR LIFTSUBS	:	As needed
D.2.11 DC LIFTING PLUGS	:	n/a
D.2.12 BIT BREAKER
Quantity	no.:	1
For bit size	inch:	26
Quantity	no.:	1
For bit size	inch:	17.1/2”
Quantity	no.:	1
For bit size	inch:	14 3/4”
Quantity	no.:	1
For bit size	inch:	12. 1/4
Quantity	no.:	1
For bit size	inch:	8.1/2
D.2.13. GAUGE RINGS
Sizes		26, 17 1/2, 14 3/4, 12 1/4, 8 1/2
D.2.14 ELEVATOR LINKS
Quantity of sets	no.:	1
Make/Type	:	VARCO
Size	inch:	3.5
Length	ft:	11
Rated capacity	st:	500
Quantity of sets	no.:	1
Make/Type	:	VARCO
Size	inch:	4 3/4”
Length	ft:	22
Rated capacity	st:	750
Quantity of sets	no.:	1
Make/Type	:	VARCO
Size	inch:	4 3/4”
Length	ft:	22
Rated capacity	st:	1000
D.2.15 DRILL PIPE SPINNER	Type:	Varco SSW-40
D.2.16 MUD SAVER BUCKET
Make	:	Dreco
Size	inch:	9 3/4 to 3 1/2”
Operation	:	Remote from DWS
D.2.17 EZY TORGUE
Make/Type	:	Varco
Maximum linepull	lb:	31000
Quantity		2

29

D.2.18 ROTARY RIG TONGS
Quantity	no.:	2
Make/Type	:	Varco HT 100
Size range (max OD/min OD)	inch/inch:	17 to 4
Torque rating	ft lbs:	Max 100,000, reduces depending on size
Quantity	no.:	2
Make/Type	:	Varco HT 50
Size range (max OD/min OD)	:	17 1/4 to 20”
Torque rating	Ft/lb:	50000
D.2.19 TUBING TONGS (MANUAL)
D.2.20 TUBING TONGS (POWER)
D.2.21 IRON ROUGHNECK
Make/Type	:	VARCO / AR3200
Size range (max OD/min OD) Drill Coll inch/inch:		4 “ to - 9 1/2”
Size range (max OD/min OD) Drillpipe		3 1/2” to 6 5/8
D.3 FISHING EQUIPMENT
D.3.1 OVERSHOTS
Quantity	no.:	1
Make/Type	:	F.S
Top sub connection type	:	6 5/8 Reg
Overshot OD	inch:	11 3/4”
Max catch size	inch:	9 1/2”
To catch size Spiral grapple	inch:	9.1/2
		9 3/8,8 1/2,8 3/8,8 1/4,8 1/8,7 1/4,7 1/8,7, 6 7/8, 6 5/8,6
To catch size Basket grapple	inch:	1/2, 6 3/8, 5 1/2, 5
Control rings		For above grapples
Extension sub length	ft:	2.5
Lipped guide (oversize, regular)	“:	113/4,15, 21
Quantity	no.:	1
Make/Type	:	TBA S.H Series 150
Top sub connection type	:	4 IF
Overshot OD	inch:	8.3/8
Max catch size	inch:	7 1/4”
To catch size Spiral grapple	inch:	7 1/4, 7 1/8, 7, 6 7/8,
To catch size Basket grapple	inch:	6 5/8, 6 1/2, 6 3/8, 5 1/2, 5
Control rings		For above grapples
Extension sub length	ft:	2.5
Lipped guide (oversize, regular)	:	8 3/8, 11,
D.3.2 HYDRAULIC FISHING JAR		Company Supplied
D.3.3 JAR INTENSIFIER		Company Supplied
D.3.4 SURFACE JAR		Company Supplied
D.3.5 FISHING BUMPERSUBS
Quantity	no.:	1
Make/Type	:	TBA
OD body	inch:	8
Min.ID	inch:	3.5

30

Stroke	inch:	20
Connection type	:	6 5/8 Reg
Quantity	no.:	1
Make/Type	:	TBA
OD body	inch:	6.25
Min. ID	inch:	2.25
Stroke	inch:	20
Connection type	:	4 IF
D.3.6SAFETY JOINTS		Company Supplied
D.3.7 JUNK BASKETS (REVERSE CIRC.)		Company Supplied
D.3.8 JUNK SUBS		Company Supplied
Quantity	no.:	1
Make/Type	:	TBA
For hole size	inch:	17.5
Boot OD	inch:	12.875
Connection type	:	7 5/8 Reg
Quantity	no.:	1
Make/Type	:	TBA
For hole size	inch:	12.25
Boot OD	inch:	9.625
Connection type	:	6 5/8 Reg
Quantity	no.:	1
Make/Type	:	TBA
For hole size	inch:	8.5
Boot OD	inch:	6.625
Connection type	:	4 1/2 Reg
D.3.9 FLAT BOTTOM JUNK MILL		Company Supplied
D.3.10 MAGNET FISHING TOOL
Quantity	no.:	1
Make/Type	:	TBA/ Flush guide
OD body	inch:	16
Hole size	inch:	17.5
Connection type	:	6 5/8 reg
D.3.11 TAPER TAPS		Company Supplied
D.3.12 DIE COLLARS		Company Supplied
E. WELL CONTROL/SUBSEA EQUIPMENT
E.1 LOWER RISER DIVERTER ASSY		N/A
E.2PRIMARY BOP STACK (from bottom to top)
Stack complete with:
· guide frame	yes/no:	YES
· pick up attachment	yes/no:	YES
· transport base	yes/no:	YES
Size (bore)	inch:	18.75
Working pressure	psi:	15000
H2S service	yes/no:	YES

31

E.2.1 ALTERNATE HYDRAULIC CONNECT N/A
E.2.2 HYDRAULIC WELLHEAD CONNECTOR
Size	inch:	18-3/4”
Make/Type	:	Vetco SD H-4
Working pressure	psi:	15000
Hot tap for underwater intervention ROV	yes/no:	YES
Spare connector same type	yes/no:	NO
Hydrate seal	yes/no:	Yes (1 oring & 1 Lip seal Option as STD.)
Glycol Injection ( ROV)	yes/no:	yes (4 x 1” Npt @ 90 deg increments
Pilot Operated check Valve, close function	Yes/No:	Yes
E.2.3 RAM TYPE PREVENTERS
Preventers:
Quantity	no.:	5
Bore size	inch:	18.3/4”
Working Pressure	psi:	15000
Make	:	CAMERON or equivalent
Model	:	TYPE T1
Type (single/double)	:	Double x2 , Single x 1
Stack Configuration	:	Al, A2, CL, SSCSR BSR,VBR,VBR,LFPR,CH
Ram locks	yes/no:	YES
Preventer connection type - top	:	CX18 (BX-164 Option Available)
Preventer connection type - bottom	:	CX18 (BX-164 Option Available)
Side oultlets	yes/no:	YES
Size	inch:	3.1/16
Connection type	:	No. 6 CAMERON CLAMP AX GROOVE
Super/Shear rams:		Less than or equal to 13-5/8”
Quantity	no.:	1 set
Blind/Shear rams:
Quantity	no.:	1 set
Variable rams:
Quantity	no.:	1 set
Size range (max/min)	inch/inch:	Customer to advise
Quantity	no.:	1 set
Size range (max/min)	inch-inch:	Customer to advise
Pipe rams:
Quantity	no.:	1 set
Size	inch:	Customer to advse
E.2.4 STACK CONFIGURATION
(Blind/Shear/Pipe/Variable)
Upper Shear ra Cavity 5		SSCSR (Less than or equal to 13-5/8”)
Lower shear ra Cavity 4	:	BSR
Middle Upper Cavity 3	:	VBR
Middle Lower Cavity 2	:	VBR
Lower rams Cavity 1	:	LFPR
Position of side outlets - kill
Upper	:	Below BSR (Cavity #4)
Lower	:	Below LFPR (Cavity #1)

32

Position of side outlets - choke
LMRP		Below upper Annular (Al)
Stack		Below Top VBR (Cavity #3)
Stack	:	Below Bottom VBR (Cavity #2)
E.2.5 ANNULAR TYPE PREVENTER ON STACK
Size	inch:	n/a
Working pressure	psi:	n/a
Make/Type	:	n/a
E.2.6 MANDREL
Make/Type	:	Cameron 18-3/4 10 HC
Size	inch:	18.75
E.2.7 FAIL-SAFE HYDRAULIC VALVES
(Kill and Choke)
Quantity on each side outlet	no.:	2
Size (ID)	inch:	42430
Make/Type	:	Cameron MCS
Working pressure	psi:	15000
Solid block	yes/no:	YES
E.2.8 SUBSEA ACCUMULATORS
(See also E.7.1 - Surface Accummulator Unit)
Quantity	no.:	17 ( team to evaluate)
Useful capacity per accumulator (w/o prUS gallons	:	13.1
Bottle working pressure	psi:	5000 (team to evaluate)
E.2.9 HYDRAULIC CONTROL POD/RECEPTACLES
Quantity	no.:	2
Redundancy	%:	100
Color Coded	yes/no:	YES
Remote regulation of operating pressure for
functions requiring lower operating press	yes/no:	YES
Spare control pod	yes/no:	NO
Deadman system	yes/no:	YES
Pressure & tempreture Sensor’s LMRP	yes/no:	YES
E.3 PRIMARY LOWER MARINE RISER PACKAGE
(From Bottom To Top)
E.3.1 HYDRAULIC CONNECTOR
Make/Type	:	Cameron 18-3/4-10 HC or equivalent
Size	inch:	18.75
Working pressure	psi:	10000
Hot tap for underwater intervention	yes/no:	YES
Spare connector same type	yes/no:	NO
E.3.2 ANNULAR TYPE PREVENTER (LMRP)
Size	inch:	18-3/4”
Qty.	no:	2
Working pressure	psi:	10000
Make/Type (2*70.5=141” Total Heigl	:	CAMERON TYPE DL

33

E.3.3 FLEX JOINT
Make/Type	:	Oil States 18-3/4”
Size	inch:	21
Max deflection	degrees:	20 (10 from vertical)
E.3.4 RISER ADAPTER
Make/Type	:	Vetco HMF-class H
Size	inch:	21
E.3.5 CONNECTION LINES TO RISER
Type (rigid loops, coflexip, etc.)	Make:	COFLEXIP
	Size:	3-1/16
	WP:	15,000 psi
	Collapse Psi	12,7l0psi
E.3.6 RISER CENTRALIZER		Hydralift
E.4 ANNULAR GAS HANDLER
Make / Type		Supplied by Company at later date. Hard piping and control functions to be supplied by Contractor
Rating		1,500 psi
Number Outlets		2
Number Valves		4
E.5 SECONDARY LOWER MARINE RISER P N/A
E.6 PRIMARY MARINE RISER SYSTEM
E.6.1 MARINE RISER JOINTS		To be designed for 10,000’ wd
Make/Model	:	Vetco or equivalent (HMF-class H)
OD	inch	To be determined by final riser analysis
ID	inch	To be determined by final riser analysis
Wall thickness	inch:	To be determined by final riser analysis
Average length of each joint	ft:	90
		62,311 for 5k buoancy, 54,424 for 3k buoancy, 31,620
Weight of one complete joint (in air)	Ibs:	for 3/4” Slick, 36,900 1” slick
Quantity	no.:	Sufficient for 8,000 ft. water depth
Pipe material	grade:	API 5L Grade X80 Mod.
Minimum yield strength	psi:	80KSI
Type riser connectors	:	HMF- class H
Dogs	no.:	To be determined by final riser analysis
Pup joints:
Quantity	no.:	1
Length	ft:	45.0’
Quantity	no.:	1
Length	ft:	37.5’
Quantity	no.:	1
Length	ft:	30.0’
Quantity	no.:	1
Length	ft:	22.5’

34

Quantity	no.:	1
Length	ft:	15’
E.6.2 TELESCOPIC JOINT
Make/Type	:	Vetco
Size (ID)	inch:	19.25
Stroke	ft:	65
Double Seals	yes/no:	YES
Working pressure	psi	500
Spare telescoping joint	yes/no:	no
Location	:	N/A
Rotating support ring for riser tensioners	type:	Vetco SDC
Connection points	no.:	6
E.6.3 KILL/CHOKE LINES
Quantity	no.:	2
Outside diameter	inch:	6.5
Inside diameter	inch:	4.5
Working pressure	psi:	15000
LMRP Isolation valves	YES/NO	YES. Fail Close
E.6.4 BOOSTER LINES (If Fitted)
Quantity	no.:	1
Outside diameter	inch:	4.5
Inside diameter	inch:	3.83
Working pressure	psi:	6000
LMRP Isolation valve	YES/NO	YES
E.6.5 HYDRAULIC SUPPLY LINES
Quantity	no.:	1
Outside Diameter	inch:	3.5
Inside Diameter	inch:	2.62
Working pressure	psi:	5000
E.6.6 UPPER BALL (FLEX) JOINT
Make/Type	:	Oilstates Diverter 3
Size	inch:	21-1/4
Maximum deflection	deg.:	30 (15 from vertical)
Spare upper ball (flex) joint	yes/no.:	NO
E.6.7 BUOYANCY MODULES (If Fitted)
Make	:	To be determined by riser analysis
Quantity of buoyed riser joints	no.:	To be determined by riser analysis
OD of buoyed riser joints	inch:	To be determined by riser analysis
Length of each module	ft:	To be determined by riser analysis
Volume of each module	ft3:	To be determined by riser analysis
Buoyancy in seawater	st/ft3:	To be determined by riser analysis
Rated water depth	ft:	To be determined by riser analysis
Make	:	To be determined by riser analysis
Quantity of buoyed riser joints	no.:	To be determined by riser analysis
OD of buoyed riser joints	inch:	To be determined by riser analysis

35

Length of each module	ft:	To be determined by riser analysis
Volume of each module	ft3:	To be determined by riser analysis
Buoyancy in seawater	st/ft3:	To be determined by riser analysis
Rated water depth	ft:	To be determined by riser analysis
E.6.8 MARINE RISER SPIDER
Make/Type	:	VETCO / HYDRAULIC
E.6.9 Marine Riser Gimbal
Make/Type	:	VETCO
E.6.10 RISER HANDLING TOOLS
Tool, riser lifting	no.:	3
1000 ton Solid Body Elevators	no :	1 set ( team to evaluate)
Type	:	HMF- Class h
Torque Wrenches	:	2 - dual speed
E.6.11 RISER TEST TOOLS
Quantity	no.:	2
Type	:	HMF- Class H Hydraulic Test Tool
E.6.12 INSTRUMENTED RISER JT	:	N/A
E.7 SECONDARY MARINE RISER	:	N/A
E.8 DIVERTER BOP
(For installation in fixed bell nipple)
Make/Type	:	Hydril 60
Max Bore Size	inch:	21-1/4
Working pressure	psi:	500
Number of diverter outlets	no.:	2
Outlet OD	inch:	14
Insert packer size ID	inch:	N/A CSO
Element type.	:	Nitrile rubber
Running from diverter to	:	Overboard , port/ starb./ Poorboy MGS
E.8.1 DIVERTER FLOWLINE
Quantity	no.:	1
I.D of flowline	inch:	16” Nominal
Valve types	:	Diverter Sleeve
Size	inch:	16
Working pressure	psi:	500
Control valve type (air/hydraulic/etc.)	:	HYDRAULIC
Remote controlled from	location:	DRILLERS WORKSTATION
E.8.2 DIVERTER CONTROL PANELS
Driller’s panel
Make	:	CAMERON OR EQUIVALENT
Model	:	MULTIPLEX
Location	:	DRILLERS WORKSTATION
Locking/unclocking control	yes/no:	YES

36

Remote panel
Make		: CAMERON
Model		: MULTIPLEX
Location		: CONTROL ROOM
Locking/unclocking control	yes/no	: YES
E.9SUBSEA SUPPORT SYSTEM
E.9.1RISER TENSIONERS		Ability To Skid Tensioners From Well Centerline
Quantity	no.:	6
Make/Type	:	HYDRALIFT - INLINE
Capacity each tensioner	st:	800 kips
Maximum stroke	ft:	50
Wireline size	inch:	N/A (9” ROD)
Line travel	ft:	N/A (9” ROD)
Independent air compressors	yes/no:	YES
Independent air drying unit	yes/no:	YES
Riser Recoil System	yes/no:	yes
E.9.2GUIDELINE SYSTEM		N/A
E.9.3 REMOTE GUIDELINE REPL. TOOL		N/A
E.9.4REMOTE GUIDELINE CUTTING TOOL		N/A
E.9.5POD LINE TENSIONERS		TURN DOWN SHEAVE’S COMPLETE WITH STORM LOOP WITHIN MOONPOOL INCLUDED WITHIN DESIGN LAYOUT
E.9.6TENSIONER/COMPENSATOR AIR PRESSURE VESSELS
Quantity	no.:	30
Total capacity	ft3:	2747
Rated working pressure	psi:	3000
Pressure relief valve installed	yes/no:	YES
E.10BOP CONTROL SYSTEM
		Cameron or equivalent Mux system including: 2 each remote control panels, one located in driller’s house and one in the control room, both panels incorporate full function and monitoring system for BOP’s and diverter system. 1 each pod test stand and Mux system analyzer consisting of test stand and portable computer test set. 2 each Mux cable reels complete with 11,000’ of Multiplex cable, one reel blue and one reel yellow for functioning yellow and blue pods plus one spare. 2 each stack mounted pods, complete with subsea electronics
E.10.1SURFACE ACCUMULATOR UNIT
(See also E.2.8 & E.4.8 - Subsea Accumulators)
Make	:	CAMERON or equivalent
Model/Type	:	MUX
Location	:	ACCUMULATOR ROOM
Soluble oil reservoir capacity	US gallons:	300
Oil/water mix.capacity	US gals/min:	838
Glycol reservoir capacity	US gallons:	1000

37

No. of bottles installed	no.:	38 team to evaluate bottles required for 10,000’
Useful cap. per accum. (w/o pre-charge)US gallons	:	40
Bottle working pressure	psi:	5000
Control manifold model	:	MULTIPLEX
Regulator type	:	PRESSURE SWITCH / RELIEF VALVES
Total useful accumulator volume (surface and stack)
Equals all preventer opening and closing	yes/no:	YES
Plus percent additional volume	%:	50
E.10.2ACCUMULATOR HYDRAULIC PUMPS
Electric Driven
Quantity	no.:	2
Power source	:	From BUS A
Make	:	US Motors
Model	:
Each driven by motor of power	hp:	100
Flow rate of each pump	US gals/min:	26
At minimum operating pressure	psi:	5000
Secondary
Quantity	no.:	1
Power source	:	From BUS B
Make	:	US Motors
Model	:
Each driven by motor of power	hp:	100
Flow rate of each pump	US gals/min:	26
At minimum operating pressure	psi:	5000
E.10.3DRILLER’S CONTROL PANEL
Graphic control panel at driller’s position showing subsea functions with controls for the following functions of the BOP stack Location.		Driller Work Station.
Boost Line Control Valve	yes/no:	YES
Marine riser connector	yes/no:	YES
All annular type BOP’s	yes/no:	YES
All ram type BOP’s	yes/no:	YES
Lock for ram type BOPs	yes/no:	YES
Wellhead and LMRP connector	yes/no:	YES
Inner and outer kill and choke line valve:	yes/no:	YES
Low acc. pressure warning	yes/no:	YES
Low reservoir level warning	yes/no:	YES
Low rig air pressure warning	yes/no:	YES
Pressure regulator for annular	yes/no:	YES
Flowmeter	yes/no:	YES
Quantity of pressure gauges	no.:	7+
Emergency push button for automatic riser disconnection	:	YES
Other control functions	yes/no:	YES
Control panel make	:	CAMERON
Control panel model	:	MULTIPLEX

38

E.10.4REMOTE CONTROL PANELS
Ability to operate main closing unit valv	yes/no:	NO
Quantity	no.:	2
Make/Model	:	CAMERON / MULTIPLEX
Locations	:	DRILLERS WORK STATION & CONTROL ROOM
Operating System Routing (Direct/via Primary Control Panel)	:	DIRECT DUAL BUS
E.11SUBSEA CONTROL SYSTEM
E.11.1HOSE REELS
Quantity	no.:	2 Bop Control (MUX)
Location	:	MOONPOOL
Make/Type	:	CAMERON
Maximum storage length each	ft:	11000
Drive motor type	:	AIR
Quantity	no.:	1 HOTLINE
Location	:	MOONPOOL
Make/Type	:	SYNFLEX (KEVLAR)
Maximum storage length each	ft:	11,000
Drive motor type	:	AIR
E.11.2POD HOSE
E.11.3POD HOSE MANIFOLD
Make/Model	:	NONE
Surface test stump	yes/no:	YES
E.11.4SURFACE TEST POD	yes/no:	N/A
E.12ACOUSTIC EMER. BOP CONTROL SYS	:	N/A
E.13SUBSEA AUXILARY EQUIPMENT
E.13.1HOLE POSITION INDICATOR
Make/Type	:	Simrad
Quantity of monitors	no.:	2 (Blue pod / Yellow pod)
Monitor location	:	Drillers Work station
Monitor location	:	Control Room
Recorder	yes/no:	no
E.13.2RISER ANGLE INDICATOR
Make/Type	:	To be incorporated into Mux system
Quantity of monitors	no.:	2 (Blue pod / Yellow pod)
Monitor location	:	Drillers Work station
Monitor location	:	Control Room
Recorder	yes/no:	no
Location		Flex joint neck
E.13.3SLOPE INDICATORS
Make	:	RECAN

39

Quantity	no.:	3
Provision for installation on
BOP	yes/no:	YES
Pin Connector	yes/no:	NO
Other	:	LOWER STACK, LMRP & RISER
E.13.5ROV System		Power and foundations supplied
E.14CHOKE MANIFOLD		Per Drawing # D-233669
E.14.1 CHOKE MANIFOLD (For Instrumentation, see H.3)
Make	:	CONTROL FLOW
Minimum ID	inch:	3-1/16
Maximum WP	psi:	15000
H2S service	yes/no:	YES
Quantity of fixed chokes	no.:	n/a
Make	:	n/a
Model	:	n/a
Size (ID)	inch:	n/a
Quantity of adjustable chokes	no.:	n/a
Make	:	n/a
Model	:	n/a
Size (ID)	inch:	n/a
Quantity of power chokes	no.:	3 ( team to evaluate)
Make	:	CONTROL FLOW
Model	:	15000
Size (ID)	inch:	2 Team to evaluate
Power choke remote control panel	yes/no:	YES
Make	:	Houston Digital
Model	:	CPU 27” MONITOR AND MANUAL HYD. BACK-UP.
Location	:	DRILLERS WORKSTATION / CHOKE MANIFOLD
Glycol injection	yes/no:	NO
E.14.2FLEXIBLE CHOKE AND KILL LINES (Connecting Riser to Drilling Unit)
Quantity	no.:	2
Make/Type	:	Coflexip
ID	inch:	3 ( team to review)
Working pressure/test pressure	psi/psi:	15000 / 22500
Quantity	no.:	n/a
Make/Type	:	n/a
ID	inch:	n/a
Working pressure/test pressure	psi/psi:	n/a
E.15BOP TESTING EQUIPMENT
E.15.1HYDRAULIC BOP TEST PUMP
Make	:	SHAFFER
Model/Type	:	ELECTRO HYDRAULIC VARIABLE SPEED 5 GPM
Pressure rating	psi:	22500

40

Chart recorder	yes/no:	0-5000 0-30000
E.15.2BOP TEST STUMP
Quantity	no.:	1
Test pressure	psi:	15000
Type	:	VETCO / CAMERON
Size	:	18.75
Connected to deck (welded/bolted)	:	BOLTED
E.16WELLHEAD RUNNING/RETRIEVING/TESTING TOOLS (RT/RRT/TT)
E.16.1RT’s FOR CASING INSTALLATION		Company Supplied
E.16.2RRT’s FOR CASING INSTALLATION		Company Supplied
E.16.3MISCELLANEOUS TOOLS		Company Supplied
E.16.4DP HANG-OFF SUBS		Company Supplied
E.16.5MINI HOSE BUNDLE FOR HYD. R. TOOLS		Company Supplied
E.16.6EMERGENCY BOP RECOVER	yes/no:	yes
Make/type	:	CAMERON
F.1HIGH PRESSURE MUD SYSTEM
System working pressure	psi:	7500
System test pressure	psi:	11250
Built to which design standard	:	ANSI, API
F.1.1MUD PUMPS
Quantity	no.:	4
Make	:	National
Model	:	14P-220
Type (Triplex/Duplex)	:	Triplex
Liner sizes available	inch:	5” - 9”
Mud pump drive motors	no.:	2
Motor type	:	AC
Continuous power rating per motor	hp:	1150
Fluid end	type:	Two piece
Maximum working pressure	psi:	7500
Test pressure	psi:	11250
Pump stroke counter	type:	Hitec
Supercharging pump	type:	Halco
Driven by motor of power	bp:	100
Discharge/Suction line ID	inch/inch	5” / 10”
M.P. Pulsation Dampener	type:	White Rock
Soft Pump	:	I system
Reset Relief Valve	type:	TBA
Working flowrate per pump at 90% of max spm
Maximum SPM	:	105 SPM @ 100%

41

F.1.2TRANSFER PUMPS/MIXING PUMPS (centrifugal)
Treatment pumps (Desilter/Desander)
Quantity		4
Make		Halco
Model		2500
Drive motor type		Electric
Power output		100 hp
Impeller		14”
Impeller speed		1200 rpm
Packing type		Mechanical seal
Mixing Pumps
Quantity	no.:	2
Make	:	Halco
Model	:	2500
Drive motor type	:	Electric /Belt
Power output	hp:	100
Impeller	:	14”
Impeller speed	RPM:	1200
Packing type	;	Mechanical seal
Shearing Pumps
Quantity	no.:	2
Make	:	Halco
Model	:	T 6550
Drive motor type	:	Electric /Belt
Power output	hp:	100
Impeller	:	Shearing type
Impeller speed	RPM:	1800
Packing type	;	Mechanical seal
Charging Pumps
Quantity	no.:	4
Make	:	Halco
Model	:	2500
Drive motor type	:	Electric /Belt
Power output	hp:	100
Impeller	:	14”
Impeller speed	RPM:	1200
Packing type	;	Mechanical seal
Column Transfer
Quantity	no.:	4
Make	:	Halco
Model	:	2500
Drive motor type	:	Electric /Belt
Power output	hp:	125
Impeller	:	12
Impeller speed	RPM:	1800
Packing type	;	Mechanical seal
F.1.3BOOSTER PUMP
Quantity	no.:	Rig Mud pump
Make/Type	:
Pumping capacity (each)	US gals/min:

42

Drive motor type	:
Power output	hp:
F.1.4 STANDPIPE MANIFOLD
Quantity of standpipes	no.:	2 @ 7500 psi wp
Standpipes ID	inch:	5
H-Type standpipe manifold	yes/no:	yes
Kill line outlet	yes/no:	yes
Fill-up/bleed-off line outlet	yes/no:	yes
Outlets (total)	no.:	4
ID	inch:	5 & 3
Type connections	:	Weco
Dimensions OD x ID	inch x inch:	6 x 5
Design standard	:	ANSI, API
F.1.5 ROTARY HOSES
Quantity	no.:	2 @ 7500 psi wp
Make/Type	:	Beattie
ID x length	inch x ft:	4 x 88
Snubbing lines	yes/no:	yes
F.1.6 CEMENTING HOSE
Type (i.e. Coflexip)	:	Beattie
Length	ft:	85
ID	inch:	3
Working pressure	psi:	15000
F.1.7 CHIKSAN STEEL HOSES
Integral non-screwed	yes/no:	yes
Make/type	:	TBA / 1502
ID Nonimal	inch:	2”
Section length	ft:
Quantity	no.:
Section length	ft:
Quantity	no.:
Sweep swivels, make/type	:
Nom. size ID	inch:
Fittings, non-screwed type	yes/no:	Yes
Suitable for H2S service	yes/no:
F.2 LOW PRESSURE MID SYSTEM
F.2.1 MUD TANKS
Quantity	no.:	15
Column Tanks
Quanity	:	4
Capacity 85%		4600
Surface Tanks

43

Quanity		10
Capacity 85%		4000
Capacity, tank No. 1	bbls:	460
Type (active/reserve)	:	Active
Capacity, tank No. 2	bbls:	460
Type (active/reserve)	:	Active
Capacity, tank No. 3	bbls:	460
Type (active/reserve)	:	Active
Capacity, tank No. 4	bbls:	650
Type (active/reserve)	:	Active
Capacity, tank No. 5	bbls:	650
Type (active/reserve)	:	Active
Capacity, tank No. 6	bbls:	680
Type (active/reserve)	:	Active
Capacity, tank No. 7	bbls:	160
Type (active/reserve)	:	Chemical
Capacity, tank No. 8	bbls:	160
Type (active/reserve)	:	Chemical
Capacity, tank No. 9	bbls:	160
Type (active/reserve)	:	Chemical
Capacity, tank No. 10	bbls:	160
Type (active/reserve)	:	Chemical
Mixer in each tank	yes/no:	Yes
Mud guns in each tank	yes/no:	Yes
F.2.2 PROCESSING TANKS
Quantity	no.:	6
Total capacity (@ 100%)	bbls:	450
Capacity Sand Trap tank	bbls:	75
Capacity degasser tank	bbls:	75
Capacity desander tank	bbls:	75
Capacity desilter tank	bbls:	75
Capacity desilter tank	bbls:	75
Capacity treated mud tank	bbls:	75
F.2.3 PILL/SLUG TANK
Capacity (@ 100%)	bbls:	150
Mud agitator	yes/no:	yes
Mud guns	yes/no:	yes
F.2.4 TRIP TANK
Capacity (@ 100%)	bbls:	100 2 x 50
Capacity/foot	bbls/ft:	TBA
Level indicator	yes/no:	yes
Electric pump make		Halco x 2
Model/type	:	Cent.
Motor output	hp:	30
Facility for casing fill-up	yes/no:	no
Alarm and strip chart recorder (See H.1.;11)	yes/no:	Yes

44

F.2.5 STRIPPING TANK
Capacity (@100%)	bbls:	10 Approx
Capacity/foot	bbls/ft:	TBA
Equalizing facility with triptank	yes/no:	Yes
Transfer pump	yes/no:	No
Alarm and strip chart recorder (See H.1.	yes/no:	Yes
F.2.6 CHEMICAL MIXING TANK		Separate mixing tank above for mixing caustic
Capacity	bbls:	See F.2.1 Tks. 7- 10
Chemical mixer type	:
F.2.7 SHALE SHAKERS
Primary:
Quantity	no.:	7
Make/Model	:	Brandt/LCM-2D CS
Type	:	Linear Motion/ Cascading
Driven by no. of electric motors	no.:	3
Design flowrate	bbl/min:	Depending on Mud Characteristics
Cascading:
Quantity	no.:	See Above
Make/Model	:
Type	:
Driven by no. of electric motors	no.:
Design flowrate	bbl/min:
F.2.8 DESANDER
Quantity	no.:	Desander cones over one cascading shale shaker
Make/Model	:	Brandt
Type	:
Number of cones x sizes	no. x inch:	6 X 12” w/ discharge overboard
Type/size centrifugal pump	:
Driven by electric motor of	hp:
Is pump dedicated to desander	yes/no:
Max. flowrate	bbl/min:
F.2.9 DESILTER
Quantity	no.:	Desilter cones over one cascading shale shaker
Make/Model	:	Brandt
Type	:
Number of cones x sizes	no. x inch:	40 X 4” W/ discharge over shaker or overboard
Type/size centrifugal pump	:
Driven by electric motor of	hp:
Is pump dedicated to desilter	yes/no:
Max. flowrate	bbl/min:
F.2.10 MUD CLEANER
Quantity	no.:	N/A
Make/Model	:
Type	:
Number of cones x sizes	no. x inch:

45

Type/size centrifugal pump	:
Driven by electric motor of	hp:
Is pump dedicated to mud cleaner	yes/no:
Max. flowrate	bbl/min:
Inlet and outlet for centrifuge to be provided
F.2.11 MUD/GAS SEPARATOR (Poor Boy)		Shall be capable to direct flow from flowline to MGS
Make/Type	:	Swaco
Gas discharge line ID	inch:	12” nominal
Gas discharge location, primary		Top
Can discharge be tied into burner system	yes/no:	no
Mud seal height	:	20
Calculated gas throughput	mmscf:	20
Dimensions		OAL 41.5 ft. X 6 ft.
F.2.12 DEGASSER
Quanty		2
Make/Type	:	Burgess/1500
Capacity	:	1000 GPM x 2
Type/size centrifugal pump	:	N/A
Driven by electric motor of power	hp:	N/A
Discharge line running to	:	6”
Vacuum pump make	:	Internal
Type	:
F.2.13 MUD AGITATORS
Quantity	no.:	6
Make/Model	:	Philadelphia
Driven by motor of power	hp	15
Located in tanks (See F.2.1 for tank numbers)		8, 9, & 10
Quantity	no.:	3
Make/Model	:	Philadelphia
Driven by motor of power	hp	5
Located in tanks (See F.2.1 for tank numbers)		Shaker Tanks
Quantity	no.:	4
Make/Model	:	Philadelphia
Driven by motor of power	hp	10
Located in tanks (See F.2.1 for tank numbers)		1, 2, 3, & 4
Quantity	no.:	3
Make/Model	:	Philadelphia
Driven by motor of power	hp	40
Located in tanks (See F.2.1 for tank numbers)		5, 6, & 7
F.2.14 MUD CENTRIFUGE
Quantity	no.:	Power and space for 2
F.2.15 MUD HOPPER
Quantity	no.:	2
Make/Model	:	Halco

46

Feed pump make/model	:	Mixing pumps
F.2.16 SHEARING HOPPERS
Quantity	no.:	2
Make/Model	:	Halco/105-15
Feed pump make/model	:	Mixing pumps
F.2.17 DECK HOPPER
Quantity	no.:	1
Make/Model	:	Halco
Feed pump make/model	:	Mixing pumps
F.3 BULK SYSTEM
F.3.1 BARITE/BENTONITE SILOS
Quantity	no.:	5
Capacity of each silo	C.F.:	2500
Locations	:	Columns
Type weight loadcell	:	Hydraulic
Manufacturer	:	Martin Decker
Pressure rating		65
Relief valve(s) installed	yes/no:	yes
F.3.2 BARITE DAY TANKS
Quantity		2
Capacity of each silo	C.F:	1200
Locations	:	Moonpool
Type weight loadcell	:	Hydraulic
Manufacturer	:	Martin Decker
Pressure rating	psi:	65
Relief valve(s) installed	yes/no:	yes
F.3.3 SURGE TANK FOR BARITE
Quantity	no.:	2
Capacity of each tank	It:	70
Type weight loadcell	:	Hydraulic
Manufacturer	:	Martin Decker
Pressure rating	psi:	65
Relief valve(s) installed	yes/no:	yes
F.3.4 CEMENT SILOS
Quantity		3
Capacity of each silo	C.F:	2800
Locations	:	Columns
Type weight loadcell	:	Hydraulic
Manufacturer	:	Martin Decker
Pressure rating	psi:	65
Relief valve(s) installed	yes/no:	yes
Separate mud/cement loading facilities	yes/no:	yes
Discharge line for cement independent from

47

barite/bentonite discharge line	yes/no:	Yes
F.3.5 CEMENT DAY TANKS
Quantity		2
Capacity of each silo	C.F:	1100
Locations	:	Cement Room
Type weight loadcell	:	Hydraulic
Manufacturer	:	Martin Decker
Pressure rating	psi:	65
Relief valve(s) installed	yes/no:	yes
F.3.6 SURGE TANK FOR CEMENT		Third party
F.3.7 BULK TRANSFER SYSTEM (See also C.1.8 - Compressed Air Systems)
Independent air system for the silos and surge tanks consisting of a high-volume low-pressure compressor and air drier	yes/no:	no
Air reduced from main air supply through pressure regulators	yes/no:	yes
Separate volume tank and drier	yes/no:	no
G. CASING/CEMENTING EQUIPMENT		Company Supplied
G.1 CASING EQUIPMENT		Company Supplied
G.1.1 API CASING DRIFT		Company Supplied
G.1.2 CLAMP-ON CSG THREAD PROT’S		Company Supplied
G.1.3 CASING ELEVATOR
Manufacturer		Company Supplied
Type
Capacity	st:
Inserts for	inch:
G.1.3 SIDE DOOR CASING ELEVATOR		Company Supplied
G.1.4 SINGLE JOINT CASING ELEVATOR		Company Supplied
G.1.5 SLIP TYPE ELEVATOR/SPIDERS
Quantity	no.:	Company Supplied
G.1.6 CASING SLIPS (Hand)
Quantity	no.:	Company Supplied
Make/Type	:
For OD casing	inch:
Quantity	no.:
Make/Type	:
For OD casing	inch:
Quantity	no.:
Make/Type	:
For OD casing	inch:
G.1.7 CASING BOWLS
Quantity	no.:	Company Supplied

48

Make/Type	:
For OD casing (max/min)	inch/inch:
Quantity	no.:
Make/Type	:
For OD casing (max/min)	inch/inch:
Quantity	no.:
Make/Type	:
For OD casing (max/min)	inch/inch:
G.1.8 CASING TONGS		Company Supplied
G.1.9 POWER CASING TONGS		Company Supplied
G.1.10 POWER UNIT FOR CASING AND TUBING TONGS
Quantity	no.:	1 Central Hydraulic unit
Driven by electric motor	yes/no:	YES
G.1.11 CASING CIRCULATING HEAD (Swedge)		Company Supplied
G.1.12 CASING SPEARS (Internal)		Company Supplied
G.1.13 CASING CUTTERS (Internal)		Company Supplied
G.1.14 CROSSOVER CASING TO DRILL PIPE		Company Supplied
G.1.15 CASING SCRAPERS		Company Supplied
G.2 CEMENTING EQUIPMENT
G.2.1 CEMENT UNIT		Company Supplied
G.2.2 CEMENTING MANIFOLD
Discharge manifold working pressure	psi:	15000
Cement pump discharge lines min. ID	inch:	3 Nonimal
Cement pump discharge lines working p	psi:	15000
G.2.3 CEMENT KELLY		N/A
G.2.4 CEMENTING TUBING		N/A
H. INSTRUMENTATION/COMMUNICATION
H.1 DRILLING INSTRUMENTATION AT DRILLER’S POSITION
H.1.1 WEIGHT INDICATOR
Make/Type	:	HITEC SMART DRILLING INSTRUMENTATION
Sensor type	:	ELECTRONIC DEADEND
Calibrated for number of lines strung (6, 8, 10, 12, etc.)	no.:	USER SELECTABLE
H.1.2 STANDPIPE PRESSURE GAUGES
Quantity	no.:	TBA
Make/Type	:	HITEC SMART DRILLING INSTRUMENTATION
Pressure range (maximum)	psi:	TBA
H.1.3 CHOKE MANIFOLD PRESSURE GAUGE
Quantity	no.:	2
Make/Type		HITEC SMART DRILLING INSTRUMENTATION
Pressure range (maximum)	psi:	0 - 15,000

49

H.1.4 ROTARY SPEED TACHOMETER
Make/Type	:	HITEC SMART DRILLING INSTRUMENTATION
Capacity range (maximum)	rpm:	0 - 200
H.1.5 ROTARY TORQUE INDICATOR	:	HITEC SMART DRILLING INSTRUMENTATION
H.1.6 MOTION COMPENSATOR INSTRUMENTS
Make/Type	:	HITEC SMART DRILLING INSTRUMENTATION
Hook position indicator	yes/no:	YES
Lock/unlock indicator	yes/no:	YES
H.1.7 PUMP STROKE COUNTERS
Make/Type	:	HITEC SMART DRILLING INSTRUMENTATION
One pump stroke indicator and one cumulative pump stroke counter for each pump.	yes/no:	YES
H.1.8 TONG TORQUE INDICATOR
Make/Type	:
Capacity range (maximum)	ft lbs:
H.1.9 PIT VOLUME TOTALIZER
Make/Model	:	HITEC SMART DRILLING INSTRUMENTATION
Floats in active mud tanks	yes/no:	YES
Floats in reserve mud tanks	yes/no:	YES
Loss/Gain indicator	yes/no:	YES
Alarm (audio and visual)	yes/no:	YES
H.1.10 MUD FLOW INDICATOR
Make/Model	:	HITEC SMART DRILLING INSTRUMENTATION
High/low alarm (audio and visual)	yes/no:	YES
H.1.11 TRIP TANK INDICATOR
Make/Model	:	HITEC SMART DRILLING INSTRUMENTATION
Chart recorder	yes/no:	DATA LOGGING
Alarm	yes/no:	YES
H.1.12 GENERAL ALARM SYS.	yes/no:	YES
H.1.13 AUTOMATIC DRILLER
Make/Type	:	HITEC SMART DRILLING INSTRUMENTATION
H.1.14 REMOTE CHOKE CONTROL UNIT (See E.14.1)
Make/Model	:	Houston Digital
H.2 DRILLING PARAMETER RECORDER
Quantity	no.:	USER DEFINED ELECT. DATA ACQUISITION
Location - 1	:	DRILLERS HOUSE
Location - 2	:
Make/Type	:	HITEC SMART DRILLING INSTRUMENTATION
Quantity of pens	no.:	USER DEFINED ELECT. DATA ACQUISITION
Parameter recorded	:	”
Parameter recorded	:	”
Parameter recorded	:	”

50

Parameter recorded	:	”
Parameter recorded	:	”
Parameter recorded	:	”
Parameter recorded	:	”
Parameter recorded	:	”
H.3 INSTRUMENTATION AT CHOKE MANIFOLD
H.3.1 STANDPIPE PRESSURE GAUGE
Make/Type	:	Strain gauge
Pressure range (maximum)	psi:	0-10,000
H.3.2 CHOKE MANIFOLD PRESSURE GAUGE
Make/Type	:	Strain gauge
Pressure range	psi:	0-15,000
H.3.1 and H.3.2 combined on one panel	yes/no:	yes
Visible from choke operating position	yes/no:	yes
H.4 STANDPIPE PRESSURE GAUGE		Strain Gauges
Make/Type	:	OTECO
Pressure range	psi:	0-10,000
Visible from driller’s position	yes/no:	No
H.5 DEVIATION EQUIPMENT
H.5.1 MEASURING DEVICE
Quantity	no.:	1
Make/Type	:	Totco
Deviation range	degree:	0 - 8 / 0-12
H.5.2 WIRELINE WINCH
Make/Model	:	Mathey
Wire length (nominal)	ft:	25000
Depth counter	yes/no:	yes
Wire size	inch:	3/16
Pull indicator	Ibs:	yes
H.6 CALIBRATED PRESS. GAUGES	:	Strain Gauges
H.7 RIG COMMUNICATION SYSTEM
H.7.1 TELEPHONE SYSTEM
No. of stations	no.:	120
Make/Type	:	Mitel Exchange
Explosion proof	yes/no:	AS REQ’D.
No. of stations	no.:
Make/Type	:
Explosion proof	yes/no:
H.7.2 PUBLIC ADDRESS SYSTEM
Can be combined with above	yes/no:	YES

51

Make/Type	:	Akusta
Explosion proof	yes/no:	AS REQ’D.
H.7.3 DRILL FLOOR - DERRICKMAN’S TALKBACK (For Intercom System)
No. of stations	no.:	14
Location	:	DWS - 2 / PHS
Location	:	CCR / ECR
Location	:	FLOOR, ROV, CP AREA, MONKEY BD., MP ROOM, MOONPOOL, SHAKERS, CROWN
Make/Type	:	AKUSTA
Explosion proof	yes/no:	AS REQ’D.
H.7.4 HAND-HELD VHF RADIOS
Quantity		12 MIN.
Make/Type		Earmark VOX 130
H.8 ENVIRONMENTAL INSTRUMENTATION
H.8.1 TEMPERATURE INDICATORS
Air temperature		Yes
Make/Model		Kongsberg
Sea water temperature		TBA
Make/Model	:	TBA
Recorder	yes/no:	Yes
H.8.2 BAROMETRIC PRESSURE	yes/no:	Yes
Make/Model		Kongsberg
Recorder		Yes
H.8.3 HUMIDITY SENSING INDICATOR		Yes
Make/Model		Kongsberg
Recorder		No
H.8.4 WIND SPEED/DIRECTION		Yes - QTY. 2
Make/Model		Kongsberg
Recorder		Yes
H.8.5 WAVE PROFILE RECORDER		No
H.9 ADDITIONAL MODULE SPECIFIC INSTRUMENTATION
H.9.1 ROLL, PITCH AND HEAVE INDICATOR
Make/Type		Kongsberg
Recorder
H.9.2 GYRO COMPASS
Make/Model		C. Plath / Navagat X
Located at		CCR ELECT. SPACE
H.9.3 ECHO SOUNDER		Yes
Make/Model		Skipper
Located at		Bridge

52

Recorder		No
H.9.4 CURRENT INDICATOR		Doppler Current Profiler
Make/Model		TBA
Located at		Lower Hull Penetration
Recorder		TBA
H.9.5 WEATHER FACSIMILE RECOI		Yes
Make/Model	:	JRC / JAX - 9A
Located at	:	Radio Room
Recorder	yes/no:	Yes
H.9.6 RADAR	YES	Yes
Quantity	1	1
Make/Model		Norcontrol / Databridge 2000 BL
Located at		Bridge
Bandwidth	cm:	X-Band
Quantity	no.:	1
Make/Model	:	Norcontrol / Databridge 2000 BL
Located at	:	Bridge
Bandwidth	cm:	S-Band
H.10 RADIO EQUIPMENT
H.10.1 SSB TRANSCEIVER
Quantity		1
Make/Model		Sailor / RE2100
Power	watts:	600
Frequency ranges	hz:	100 khz - 30 MHz
(Synthesized/crystal)	:	Synthesized
Facsimile capable		No
Telex capable		N/A
H.10.2 E.P.I.R.B’s
Quantity		2
Make/Model	:	COSPAS / SARSAT / TRON 30S MK II
H.10.3 VHF RADIO TELEPHONE
Quantity		5
Make/Model		Norcontrol - Sailor / RT 2048 W/ DSC
Power	watts:	25 W
Channels
H.10.4 VHF RADIO TRANSCEIVER
Quantity	no.:	3
Make/Model	:	Norcontrol - Sailor / RT 2048
Power	watts:	25 W
H.10.5 RADIO BEACON TRANSM
Quantity		1
Make/Model	:	Southern Avionics / SA 100
Power	watts:	100 W

53

H.10.6 AEORNAUTICAL VHF TRANS
Quantity		1
Make/Model	:	Jotron
Power	watts:	40 W PEP
Frequency range	hz:	118 - 137
(Synthesized/crystal)	:
H.10.7 WATCH RECEIVER
Quantity		1
Make/Model	:	Sailor / R501
Frequency	khz:	2182
H.10.8 SCRAMBLER
Quantity	no.:	No
Make/Model	:
H.10.9 TELEX
Quantity	no.:	N/A
Make/Model	:
H.10.10 SATELLITE COMM. SYS
Make/Model	:	NERA / C-10-0	/ NERA / H2095 B
Type	:	Type B	/ Type C
Facsimile link		Yes
Telex link		Yes
Telephone link		Data Link (9.6 K bits / Message Terminal
Other capabilities	:
1. PRODUCTION TEST EQUIPMENT
1.1 BURNERS		N/A
1.2 BURNER BOOMS		Foundations Only
1.3 LINES ON BURNER BOOMS		N/A
1.3.1 OIL LINE
OD	inch:	4”
Working pressure	psi:	1480 psi
Connection type at burner end	:	Suitable to connect to well test equipment
H2S	yes/no:	Yes
Pressure gauge connection at barge end	inch:	Provided by well test company
1.3.2 GAS LINE
OD	inch:	3”
Working pressure	psi:	1480 psi
Extended beyond burner by	ft:	Provided by well test company
Connection type at burner end	type:	Suitable to connect to well test equipment
H2S	yes/no:	Yes
Pressure gauge connection at barge end	inch:	Provided by well test company
1.3.3 WATER LINE
OD	inch:	Seawater - 1-1/2”
Working pressure	psi:	285 psi

54

Connection type at burner end	type:	Suitable to connect to well test equipment
Pressure gauge connection at barge end	inch:	Provided by well test company
I.3.4 AIR LINE
OD	inch:	4”
Working pressure	psi:	285 psi
Connection type at burner end	type:	Suitable to connect to well test equipment
Pressure gauge connection at barge end	inch:	Provided by well test company
I.3.5 PILOT GASLINE
ID	inch:	Provided by well test company
Working pressure	psi:
Connection type at burner end	type:
Pressure gauge connection at rig end	inch:
I.4 SPRINKLER SYSTEM
Sufficient to give protection to rig and personnelagainst heat radiation damage from the b	yes/no:	Provided by well test company
1.5 FIXED LINES FOR WELL TESTING
1.5.1 DRILL FLOOR TO SEPARATOR AREA
Type (Screwed/welded, both)		Tested and certified flexible flowlines provided by well
	:	test co. for connecting from rig floor to well test equip.
1.5.2 SEPARATOR AREA TO BOTH BURNER BOOMS
Type (screwed/welded, both.)	:	Welded
Quantity	no.:	2 ea. / one oil / one gas
Size OD	inch:	3” Gas / 4” Oil
Working pressure	psi:	1480 psi
Connection type at separator	type:	Suitable for connecting to well test company
Connection type at boom	type:	As above
Number of valves/lines	no.:	Provided by well test company
Size of valves	inch:	Provided by well test company
H2S	yes/no:	Yes
Valves installed near separator area for switching gas to either burner.	yes/no:	Yes
I.53 MUD PUMPS TO 2-BURNER	:	N/A
I.5.4 RIG AIR SYSTEM TO BOTH BURNER BOOMS
Type (screwed/welded, both)	:	Welded
Quantity	no.:	1 ea. Port and Starboard
Size OD	inch:	4”
Working pressure	psi:
Non-return valves fitted	yes/no:	Yes
I.5.5 OIL STORAGE TANK TO OVERBOARD
Type (screwed/welded, both)	:	Provided by well test company
Quantity	no.:
Size ID	inch:

55

Working pressure	psi:
Height above water level	ft:
Connection type at separator area	type:
I.5.6 SEPARATOR TO VENTSTACK OF RIG
Type (screwed/welded, both)	:	No vent from separator. Relief to flair
Quantity	no.:
Size ID	inch:
Working pressure	psi:
Connection type at separator area	type:
I.6 AUXILIARY POWER AVAILABILITY
I.6.1 FOR FIELD LABORATORY
Quantity	kw	2 - 480 volt boxes
Volts	v:
Frequency	hz:
I.6.2 FOR CRUDE TRANSFER PUMP
Quantity	kw:	Yes, as above
volts	v:
Frequency	hz:
I.6.3 FOR ELECTRIC HEATERS
Quantity	kw:	Yes, as above
Volts	v:
Frequency	hz:
J. WORKOVER TOOLS		Company Supplied
K. ACCOMMODATION
K.1 OFFICES
K.1.1 CO. REP.’S OFFICE
Quantity		3
Complete with desk, filing cabinet(s) and other necessary furniture		YES
Unrestricted view to drill floor		NO(CCTV MONITOR)
K.1.2 CONT. REP.’S OFFICE
Quantity		3
Unrestricted view to drill floor		NO(CCTV MONITOR)
K.1.3 RADIO ROOM		YES
Quantity		1
K.1.4 HOSPITAL ROOM
Number of beds/bunks		2 Beds
Wash basin		YES
Medical cabinet		YES
Dangerous drugs locker		YES

56

K.1.5 MUD LABORATORY AND FACILITIES
Separate room	yes/no:	YES
Equippped with:
Mud balance	yes/no:	YES
Marsh funnel	yes/no:	YES
Filtration kit	yes/no:	YES
Sand content kit	yes/no:	YES
Stopwatch	yes/no:	YES
K.2 LIVING QUARTERS
K.2.1 TOTAL PERSONS ACCOMODATED
Quantity		130
K.2.2 ACCOMODATION FOR COMPANY’S PERSONNEL
Total quantity		60
Quantity of single bed rooms		2
C/W attached toilet		YES
Quantity of two bed rooms		30
C/W attached toilet		YES
Quantity of four bed rooms		0
C/W attached toilet	N/A
K.2.3 ACCOMODATION FOR CONTRACTOR’S PERSONNEL
Total quantity		70
Quantity of single bed rooms		7
C/W attached toilet		YES
Quantity of two bed rooms		30
C/W attached toilet		YES
Quantity of four bed rooms		O
C/W attached toilet	N/A
K.2.4 GALLEY
Quantity		1
K.2.5 MESS SEATING CAPACITY
Main mess		60
Aux. mess		N/A
K.2.6 MEETING ROOMS
Quantity		1
K.2.7 RECREATION ROOMS
Quantity		2
Recreation facilities:		YES
TV		YES
VCR		YES
Pool Table		NO
Ping Pong Table		YES
Computer		NO
Other		DARTS/CARDS/READING

57

.2.8 OTHER ROOMS
Laundry		1 + 2 In change room for dirty clothes
Dry food store		1
Refrigerator		3
Change Rooms		4
Prayer Room		NO
Cinema		NO
Workout/Weight Room		YES
L. SAFETY EQUIPMENT
L.1 GENERAL SAFETY EQUIPMENT
L.1.1 GENERAL PERSONNEL PROTECTIVE GEAR
Safety bats (contractor only/everyone/not supplied	:	CONTACTOR ONLY
Safety boots (contractor only/everyone/not supplied	:	CONTACTOR ONLY
Safety clothing (contractor only/everyone/not supplied	:	CONTACTOR ONLY
Ear protection (contractor only/everyone/not supplied	:	EVERYONE
Rubber gloves (contractor only/everyone/not supplied	:	CONTACTOR ONLY
Rubber aprons (contractor only/everyone/not supplied	:	CONTACTOR ONLY
Fullface visors (contractor only/everyone/not supplied	:	CONTACTOR ONLY
Eye shields (for grinding machines, etc.) (Contractor only/everyone/not supplied	:	CONTRACTOR ONLY
Dust masks (contractor only/everyone/not supplied	:	CONTACTOR ONLY
Rubber gloves - elbow length for chemical handling (Contractor only/everyone/not supplied	:	CONTACTOR ONLY
Explosion proof handtorches c/w batteries (Contractor only/everyone/not supplied	:	CONTACTOR ONLY
Safety belts c/w lines (contractor only/everyone/not supplied	:	CONTRACTOR ONLY
L.1.2 EYE WASH STATIONS
Quantity	no.:	3
Make/model	:	TBA
Located at	pot water	MUD PROCESS ROOM
Located at	piping	DRILL FLOOR
Located at	:	MUD MIXING ROOM
L.1.3 DERRICK SAFETY EQUIPMENT
Derrick escape chute (rem chute)	no.:	N/A
Make/Type	:
Derrick safety belts	no.:	2 W/ INERTIA REEL
Make/Type	:	TBA
L.1.4 DERRICK CLIMBING ASSISTANT
Make/Type
L.1.5 FRESH AIR BLOWERS (Bug Blowers)
Quantity	:	3
Make/Type	:
Located at	:	Rig Floor
Located at	:

58

L.2 GAS/FIRE/SMOKE DETECTION
L.2.1 H2S MONITORING SYSTEM
Make/Type	:	TBA
Sampling points at:
Bellnipple	yes/no:	YES
Drillfloor	yes/no:	YES
Shale shaker	yes/no:	YES
Mud tanks	yes/no:	YES
Ventilation system into living quarters	yes/no:	YES
Other	:	YES
General alarm	yes/no:
Alarm types (audible, visual, both) at:
Driller’s console	:	BOTH
Engine room	:	BOTH
Mud room	:	BOTH
Living quarters each level	:	AUDIBLE
Central area each structural level	:	BOTH
Other	:	BOTH
Central alarm panel	yes/no:	YES
Located at	:	CCR
L.2.2 COMBUSTIBLE GAS MONITORING SYSTEM
Make/Type	:	Simrad Integrated Alarm and Control System
Sampling points at:	yes/no:
Bellnipple	yes/no:	YES
Drill floor	yes/no:	YES
Shale Shaker	yes/no:	YES
Mud tanks	yes/no:	YES
Ventilation system into living quarters	yes/no:	YES
Other	:	YES
General alarm	yes/no:
Alarm types (audible, visual, both) at:
Driller’s console	:	BOTH
Other	:	BOTH
		YES
L.2.3 H2S DETECTORS (Portable)
Quantity	no.:	TBA
Make/Type	:
Phials for H2S: measuring range
from 1 to 20 ppm	no.:
from 100 to 600 ppm	no.:
L.2.4 CO2 GAS DETECTORS (Portable)
Quantity	no.:	TBA
Make/Type	:
Phials for CO2: measuring range
from 1 to 20 ppm	no.:
from 20 to 200 ppm	no.:
om 250-3000 ppm	no:
L.2.5 EXPLOSIMETERS
Quantity	no.:	TBA
Make/Type	:

59

L.2.6 FIRE/SMOKE DETECTORS IN ACCOMODATION
Make/type		:	THERMAL
Fire detection		yes/no:	YES
Smoke detection		yes/no:	YES
Central alarm panel		yes/no:	YES
Location		:	CCR
L.3 FIRE FIGHTING EQUIPMENT
L.3.1 FIRE PUMPS
Quantity		no.:	2
Make/Model		:	Patterson
Type		:	CENTRIFUGAL
Output	US gals/min:		550
All offtake points supplied by each pump		yes/no:	YES
Location of pumps		:	AUX. MACHINE ROOM PORT
Location of pumps		:	AUX. MACHINE ROOM FWD.
Fire fighting water delivery conforms to		yes/no:	YES
MODU spec version		:
L 3.2 HYDRANTS AND HOSES
Hydrants positioned such that any point may be reached
by a single hose length from two separate hydrants		yes/no:	YES
Quantity of hydrants		no.:	48
Hose connections/hydrant		no.:	46 X 1
Hose max. diam.		inch:	2.5” OD
Length		ft:	50’
L.3.3 PORTABLE FIRE EXTINGUISHERS
Quantity (total)		no.:	70
Type 1- CO2		no./lbs:	2 @ 4
		no./lbs:	37 @ 15
		no./lbs:	2 @ 150
Type 2 - Dry chemical		no./lbs:	17 @ 5
		no./lbs:	9 @ 10
		no./lbs:	3 @ 50
Type 3 - Foam		no./lbs:	0
		no./lbs:	0
		no./lbs:	0
Mounted adjacent to access ways and escape routes		yes/no:	yes
L.3.4 FIRE BLANKETS
Location		:	RIG FLOOR, GALLEY, HELICOPTER BOX
Quantity		no.:	3
L.3.5 FIXED FOAM SYSTEM
Automatically injected into fixed fire water system at central point with remote manual control		yes/no:	YES
Make/Type		:	Patterson
Quantity foam stored on site		GALLONS	700 GPM

60

Inductor tube	yes/no:	YES
Foam nozzles	no.:	4
Located at	:	HELIPORT -3 TURRET MOUNTED
Located at	:	HELIPORT -1 HOSE REELS
Located at	:
L.3.6 HELIDECK FOAM SYSTEM
Dedicated system adequate for at least 10 minutes fire fighting at the rate quoted in the IMO MODU code	yes/no:	YES
IMO MODU code version	:	TBA
Make/Type	:	DOOLY
Quantity of monitors	no.:	3
Foam type	:	TBA
Rate	US gals/min:	350 gal. min. each
L.3.7 FIXED FIRE EXTINGUISHING SYSTEM
Protected spaces
Engine room, type (Halon/CO2)		CO2
Paint locker, type (Halon/CO2)		CO2
Emergency generator, type (Halon/CO2)		CO2
SCR room, type (Halon/CO2)		CO2
Other (specify location & type)		CO2 IN MUD PUMP ROOM
Alarms (audible, visual or both)	:
Automatic shutting of mechanical ventilation in protected spaces	yes/no:	YES
Remote manual release located at	:
Remote manual release located at	:
Remote manual release located at	:
L.3.8 MANUAL WATER DELUGE SYSTEM	yes/no:	YES
Protected spaces	:	DRILL FLOOR, LIFEBOATS
Protected spaces	:	LIFERAFTS, MOONPOOL
Water supplied from fire main line	yes/no:	YES MAIN SALT WATER RING
L.3.9 WATER SPRINKLER SYSTEM IN ACCOMODATION
Automatic	yes/no:	YES
Working pressure	psi:	130
Pressurized tank capacity	ft3:	53.47
L.4 BREATHING APPARATUS	:	TBA
L.5 EMERGENCY FIRST AID EQUIPMENT
L.5.1 FIRST AID KITS
Quantity	no.:	TBA
L.5.2 BURN KITS
Quantity	no.:	TBA
L.5.3 RESUSCITATORS
Quantity	no.:	TBA

61

Charged (spare) oxygen cylinders	no.:
L.5.4 STRETCHERS
Quantity	no.:	TBA
Type	:
Located at	:
L.6 HELIDECK RESCUE EQUIPMENT
L.6.1 STORAGE BOXES
Quantity	no.:	TBA
Construction material	:	FIBERGLASS
Max height open	inch:	TBA
L.6.2 EQUIPMENT
Aircraft axe	yes/no:	YES
Large firemans rescue axe	yes/no:	YES
Crowbar	yes/no:	YES
Heavy duty hacksaw	yes/no:	YES
Spare blades	yes/no:	YES
Grapnel hook	yes/no:	NO
Length of wire rope attached	ft:
Quick release knife	yes/no:	YES
Bolt croppers	yes/no:	YES
L.7 RIG SAFETY STORE
Equipment to repair, recharge and restock		R&BF will carry all spares necessary to ensure an efficient and safe operation.
L.8 EMERGENCY WARNING ALARMS
Approved system to give warning of different emergencies	yes/no:	YES
L.9 SURVIVAL EQUIPMENT
L.9.1 LIFEBOATS
Make/Type	:	TBA
Quantity	no.:	2
Capacity	person/craft:	65
Locations (fore, apt, port, stbd)	:	2 FORE
Fire protection	yes/no:	YES
Radios	yes/no:	YES
Flares	yes/no:	YES
Food	yes/no:	YES
First aid kits	yes/no:	YES
Maker/Type	:	TBA
Quantity	no.:	2
Capacity	person/craft:	65
Locations (fore, apt, port, stbd)	:	AFT
Fire protection	yes/no:	YES
Radios	yes/no:	YES
Flares	yes/no:	YES

62

Food	yes/no:	YES
First aid kits	yes/no:	YES
L.9.2 LIFERAFTS
Make/Type	:	TBA
Quantity	no.:	3
Capacity	person/craft:	30
Davit launched	yes/no:	YES & FLOAT FREE
Locations (fore, apt, port, stbd)	:	FORE
Fire protection	yes/no:
Radios	yes/no:	TBA
Flares	yes/no:	YES
Food	yes/no:	YES
First aid kits	yes/no:	YES
Make/Type	:	TBA
Quantity	no.:	2
Capacity	person/craft:	30
Davit launched	yes/no:	YES
Locations (fore, apt, port, stbd)	:	AFT
Fire protection	yes/no:
Radios	yes/no:	TBA
Flares	yes/no:	YES
Food	yes/no:	YES
First aid kits	yes/no:	YES
L.9.3 RESCUE BOAT
Make/Type	:	Port Fwd lifeboat is designated as a rescue boat
Engine power	hp:
L.9.4 LIFE JACKETS
Make/Type		TBA
Quantity	no.:	163
L.9.5 LIFE BUOYS
Make/Type	:	TBA
Quantity	no.:	10
L.9.6 WORK VESTS
Make/Type	:	TBA
Quantity	no:	25
L.9.7 ESCAPE LADDERS/NETS
Make/Type	:	PERMANENT LADDERS
Quantity	no.:	4, 1 PER CORNER COL.
L.9.8 DISTRESS SIGNALS
Type	:	TBA
Quantity	no.:	1 SET
M. POLLUTION PREVENTION EQUIPMENT
M.1 SEWAGE TREATMENT

63

Make/Model	:	HAMMWORTHY (USCG APPROVED)
System type	:	BIOLOGICAL
Conforms to (Marpol annex IV, etc.)	:	YES
M.2 GARBAGE COMPACTION
Make/Model	:	To be provided
System type	:
Conforms to (Marpol annex IV, etc.)	:
Make/Model	:
System type	:
Conforms to (Marpol annex IV, etc.)	:
M.3 GARBAGE DISPOSAL/GRINDER
Make/Model	:	To be provided
System type	:
Conforms to (Marpol annex IV, etc.)	:
N.1 THIRD PARTY EQUIPMENT
Mud Loggers (available sq feet)		555 sq. ft.
MWD / LWD (available sq feet)		555 sq. ft.
Cement Unit (available sq. feet)		1,087 sq. ft.
ROV (available sq. feet)		1184 sq. ft.
Electric Log (available sq. feet)		895 sq. ft.

64

EXHIBIT B-3

MATERIAL, SUPPLIES AND SERVICES

Categories:	I. Furnished by CONTRACTOR, paid by CONTRACTOR.
	II. Furnished by COMPANY, paid by COMPANY.
	III. Furnished by CONTRACTOR, paid by COMPANY.

Category I

Furnished by CONTRACTOR, paid by CONTRACTOR

1.1	Fuel storage.
1.2	Lube oils and greases.
1.3	Tool joint lubricant for CONTRACTOR’S drill string.
1.4	Replacement screens on shale shaker for screen sizes 84 mesh and coarser.
1.5	Replacement screens for mud cleaner(s) for screen sizes 150 mesh and coarser.
1.6	Initial set of rig hoses for receiving or discharge of liquid and bulk consumables from workboats.
1.7	Initial installation and utility provision for AC drive cementing unit and cement mixing pumps in shipyard. (rental only - as provided in Rental Agreement).
1.8	Initial installation for ROV unit and installation of ROV cursor system. Provision of utilities for electric motor generator for ROV main power.
1.9	Welding services with welder in CONTRACTOR’S crew (overtime not included).
1.10	Except as otherwise provided in Exhibit “B-2” herein rig and equipment maintenance, running supplies, spares and replacement parts, and services for continuous operation of CONTRACTOR’S equipment.
1.11	Towing bridle and replacement of same from Drilling Unit to towing vessel(s) during all rig moves.
1.12	Supply vessel mooring system at Drilling Unit.
1.13	Labor on the Drilling Unit to load and unload all CONTRACTOR’S and COMPANY’S equipment, materials and supplies between supply vessels and Drilling Unit.
1.14	CONTRACTOR’S Shore Base.
1.15	Medical doctor on notice in the Operating Area for emergency treatment of CONTRACTOR’S personnel injured aboard the Drilling Unit.
1.16	Meals, bunk and accommodations, including medical services, on board Drilling Unit for all CONTRACTOR’S personnel and an average of ten (10) COMPANY and COMPANY third party personnel per day.
1.17	Personnel for Drilling Unit and shore base as set out in Exhibit “F”.
1.18	Disposal of all liquids and other waste generated by CONTRACTOR including drum disposal.

1

1.19	Complement of personal protective equipment required to handle completion brines and synthetic base mud for those crew members with potential exposure.
1.20	Blowout preventers, choke and kill lines, ring gaskets, controls, handling, testing tools and spare parts as required set out in Exhibit “B-2”.
1.21	Wellhead connector and spare parts as required in Exhibit “B-2” to adapt CONTRACTOR’S BOP stack to COMPANY’S wellhead.
1.22	All other well control equipment components and replacement parts, including failsafe valves, riser, choke and kill lines and choke manifold. All replacement parts shall be Original Manufacturer’s Equipment.
1.23	Initial set of ram packer elements, annular elements, top seals, related equipment as required in Exhibit “B-2” CONTRACTOR’S BOP EQUIPMENT. All elements, packers, seals and related rubber goods shall be Original Manufacturer’s Equipment and oil mud compatible.
1.24	Manifolding and piping as required to flare burners for oil, gas, water and air.
1.25	CONTRACTOR shall conduct a drillpipe inspection on all drillpipe, drill collars, subs, rotary and handling tools prior to spudding the first well under this CONTRACT. A specified inspection including all optional inspections as specified by API-RP7G, such as; Transverse Defect inspection using induction coils and a magnetic particle inspection of tube ends, couplings, and verification of defects found by gamma ray wall thickness inspection. Drillpipe must satisfy criteria as new or premium drillpipe to be used on COMPANY’S wells.
1.26	CONTRACTOR shall conduct an inspection on all drillpipe after every 100,000’ drilled or 1500 rotating hours (whichever is less). Inspection type will satisfy criteria spelled out in API-IADC specified inspection for used drillpipe. Inspection will include all operational inspections in same API criteria along with magnetic particle for tube ends and couplings. Drillpipe must satisfy criteria as new or premium drillpipe to be used on COMPANY’S wells.
1.27	CONTRACTOR shall conduct an inspection on topdrive valves and subs, all drill collars, subs and related bottom hole assembly components every 250 rotating hours. All bottom hole assembly components shall meet a bending strength ratio of 2.25 to 3.00.
1.28	Living Quarters to accommodate 130 personnel minimum. Must have separate facilities for up to 10 women.
1.29	Three COMPANY designated offices. One for COMPANY’S drilling supervisors, one for COMPANY’S third partys and one for COMPANY’S geologists. All offices complete with intercom system, television, VCR’s, surge suppression for up to 4 computers, 2 desks and file cabinets.
1.30	All equipment shall comply with MMS regulations.
1.31	Spare parts inventory for surface and subsurface BOP equipment as per CONTRACTOR BOP EQUIPMENT LIST, Exhibit B-2. Spare parts inventory list to be provided to and agreed by COMPANY.
1.32	Supply labor required to test, service, and maintain, all surface, and subsurface BOP and well control equipment and tools including COMPANY’S wellhead running tools.
1.33	Mud pump liners and pistons for two (2) sizes as specified by COMPANY.
1.34	Fishing tools to include overshots, grapples, and crossover subs required to catch all contractor supplied drill string and bottom hole assembly components

2

	listed in Exhibit “B-2”.
1.35	Diver services and equipment as required by CONTRACTOR.
1.36	Mud bucket for each size of CONTRACTOR supplied drill pipe.
1.37	Outside pipe wipers for each size of CONTRACTOR supplied drill pipe.
1.38	Pressure washer for rig floor and maintaining same.
1.39	Mud vacuum system for rig floor clean up and maintenance.
1.40	Space and utilities for the following COMPANY’S third party equipment: electric wireline logging unit, MWD/LWD logging unit, mud logging unit and two (2) centrifuges.
1.41	Space or accommodation for COMPANY’S warehouse.
Category II Furnished by COMPANY, paid by COMPANY
2.1	Thread compound for COMPANY’S connectors and casing.
2.2	Potable and fresh water for drilling, cementing and wash down of CONTRACTOR’S equipment and for personnel use but with respect to the latter only in excess of the capacity of the distillation unit.
2.3	Diesel fuel.
2.4	Drill sites, location surveys, marker buoys.
2.5	All permits and licenses required for the drilling site and to permit access thereto and egress therefrom.
2.6	Weather forecast service.
2.7	Stabilizers, including sleeves and spare parts and maintenance.
2.8	Core heads, core catchers and coring service charges.
2.9	Drilling bits, bit breakers (not supplied per Exhibit B-2), underreamers, hole openers, shock subs, wall scrapers, and other down hole tools, plus maintenance and repairs.
2.10	Water based mud, chemicals and additives.
2.11	Synthetic oil base mud, oil emulsion and other special drilling and completion fluids for completing wells.
2.12	Mud engineering services, and other mud supervision.
2.13	Mud centrifuge.
2.14	Pumping and blowing of bulk materials from work boats to Drilling Unit and between workboats and dock storage facilities.
2.15	All completion and production equipment, including hangers, packers, liners, floats, centralizers, scratchers, casing shoes, float collars, wellheads, spacer spools, Christmas trees including ring gaskets, valves, well connections and all necessary tools and equipment for installation.
2.16	Wellhead running retrieving, handling and testing tools.
2.17	Cementing unit and cement mixing pumps.
2.18	Cement and cement services, including special rental charge.
2.19	Electric logging unit, services and related tools.
2.20	Gun perforating and related services.
2.21	Mud logging unit and related services.

3

2.22	Whipstocks, directional drilling tools and services.
2.23	All surface and down hole survey equipment and services, except for drift indicators and slick line unit as described in Exhibit “B-2”.
2.24	Drill stem, formation testing tools and services.
2.25	Test tanks and accessories for production testing.
2.26	Well test burner equipment, burners, separators, flow meters, any other well testing equipment, including installation costs and well testing services.
2.27	All permanent or special installations and services, including services for controlling blowouts and fires.
2.28	Diver, ROV services and equipment as required by COMPANY.
2.29	Additional welding services required by COMPANY.
2.30	Spare parts and operating supplies for COMPANY’S tools and equipment.
2.31	All transportation required for CONTRACTOR’S and COMPANY’S equipment, supplies, drilling and potable water and personnel between shore and Drilling Unit.
2.32	Transportation from base of operations to Drilling Unit by sea, air and/or helicopter.
2.33	Anchor handling vessels and crews to deploy and recover mooring system at COMPANY’S drilling location.
2.34	Dock and dockside facilities, including cranes and trucks, labor equipment for loading and unloading CONTRACTOR’S and COMPANY’S equipment, materials and supplies at COMPANY’S shore base, port charges, pilot fees, canal fees, wharfage, agent fees and related costs for movement of equipment and material at COMPANY’S shore base and dock facilities.
2.35	Any radio equipment required by COMPANY in excess of those described in Exhibit “B-2”, and maintenance of such radio equipment.
2.36	All radio permits and licenses for COMPANY’S radios.
2.37	Disposal of all liquid and other waste generated by COMPANY including drum disposal.
2.38	Disposal of cuttings, mud materials from the well, if required.
2.39	Wellhead, wellhead gasket, wear bushing and bore protectors. All other gaskets and bore protectors for CONTRACTOR’S account.
2.40	Casing and or tubing tools and crews not listed in Exhibit “B-2”.
2.41	All casing, tubing and accessories.
2.42	Casing cutting tools.
2.43	Drill pipe, drill collars and accessories other than that furnished by CONTRACTOR listed in Exhibit “B-2”.

4

Category III

Furnished by CONTRACTOR, paid by COMPANY

3.1	Special safety equipment required other than as described in Exhibit “D”.
3.2	Replacement screens on shale shakers for screen sizes finer than 84 mesh.
3.3	Replacement screens on mud cleaners for screen sizes finer than 150 mesh.
3.4	Welding consumables for welding COMPANY furnished equipment.
3.5	Additional off tour labor authorized by COMPANY for mixing cement, moving mud materials, COMPANY’S tubulars, etc.
3.6	Overtime beyond normal work schedule and extra CONTRACTOR personnel requested by COMPANY.
3.7	Replacement of CONTRACTOR supplied supply vessel mooring system ropes.
3.8	Replacement set of ram packer elements, top seals and annular elements. All elements, packers, seals and related rubber goods shall be Original Equipment Manufacturer equipment and oil mud compatible.
3.9	Replacement of CONTRACTOR supplied hoses for receiving and discharge of liquid and bulk consumables from workboats.
3.10	Meals and accommodations on board the Drilling Unit for COMPANY and COMPANY’S third party personnel in excess of an average of ten (10) per day calculated over a period of one (1) calendar month will be billed at CONTRACTOR’S actual cost.

5

EXHIBIT C

INSURANCE REQUIREMENTS

1.The insurance required to be carried by CONTRACTOR under this Contract is as follows:

a.Workers’ Compensation as may be required by the laws of the jurisdictions which the work is performed, including occupational disease. If the performance of the CONTRACT requires the use of watercraft or is performed over water, CONTRACTOR shall provide coverage for liability under the U.S. Longshoreman’s and Harbor Workers Compensation Act, the Outer Continental Shelf Lands Act, and liability for admiralty benefits and damages under the Jones Act, Death on the High Seas Act, and general maritime laws on all employees except members of crews of vessels if crew liabilities are covered under Protection and Indemnity Insurance, and shall further provide that a claim “in rem”, or against the Drilling Unit, shall be treated as a claim against the employer.

b.Employer’s Liability Insurance with limits not less than $10,000,000 per occurrence covering injury or death to any employee.

c.Comprehensive General Liability Insurance, including contractual liability insuring the indemnity agreement as set forth in the Contract and products-completed operations coverage with a combined single limit of not less than $10,000,000 covering bodily injury, sickness, death and property damage. This insurance shall provide that a claim “in rem” or against the Drilling Unit be treated as a claim against the insured.

d.Comprehensive Automobile Liability Insurance including contractual liability, insuring owned, non-owned, hired, and all vehicles used by CONTRACTOR with a combined single limit of not less than $10,000,000 applicable to bodily injury, sickness, or death and loss of or damage to property in any one occurrence.

e.Watercraft Insurance: If the performance of this CONTRACT requires the use of watercraft to be provided by CONTRACTOR, CONTRACTOR shall carry or require the owners of the watercraft to carry: (1) Hull and Machinery (including Collision Liability) insurance, subject to the American Institute Hull Clauses or equivalent, in an amount not less than the stated value of the watercraft (any language in this policy which limits the coverage of an insured who is not an owner or who is not entitled to limitation of liability shall not apply to the extent the owner has assumed liability for the loss); (2) Protection and Indemnity Insurance, in an amount not less than the stated value of the watercraft or $5,000,000, whichever is greater (any language in this policy which limits the coverage of an insured who is not an owner or who is not entitled to limitation of liability shall not apply to the extent the owner has assumed liability for the loss); and (3) in respect to all chartered vessels, Marine Operator’s Charterer’s Legal Liability insurance with limits of not less that $5,000,000.

1

f.Aircraft Insurance: If the performance of this Contract requires the use of aircraft provided by CONTRACTOR, CONTRACTOR shall carry, or require the owners of the aircraft to carry: (1) All Risks Hull insurance in an amount equal to the replacement value of the aircraft, and (2) Bodily Injury Liability, including Passenger Liability of not less than $2,000,000 per passenger seat in any one occurrence and $25,000,000 property damage in any one occurrence.

g.All Risks Hull and Machinery/Physical Damage Insurance, includingCollision Liability, blowout and cratering coverage, in an amount equal to full value of the CONTRACTOR’S Drilling Unit and other equipment employed, including CONTRACTOR’S associated equipment and non-floating items normally situated in the ocean, such as blowout preventers, riser systems, anchors, anchor chains, and/or cable, pendant wires and pendant buoys. This coverage shall include at least $5,000,000 for costs or expenses of the removal of the wreck or debris of the Drilling Unit.

h.Protection and Indemnity Insurance on the Drilling Unit owned and/or operated by the CONTRACTOR in an amount of not less than the full value of the Drilling Unit or Five Million Dollars ($5,000,000),whichever is greater. This coverage may exclude liability to CONTRACTOR’S employees and members of the crew of the insured drilling unit provided the insurance set forth in Sections “a and b” hereof is warranted to remain in full force and effect during the term of this Contract. (Any language in this policy which limits the coverage of an insured who is not an owner or who is not entitled to limitations of liability shall not apply to the extent the owner has assumed liability for the loss.)

i.Pollution Liability Insurance on the vessel, in accordance with the terms of entry provided by the CONTRACTOR’S P&I Club (as required by the Oil Pollution Act of 1990 OPA 90).

2.All the insurance shall be carried by CONTRACTOR at CONTRACTOR’S expense with an insurance company or companies authorized to do business in the jurisdictions where the work is to be performed and satisfactory to Vastar. CONTRACTOR shall furnish certificates of insurance to Vastar evidencing the insurance required hereunder and, upon request, Vastar may examine true copies of the actual policies. Each certificate shall provide that the insurance is in full force and effect and that it shall not be canceled or materially changed without thirty (30) days (seven (7) days with respect to war risks, prior written notice to Vastar. All certificates must contain reference to endorsements (i.e., Additional Insured, Waiver of Subrogation, etc.) as required herein.

3.Vastar, its subsidiaries and affiliated companies, co-owners, and joint venturers, if any, and their employees, officers, and agents shall be named as additional insureds in each of CONTRACTOR’S policies, except Workers’ Compensation for liabilities assumed by CONTRACTOR under the terms of this Contract.

2

4.All CONTRACTOR’S insurance policies shall be endorsed to provide that underwriters and insurance companies of CONTRACTOR shall not have any right of subrogation against Vastar, its subsidiaries, co-owners and joint venturers, if any, and their agents, employees, officers, invitees, servants, contractors, subcontractors, insurers, and underwriters.

5.Any coverage provided to Vastar by the CONTRACTOR’S insurance under this CONTRACT is primary insurance and shall not be considered contributory insurance with any insurance policies of Vastar, its subsidiaries, co-owners and joint venturers, if any..

6.All policies shall be endorsed to provide that there will be no recourse against Vastar for payment of premium.

7.CONTRACTOR shall require all its subcontractors to carry adequate insurance coverage during the term they are engaged in performing any work hereunder. Subcontractors shall furnish Vastar acceptable evidence of insurance upon its request.

8.Except where specifically provided for in this Contract any and all deductibles in the required insurance policies shall be assumed by, for the account of, and at CONTRACTOR’S sole risk.

9.In the event the premium for war, expropriation, nationalization and non re-exportation risks insurance for the CONTRACTOR’S Drilling Unit increases as a result of the importation of the Drilling Unit into a specific Area of Operations, CONTRACTOR shall notify Vastar of the increase in premium prior to payment by CONTRACTOR, and Vastar, at its sole option shall, within 48 hours of being given such notice either agree to reimburse CONTRACTOR for the documented increase in premium or allow the Drilling Unit to depart the Area of Operations for safe harbor once the well in progress is made safe.

3

EXHIBIT D

SAFETY, HEALTH, AND ENVIRONMENT MANAGEMENT SYSTEM

CONTRACTOR agrees in addition to CONTRACTOR’S Safety, Health and Environment program and COMPANY’S Safety, Health and Environment Manual (“SHE Manual”). to develop a “RIG SITE SAFETY MANAGEMENT SYSTEM”. Thesystem shall contain provisions for self-monitoring and accountability.

The Rig Site Safety Management System shall, at a minimum, address the following items:

1. Safety and job planning meetings.

2. Training drills to verify viability of all response plans and to develop personnel.

3. A “Work Permit System” to include the following:

a. Hotwork outside safe welding areas,

b. Confined Space Entry,

c. Working on High Pressure Lines,

d. Pumping of Hazardous Materials,

e. Maintenance of Life Boats,

f. Bypassing or repairs to “Critical Safety Systems,”

g. Handling of radioactive sources and explosives,

h. Any work involving Dynamic Positioning system equipment,

i. Work on or near remote start equipment, and

j. Crane offload or backload lifts from workboat greater than 15 tons.

CONTRACTOR shall ensure that:

1.All chemicals received and shipped from the Drilling Unit are properly labeled, container undamaged, and a MSDS sheet accompanies product shipment. CONTRACTOR shall be responsible for the proper disposition of CONTRACTOR’S generated waste such as, but not limited to; lube oils, motor oils, antifreeze, batteries, tires, rubber products, junk iron, drill line, etc.

2. An inventory of all hazardous materials and chemicals is maintained on the Drilling Unit.

3.All radioactive sources and explosives shall be stored in appropriate and approved magazines.

4.All source containers are to be locked and stored in a safe area away from normal operations, living quarters and passage ways.

5.All personal protective equipment is identified and required to be used with each work activity.

1

6.CONTRACTOR will provide a Readiness Checklist for the following critical operations including, but not limited to, such as; Drill floor pre-tour, DP pre-tour, hydrocarbon transfer, lifesaving equipment, monthly Drilling Unit inspection, radioactive and explosives usage.

7.CONTRACTOR shall have in place a Safety Observation Program.

8.CONTRACTOR shall perform; pre-tour safety and weekly safety meetings, fire, abandon, man overboard and helicopter crash drills. Scenario drill records are to filed on location and be available for review by COMPANY’S personnel and regulatory bodies.

9.CONTRACTOR shall provide a designated firefighting team and equipment complete with back-up firefighting team.

10.CONTRACTOR and COMPANY will work together to incorporate an individual safety incentive program to be combined with safety and rig personnel performance and mutually agreed upon at a later date.

11.CONTRACTOR shall have an active Alcohol and Drug Screening Program. CONTRACTOR agrees to conduct periodic searches and testing for such substances. CONTRACTOR’S personnel who are considered to be safety sensitive personnel under the Department of Transportation regulations shall be subject to and in compliance with the U.S. Coast Guard regulations with respect to drug and alcohol testing as set forth in 46 CFR Parts 4 and 16, and 49 CFR Part 40.

12.CONTRACTOR shall ensure that all its employees receive Hazardous Materials training and how to use OSHA Form 20, known as Materials Safety Data Sheets, which permits employee reporting on toxic substances.

13.CONTRACTOR shall maintain current records of training and certification of personnel for the following: Hazcom, Well Control, Ballast Control, Crane Operations, Hotwork Firewatch Training, Welding, and Electrical. CONTRACTOR is required to maintain a Training Matrix Schedule for each position.

14.CONTRACTOR shall insure that Drilling Unit housekeeping, cleanliness and personal hygiene meets requirements of COMPANY’S SHE manual.

15.CONTRACTOR shall have on location at all times at least two (2) personnel trained in oil spill containment and hazardous materials handling and clean up.

16.CONTRACTOR shall immediately report to COMPANY’S representative, regardless of quantity, all environmentally sensitive spills such as, but not limited to, hydrocarbons or toxic materials.

2

17. CONTRACTOR to have an updated Spill Contingency Plan on site at all times.

18.CONTRACTOR shall immediately report to COMPANY’S representative and maintain records of the following: all incidents including but not limited to near misses, first aids, recordable accidents, lost time injuries, illnesses, spills, pollution, incidents involving hazardous and explosive materials, property and equipment damage.

19.CONTRACTOR shall maintain a daily Personnel on Board list to include personnel name, company and position.

20.During hurricane season, CONTRACTOR shall keep an updated Hurricane Evacuation Procedure complete with operational times to: secure the well, recover the riser/BOP’s, secure the rig and offload all non essential or all personnel if required.

CONTRACTOR SAFETY REPORTING:

CONTRACTOR shall provide to the COMPANY’S Safety, Health and Environmental Representative a completed accident investigation report within twenty-four hours of each occurrence designated in Exhibit D-18 above. CONTRACTOR shall submit additional information each month concerning safety performance of CONTRACTOR’S employees in connection with the work performed hereunder. The following is a breakdown of the information that shall be submitted on or before the tenth day of each month for the previous month’s safety performance.

1. Total man hours worked (month / YTD)

2. Total lost time accidents (month / YTD)

3. Total lost time days (month / YTD)

4. Total recordable accidents (month / YTD)

5.Total first aid cases (month / YTD)

6. Total cost equipment / property damage (month / YTD)

7.Any safety or health inspections, warnings, notices or asserted violations issued by any governmental agencies

This information should be mailed or telecopied to:

SHE Representative

Vastar Resources, Inc.

15375 Memorial Drive

Houston, Texas 77079

Telephone: 281/584-6100

FAX: 281/584-6810

3

SAFETY MANUAL RECEIPT ACKNOWLEDGMENT

Attached to the Drilling Contract between Vastar Resources, Inc.. and R&B Falcon Drilling Co. dated as of December 9, 1998.

Ron Tafery a duly authorized representative of Contractor and on behalf of Contractor hereby acknowledges receipt of the “Safety and Health Manual” of Vastar Resources, Inc. Contractor agrees that they have or agree to become familiar with said Safety and Health Manual and shall, to the extent not inconsistent with Contractor’s manual, policy and procedures, comply and cause Contractor’s employees, agents and others under Contractor’s control entering upon Vastar Resources’ premises in the performance of work or services or in connection therewith to comply with the applicable standards contained in the Safety and Health Manual of Vastar Resources, Inc. Vastar is not required by Contractor to police Contractor’s compliance with any safety, health, and environmental rules, laws, regulations or orders and Contractor’s agreement to comply therewith shall not impose any obligation on the part of Vastar under such rules, laws regulations or orders.

Contractor: R&B Falcon Drilling Co.

Name:	Ron Tafery
Title:	Vice President
Signature:	/s/ Ron Tafery
Date:	December 9, 1998

4

EXHIBIT E

TERMINATION PAYMENT SCHEDULE

Termination Pursuant to Article 27

Should COMPANY terminate the CONTRACT pursuant to Article 27.1, COMPANY shall pay CONTRACTOR a Lump Sum Payment as liquidated damages and not as a penalty, within ninety (90) days of termination calculated as follows:

Lump Sum equals Operating Rate less eighty (80)% of the documented operating costs times the number of days remaining under the Contract Term discounted to present value using the annual prime rate of interest as posted by CitiBank N.A. on the first day of the month in which Company terminates the Contract.

During the remaining Contract Period, CONTRACTOR shall make a good faith effort to market the Drilling Unit. Should CONTRACTOR be successful, CONTRACTOR shall refund to COMPANY any funds actually received or accrued from any other entity for the use of the Drilling Unit as follows:

(1)	The repayment will be reduced by the eighty percent (80%) of the fixed cost not already paid by COMPANY.
(2)	The repayment will be reduced by an amount equal to five percent (5%)as an incentive for CONTRATOR to actively market the Drilling Unit.
(3)	Repayments by CONTRACTOR to COMPANY shall never exceed Contract Rate.

1

EXHIBIT F-1

CREW COMPLEMENT

Drill Crew	Total	On Board	Remarks
Drilling Rig Supt	2	1
Toolpusher	4	2
Driller	4	2
Asst. Driller	8	4
Pumpman	4	2
Floorman	12	6
Maintenance Supervisor (Electrical)	2	1
Electrician	4	2
Assistant Electrician	2	1
Electronic Technician	4	2
Mechanic	4	2
Assistant Mechanic	2	1
Welder	2	1
Sub Sea Engineer	2	1
Assistant Sub Sea	2	1
Crane Operator	4	2
Roustabout	16	8
RTSC	2	1
Medic	2	1
Materialsman	4	2
Captain/OIM	2	1
Chief Officer	2	1
D.P. Operator	4	2
Assist. D.P. Operator	4	2
A.B. Seaman/Painters	6	3
Chief Engineer	2	1
First Engineer	2	1
2nd Engineer	4	2
Oiler/Motorman	4	2
Boatswain	2	1
Galley	As Needed
Total:	118	59

a)	Galley crew ratio of one to every 10 persons on board.
b)	A mutually agreed pre-commencement manning schedule shall be attached.
c)	Contractor may, with Company approval, reduce the marine crew manning based upon Coast Guard requirements, when available.

1

EXHIBIT F-2

COST OF ADDITIONAL PERSONNEL

Title	Total	On Drilling Rig	Regular Hourly Rate ($)	Overtime Rate with Burden	Daily Rate Per Man (w/ Burden)
Drilling Rig Supt	2	1	34.83	75.76	831.81
Toolpusher	4	2	30.48	66.29	736.47
Driller	4	2	25.69	55.88	637.43
Asst. Driller	8	4	17.85	38.83	465.29
Pumpman	4	2	13.50	29.36	369.78
Floorman	12	6	13.00	28.28	358.80
Maintenance Supervisor (Electrical)	2	1	26.12	56.81	641.12
Electrician	4	2	21.77	47.36	551.36
Assistant Electrician	2	1	16.50	35.89	435.65
Electronic Technician	4	2	22.86	49.72	575.30
Mechanic	4	2	21.77	47.36	551.36
Assistant Mechanic	2	1	16.50	35.89	435.65
Welder	2	1	15.75	34.26	419.18
Sub Sea Engineer	2	1	25.44	55.33	631.95
Assistant Sub Sea	2	1	21.77	47.36	551.36
Crane Operator	4	2	16.55	36.00	436.75
Roustabout	16	8	11.00	23.93	314.88
RTSC	2	1	17.85	38.83	465.29
Medic	2	1	15.67	34.09	417.42
Materialsman	4	2	15.02	32.67	398.00
Captain/OIM	2	1	35.70	77.65	850.88
Chief Officer	2	1	26.12	56.81	641.12
D.P. Operator	4	2	29.17	63.45	707.86
Assist. D.P. Operator	4	2	22.64	49.24	570.47
A.B. Seaman/Painters	6	3	11.00	23.93	314.88
Chief Engineer	2	1	28.30	61.55	688.79
First Engineer	2	1	22.64	49.24	570.47
2nd Engineer	4	2	19.59	42.62	503.50
Oiler/Motorman	4	2	14.00	30.45	380.76
Boatswain	2	1	17.42	37.89	455.85
Galley	As Needed
Total:	118	59

1

RBS8-D REPORTING ORGANIZATION CHART

EXHIBIT G

VESSEL / EQUIPMENT PERFORMANCE / ACCEPTANCE

VESSEL TESTS / ACCEPTANCE

CONTRACTOR and COMPANY agree that the Drilling Unit must satisfy various sea worthy type certifications, including but not limited to, U.S. Coast Guard, ABS, and certifications pertinent to the flag the vessel will be registered under. CONTRACTOR shall supply COMPANY with a copy of these certificates witnessed or approved by any regulatory body.

CONTRACTOR shall provide OPERATOR with a preliminary copy of the Drilling Unit’s Operations Manual as soon as it is available, prior to the Commencement Date and a final signed, dated and approved by ABS, as soon as received.

Additional vessel and equipment function/acceptance test criteria shall be developed and mutually agreed by CONTRACTOR and COMPANY and provided by the CONTRACTOR as a condition of delivery of the vessel. These shall include, but not be limited to: vessel, equipment acceptance, seatrials, full scale recoil test, dynamic position system (DP) / power systems failure mode effect analysis (FMEA) and fault tree analysis and a blowout preventer (BOP) multiplex control system (Mux) System FMEA and fault tree analysis. In principle, Shipyard Sea Trials shall be conducted as specified in the Shipyard Specifications, Chapter 18, Test and Trials. Additional test may be required upon arrival in the Gulf of Mexico, as mutually agreed. The project managers of the Parties agree to provide the following:

·	Vessel / equipment acceptance / seatrials procedures:	one (1) month prior to delivery
·	DP/power systems FMEA and fault tree analysis:	two (2) month after final design
·	BOP mux control system FMEA and fault tree analysis:	two (2) month after final design

1

EXHIBIT H

PROJECT EXECUTION PLAN

Construction and operation of the Drilling Unit (RBS8D) represents a major financial commitment to the Parties. Additionally, the Drilling Unit will be an integral part of COMPANY’S long range business plan for oil and gas exploration in the deepwater’s of the Gulf of Mexico. Any change in cost, delivery or operability relating to the Drilling Unit could have a substantial impact on COMPANY’S plan, therefore, COMPANY must be notified immediately of any changes that would effect these items.

To help mitigate the risk, a mutually agreed Project Execution Plan will be developed to insure the Drilling Unit is delivered on time, within budget, is outfitted and will operate in accordance with this CONTRACT. To ensure that the latest technology is incorporated and maximum performance achieved, representatives from third party suppliers shall also be included. As a minimum, The Project Execution Plan will address the following items in appropriate detail:

· Project Goals/Operating Principles

· Project Organization

· Roles/Responsibilities/Accountabilities

· Project Description/Schedule/Milestones

· Overall Assurance Plan

· Safety

· Interface Coordination Plan (Communication)

· Quality Plan

· Document Control

· Approval Process

· Change Control Procedures

· Management of Change

· Meeting/Presentation Schedule

· Risk Management Register

· Cost Control

Without limiting CONTRACTOR’S obligations under this CONTRACT, COMPANY will provide representatives to monitor the design and construction of the Drilling Unit. Any changes to the Drilling Unit that would effect the Dayrate, delivery or operability will require an amendment to the CONTRACT as set forth in Article 35.2. All changes to the design or specifications set forth in this CONTRACT require the Company Project Manager approval.

The project manager of the Parties agree to have a mutually agreed Project Execution Plan finalized by February 1, 1999.

1

April 13, 1999

Vastar Resources, Inc.

15375 Memorial Drive

Houston, TX 77079

Attention: Mr. Don Weisinger

Re: Drilling Contract dated December 08, 1998 between Vastar Resources, Inc. and R&B Falcon Drilling Co. for the Drilling Unit “RBS-8D” - Effective Date Establishment of Base Figures in accordance with Article 2.3.2 of the Contract

Gentlemen:

Pursuant to Article 2.3.2, we wish to advise that our base figures for the 4 items are as follows:

a. Labor (all inclusive)	U.S.$21,420 \ Day
b. Catering	U.S.$2,364 \ Day
c. Spare Parts & Supplies	PPI Code No. 1191.02 Base = 133.8 (Preliminary - December, 1998) -
d. Insurance	U.S.$2,660 \ Day

As the United States Department of Labor has not yet published the final December, 1998 index for Code No. 1191.02 “Oil Field and Gas Field Drilling Machinery”, the above base index of 133.8 is still officially classified as preliminary and may be subject to change. The final index will be published in early May 1999. We shall write to you again at this time either to confirm 133.8 as the final figure or to advise the new figure. In any event, we felt it best not to further delay the submission to you of the other base figures due to the 4 month time lag in the publication of Government economic statistics.

Whilst writing, we wish to bring to your attention the following errors in Exhibit F-2 “Cost of Additional Personnel”:

Title	Hrly Rate Shown			Correct Hrly Rate
Drilling Rig Supt	$	34.83	Should be	$	35.70
Captain/OIM	$	35.70	Should be	$	34.83
Chief Officer	$	26.12	Should be	$	27.43
D. P. Operator	$	29.17	Should be	$	23.08
Assist D. P. Operator	$	22.64	Should be	$	20.90

We shall go ahead and formally change Exhibit F-2 to show the correct rates and revised corresponding extension figures upon receipt of your agreement to the above.

Sincerely yours,

R&B Falcon Drilling Co.

/s/ W.L. Ellis

W.L. Ellis

Regional Operations Manager

R&B Falcon Corporation 901 Threadneedle · Houston, Texas 77079 · (281) 496-5000 www.rbfalcon.com

Contract Budget Request

RBS8-D Vastar Resources, Inc. / Gull of Mexico

Expatriate Rig Payroll

Exchange Rate: US $1.00 =1 U.S. $ [03PAY]

			Total Per Employee
	Budgeted	Budgeted	Annual	Regular	Regular	Regular	Regular	Payroll/	Payroll
	On Board	Total	Work	Monthly	Monthly	Monthly	Annual	Calenday	Per
Rig-based	Expats	Expats	Days	Base	Travel Pay	Total	Total	Day	Work Day
Asst. Superintendent*	1.00	2.00	182.50	8,000		8,000	96,000	263	526
Toolpusher	2.00	4.00	182.50	7,000		7,000	84,000	230	460
Tourpusher						0	0
Barge Engineer*				6,000		6,000	72.000
Asst. Barge Engineer*				4,800		4,800	57,600
Maintenance Supervisor*	1.00	2.00	182.50	6,000		6,000	72,000	197	395
Driller	2.00	4.00	182.50	5,900		5,900	70,800	194	388
Alternate Driller	4.00	8.00	182.50	5,000		5,000	60,000	164	329
Alternate Driller Trainee						0	0
Derrickman				3,330		3,330	39,960
Pumpman	2.00	4.00	182.50	3,101	250	3,351	40,212	110	220
Motorman				3,215		3,215	38,580
Welder	1.00	2.00	182.50	3,617		3,617	43,404	119	238
Crane Operator	2.00	4.00	182.50	3,800		3,800	45,600	125	250
Heavy Lift Crane Operator**						0	0
Barge Captain						0	0
Asst. Barge Captain						0	0
Control Room Operator*				4,500		4,500	54,000
Asst. Control Room Operator*				3,600		3,600	43,200
Mechanic	2.00	4.00	182.50	5,000		5,000	60,000	164	329
Asst. Mechanic	1.00	2.00	182.50	3,790		3,790	45,480	125	249
Mechanic Helper						0	0
Electronic Technician*	2.00	4.00	182.50	5,250		5,250	63,000	173	345
Electrician	2.00	4.00	182.50	5,000		5,000	60,000	164	329
Asst. Electrician	1.00	2.00	182.50	3,790		3,790	45,480	125	249
Electrician Helper						0	0
Subsea Engineer*	1.00	2.00	182.50	7,000		7,000	84,000	230	460
Asst. Subsea Engineer*	1.00	2.00	182.50	5,000		5,000	60,000	164	329
Materialsman						0	0
Storekeeper	2.00	4.00	182.50	3,450		3,450	41,400	113	227
Medic	1.00	2.00	182.50	3,450		3,450	41,400	113	227
Radio Operator				3,101		3,101	37,212
Floorman	6.00	12.00	182.50	2,986	250	3,236	38,832	106	213
Lead Roustabout						0	0
Roustabout	8.00	16.00	182.50	2,526	250	2,776	33,312	91	183
Paint Foreman						0	0
Painter				2,124		2,124	25,488
Captain/Master***	1.00	2.00	182.50	8,000		8,000	96,000	263	526
Chief Officer***	1.00	2.00	182.50	6,300		6,300	75,600	207	414
First Officer***				5,300		5,300	63,600
Second Officer***				4,800		4,800	57,600
Third Officer***				4,200		4,200	50,400
Chief Engineer***	1.00	2.00	182.50	6,500		6,500	78,000	214	427
First Engineer***	1.00	2.00	182.50	6,000		6,000	72,000	197	395
Second Engineer***	2.00	4.00	182.50	5,200		5,200	62,400	171	342
Bosun***	1.00	2.00	182.50	4,000		4,000	48,000	132	263
Deck Supervisor***				4,000		4,000	48,000
D.P. Operator***	2.00	4.00	182.50	5,300		5,300	63,000	174	348
Asst. D.P. Operator***	2.00	4.00	182.50	4,800		4,800	57,600	158	316
Oiler***	2.00	4.00	182.50	3,215	250	3,465	41,580	114	228
Able Seaman***	3.00	6.00	182.50	2,526	250	2,776	33,312	91	183
Rig Safety & Training Coordinator	1.00	2.00	182.50	4,100		4,100	49,200	135	270
Other						0	0
Total	59.00	118.00	Overtime Wages Total				0
			OIM Premium ($4,800 if applicable)				4.800
			Total Annual Expatriate Payroll				6,257,544
			Total Per Day Expatriate Payroll				17,144	(Posts to Rig Payroll)

* Semisubmersibles Only
** Super Tenders Only	Total Payroll Burden Per Day	20	%	3,429	(Posts to Payroll Burden)

Contract Budget Request

RBS8-D / Vastar Resources, Inc. / Gulf of Mexico

Expatriate Training Costs

Exchange Rate: US $1.00 =1 U.S. $ [09XPTTRN]

Employee Name	Employee Position	Name of School	School Location	# of Days	Training Wages Per Day	Outside Tuition	International Airfare	Domestic/ Charter	Hotel Per Day	Meals Per Day	Other
T.B.A.	Various	Well Control		10	75	2,500	300		100	35	20
T.B.A.	Various	Cyberchair		10	75	2,500	300		100	35	20
T.B.A.	Various	Varco		10	75	2,500	300		100	35	20
T.B.A.	Various	PM		10	75	2,500	300		100	35	20
T.B.A.	Various	GE		10	75	2,500	300		100	35	20
T.B.A.	Various	Burgess		10	75	2,500	300		100	35	20
T.B.A.	Various	Brandt		10	75	2,500	300		100	35	20
T.B.A.	Various	Fire Fighting		10	75	2,500	300		100	35	20
T.B.A.	Various	Sea Survival		10	75	2,500	300		100	35	20
T.B.A.	Various	Wartslia		10	75	2,500	300		100	35	20
T.B.A.	Various	Kamewa		10	75	2,500	300		100	35	20
T.B.A.	Various	Simrad		10	75	2,500	300		100	35	20
T.B.A.	Various	High Voltage		10	75	2,500	300		100	35	20
T.B.A.	Various	Alborg		10	75	2,500	300		100	35	20
T.B.A.	Various	Bridge Mgn		10	75	2,500	300		100	35	20
T.B.A.	Various	Radar		10	75	2,500	300		100	35	20
T.B.A.	Various	GMDSS		10	75	2,500	300		100	35	20
T.B.A.	Various	HLO		10	75	2,500	300		100	35	20
T.B.A.	Various	Crane Ops		10	75	2,500	300		100	35	20
T.B.A.	Various	AWC		10	75	2,500	300		100	35	20
T.B.A.	Various	STOP / H2S		10	75	2,500	300		100	35	20
T.B.A.	Various	EPT		10	75	2,500	300		100	35	20
T.B.A.	Various	DGPS		10	75	2,500	300		100	35	20
				230	1,725	57,500	6,900	0	2,300	805	460
				Total Training Wages			17,250
				Total Outside Tuition			57,500
				Total Training Travel			38,410
				Total Training Costs			113,160
				Per Day Training Costs			310	(Posts to Training Costs)

Contract Budget Request

RBS8-D / Vastar Resources, Inc. / Gulf of Mexico

Expatriate Operational Travel

Exchange Rate: US $1.00 =1 U.S. $ [15EXTRAV]

Crew Change Commuter Travel

		Annual	Cost Per Trip					Total		Round
Airport of Origin	Total Personnel	Roundtrips Per Emp.	International Airfare	Domestic/ Charter	Hotel	Meals	Other	Annual costs	Commuter Schedule	Trips Per Year
East Coast	12	8.69		300	75	35	20	44,840	7x7	26.07
West Coast	12	8.69		300	75	35	20	44,840	14x14	13.04
North Central	12	8.69		200	75	35	20	34,412	21x21	8.69
Texas	12	8.69		100	75	35	20	23,984	28x28	6.52
Louisana	12	8.69		100	75	35	20	23,984	35x35	5.21
Mississippi	12	8.69		100	75	35	20	23,984	42x42	4.35
Other	4							0	56x56	3.26
								0	14x7	17.38
								0	21x14	10.43
								0	28x14	8.69
								0	56x28	4.35
								0	112x56	2.17
								0
								0
								0
								0
								0
								0
								0
								0
								0
								0
								0
								0
								0
								0
								0
								0
								0
								0
Expatriate Commuters	76		Total Annual Expatriate Commuter Travel					196.046
			Expat Cost / Man / Calendar Day				7.07
			Total Annual Expatriate Operationl Travel					196,046
			Total Per Day Expatriate Operational Travel					537	(Posts to Operational Travel)

Contract Budget Request

RBS8-D / Vastar Resources, Inc. / Gulf of Mexico

Catering

Exchange Rate: US $1.00 =1 U.S. $ [12CAT]

Category	Personnel On Board		Manday Rate		Total/Day Per Category		Annual Catering Costs
Expatriate	59.00		34.26		2,021		737,789
TCN	0.00		34.26		0		0
National	0.00		34.26		0		0
Total Regular Crews	59.00				2,021		737,789
AVG OPERATOR ON BOARD	30.00		34.26		1,028		375,147
OPERATOR RECHARGE	(20.00	)	(34.26	)	(685	)	(250,098	)
NET OPERATOR CATERING	10.00

NOTE:

AVG OPERATOR ON BOARD = ACTUAL AVERAGE OPERATOR/THIRD PARTY PERSONNEL ON BOARD. MANUAL INPUT REQUIRED.

OPERATOR RECHARGE = AUTOMATIC CALCULATION.

NET OPERATOR CATERING = CONTRACT SPECIFIED NUMBER OF OPERATOR/THIRD PARTY PERSONNEL TO PROVIDE CATERING.

MANUAL INPUT REQUIRED.

Office Staff	0.00	34.26	0	0
Crew Change	0.00	34.26	0	0
Other Mandays	0.00	34.26	0	0
Total Other Mandays	0.00		0	0
			Other Annual Amounts	0
			Other Annual Amounts	0
			Total Annual Catering Cost	862,838
Daily Personnel On Board	89.00		Total Per Day Catering Cost	2,364	(Posts to Catering)

Data extracted on: April 12, 1999 (10:20 AM)

Producer Price Index-Commodities

Series Catalog:

Series ID : wpu119102

Not Seasonally Adjusted

Group : Machinery and equipment

Item : Oil field and gas field drilling machinery

Base Date : 8200

Data:

Year	Jan		Feb		Mar		Apr	May	Jun	Jul	Aug	Sep	Oct	Nov	Dec		Ann
1989	96.9		97.1		97.2		97.1	97.6	97.6	97.6	98.4	98.6	99.3	99.5	99.5		98.0
1990	99.6		99.6		99.2		99.2	99.3	99.9	100.2	101.5	105.8	106.2	106.6	106.6		102.0
1991	106.7		107.7		108.7		108.8	110.0	110.0	110.0	110.0	110.0	110.0	110.1	110.1		109.3
1992	110.1		110.1		110.1		110.1	110.2	110.4	110.6	110.6	110.6	110.8	112.4	112.5		110.7
1993	112.8		112.9		113.3		112.1	112.0	112.2	112.3	112.3	113.4	113.4	113.4	114.6		112.9
1994	114.6		114.6		114.6		114.6	114.7	114.9	115.4	115.4	115.9	117.8	117.8	117.8		115.7
1995	118.3		118.6		119.2		119.2	119.3	119.6	120.4	120.4	120.4	122.0	122.2	122.2		120.1
1996	124.0		124.0		124.0		124.3	124.2	124.8	125.3	125.3	125.3	126.2	126.6	127.1		125.1
1997	127.7		127.9		128.6		129.1	129.2	129.3	129.3	129.5	129.7	130.3	131.4	132.0		129.5
1998	133.1		132.9		133.1		133.0	133.0	133.0	132.9	132.9	132.9	133.6	133.6	133.8	(P)	133.2	(P)
1999	134.0	(P)	133.9	(P)	133.9	(P)

P: Preliminary. All indexes are subject to revision four months after original publication.

Data Home Page

BLS Home Page

http://146.142.4.24/cgi-bin/srgatc

Memo

To:	John Luedtke	Date:	August 3, 1998
From:	Robert B. Carvell
Subject:	Estimated Annual Premium
	RBS-8 M
	Effective 15 March 1998

CONFIDENTIAL
I.	Coverage:	All Risk Hull & Machinery
	Insured Value:	$325,000,000
	Deductible:	$250,000 Per Occurrence
	NET ANNUAL PREMIUM:	$528,996.80
II.	Coverage:	Loss of Hire
	Daily Indemnity:	$189,000
	Policy Limits:	180 Days
	Deductible Period	21 Days
	NET ANNUAL PREMIUM	$232,867
III.	Coverage:	Primary Marine Protection & Indemnity
	Policy Limits:	$1,000,000 Per Occurrence
	Deductible:	$100,000 Per Occurrence
	NET ANNUAL PREMIUM (U.S. WATERS)	$182,000.00
	NET ANNUAL PREMIUM (FOREIGN WATERS)	$ 78,000.00
IV.	Coverage:	Excess Liability
	Policy Limits:	$400,000,000
	Deductible:	XS of Primary Marine P&I
	NET ANNUAL PREMIUM	$6,795.00

Continued/......

V.	Coverage:		Contingent Energy Exploration & Development
	Policy Limits:		$100,000,000
	Deductible		$250,000 Per Occurrence
	NET ANNUAL PREMIUM		$704.76
VI.	U.S. Brokers:		Aon Risk Services, Inc.
	ANNUAL FEE		$19,379.85
TOTAL ANNUAL PREMIUM:		(U.S. Waters)	$970,743.41
		(Foreign Waters)	$866,743.41

  Mike Roth MARKETING MANAGER NAR R & B FALCON DRILLNG CO. 311 BROADFIELD BLVD., SUITE 400 HOUSTON, TEXAS 77084

July 24, 2001

Vastar Resources, Inc

15375 Memorial Drive

Houston, TX 77079

Attn:	Mr. Don Weisinger
Re:	Vastar Resources Inc. (“Vastar”) & R & B Falcon Drilling Company (“R &B”) Drilling Contract — RBS-8D — Deepwater Horizon (“Rig”) (hereinafter referred to as the “Contract”) Deepwater Horizon Contract Amendment — Additional Personnel

Dear Mr. Weisinger,

Reference is made for all purposes to that certain Offshore Drilling/Workover/Completion Contract dated December 9, 1998 (“Contract”), by and between R&B Falcon Drilling Co. (“R&B”) and Vastar Resources, Inc. (“Vastar”).

Upon Commencement Date of the Contract, Vastar has requested and R&B agrees to provide two additional (2) Deck Foremen, four (4) Assistant Pumphands, four (4) Solid Control Technicians and four (4) Roustabouts in addition to those specified to be provided in Exhibit F-2 of the Contract, for operations on the semi-submersible Deepwater Horizon. Exhibit F-2 shall be amended, effective as of June 26, 2001 to provide for these additional personnel, at cost to be paid by Vastar based upon the following rates, subject to the labor cost escalations set forth therein:

Title	Total	On Rig	Overtime Rate (per person per hour) with Burden		Daily Rate (per person) with Burden		Total Day Rate with Burden
Asst. Pumpman	4	2	$	27.18	$	368.30	$	736.60
Solid Control Tech	4	2	$	27.18	$	368.30	$	736.60
Deck Foreman	2	1	$	38.14	$	478.93	$	478.93
Roustabout	4	2	$	23.08	$	332.89	$	665.78
TOTAL ADDITIONAL PERSONNEL	14	7					$	2,617.91

Above rates are exclusive of a $65.00 per manday cost of training and transportation.

Vastar reserves the right to elect to release one or all of the above additional personnel upon thirty (30) days written notice to R&B. R&B may, if at that time R&B deems such personnel necessary for its operations, elect to retain such personnel at its own cost.

PHONE: 281-647-8518 FAX: 281-647-8754 EMAIL:mroth@deepwater.com

VASTAR RESOURCES, INC.
Deepwater Horizon Contract Amendment – Additional Personnel	June 26, 2001
TSF File #01-063

Except as expressly amended herein, the terms and conditions of the Contract shall remain in full force and effect as originally executed.

If the above and foregoing sets forth your understanding of the agreement between R&B and Vastar, please sign both originals in the space provided below and return one fully executed original agreement to the undersigned.

Sincerely,

R & B Falcon Drilling Co.

/s/ Mike Roth

Mike Roth

AGREED AND ACCEPTED

THIS 26 DAY OF JULY, 2001

VASTAR RESOURCES INC.

SIGNED	/s/ Don Weisinger
PRINTED	Don Weisinger
TITLE	Drilling Team Leader

TERRY BONNO	R & B FALCON DRILLING COMPANY
SR. MARKETING REPRESENTATIVE	311 BROADFIELD BLVD., SUITE 400
	HOUSTON, TEXAS 77084

December 12, 2001

BP America Production Company

Attn: Don Weisinger

501 WestLake Park Blvd.

Houston, TX 77079

Reference:	Drilling Contract No. 980249 between Vastar Resources Inc. , predecessor in interest to BP America Production Company (“BP”) and R&B Falcon Drilling Company (“R&B”) dated December 9, 1998 for RBS-8D (now known as the Deepwater Horizon), as amended (the “Contract”)
Subject:	Letter of Agreement for Cost Escalation and Naming Convention Adjustments

Dear Mr. Weisinger,

In accordance with Article 2 – Dayrates, Section 2.3 – Adjustment in Dayrates, we have recently completed an analysis of the costs of the Deepwater Horizon. To assist in clarification of position titles as related to the merger between R&B Falcon and Transocean, we have amended Exhibit F-1 – Crew Compliment and Exhibit F-2 – Cost of Additional Personnel. Both amended exhibits are attached and titled, Exhibit F-1a and Exhibit F-2a, which are the original Exhibit F-1 and F-2 with the only revisions made are position title changes as per the Naming Conventions of the merged company and will supercede the originals.

Cost analysis for the Deepwater Horizon has been calculated based on the contract and the Establishment of Base Figures letter dated April 13, 1999. All costs have been reviewed and adjusted relative to the Contract Section 2.3.2 a) Labour Costs, b) Catering Costs, c) Spare Parts/Supplies Element, and d) Insurance Element. Please find the attached documents to substantiate our escalations including the Basis for Cost Escalations spreadsheet, Personnel List with rates, and the Bureau of Labor Statistics Data printout. The attached Basis for Cost Escalation Spreadsheet specifies the base rates, the new totals after this escalation and the variance column indicates the increase or decrease as appropriate per section. Payments of such adjustments shall be deemed to be effective beginning on the date the rig commenced operations, September 18, 2001. R&B shall issue an invoice for this retroactive adjustment and BP shall pay this invoice in accordance with the billing and payment procedures in the Contract.

In accordance with the terms of the referenced contract, the parties agree to the following new dayrate changes under this letter of agreement:

2.3.2a	The Base Labor cost adjustment will be an increase of $6,876 from the baseline of $21,420 with a new total of $28,296. Labor will also increase by $239 on the additional personnel to a new total of $2,613.
2.3.2b	Contractor’s cost of catering has decreased by ($541) to a new total of $2,067 under the baseline of $2,608.

PHONE: 281-675-8848 FAX: 281-647-8754 EMAIL:tbonno@deepwater.com

BP America Production Company

Deepwater Horizon Contract - Cost Escalation

TSF File #01-063

2.3.2c	Based on the initial base Spare Parts/Supplies Element of $12,692, there will be an increase of $1,159 to a new baseline of $13,851.
2.3.2d	The insurance element has decreased by $861 over the baseline figure of $2,660 and the new Total Base Insurance Cost will be $1,799.

Except as expressly provided herein, the terms and conditions of the Contract shall remain in full force and effect. Each party represents that this letter agreement has been validly executed and delivered, and has been duly authorized by all action necessary for the authorization therefore.

In summary, the following changes are effective as follows:

Paragraph	2.3.2a	$	6,876
Paragraph	2.3.2a	239			(additional personnel)
Paragraph	2.3.2b	(541		)
Paragraph	2.3.2c	1,159
Paragraph	2.3.2d	(861		)
Total		$	6,872

If the above and foregoing sets forth your understanding of the agreement between R&B and BP, please sign both originals in the space provided below and return one fully executed original agreement to the undersigned.

If you have any questions, please contact the undersigned or John Keeton at Transocean’s Park Ten Office 281-647-8500.

Sincerely,

/s/ Terry Bonno

Terry Bonno

Sr. Marketing Representative

On Behalf of R & B Falcon Drilling Co.

AGREED AND ACCEPTED

THIS 13th DAY OF JUNE, 2002

BP AMERICA PRODUCTION COMPANY

SIGNED	/s/ R. Kevin Guerre
PRINTED	R. Kevin Guerre
TITLE	TL - SCM

2

EXHIBIT F-1a

CREW COMPLEMENT

Drill Crew	Total	On Board
Drilling Rig Supt/OIM	2	1
Toolpusher	4	2
Driller	4	2
Asst. Driller	8	4
Pumphand	4	2
Floorhand Roughneek	12	6
Maintenance Electrical Supervisor (Electrical)	2	1
Chief Electrician	4	2
Assistant Electrician	2	1
Chief Electronic Technician	4	2
Chief Mechanic	4	2
Assistant Mechanic	2	1
Welder	2	1
Sub Sea Supervisor Engineer	2	1
Assistant Sub Sea	2	1
Crane Operator	4	2
Roustabout	16	8
Rig Safety & Training Coordinator Officer	2	1
Medic	2	1
Materialsman Materials Coordinator	4	2
Captain Master/OIM	2	1
Chief Mate Officer	2	1
D. P. Operator	4	2
Assist. D.P. Operator	4	2
A.B. Seaman/Painters	6	3
Chief Engineer	2	1
First Asst. Engineer	2	1
2ndAsst. Engineer	4	2
Motorhand	4	2
Beatswain Bosun	2	1
Galley	As Needed
Tota1:	118	59

a)	Galley crew ratio of one to every 10 persons on board.
b)	A mutually agreed pre-commencement manning schedule shall be attached.
c)	Contractor may, with Company approval, reduce the marine crew manning based upon Coast Guard requirements, when available.

Contract No. 980249

1

BASIS FOR COST ESCALATIONS

DEEPWATER HORIZON

As of September 1, 2001

	Per Baseline
	Costs Plus				2001
	July 24, 2001 Letter		Sept. 2001		Variance
Base Labor Cost:
Labor & Burden (per schedule)	$	20,573	25,476		4,903
Training & Transportation Costs	847		2,820		1,973
Total Base Labor Cost	$	21,420	$	28,296	$	6,876
Percentage Increase					32		%
Additional Crew Increase per agreement dated July 24, 2001
Labor & Burden (per schedule)	2,163		2,278		115
Training & Transportation Costs	$	211	335		124
Total Additional Personnel Cost	$	2,374	$	2,613	$	239
Percentage Increase					10		%
Base Catering Cost:
59 Combined Personnel @            $ 27.20	$	2,021	$	1,605	(417		)
7 Additional Personnel @            $ 27.20	$	244	$	190	(53		)
10 Company Personnel @             $ 27.20	$	343	$	272	(71		)
Total Base Catering Costs	$	2,608	$	2,067	$	(541	)
Percentage Increase					-21		%
Base Insurance Cost	$	2,660	$	1,799	$	(861	)
Percentage Increase					-32		%
Base Repair and Maintenance Cost	$	12,692	$	13,851	$	1,159
Percentage Increase					9		%
Total Baseline Operating Costs	$	41,754	$	48,626	$	6,872

Horizon Cost Escalations

1

DEEPWATER HORIZON

Adjusted Base Labor as of September 1, 2001

				A	B		C	D
Gulf of Mexico Crew Complement				GOM Base Labor w/Burden			GOM Overtime Rates
	No. of Personnel			Daily Rate	Total Daily		Daily	Hourly
JOB	On	Assigned		(per person)	On Board		Rate	Rate
CODE	Board	To Rig	JOB CLASSIFICATION	w/ Burden*	Cost**		w/ Burden**	w/ Burden**
	1	2	Offshore Installation Manager	930.23	855.23		Salaried
	2	4	Toolpusher	761.90	1,373.80		Salaried
	2	4	Driller	650.87	1,151.74		650.12	54.18
	4	8	Assistant Driller	493.35	1,673.41		462.88	38.57
	2	4	Pumphand	408.82	667.65		362.40	30.20
	10	20	Floorhand	395.57	3,205.71		346.65	28.89
	10	20	Roustabout	353.97	2,789.67		297.20	24.77
	1	2	Welder	475.62	400.62		441.80	36.82
	2	4	Crane Operator	493.35	836.70		462.88	38.57
	2	4	Chief Mechanic	581.84	1,013.67		568.06	47.34
	1	2	Mechanic	471.20	396.20		436.55	36.38
	2	4	Motor Operator	395.97	641.93		347.12	28.93
	1	2	Electrical Supervisor	663.46	588.46		Salaried
	2	4	Chief Electrician	581.84	1,013.67		568.06	47.34
	1	2	Electrician	471.20	396.20		436.55	36.38
	2	4	Chief Electronic Technician	590.67	1,031.34		578.56	48.21
	1	2	Senior Sub Sea Supervisor	768.23	693.23		Salaried
	1	2	Assistant Sub Sea Supervisor	546.43	471.43		525.97	43.83
	2	4	Materials Coordinator	435.79	721.58		394.46	32.87
	1	2	Master	810.10	735.10		Salaried
	1	2	Chief Mate	675.99	600.99		679.98	56.66
	1	2	Chief Engineer	751.42	676.42		Salaried
	1	2	1st Assist. Engineer	634.12	559.12		630.21	52.52
	2	4	2nd Assist. Engineer	599.57	1,049.14		589.14	49.10
	2	4	Dynamic Position Operator	546.43	942.86		525.97	43.83
	2	4	Assistant Dynamic Position Operator	457.95	765.89		420.79	35.07
	1	2	Deck Pusher	512.80	437.80		486.00	40.50
	1	2	Bosun	457.95	382.95		420.79	35.07
	3	6	Able Bodied Seaman	413.70	1,016.11		368.20	30.68
	1	2	Rig & Safety Training Technician*	466.78	391.78		431.29	35.94
	1	2	Rig Medic/Clerk	348.23	273.23		290.38	24.20
	66	132	Total Base Labor Costs =		$	27,753.63

	*	Does include catering, transportation, or training expense.
	**	Does NOT include catering transportation, or training expense.
Notes:	1)	The figures in column “A” are to be used as the basis for adding personnel to the permanent crew and for determining the credit for crew members short.
	2)	The figures in column “B” are the product of multiplying the number of “on board” personnel by the “Daily Rate w/ Burden” in column “A”. The Sum of column “B” is the “Total Base Labor Cost” per day.
	3)	The figures in columns “C” and “D” are the basis for charging the Operator for overtime hours worked at the request of the Operator.

Bureau of Labor Statistics Data	Bureau of Labor Statistics U.S. Department of Labor
Home · Programs & Surveys · Get Detailed Statistics · Topics A-Z · Glossary · What’s New

Data extracted on: June 13, 2002 (10:18 AM)

Producer Price Index-Commodities

Series Catalog:

Series ID : wpu119102

Not Seasonally Adjusted

Group : Machinery and equipment

Item : Oil field and gas field drilling machinery

Base Date : 8200

Data :

Year	Jan	Feb		Mar		Apr		May		Jun	Jul	Aug	Sep	Oct	Nov	Dec	Ann
1992	110.1	110.1		110.1		110.1		110.2		110.4	110.6	110.6	110.6	110.8	112.4	112.5	110.7
1993	112.8	112.9		113.3		112.1		112.0		112.2	112.3	112.3	113.4	113.4	113.4	114.6	112.9
1994	114.6	114.6		114.6		114.6		114.7		114.9	115.4	115.4	115.9	117.8	117.8	117.8	115.7
1995	118.3	118.6		119.2		119.2		119.3		119.6	120.4	120.4	120.4	122.0	122.2	122.2	120.1
1996	124.0	124.0		124.0		124.3		124.2		124.8	125.3	125.3	125.3	126.2	126.6	127.1	125.1
1997	127.7	127.9		128.6		129.1		129.2		129.3	129.3	129.5	129.7	130.3	131.4	132.0	129.5
1998	133.1	132.9		133.1		133.0		133.0		133.0	132.9	132.9	132.9	133.6	133.6	133.6	133.1
1999	133.8	133.7		133.7		133.9		133.9		134.0	134.0	133.7	133.7	133.7	134.4	134.6	133.9
2000	134.9	136.3		136.3		136.3		136.5		136.5	136.5	136.6	136.7	138.7	138.7	138.7	136.9
2001	143.5	143.9		144.0		144.0		144.0		145.5	145.6	145.8	145.7	146.1	146.1	146.1	145.0
2002	146.2	146.0	(P)	146.7	(P)	146.7	(P)	146.5	(P)

Preliminary. All indexes are subject to revision four months after original publication.

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			Memo
To:	Terry Bonno	Date:	December 6, 2001
From:	James Mitchell, Director of Risk Management
Subject:	Estimated Annual Premium – Deepwater Horizon

CONFIDENTIAL

The following annual premiums have been established for the Deepwater Horizon and are effective September 1, 2001:

Coverage: Insured Value: Deductible: NET ANNUAL PREMIUM:	All Risk Hull & Machinery $350,000,000 ($5MM/$7.5MM/$7.5MM/$10MM aggregate layers) $470,329
Coverage: Policy Limits: Deductible: NET ANNUAL PREMIUM (US WATERS): NET ANNUAL PREMIUM (FOREIGN WATERS):	Primary Marine Protection & Indemnity $1,000,000 per occurrence $250,000 Per Occurrence $125,352 $53,796
Coverage: Insured Value: Deductible: NET ANNUAL PREMIUM:	Excess Liability $452,000,000 XS of Primary Marine P&I $26,334
U.S. BROKERS: ANNUAL FEE	McGriff Seibels & Williams, Inc. $34,454
TOTAL ANNUAL PREMIUM: (U.S. WATERS)	$656,469
TOTAL ANNUAL PREMIUM: (FOREIGN WATERS)	$584,913

Rig Name Contractor & No.	Effective Date	Commence Date	Duration Mos. &	Last Update/	Reoccurrence Timing	Reoccurrence Condition
Horizon(2) Vastar (BP) 01-063	Dec. 8, 1998	Sept. 1, 2001			Annually	=> 5%

	12/8/98 Baselines		9/1/01 Costs
A. Baseline Labor	$	21,420	$	28,296	32.10	%	$	6,876
Addtl Personnel	$	2,374	$	2,613			$	239
Total Labor	$	23,794	$	30,909			$	7,115
B. Catering	$	2,608	$	2,067			$	-541
C. Cost of R&M	$	12,692	$	13,851			$	1,159
BLS Indices	133.6		145.8		9.13	%
D. Insurance Premiums	$	2,660	1,799.00				$	-861
	$	41,754	$	48,626			$	6,872
								16	%

Summary

Escalations and baselines provide for increases in labor costs, catering costs, increases in the cost of repairs and maintenance and insurance premiums. All increases must exceed 5% and can be addressed as early as the Commencement Date and then only annually there after.

	R & B FALCON DRILLNG CO.
	1311 BROADFIELD BLVD., SUITE 400 HOUSTON, TEXAS 77084
JOHN KEETON RIG MANAGER

April 23, 2002

Vastar Resources, Inc.

C/O BP America Inc.

15375 Memorial Drive

Houston, TX 77079

Attn: Mr. Mike Stefanov

Reference:Deepwater Horizon Letter Agreement — Additional Personnel for Mad Dog Project CONTRACTOR-5121-2002-005

Dear Mr. Stefanov,

Reference is made for all purposes to that certain Offshore Drilling/Workover/Completion Contract dated December 9, 1998 (“Contract”), by and between R&B Falcon Drilling Co. (“Contractor”)and Vastar Resources, Inc. (“Company”), as amended.

Company has requested and Company and Contractor agree that CONTRACTOR will provide one (1) additional OIM and one (1) additional Sr. Toolpusher to work on the Mad Dog Project. The OIM and the Sr. Toolpusher will be shorebased and work at CONTRACTOR’s Park 10 office and at COMPANY’s offices as required to support the Mad Dog Project on an even rotating schedule. Work will commence on or about May 15, 2002 with an expected duration of approximately three (3) months.

CONTRACTOR shall invoice COMPANY at the rate of US$1,200 (one thousand two hundred) per day with CONTRACTOR being responsible for all costs for lodging, food, transportation and CONTRACTOR required training. The OIM and Sr. Toolpusher will be available for work seven days a week on an even rotating schedule and COMPANY shall be billed for the full seven days each week. CONTRACTOR will supply supporting documentation with each monthly invoice as evidence of days available for work.

COMPANY reserves the right to release the services of the OIM and Sr. Toolpusher at anytime upon thirty (30) days prior written notice to CONTRACTOR. COMPANY and CONTRACTOR will document when the OIM and Sr. Toolpusher are released from duty for services on this special Mad Dog Project assignment, thus ending the applicability of this contract amendment.

All other terms and conditions of the referenced Contract, as amended, shall remain in full force and effect.

If the above sets forth your understanding of the agreement, please sign both originals in the space provided below and return one (1) fully signed original to us for our file.

PHONE: 832-587-8533 FAX: 832-587-8754 EMAIL:JKeeton@houston.deepwater.com

VASTAR RESOURCES INC

Deepwater Horizon Letter Agreement - Additional Personnel

CONTRACTOR File #01-063

We appreciate this opportunity to be of service to BP. If you have questions, please contact Terry Bonno for commercial concerns at 832-587-8848 or myself for technical concerns at 832-587-8533.

Sincerely,

/s/ John Keeton

John Keeton

R & B Falcon Drilling Co.

/ks

AGREED AND ACCEPTED THIS 24 DAY OF APRIL, 2002

VASTAR RESOURCES INC.

SIGNED	/s/ Allen Cook
PRINTED	Allen Cook
TITLE	MD Well Delivery TL

2

	R & B FALCON DRILLNG CO.
	1311 BROADFIELD BLVD., SUITE 400 HOUSTON, TEXAS 77084
TERRY BONNO
SR. MARKETING REPRESENTATIVE

June 3, 2002

BP America Production Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn:Mr. Jon Sprague

Mr. Charles Taylor

Reference:Deepwater Horizon Letter Agreement — Additional Personnel for Deepwater Horizon CONTRACTOR-5121-2002-006

Gentlemen:

Reference is made for all purposes to that certain Offshore Drilling/Workover/Completion Contract dated December 9, 1998 (“Contract”), by and between R&B Falcon Drilling Co. (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended.

Company and CONTRACTOR have recently discussed and agreed that the current manning level on the Deepwater Horizon is not sufficient to produce the potential operating efficiency levels for this type of Drilling Unit. In addition, recent feedback from the crew provided clear evidence that the crews feel that there are insufficient personnel to conduct simultaneous operations.

In a recent survey of crewing levels on similar Drilling Units in our fleet the following results were obtained:

	Horizon	Nautilus	Marianas
Crew Total	72	88	96

Based on these findings and our experience on these Drilling Units, CONTRACTOR suggests the following additional personnel to be added to the Deepwater Horizon on a semi-permanent basis to afford both companies the opportunity to conduct simultaneous operations.

Upon execution of this Letter Agreement by COMPANY and CONTRACTOR, CONTRACTOR agrees to provide two (2) additional Toolpushers, four (4) Floorhands, four (4) Crane Operators and eight (8) Roustabouts in addition to those specified to be provided in Exhibit F-2 of the Contract as amended, for operation on the semi-submersible Deepwater Horizon. Exhibit F-2 shall be amended to provide for these additional personnel, at cost to be paid by COMPANY based upon the following rates (as per the Escalation Letter Agreement dated December 12, 2001), subject to the cost escalations set forth therein:

Title	Total	On Rig	Overtime Rate (per person per hour) with Burden		Daily Rate (per person) with Burden		Total Day Rate with Burden
Toolpusher	2	1	N/A		$	761.90	$	761.90
Floorhand	4	2	$	28.89	$	395.57	$	791.14
Crane Operator	4	2	$	38.57	$	493.35	$	986.70
Roustabout	8	4	$	24.77	$	353.97	$	1,415.88
TOTAL ADDITIONAL PERSONNEL	18	9					$	3,955.62

In addition, COMPANY requests that one (1) additional Driller and welder per crew be added during the upcoming

PHONE: 832-587-8848 FAX: 832-587-8754 EMAIL:tbonno@houston.deepwater.com

VASTAR RESOURCES INC

Deepwater Horizon Letter Agreement - Additional Personnel

CONTRACTOR File #01-063

twenty-one day batch setting exercise on Atlantis as follows:

Title	Total	On Rig	Overtime Rate (per person per hour) with Burden		Daily Rate (per person) with Burden		Total Day Rate with Burden
Driller	2	1	$	54.18	$	650.87	$	650.87
Welder	2	1	$	36.82	$	475.62	$	475.62
TOTAL ADDITIONAL PERSONNEL	4	2					$	1,126.49

COMPANY reserves the right to release the services of the additional personnel at anytime upon thirty (30) days prior written notice to CONTRACTOR.

All other terms and conditions of the referenced Contract, as amended, shall remain in full force and effect.

If the above sets forth your understanding of the agreement, please sign both originals in the space provided below and return one (1) fully signed original to us for our file.

We appreciate this opportunity to be of service to BP. If you have questions, please contact me for commercial concerns at 832-587-8848 or John Keeton for technical concerns at 832-587-8533.

Sincerely,

/s/ Terry Bonno

Terry Bonno

R & B Falcon Drilling Co.

/ks

AGREED AND ACCEFTED THIS 10th DAY OF JUNE, 2002

BP AMERICA PRODUCTION COMPANY

SIGNED	/s/ R Kevin Guerre
PRINTED	R Kevin Guerre
TITLE	TL-SCM

2

R & B FALCON DRILLNG CO.

1311 BROADFIELD BLVD., SUITE 400

HOUSTON, TEXAS 77084

TERRY BONNO

SR MARKETING REPRESENTATIVE

June 12, 2002

BP America Production Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn:Mr. Don Weisinger

Reference:	Deepwater Horizon Letter Agreement – Cameron Variable Bore Rams Deepwater Horizon
	CONTRACTOR-5121-2002-007

Gentlemen:

Reference is made for all purposes to that certain Offshore Drilling/Workover/Completion Contract dated December 9, 1998 (“Contract”), by and between R&B Falcon Drilling Co. (“Contractor”) and Vastar Resources, Inc. (“Vastar”), predecessor in interest to BP America Production Company (“Company”), as amended.

Company and Contractor have recently discussed and agreed to provide a Cameron 3-1/2” X 6-5/8” Variable Bore Rams (“Equipment”) for use on the Deepwater Horizon. This Letter Agreement outlines the terms and conditions to provide the Equipment as follows:

1.The Equipment is limited to the following components

Description	Quantity
Variable Bore Ram 18-3/4” 15M BOP, 3-1/2” X 6-5/8” OD Pipe, API 16A, ABS and DNV Certification	2
Ram Wear Pad, Right Side 18-3/4” BOP	2
Ram Wear Pad, Left Side 18-3/4” BOP	2
Screw, Ram Wear Pads	8

2.Company has authorized Contractor to purchase Equipment and has agreed to a dayrate reimbursement fee of $125.00 per day to be paid over the remainder of the Contract on the Deepwater Horizon. Dayrate reimbursement fee shall commence on June 13, 2002.

3.If the Contract is terminated prior to September 18, 2004, Company shall reimburse Contractor via a lump sum payment of $125.00 per day times the days remaining in contract after termination date. Such payment shall be due within thirty days after presentation of an invoice to Company.

4.The Equipment provided under this agreement shall become part of Contractor’s equipment and incorporated into Exhibit B-2 of the Contract.

All other terms and conditions of the referenced Contract, as amended, shall remain in full force and effect.

PHONE: 832-587-8848 FAX: 832-587-8754 EMAIL:tbonno@houston.deepwater.com

VASTAR RESOURCES, INC.

Deepwater Horizon Letter Agreement – Variable Bore Rams

CONTRACTOR File #01-063

If the above sets forth your understanding of the agreement, please sign both originals in the space provided below and return one (1) fully signed original to us for our file.

We appreciate this opportunity to be of service to BP. If you have questions, please contact me for commercial concerns at 832-587-8848 or John Keeton for technical concerns at 832-587-8533.

Sincerely,

/s/ Terry Bonno

Terry Bonno

R & B Falcon Drilling Co.

/ks

AGREED AND ACCEPTED THIS 20th DAY OF JUNE, 2002

BP AMERICA PRODUCTION COMPANY

SIGNED	/s/ Jerry R Rhoads
PRINTED	Jerry R Rhoads
TITLE	Contracts Specialist

2

R & B FALCON DRILLNG CO.

1311 BROADFIELD BLVD., SUITE 400

HOUSTON, TEXAS 77084

CHRISTOPHER S. YOUNG

SR. MARKETING REPRESENTATIVE

August 26, 2002

BP America Production Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn: Mr. Randy Rhoads

Reference:	Deepwater Horizon Letter Agreement -
	CONTRACTOR-5121-2002-010

Gentlemen:

Reference is made for all purposes to that certain Offshore Drilling/Workover/Completion Contract dated December 9, 1998 (“Contract”), by and between R&B Falcon Drilling Co. (“Contractor”) and Vastar Resources,Inc. predecessor in interest to BP America Production Company (“Company”), as amended.

This is to document the recent agreement between our Mr. Doug Halkett and your Mr. Jon Sprague with respect to the cost of re-drilling the GC74344 well as a result of the recent “lost hole” incident.

Due to the special circumstances involved in the recent event in which the hole was lost while running 20” casing, the parties agree that, by way of compromise and in order to avoid further disputes with respect to the obligations under the Contract with respect to such event, commencing as of 13:00 August 15, 2002, Contractor shall be obligated at Company’s election to re-drill the hole, and Company shall pay ninety percent (90%) of the applicable Operating Rate, until such time as the depth at which the hole was lost is reached, but otherwise all subject to the terms and conditions of the Contract. Once we reach the depth at which the hole was lost, the parties agree that the applicable Operating Rate shall control per the Contract.

All other terms and conditions of the referenced Contract, as amended, shall remain in full force and effect.

If the above sets forth your understanding of the agreement, please sign both originals in the space provided below and return one (1) fully signed original to us for our files. We appreciate this opportunity to be of service to BP. If you have questions, please contact me at 832-587-8506 or John Keeton at 832-587-8533.

Yours very truly,

/s/ Christopher S. Young

Christopher S. Young

R & B Falcon Drilling Co.

PHONE: 832-587-8506 FAX: 832-587-8754 EMAIL:cyoung@houston.deepwater.com

BP America Production Company.

Deepwater Horizon Letter Agreement

CONTRACTOR File #01-063

/ks

AGREED AND ACCEPTED THIS 16th DAY OF SEPTEMBER, 2002

BP AMERICA PRODUCTION COMPANY

SIGNED	/s/ Jerry R Rhoads
PRINTED	Jerry R Rhoads
TITLE	Contracts Specialist

2

R&B FALCON DRILLING COMPANY

1311 BROADFIELD, SUITE 400

HOUSTON, TX 77084

CHRISTOPHER S. YOUNG

SR. MARKETING REPRESENTATIVE

September 18, 2002

BP America Production Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn:Mr. Randy Rhoads

Re: Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject:	Letter of Agreement for adding Deck Pusher
	CONTRACTOR-5121-2002-011

Dear Mr. Rhoads,

This letter will serve as our agreement to add another Deck Pusher to the crew complement of the Deepwater Horizon. Upon execution of this Letter Agreement by Company, Contractor agrees to provide one (1) Deck Pusher onboard the Deepwater Horizon in addition to those specified to be specified to be provided in Exhibit F-2 of the Contract as amended. Since we added the Deck Pusher in August, Exhibit F-l of the Contract shall be amended, as of August 1, 2002 to provide for the following additional personnel:

Title	On Board	Assigned to Rig	Daily Rate per Person w/ Burden		Hourly Overtime Rate w/Burden
Deck Pusher	1	2	$	512.80	$	40.50

Therefore, the amended crew complement shall show two (2) Deck Pushers “On Board” and four (4) “Assigned to Rig”. The amended crew complement is attached. In summary, all rates in the Contract shall increase by $512.80 per day effective August 1, 2002. Except as specifically provided herein, all other terms and conditions of the Contract shall remain in full force and effect. Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files.

If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

Sincerely,

/s/ Christopher S. Young

Christopher S. Young

Sr. Marketing Representative

On Behalf of R & B Falcon Drilling Co.

PHONE: (832) 587 8506 FAX: (832) 587 8754 EMAIL:cyoung@houston.deepwater.com

BP

Horizon – Escalation 2002

TSF File #01-063

AGREED AND ACCEPTED THIS 2ND DAY OF DECEMBER, 2002
BP AMERICA PRODUCTION COMPANY
SIGNED	/s/ Jerry R Rhoads
PRINTED	Jerry R Rhoads
TITLE	Contracts Specialist

2

DEEPWATER HORIZON

Adjusted Base Labor as of September 18, 2002

				A	B		C	D
Gulf of Mexico Crew Complement				GOM Base Labor w/Burden			GOM Overtime Rates
	No. of Personnel			Daily Rate	Total Daily		Daily	Hourly
JOB	On	Assigned		(per person)	On Board		Rate	Rate
CODE	Board	To Rig	JOB CLASSIFICATION	w/ Burden*	Cost* *		w/ Burden* *	w/ Burden* *
1883	1	2	Offshore Installation Manager	930.23	855.23		Salaried
1276	3	6	Toolpusher	761.90	2,060.70		Salaried
1295	2	4	Driller	650.87	1,151.74		650.12	54.18
1302	4	8	Assistant Driller	493.35	1,673.41		462.88	38.57
1845	2	4	Pumphand	408.82	667.65		362.40	30.20
1296	12	24	Floorhand	395.57	3,846.86		346.65	28.89
1297	14	28	Roustabout	353.97	3,905.54		297.20	24.77
799	1	2	Welder	475.02	400.02		441.00	36.82
1289	4	8	Crane Operator	493.35	1,673.41		462.88	38.57
1381	2	4	Chief Mechanic	581.84	1,013.67		568.06	47.34
1286	1	2	Mechanic	471.20	396.20		436.55	36.38
1305	2	4	Motor Operator	395.97	641.93		347.12	28.93
1355	1	2	Electrical Supervisor	663.46	588.46		Salaried
1345	2	4	Chief Electrician	581.84	1,013.67		568.06	47.34
1280	1	2	Electrician	471.20	396.20		436.55	36.38
1387	2	4	Chief Electronic Technician	590.67	1,031.34		578.56	48.21
1388	1	2	Senior Sub Sea Supervisor	768.23	693.23		Salaried
1372	1	2	Assistant Sub Sea Supervisor	546.43	471.43		525.97	43.83
394	2	4	Materials Coordinator	435.79	721.58		394.46	32.87
1668	1	2	Master	810.10	735.10		Salaried
1299	1	2	Chief Mate	675.99	600.99		679.98	56.66
1539	1	2	Chief Engineer	751.42	676.42		Salaried
0	1	2	1st Assist. Engineer	634.12	559.12		630.21	52.52
0	2	4	2nd Assist. Engineer	599.57	1,049.14		589.14	49.10
1688	2	4	Dynamic Position Operator	546.43	942.86		525.97	43.83
1323	2	4	Assistant Dynamic Position Operator	457.95	765.89		420.79	35.07
1238	2	4	Deck Pusher	512.80	875.60		486.00	40.50
1298	1	2	Bosun	457.95	382.95		420.79	35.07
1300	3	6	Able Bodied Seaman	413.70	1,016.11		368.20	30.68
1608	1	2	Rig & Safety Training Technician*	466.78	391.78		431.29	35.94
1677	1	2	Rig Medic/Clerk	351.73	276.73		294.53	24.54
	76	152	Total Base Labor Costs =		$	31,475.54

	*	Does include catering, transportation, or training expense.
	* *	Does NOT include catering transportation, or training expense.
Notes:	1)	The figures in column “A” are to be used as the basis for adding personnel to the permanent crew and for determining the credit for crew members short.
	2)	The figures in column “B” are the product of multiplying the number of “on board” personnel by the “Daily Rate w/ Burden” in column “A”. The Sum of column “B” is the “Total Base Labor Cost” per day.
	3)	The figures in columns “C” and “D” are the basis for charging the Operator for overtime hours worked at the request of the Operator.

3

AGREEMENT FOR ASSIGNMENT OF DRILLING CONTRACT

This Agreement (“Agreement”) is entered into this 14 day of October, 2002 between R&B FALCON DRILLING CO. (hereinafter “RBFDC”), an Oklahoma corporation having an office at Park Ten Centre, 1311 Broadfield Boulevard, Suite 400, Houston, Texas 77084 and TRANSOCEAN HOLDINGS INC. (hereinafter “THI”), a Delaware corporation, having an office at 4 Greenway Plaza, Houston, Texas 77046. RBFDC and THI may hereinafter sometimes be referred to individually as “Party” and collectively as “Parties”.

WHEREAS, RBFDC is a party to that drilling contract No. 980249 of December 9, 1998 with VASTAR RESOURCES, INC. (hereinafter “VASTAR”), now succeeded in interest by BP AMERICA PRODUCTION COMPANY (hereinafter “BP”), pertaining to the mobile offshore drilling unit “DEEPWATER HORIZON” (hereinafter “RIG”), as amended to date (hereinafter “Drilling Contract”); and,

WHEREAS, RBFDC wishes to assign the Drilling Contract to THI and THI is willing to accept said assignment.

NOW THEREFORE, for Ten Dollars (US$10.00) and other good and valuable consideration including the mutual covenants and agreements contained in this Agreement, the Parties agree as follows:

1.0Effective at midnight October 31, 2002, RBFDC assigns to THI all of RBFDC’s rights and obligations under the Drilling Contract, and THI accepts the assignment and agrees to assume and perform all the said obligations under the Drilling Contract.

2.0RBFDC agrees to notify and provide reasonably requested documentation to the other party to the Drilling Contract to effect the assignment.

3.0Written notice to a Party under this Agreement will be considered to be properly served if received at the Party’s address appearing above by personal delivery or registered mail.

4.0Any failure by a Party to enforce the terms of this Agreement or to exercise any rights will not constitute a waiver of those terms or rights, nor will it constitute any precedence.

5.0This Agreement is to be governed by and construed in accordance with the governing law provisions of the Drilling Contract.

IN WITNESS WHEREOF, the Parties execute this Agreement as of the date first above written.

R&B FALCON DRILLING CO.		TRANSOCEAN HOLDINGS INC.
By:	/s/ Jean P. Cahuzac	By:	/s/ Eric B. Brown
Name: Jean P. Cahuzac		Name: Eric B. Brown
Title: Vice President		Title: Vice President

TRANSOCEAN OFFSHORE DEEPWATER DRILLING INC.

1311 BROADFIELD, SUITE 400

HOUSTON, TX 77084

CHRISTOPHER S. YOUNG

SR. MARKETING REPRESENTATIVE

November 1, 2002

BP America Production Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn: Mr. Randy Rhoads

Re:Drilling Contract No. 980249 dated December 9, 1998 (“Contract”) by and between R&B Falcon Drilling Company predecessor in interest to Transocean Holdings, Inc,(“Contractor or TODDI”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject:	Letter of Agreement for 6 5/8” Drill Pipe Rental
	CONTRACTOR-5121-2002-011

Dear Randy,

This letter is to document the agreement between Transocean Offshore Deepwater Drilling Inc. (TODDI) and Company for the rental of 18,000 feet of 6 5/8” R-3 drill pipe for use on the Deepwater Horizon.

Company and TODDI hereby agree to the following terms and conditions:

1.TODDI shall purchase the following pipe and rent it to Company over the remaining term of the Contract referenced above. Specifications of the pipe are as follows:

Footage	18,000	Joints	439
Pipe OD	6 5/8”	Connection	6 5/8 FH
Weight	34.01	OD	8 1/4”
Grade	S-135	ID	4 1/4”
Upset	IEU	Pin Tong	10”
Range	3	Box Tong	13”
Internal Coating	TK 34 XT*	Hardfacing Pin	None
Inspection	Truscope AS	Hardfacing Box	Armacor M
Delivery	16 weeks*
Make & Break & 95% wall included

* Changes from Grant Prideco quote 30726

2.Tooljoints (Pin & Box) shall be manufactured long enough to provide for a minimum of two full recuts and still have sufficient tong space excluding proud hardbanded area. Company’s coating, hardbanding and make & break specifications are attached and made a part of this Agreement.

PHONE: (832) 587-8506 FAX: (832) 587-8754 EMAIL:cyoung@houston.deepwater.com

3.The rental rate will be approximately $3,000/day assuming that 18 months will be remaining on the contract at time of pipe delivery and that the total cost of the pipe is approximately $1.29 million. The exact calculation will be made when the pipe is delivered and the total cost (based on good footage) and the remaining number of days in the term are known. The total rental amount to be recovered will be calculated at 1.27418155 times the total cost of the pipe. The total cost of the pipe will include inspection and transportation.

4.The rental rate shall begin upon delivery of the pipe to TODDI following acceptance in accordance with Company’s QA/QC specifications and inspection criteria. These specifications and criteria are made a part of this Agreement. The rental rate shall cease when the total rental paid equals 1.27418155 times the final cost of the pipe. The rental agreement will continue as long the Contract is in force however the rental rate will be zero after the total rental paid equals 1.27418155 times the final cost of the pipe.

5.Contractor shall furnish all handling equipment required for this pipe during the term of the rental at no cost to Company.

6.Initial inspection is included in the cost of the pipe. Company reserves the right to re-inspect the pipe at Company’s cost. Company will be responsible for all inspections during the term of the rental.

7.The pipe shall be treated as Contractor’s in-hole equipment per Article 22.3 of the Contract except for the cost of inspections.

8.During the term of the rental, Company will have the option of moving the pipe to another Transocean Rig at Company’s option and expense.

If you are in agreement with the above, please sign in the space provided below and return one fully executed copy of this letter to me for our files.

If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

Sincerely,

/s/ Christopher S. Young

Christopher S. Young

Sr. Marketing Representative

AGREED AND ACCEPTED THIS 3RD DAY OF FEBRUARY, 2003

BP AMERICA PRODUCTION COMPANY

SIGNED	/s/ Jerry R Rhoads
PRINTED	Jerry R Rhoads
TITLE	Contracts Specialist

INTERNAL PLASTIC COATING OF	Procedure: BP-DEIP-IPC001	Revision: 1
DRILL PIPE AND WORKSTRINGS	Date: 6/6/02	Page: 1 Of: 7

B P DEIP

INTERNAL PLASTIC

COATING OF DRILL PIPE

AND WORKSTRINGS

Approved By: Date:

1.0Scope.

1.1This procedure details the BP GoM requirements for internal plastic coating of both new and used drill pipe, workstrings and pup joints. Additionally, this procedure details the BP GoM minimum requirements for used internal plastic coatings.

1.2This procedure includes a visual examination of all threaded connections after internal blasting at final inspection. All workstring tubing, and workstring tubing pup joints will be full length drifted at final inspection.

2.0Referenced Documents.

2.1The following documents are used as references for establishing this procedure.

2.1.1NACE TM-01-70

2.1.2NACE TM-03-89

2.1.3BP GoM OCTG Inspection Procedures and Requirements.

2.1.4The Coating Contractor’s Standard Operating Procedures manual for the application and inspection of internal coatings.

3.0Contractors Internal Coating Operating Procedures And Equipment Capabilities.

3.1The coating Contractor shall provide to BP for approval, complete standard operating procedures and equipment capabilities applicable to the individual pieces of equipment utilized for this process. The procedures will be of sufficient detail to enable the operator to perform required setup, calibration and adjustments to the equipment for preparation, application and inspection of the coatings.

4.0Requirements For Material And Equipment.

4.1All material, equipment, tools and supplies furnished by the Contractor shall be of good quality and adequate design, shall be maintained in good condition during use, shall conform to the requirements described in the Contractor’s Specifications and Standard Operating Procedures and shall be subject to BP’s approval.

5.0Preparation.

5.1Thread protectors shall be removed cleaned and stored until they are re-applied after final inspection.

5.2All threaded connections shall be cleaned with steam cleaners, soapy water, varsol or other mineral spirits.

5.3The material will then be visually examined internally for obvious defects, such as ridges or rough surfaces that would limit the coat-ability of the material. Rejected lengths will be identified, marked, segregated from the prime material and BP will be notified. No attempt will be made to coat these lengths until corrections have been made. Material with uncorrectable damage will be classified as “not suitable for coating” (NSC).

5.4The material will undergo a thermal cleaning by prebaking the material at 600° – 800° F (pipe temperature) for a minimum period of 2 hours or as agreed to by BP. Longer prebake periods may be required depending upon the characteristics of the material being processed.

5.5In order to insure that the proper oven temperatures are maintained, the BP QA/QC Inspector will be given a copy of the heat charts. These heat charts will be included with the BP QA/QC Inspector’s final job report. Additionally, at BP’s request the contractor will satisfactorily demonstrate to the BP QA/QC Inspector that the surface temperature of the pipe meets but does not exceed the established temperature limitations during the thermal cleaning, regardless of the method by which the material is heated (i.e., conveyor system or batch ovens).

5.6After thermal cleaning is completed, the material will be internally blasted “to white metal” with an abrasive material to thoroughly clean and roughen the metal surface in order to form a suitable anchor pattern for coating.

Note: “White metal” blast cleaning is defined by NACE as follows: “White metal blasting cleaning is a method of preparing steel surfaces which, when viewed without magnification, shall be free of all visible oil, grease, dirt, drilling mud, cement, mill scale, rust, paint and coatings.” All surfaces blasted to “white metal” will be inspected visually from both ends, without magnification, using visual comparators to insure proper surface preparation to NACE TM-01-70.

5.7The abrasive blasting operation will be repeated until the proper “white metal” surface condition is achieved.

5.8The Material must be dry before abrasive blasting begins.

5.9The compressed air used for abrasive blasting shall be free of water and oil. At the beginning of each shift the operator will verify this. The operator will partially open the air supply at the blast station and hold a clean cloth or blotter against the airflow. If any oil or water is found, the system must be cleaned or dried prior to abrasive cleaning. Air pressure will be provided at 85 to 110 P.S.I. as measured at the blast plot.

5.10The abrasive materials used for cleaning will be coarse Flintabrasive, Garnet, or other abrasive material meeting the Contractor’s specifications. Prior to the start of the job, the Contractor shall present, blast material specifications and quality control procedures for abrasive materials, to BP for acceptance.

5.11Prior to abrasive blasting, the material shall have protector masks installed to protect threads, seal areas and shoulders from damage.

5.12After abrasive blasting, the material shall be thoroughly cleaned with dry, oil free compressed air to remove abrasive blasting material and other foreign material from the surface area.

5.13The Contractor will conduct tests on both ends of the first 10 blasted pieces to establish that the anchor profile depth and appearance are satisfactory. Thereafter, tests will be conducted on both ends of every twenty-fifth piece. The test must be conducted with Testex Coarse Press-O-Film or equivalent and measured with the appropriate gauge. These tests will be conducted after full length blasting but before end blasting. Acceptable anchor profile depth will be verified to the Contractor’s Specifications. At BP’s request the BP QA/QC Inspector shall witness these tests, maintain the test results and include them with the final job report.

5.14After the material is blasted and the anchor profile depth and appearance tests are completed, the material will be visually inspected to determine coat-ability. The material will be classified “not suitable for coating” (NSC), if, in the opinion of the Contractors representative or the BP QA/QC Inspector, the surface condition of the material would preclude application of coatings to the material in accordance with the Contractors Specifications. The Contractor must, however, make every reasonable effort to blast the surface of the material to a coat-able condition. The NSC material will be identified, marked and segregated from the coat-able material and BP shall be notified. If it is determined by the Contractor or the BP QA/QC Inspector that a second blast attempt on the NSC joint would possibly result in a coat-able piece, a second blast attempt, of at least two (2) passes, will be made.

6.0Internal Plastic Coating Application.

6.1Application of the coating material, as designated by BP, will be performed so that the required film thickness and coating properties are attained.

6.2Coating, mixing, and thinning will be controlled in accordance with the Contractor’s Standard Operating Procedures. These procedures will specify the coating material handling requirements, mixing methods, and general equipment settings necessary for a quality application.

6.3Individual coats should produce a uniform continuous coverage of the internal surface. When additional coats are required to meet specifications, those additional processes will be the decision and responsibility of the Contractor.

6.4Prior to coating, the material shall be properly masked to protect the threads, seal areas and shoulders from coating overspray or damage.

6.5When required, a sample from each batch of liquid coating will be taken. This sample will be sealed with tape, properly labeled with the batch number, job number and well charges. At BP’s request the BP QA/QC Inspector shall witness this process and initial each sample. The sample will be retained by the Contractor for subsequent evaluation, as directed, by BP.

6.6Different coating batches will not be mixed on individual lengths of material.

6.7The coating batch number(s) applicable to each BP order must be documented by the Contractor and retained in a permanent job file. At BP’s request the BP QA/QC Inspector will verify the coating batch(s) utilized and include them in the final job report.

6.8The shelf life of the batch(s) utilized on the BP material will be verified and documented by the Contractor. If the age of the coating exceeds the manufacturer’s suggested shelf life, it will not be applied to the BP material. At BP’s request the BP QA/QC inspector will verify the shelf life of the batch(s) utilized and include them in the final job report.

6.9The first coat of coating shall be applied as soon as possible after blasting. In no case shall coating be delayed more than one (1) hour without reblasting. If the event a rust bloom or visual oxidation occurs before the application of the first coat, the material must be re-blasted.

6.10Coating thickness and number of coats shall be in accordance with the Contractor’s coating specifications and provide a dry film thickness (DFT) as specified by the Contractor.

6.11Coating intermediate and final bake temperatures and times shall be in accordance with the Contractor’s coating specifications. Intermediate baking will be performed at 250° – 350° F for periods of 45 minutes to 1-1/2 hours depending on coating, material size and weight. Final baking will be done at temperatures of 400° – 500° F for periods of 1-4 hours depending on coating, material size and weight. The staging of temperatures during final bake is permitted. In order to insure that proper oven temperatures are maintained the BP QA/QC Inspector will be given a copy of the heat charts. These heat charts will be included with the BP QA/QC Inspector’s final job report. Additionally, at BP’s request the Contractor shall satisfactorily demonstrate to the BP QA/QC Inspector that the surface temperature of the material meets but does not exceed the established temperature limitations for both the intermediate and final bakes regardless of the method by which the material is heated (i.e., conveyor system or batch ovens).

6.12Minor irregularities in individual coats may be repaired to meet specifications anytime prior to final bake at the option of the Contractor. Repairs of this nature are limited to the end area of material where thickness of repairs can be measured. Minor surface irregularities that are within the coating thickness specifications will be considered acceptable. Runs, sags, blobs, filled threads and/or blisters will be rejected.

6.13The Contractor will conduct a sufficient number of visual and film thickness checks on the material in order to assure conformity to final product specifications.

7.0Final Inspection.

7.1After the final bake, the BP QA/QC Inspector shall conduct, at random, a dry film thickness test and visual inspection of the coated material. In addition to obvious defects such as blobs, blisters, etc., the visual inspection will verify that the final coating color is within the Contractors specifications. The color of the coating should be uniform throughout the entire length of the material.

7.2The color of finished baked coatings is variable. The Contractor will maintain coating color standards at the coating facility. The coating color standards will be used to determine the acceptable finished color of all thermoset coatings. Lengths that contain coating color within the standard range of the coating color standards will be considered acceptable. After each final bake, the color will be verified with the proper comparator. The BP QA/QC Inspector shall witness the coating color inspection process.

7.3The material shall be visually inspected from each end with sufficient light to detect any coating anomalies. The material will be sufficiently rotated during the visual inspection to inspect the entire inside area of the material. The material must be in a single layer for the inspection. Material will not be stacked during the final inspection. The final product should be free of runs, sags, and blisters. Surface roughness or surface irregularities will not be considered cause for rejection provided that the coating thickness is within specification.

7.4The dry film thickness of the material will be measured on both ends of the material with a MIKROTEST DFG magnetic thickness gauge. The calibration of the thickness gauge will be conducted at the beginning of each shift or every eight hours, whichever comes first, and must be witnessed by the BP QA/QC Inspector. Material with coating thickness outside of the specified ranges (specified by the Contractor) will be rejected and reprocessed.

BP requires the average Dry Film Thickness to be .5 mils greater than the Contractor’s specified minimum Dry Film Thickness and .5 mils less than the Contractor’s specified maximum Dry Film Thickness. However, if any Dry Film Thickness measurement of the coating is not within this range, three additional Dry Film Thickness measurements must be taken. These measurements will be taken at 90°, 180°, and 270° and an average of the four readings will then be computed. If this average falls in the Contractor’s specified Dry Film Thickness range that end of the piece is acceptable and if this average falls out of the Contractor’s specified Dry Film Thickness range the whole piece is rejected.

7.5Coatings on the face of the pipe ends are exempted from the standard minimum coating thickness requirements.

8.0Holiday Testing.

8.1Holiday testing will be performed per NACE Standard TM-03-84 on each length of pipe coated with thin film holiday free internal coating. The testing will be performed utilizing a “Tinker-Rasor” type M-1 holiday tester or equivalent, which is calibrated at the beginning of each shift or when requested by the BP QA/QC Inspector. All calibrations and testing must be witnessed by the BP QA/QC Inspector. The procedure for holiday testing of the material is as follows:

·A 2” thick cellulose sponge probe head saturated with selected electrolyte and detergent will be employed.

·The sponge will be large enough to insure a 360° contact throughout the length of the pipe. The sponge will be replaced when worn.

·A constant potential of 67.5 volts DC will be maintained between the sponge probe and the body of the tube during testing. The negative lead shall be connected to the pipe and the positive lead shall have continuity to the sponge. The tester alarm shall be activated before the testing of each joint to insure that continuity exists between the tube body and the holiday tester.

·The sponge probe will be moved through the pipe at a rate of 60 fpm +5%.

·Each length of pipe will be holiday tested once at the Contractor’s facility. Thin film coatings will be defined as holiday free when the electrical resistance between the wet sponge and the tube body is at no point less than 80,000 ohms.

·The holiday test will be performed in both directions while running the wet sponge in and out of the tube.

·All thin film corrosion coatings for both new and used pipe will be holiday free and will be applied and tested in accordance with the methods outlined above.

·The holiday free specifications will apply only while the material is at the Contractor’s coating facility.

·All coated pipe that is rejected shall be reprocessed according to surface preparation, application, and inspection procedures as outlined in this specification. Those coated lengths not meeting holiday specifications after being coated a second time are to be classified as NSC. Any length that Contractor or BP determines to be unsuitable for coating (NSC) due to internal surface defects (e.g., slivers, pitting, etc.) will be set aside. This pipe will be reprocessed only upon instructions from BP.

9.0Full Length Drifting.

9.1After final inspection, each length will be full length drifted with a plastic or wooden drift mandrel meeting the applicable API specifications for coated material with the exception of drill pipe products, which do not require full length drifting.

10.0Visual Thread Inspection.

10.1After final inspection and full length drifting, is completed, the threads and sealing surfaces shall be visually inspected in accordance with the procedure BP-DEIP-P004. Thread compound, as specified by BP, will be applied to all threaded surfaces and the proper clean dry thread protectors installed.

11.1Marking and Stenciling.

11.1The Contractor will re-apply inspection bands and stencils as instructed by BP. Further, a clear mill varnish, acceptable to BP, will be applied to the outer surface of the material to prevent corrosion.

12.1Documentation, Records And Reporting.

12.1At the end of the job, the Contractor will provide BP the following documents:

·Prebake Heat Charts.

·Testex Coarse Press-O-Film test strips.

·Coating Batch number(s).

·Intermediate Bake Heat Charts.

·Final Bake Heat Charts.

·Final report, stating the piece quantity, Prime and rejects (including NSC), along with the footage’s. The reason for rejection must be reported.

·Individual pipe tally sheets indicating “threads off’ footage.

12.2Documentation, records and reporting requirements as listed in BP-DEIP-P005 shall apply.

13.0Health, Safety And Environmental.

13.1Health, safety and environmental requirements as listed in BP-DEIP-P001 shall apply.

14.0Visual Inspection Of Used Internal Plastic Coatings.

15.1

HARDBANDING OF DRILL PIPE TOOLJOINTS,	Procedure: BP-DEIP-P002	Revision: 0
HEAVYWEIGHT DRILL PIPE AND DRILL COLLARS	Date: 7/2/902

BP DEIP

HARDBANDING OF

DRILL PIPE TOOLJOINTS

HEAVY WEIGHT DRILL PIPE

AND DRILL COLLARS

Approved By: Date:

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1.0Scope.

1.1This procedure details the BP GoM requirements for the hardbanding of drill pipe tooljoints (loose or attached), heavyweight drill pipe and drill collars. It is applicable to new or used non-hardbanded material and material which requires re-hardbanding.

1.2The application of proud wear resistant alloy hardfacing bands onto tooljoints, heavyweight drill pipe and drill collars significantly reduces external wear and casing wear.

2.0Referenced Documents.

2.1The following documents were used as reference for establishing this procedure.

2.1.1Part 1 BP Drill-string Hardbanding Specification for General Release (4/6/2000).

2.1.2ISO 9002 Quality Systems – Model for quality assurance in production and installation.

2.1.3ISO 9003 Quality Systems – Model for quality assurance in final inspection and test.

2.1.4API Q1 – Specification for Quality Programs.

2.1.5ASME IX – ASME Boiler and Pressure Vessel Code. Welding and Brazing Qualifications.

2.1.6ASTM E 709 – Standard Guide for Magnetic Particle Examination.

2.1.7ASTM E 165 – Standard Test Method for Liquid Penetrant Examination.

2.1.8API Specification 7 - Rotary Drill Stem Elements.

2.1.9API Recommended Practice 7G - Drill Stem Design and Operating Limits.

3.0Quality Assurance.

3.1The Applicator shall operate a Quality Assurance organization responsible for formulating and implementing a Quality System, which insures that the requirements of this procedure are met.

3.2The Applicator’s Ouality System shall be based on ISO 9002 and ISO 9003 or API Q1. Particular attention is drawn to Section 4.8.2 in ISO 9002 and Section 3.12 in API Q1 concerning Special Processes. Hardbanding and the associated practices are considered to be Special Processes and shall be qualified strictly in accordance with the requirements of this procedure.

3.3The effectiveness of the Applicator’s Quality System will be subject to monitoring by BP and may be audited following and agreed period of notice.

4.0Hardbandinq Types.

4.1There are two basic types or categories of hardbanding for drill pipe tooljoints, heavyweight drill pipe and drill collars utilized in the Oil Industry today. These comprise weld overlays that consist of wear resistant alloys that do not contain tungsten carbide granules and weld overlays consisting of tungsten carbide granules within a metallic substrate (normally a low carbon steel). In this procedure these types will be referred to as “Wear Resistant Alloy Overlays” and “Tungsten Carbide Overlays”.

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4.2Wear Resistant Alloy Overlays. These materials are hard alloys containing no solid particles. Therefore, unlike tungsten carbide overlays, there is no possibility of hard particles standing proud or becoming exposed from a softer matrix and producing severe abrasive wear of the casing. Wear resistant alloy overlays are required when applying hardfacing for BP GoM and are strongly recommended verses tungsten carbide overlays in all cases.

4.3Tungsten Carbide Overlays. These consist of granules of tungsten carbide in a steel matrix. The use of tungsten carbide overlays is not permitted when applying hardfacing for BP GoM on drill pipe tooljoints, heavyweight drill pipe or drill collars. The use of drill pipe with tungsten carbide overlays is not permitted without the express consent of the responsible BP Engineer. Since heavyweight drill pipe and drill collars are used in open-hole sections the majority of time while drilling, BP GoM may accept tungsten carbide overlays on these items. However, if tungsten carbide overlays are used on heavyweight drill pipe or drill collars BP GoM reserves the right to examine the hardfacing for acceptance on a case, by case basis.

5.0Welding Issues.

5.1Welding Processes. Hardbanding shall be deposited by the use of a mechanized GMAW welding technique using a solid wire or cored wire consumable. Self shielded or open arc welding techniques may also be used. Other techniques for the deposition of hardbanding may be proposed for consideration by BP.

The hardbanding shall be applied as individual circumferential weld beads laid side by side to achieve the specified width of hardbanding. The as welded surface shall be smooth and the adjacent beads shall be deposited with sufficient overlap to avoid the formation of inter-bead troughs or valleys. High crowns or severe ridges must also be avoided.

5.2Preheat And Interpass Temperature. A minimum preheat temperature of 400°F shall be achieved through the full thickness of the component prior to the start of hardbanding or application of mild steel (butter-pass) and this temperature shall be maintained as the minimum interpass temperature throughout the welding process. The maximum interpass temperature for the application of hardbanding or mild steel shall be 650°F.

5.3Post Weld Thermal Regime. Immediately on completion of welding, the component shall be subjected to one of the following alternative thermal regimes:

5.3.1The temperature of the internal and external surface of the component shall be measured and if necessary the component shall be heated such that a temperature of 650°F is attained through the full thickness. The component shall then be allowed to slow cool to ambient temperature while fully wrapped in an insulating blanket or specially constructed insulating can. The components shall be kept under cover and shall not be exposed to any wind, drafts or rain during the cooling period.

5.3.2The component shall be placed in an oven and maintained at a temperature of 400°F for a minimum period of two (2) hours prior to slow cooling under insulation, as detailed in section 5.3.1 above.

5.4Welding Parameters. The welding parameters employed for hardbanding should be based on those recommended by the consumable manufacturer. However, it should be noted that these parameter values are often provided for guidance only and Applicators should undertake sufficient welding procedure development work to insure that they have established a stable welding condition prior to welding procedure qualification.

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5.5Welding Procedures (WPS). All welding procedures associated with the application of hardbanding or mild steel shall be qualified in accordance with ASME IX, QW 216, QW 453 and the requirements of this procedure. Production welding equipment shall be employed for the welding procedure qualification.

Individual welding procedures shall be qualified by the Applicator for:

·The application of flush and proud hardbanding. A separate WPS is required for each type of hard metal consumable.

·The application of mild steel.

·The application of mild steel (butter-pass), flush and proud hardbanding on re-hardbanded components. A separate WPS is required for each type of hard metal consumable.

The application of mild steel and hardbanding on re-hardbanded components may be qualified in a single procedure.

The welding procedure specification (WPS) and procedure qualification record (PQR) shall be submitted to BP GoM for approval prior to the commencement of any production welding. These documents shall be prepared in the ASME format with supplementary pages as necessary to provide a full and detailed description of the hardbanding procedure.

5.6Welding Procedure Qualification (PQR). All welding procedure qualifications shall be performed on a 4145H tubular material, preferred size of 6 5/8” OD and 2 3/4” ID, representing a typical drill collar. The manufacturer’s certificate, including full details of heat treatment, mechanical testing results and chemical analysis, for this material and the welding consumable shall be included in the PQR documentation. All relevant welding parameters shall be monitored and recorded during the production of the test weld and reported in the PQR.

The hardbanding shall be allowed to stand at ambient temperature for a minimum of forty-eight (48) hours prior to the examination detailed in Note 3, QW 453. The acceptance criteria for this examination shall be as detailed in section 10.0 of this procedure.

Subsequent to the above an ultrasonic examination of the hardbanding and parent metal interface shall be performed to demonstrate freedom from lack of fusion or any under bead cracking. The surface of the hardbanding shall be prepared for this examination by machining or grinding. Testing shall examine the full width of the hardbanding at five equally spaced locations around the circumference.

Following the above ultrasonic examination the Rockwell hardness of each band of hardfacing shall be measured at each of the five locations and each hardness reading shall meet the published recommendations of the consumable supplier.

Two coupons shall be cut and prepared for examination as detailed in Note 8, QW 453 except that only one surface on each need be polished and etched. These coupons shall be taken at least 90° apart. A macrograph shall be taken of each prepared surface and included in the PQR.

Additionally, three (3) vertical hardness traverses shall be made across the fusion boundary from the weld deposit into the heat-affected zone of the 4145H material. These measurements shall be made using a Vickers indenter with either a 5kg or 10kg load.

A full chemical analysis shall be performed in accordance with Note 9, QW 453.

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5.7Manufacturing Reference Standards. Subsequent to the testing detailed in Section 5.6 above the remainder of the welding procedure qualification test piece shall be retained by the Applicator to act as a reference standard during production.

5.8Welder/Machine Operators Performance Qualification. Working in accordance with a qualified WPS each hardbanding welder/machine operator shall manufacture a test piece as detailed in section 5.6 in order to demonstrate his ability. The test piece shall be subjected to the examination detailed in Note 3, QW 453 and meet the criteria outlined in section 10.0 of this procedure. Each welder/machine operator performing a successful welding procedure qualification test shall be deemed to have completed a satisfactory performance test.

The Applicator’s Quality Assurance department shall maintain a record of each welder/machine operator’s qualification and working experience. A welder/machine operators qualification shall lapse and re-qualification will be required if he/she does not perform hardbanding for a period exceeding three months.

5.9Production Welding. Production welding shall be undertaken strictly in accordance with the qualified welding procedures. All welder/machine operators shall be qualified in accordance with section 5.8. A copy of the basic elements of the WPS shall be available for reference at each hardbanding station.

Appropriate shop floor supervision and detailed working procedures shall be available to ensure hardbanding is deposited to this Specification at all times. Regular monitoring and recording of preheat temperatures, welding set up, welding parameters and the post weld thermal regime shall form an integral part of these procedures. All production records shall be retained within the Applicator’s Quality System archives.

6.0Hardbandinq Configurations.

6.1Definitions. When applying new hardbanding and for the purposes of this procedure the following definitions shall apply.

·“Proud” hardbanding is an overlay that stands proud from the base material. Tolerances for proud hardbanding are + 3/32” to + 1/8” as measured from the base material surface.

·“Flush” hardbanding is an overlay that is flush with the base material surface. Tolerances for flush hardbanding are + 1/64” and — 0 as measured from the base material surface.

6.2Drill Pipe Tooljoints. Hardbanding (Wear Resistant Alloy Overlay) shall be applied in the following locations:

·A three (3”) inch wide band on the box tooljoint OD next to the taper. These bands shall be applied proud.

·One 3/4” wide band on the box tooljoint 18° taper. This band shall be applied flush.

·Three 3/4” long fingers 120° apart projecting from the base of the hardbanding on the box tooljoint taper onto the box upset. Fingers shall be applied flush.

·A one and one half (1 1/2”) inch wide band on the pin tooljoint OD next to the taper. These bands shall be applied proud.

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Figure 1.1 (Drill Pipe)

6.3Heavy Weight Drill Pipe. Hardbanding (Wear Resistant Alloy Overlay) shall be applied in the following locations:

·One 4” inch wide band on the box and pin tooljoint OD next to the taper. These bands shall be applied proud.

·One 1” wide band on the tapered section of the box tooljoint. This band shall be applied flush.

·Two 3” wide bands on each end of the center wear pad. These bands shall be applied proud.

Figure 1.2 (Heavy Weight Drill Pipe)

6.4Drill Collars With Slip Recess Groove. Hardbanding (Wear Resistant Alloy Overlay) shall be applied in the following locations:

·One, 4” wide band on the box end OD located 1” away from the beginning of the slip recess groove. This band shall be applied proud.

·One, 10” wide band on the drill collar OD located 1” away from the end of the slip recess groove. This band shall be applied proud.

Figure 1.3 (Drill Collar with Slip Recess Groove)

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6.5Drill Collars With Slip And Elevator Recess Grooves. Hardbanding (Wear Resistant Alloy Overlay) shall be applied in the following locations:

·One, 4” wide band on the box end OD located 1” away from the beginning of the slip recess groove. This band shall be applied proud.

·One, 1” wide band on the wear pad OD between the two recess grooves. This band shall be applied proud.

·One, 10” wide band on the drill collar OD located 1” away from the end of the slip recess groove. This band shall be applied proud.

Figure 1.4 (Drill Collar with Slip And Elevator Recess Grooves)

7.0Pre-Hardbandinq Considerations.

7.1Mill Slots, Chip Slots and Identification Grooves. Inspect the tooljoints to determine if there are mill slots, chip slots, identification grooves or other machined areas on the tooljoints that will interfere with the application of hardbanding per section 6.2. If machined areas exist and will interfere with the hardbanding application process notify the Material Supplier prior to hardbanding the material and obtain permission to fill the machined areas in with mild steel. The application of mild steel shall meet the requirements outlined in section 5.0 and 9.0.

7.2Internal Plastic Coating. Inspect the material to determine if it is internally plastic coated. If the material is internally plastic coated notify the Material Supplier prior to hardbanding the material and inform the Material Supplier that the material will require re-coating after the hardbanding process.

Note: Under no circumstances shall material be filled with water during the hardbanding process to preserve the internal plastic coating.

7.3Pre-Existing Hardband. Inspect the material to determine it the material has been previously hardbanded. If the material has been previously hardbanded notify the Material Supplier prior to the hardbanding the material and inform the Material Supplier that the existing hardbanding will have to be removed in accordance with section 9.0 prior to applying the new hardbanding.

Note: Under no circumstances shall new hardband be applied over pre-existing hardband of any type without prior approval by the BP QA/QC Manager.

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8.0Hardbanding Procedure.

8.1Machining. When applying proud hardbanding, a groove shall be machined into the surface of the material prior to the application of hardbanding. The groove depth shall be 1/32” (+/-.010”) as measured from the surface of the material. When applying flush hardbanding, a groove shall be machined into the surface of the material prior to the application of hardbanding. The groove depth shall be 3/32” (- 0 + 1/32”) as measured from the surface of the material. When applying flush hardbanded fingers, three, 3/4” long, 1/2” wide and 3/32” deep slots shall be ground into the drill pipe box end upset. All groove and slot widths shall equal the intended width of the hardbanding to be applied as defined in section 6.0.

Note: It may be necessary to modify the groove depth on the box taper to achieve a smooth tie in to the three (3) inch band located on the box OD.

8.2Surface Preparation. Hardbanding shall be deposited onto a machined or ground white metal surface. This surface shall be free from dirt, drilling mud, cement, paint, rust, cutting fluid, grease etc. Additionally, a two (2) inch band on either side of the machined area shall be thoroughly cleaned and degreased.

8.3Preheat. Preheat the area requiring hardbanding in accordance with the BP approved WPS (See section 5.0 for more details). The preheat temperature shall be verified on each area requiring hardbanding on each piece with a calibrated pyrometer or the properly rated temperature sticks. When temperature sticks are used the Applicator shall have at a minimum, temperature sticks rated to the preheat temperature and maximum interpass temperature.

8.4Hardbanding Application. Apply hardbanding to the material in accordance with the BP approved WPS (See section 5.0 for more details).

8.5Interpass Temperature. Monitor the interpass temperature throughout the hardband application process to insure the minimum and maximum interpass temperatures are maintained in accordance with the BP approved WPS (See section 5.0 for more details). The interpass temperature shall be measured with a calibrated pyrometer or the properly temperature sticks. When temperature sticks are used the Applicator shall have at a minimum, temperature sticks rated to the minimum interpass temperature and maximum interpass temperature.

8.6Post Weld Thermal Regime / Slow Cooling. Immediately on completion of the hardband application, the material shall be subjected to a post weld thermal regime in accordance with the BP approved WPS (See section 5.0 for more details).

8.7Surface Finish. After the material has slow cooled to ambient temperature, remove all weld spatter or protrusions by grinding, sanding or machining methods. Close control of the hardband welding parameters should result in a good surface finish, such that it is not usually necessary to grind, sand or machine the entire hardbanded surface.

Note: Unless specified by BP, Amorphous type hardfacings do not require post application grinding or sanding to increase the surface hardness of the material.

8.8Inspection. Perform a dimensional inspection on each hardbanded area to insure the requirements outlined in section 6.0 have been met.

8.8.1Perform a visual inspection on each hardbanded area. Acceptance and rejection criteria shall be per section 10.0.

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Note: When required by BP, contrast paint shall be applied to the hardbanding in order to assist the visual examination.

8.8.2Clean all connections and perform a visual inspection on the threaded and sealing surfaces in accordance with procedure BP-DEIP-P004.

8.8.3Perform a bi-directional wet magnetic particle inspection on the HAZ and at least two (2) inches of the surrounding parent metal around all hardbanded areas. The bi-directional WMPI shall be performed in accordance with procedure BP-DEIP-P002 (the transverse MPI method shall be per section 7.0 and the longitudinal MPI method shall be per section 8.0). Acceptance and rejection criteria shall be per section 10.0.

8.9Finishing. Blow the material ID out with compressed air to remove any debris. Apply the appropriate thread compound to all connections as specified by the Material Supplier and install clean dry thread protectors wrench tight. Apply a thin coat of rust inhibitor to the freshly hardbanded, ground, sanded or machined areas.

9.0Removal of Existing Hardbanding and Application of Mild Steel.

9.1Removal of Existing Hardbanding. The removal of existing hardbanding shall be performed with pre-approved methods or techniques such as, plasma arc gouging, grinding or machining. When plasma arc gouging techniques are used care shall be taken to minimize the heat input.

9.1.1After removal of the existing hardbanding with plasma arc gouging techniques, the excavated area shall be machined smooth to provide a suitable surface for WMPI.

9.2Inspection. All areas where previous hardbanding has been removed shall be etched with a 5% Nital solution to verify that all of the hardband material has been removed. This process shall be repeated as many times as necessary to insure all previous hardband material has been completely removed.

9.2.1Perform a bi-directional wet magnetic particle inspection on all areas where hardbanding has been removed and all areas that have been affected during the removal process. The bi-directional WMPI shall be performed in accordance with procedure BP-DEIP-P002 (the transverse MPI method shall be per section 7.0 and the longitudinal MPI method shall be per section 8.0). Acceptance and rejection criteria shall be per section 10.0.

9.3Application of Mild Steel. Apply mild steel to the previously excavated areas and/or mill slots, chip slots or identification grooves if necessary in accordance with the BP approved WPS (See section 5.0 for more details).

9.4Machining. Machine the areas where mild steel has been applied back to the original OD or taper of the area.

Note: Grooves for new hardbanding as outlined in section 8.1 can be machined in conjunction with the above machining process prior to performing the WMPI detailed in section 9.5.

9.5Inspection. Perform a bi-directional wet magnetic particle inspection on all areas where mild steel has been applied. The bi-directional WMPI shall be performed in accordance with procedure BP-DEIP-P002 (the transverse MPI method shall be per section 7.0 and the longitudinal MPI method shall be per section 8.0). Acceptance and rejection criteria shall be per section 10.0.

9

10.0Acceptance Criteria.

10.1Mild Steel And Parent Material. Relevant indications on the external or internal surface (including HAZ) of parts shall be removed by grinding or machining, provided that the part still conforms to BP’s, the Manufacturer’s or API acceptance criteria after the removal process.

Note: All areas that have had indications removed shall be re-inspected in accordance with the appropriate MPI method in accordance with procedure BP-DEIP-P002 section 7.0, 8.0 or 9.0 after the removal process to insure complete imperfection removal.

10.2Wear Resistant Alloy Overlays. These hard wear resistant deposits possess relatively low ductility. Therefore, weld metal cracking often occurs transverse to the weld bead under the influence of residual stresses. Typically, these cracks may run straight across the weld bead or at an angle between 30° and 45°. Occasionally the cracks will interconnect. This is acceptable as long as the cracks are less than 1/16” wide or have a minimum spacing of 1/2” apart when the cracks run across the full width of the hardbanded region. If cracks fail to meet this criteria remove the deposit and re-hardband the material in accordance with sections 8.0 and 9.0.

Figure 1.5 (Transverse Cracks)

Figure 1.5 illustrates an acceptable configuration of transverse cracks. Crack widths are less than 1/16” and cracks extending the full width of the hardband deposit are greater than 1/2” apart.

If there are circumferentially running cracks, these are unacceptable where a single continuous crack is greater than 3” long, as they can result in a premature fatigue failure of the material. Additionally, flaking or spalling of the hardband deposit is unacceptable. In such circumstances remove the deposit and re-hardband the material in accordance with sections 8.0 and 9.0.

Figure 1.6 (Circumferential Cracks and Flaking)

Figure 1.5 illustrates unacceptable circumferential cracking and flaking and acceptable circumferential cracking.

10

Small troughs between individual weld beads are acceptable as long as they are no more than 1/8” wide or 1/16” deep.

Figure 1.7 (Inter-Bead Troughs)

Figure 1.7 illustrates Inter-Bead Troughs. “Troughs” are acceptable if less than 1/8” wide and 1/16” deep.

If any cracking is detected in the HAZ, mild steel or parent material, the hardbanding and cracked areas must be completely removed in accordance with section 9.0, provided that the material still conforms to BP’s, the Manufacturer’s or API acceptance criteria after the removal process. The area shall be re-hardbanded in accordance with section 8.0.

If there are surface breaking non-linear defects, such as porosity on the hardband weld beads greater than 1/8” diameter or 1/16” deep, these may be filled using semi-automatic GMAW or SMAW. This type of repair must be performed with a consumable matching the composition of the hardband material and will require a BP approved WPS (See section 5.0 for more details).

Note: The acceptance criteria outlined in this section are the minimum requirements BP will accept, regardless of the Hardband Manufacturer’s, Material Supplier or Applicator’s acceptance criteria. However, it is necessary to obtain and review the Hardband Manufacturer’s, Material Supplier and Applicator’s acceptance criteria to insure the material is inspected correctly.

11.0Documentation, Records and Reporting.

11.1The Applicator shall submit to BP an inspection record, which will clearly state that the hardbanding has been applied and inspected in accordance with this procedure. The scope and content of this record shall include:

·A reference list of the Applicator’s procedures used in the production of the hardbanding and a copy of the WPS(s) and PQR(s).

·A copy of all NDE reports.

11.2Documentation, records and reporting requirements as listed in procedure BP-DEIP-P005 shall apply.

11

12.0General Requirements.

12.1General requirements as listed in procedure BP-DEIP-P001 shall apply.

13.0Marking And Stenciling.

13.1Marking and stenciling requirements as listed in procedure BP-DEIP-P001 shall apply.

14.0Documentation, Records and Reporting.

14.1Documentation, records and reporting requirements as listed in procedure BP-DEIP-P005 shall apply.

15.0Health, Safety And Environmental.

15.1Health, safety and environmental requirements as listed in BP-DEIP-P001 shall apply.

12

MAKE AND BREAK OF DRILL PIPE AND	Procedure: BP-DEIP-MB001	Revision: 0
WORKSTRING TOOLJOINTS	Date: 6/6/02

BP DEIP

MAKE AND BREAK OF

DRILL PIPE AND WORKSTRING

TOOLJOINTS

Approved By: Date:

1

1.0Scope.

1.1This procedure describes the processes established to make and break new drill pipe and workstring tooljoints, both, affixed or loose.

1.2Since newly machined connections are susceptible to galling the make and break process is utilized to break in new connections (tooljoints) by work hardening the connection surface.

2.0Personnel Qualifications.

2.1Personnel performing make and break operations must be trained and experienced in the operation of the make and break unit.

3.0Required Materials & Equipment.

3.1Hydraulic Make And Break Unit. The make and break unit shall be capable of making up and breaking out two joints of range III drill pipe together to the manufacturers recommended torque value.

3.1.1The unit shall be equipped with load cells and gauges capable of indicating the torque values obtained in Ft./Lbs.

3.1.2Calibration of the load cells and gauges on the make and break unit shall be performed a minimum of once every six (6) months. The calibration documentation shall be available for review at the job site.

3.1.3The make and break unit shall be equipped with the properly sized power and backup tongs.

3.1.4Power and backup tongs will utilize low stress, large contact surface area dies to reduce grip marks.

3.2Additional Required Equipment. The following equipment shall be available on the job sight and in good working order: Depth (pit) gauge, files, 50’ metal tally tape, absorbent pad, catch pans, cleaning solvent, cleaning brushes, thread compound, dope brushes, assorted paints and metal markers.

4.0Make And Break Procedures.

4.1Remove the thread protectors and stack them off the ground to prevent contamination with dirt, grit, grass etc.

4.2Visually inspect the condition of the thread compound to insure a thin uniform coat of make-up thread compound has been applied and is not contaminated with dirt, grit, rust, scale etc.

Note: The thread compound must be an approved make-up compound such as ZN-50 or Jet Lube Kopr-Kote. If the thread compound on the connections is not an approved make-up compound (i.e., kendex) it must removed by cleaning the connections with solvent, varsol etc. and drying the connections prior to applying the proper make-up thread compound.

2

4.3Verify the make and break unit has been set up properly prior to commencing the make and break operation. The unit must be level and both tongs must be perpendicular to the tooljoints. In addition, the tooljoints shall be centered in the tongs and tong dies shall contact the tooljoints in a uniform fashion to prevent excessive grip marks and slippage.

4.4Recommended torque values shall be obtained from the drill pipe manufacturer or their published documents prior to the start up of the make and break operation.

4.5The make and break process shall consist of and be performed in the order listed below.

1.Make up a box and pin connection to 100% of the specified optimum torque value. Break out the box and pin connections.

2.Clean both connections and perform visual inspection for damages or excessive grip marks. Repair any minor damages with a file or emery cloth and apply a thin coating of dry moly lubricant over the repaired connection.

Note: If the connections are damaged beyond minor field repair shut the make and break operation down and contact the responsible BP Inspection Coordinator for further instructions.

3.Provided that the damages are minor or non-existent repeat the operations outlined in step one (1) above two (2) more times without cleaning the connections.

4.After the third make and break cycle clean both connections and perform visual inspection for damages. Repair any minor damages with a file or emery cloth and apply a thin coating of dry moly lubricant over the repaired connection.

5.Repeat the operations outlined in steps one (1), two (2), three (3) and four (4) on the next four (4) sets of boxes and pins.

6.Provided that the damages are minor or non-existent on the first five (5) sets connections the remaining connections in the order shall be made up to 100% of the specified optimum torque value and broken out three (3) consecutive times without cleaning the connections between make and break cycles.

7.Clean all connections after the final make and break cycle and perform a visual inspection for damages or excessive grip marks. Repair any minor damages with a file or emery cloth and apply a thin coating of dry moly lubricant over the repaired connection.

8.Allow the connections to dry or dry the connections with compressed air. Apply a thin, uniform film of the specified thread compound to all connections and install thread protectors wrench tight.

5.0Visual And Dimensional Inspection.

5.1Visual and dimensional requirements as listed in procedure BP-DEIP-P004 shall apply.

6.0General Requirements.

6.1General requirements as listed in procedure BP-DEIP-P001 shall apply.

7.0Marking And Stenciling.

7.1Marking and stenciling requirements as listed in procedure BP-DEIP-P001 shall apply.

3

8.0Documentation, Records and Reporting.

8.1Documentation, records and reporting requirements as listed in procedure BP-DEIP-P005 shall apply.

9.0Health, Safety And Environmental.

9.1Health, safety and environmental requirements as listed in BP-DEIP-P001 shall apply.

4

  CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE TRANSOCEAN HOLDINGS INC. 1311 BROADFIELD, SUITE 400 HOUSTON, TX 77084

January 6, 2003

BP America Production Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn:Mr. Jon Sprague — Atlantis Wells Delivery Leader

Re:Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company predecessor in interest to Transocean Holdings Inc. (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject:Letter of Agreement for adding Offshore Safety Assistant

CONTRACTOR-5121-2002-011

Dear Mr. Sprague:

This letter will confirm our agreement to add additional Transocean personnel to the crew complement of the Deepwater Horizon. Upon execution of this Letter Agreement by Company, Contractor agrees to provide two (2) Offshore Safety Advisors (OSA) on the Deepwater Horizon in addition to those specified to be specified to be provided in Exhibit F-1 of the Contract as amended. Exhibits F-1 and F-2 of the Contract shall be amended, as of January 1, 2003 to provide for the following additional personnel:

Title	On Board	Assigned to Rig	Daily Rate per Person w/ Burden		Hourly Overtime Rate w/Burden
Offshore Safety Advisor	1	2	$	930.23	NA

Therefore, the amended crew complement shall show one (1) OSA “On Board” and two (2) “Assigned to Rig”. The amended crew complement is attached. In summary, all rates in the Contract shall increase by $930.23 per day effective January 1, 2003. Except as specifically provided herein, all other terms and conditions of the Contract shall remain in full force and effect. Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files.

If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

Sincerely,

/s/ Christopher S. Young

Christopher S. Young

Sr. Marketing Representative

On Behalf of Transocean Holdings Inc..

PHONE: (832) 587-8506 FAX: (832) 587-8754 EMAIL: cyoung@houston.deepwater.com

BP

Horizon – OSA

TSF File #01-063

AGREED AND ACCEPTED THIS 27th DAY OF JANUARY, 2003

BP AMERICA PRODUCTION COMPANY

SIGNED	/s/ Jerry R Rhoads
PRINTED	Jerry R Rhoads
TITLE	Contracts Specialist

2

  CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE TRANSOCEAN HOLDINGS INC. 1311 BROADFIELD, SUITE 400 HOUSTON, TX 77084

January 7, 2003

BP America Production Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn:Mr. Jon Sprague — Atlantis Wells Delivery Leader

Re:Drilling Contract No. 980249 dated December 9, 1998 (“Contract”) by and between R&B Falcon Drilling Company predecessor in interest to Transocean Holdings Inc. (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject:Letter of Agreement for Recycling program — Deepwater Horizon

CONTRACTOR-5121-2002-011

Dear Mr. Sprague:

This letter will confirm our agreement that effective, January 1, 2003, the parties desire to amend the Contract in order for Contractor to implement a recycling program on the Deepwater Horizon and that Company shall reimburse Contractor for the costs and charges associated with this Service as detailed in Attachment 1, which is attached hereto and made a part of this Letter Agreement.

Except as expressly amended herein, the terms and conditions of the Contract, as previously amended, will remain in effect. Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

Sincerely,

/s/ Christopher S. Young

Christopher S. Young

Sr. Marketing Representative

On Behalf of Transocean Holdings Inc..

AGREED AND ACCEPTED THIS 7th DAY OF FEBRUARY, 2003

BP AMERICA PRODUCTION COMPANY

SIGNED	/s/ Jerry R Rhoads
PRINTED	Jerry R Rhoads
TITLE	Contracts Specialist

PHONE: (832) 587-8506 FAX: (832) 587-8754 EMAIL: cyoung@houston.deepwater.com

BP

Horizon – OSA

TSF File #01-063

ATTACHMENT 1

SCOPE OF WORK AND COMPENSATION

RECYCLING PROGRAM — DEEPWATER HORIZON

1. Scope of Work

Company has requested and Contractor has agreed to provide a recycling program covering recyclable waste materials from Contractor’s Deepwater Horizon Drilling Unit (“Rig”). This program will commence on 1/1, 2003 and shall continue for the remaining primary term of the Contract unless terminated by Company by providing written notice thirty (30) days in advance of the termination date.

Contractor (or its subcontractor) will provide the following services:

1.Provide a recycling service to reduce and separate the waste on the Rig.

2.Furnish recycling and general waste compactor units to the Rig.

3.Supply storage bins at dock locations for collection of recycled materials.

4.Collect and transport compacted bags of recycled materials from the storage bins.

5.Track and provide totals of the volume of recycled material collected

6.Maintain and repair compactor units as needed.

7.Training of Rig personnel in operating, tagging and delivery of the recycled materials to the storage bins

At the Fourchon dock location, Company shall be responsible for ensuring that properly marked recyclable material received at the dock is placed into the appropriate “Recycle the Gulf” storage bin(s) for collection.

2. Rates

Company shall reimburse Contractor the following fees and costs during the term of this recycling service:

Service Fee                  $75.00/day

This Service Fee includes:

1.Equipment on the Rig to separate and compact recyclables

2.Storage Bin located at dock location (Fourchon)

3.Pick up and transportation (from Fourchon dock)

4.Employee Training packet

5.Processing service

Recycle the Gulf Bags — New	5.5 cuft Tri-2 Bags	$ 10.35/each
	14 cuft 6 x 2 bags	$ 10.15/each

2

Model 4000 Trash Compactor Bags	$ 10.20/each
Processing Fee (per bag of recycled material)	$ 1.85/bag

3

TRANSOCEAN OFFSHORE DEEPWATER DRILLING, INC.
4 GREENWAY PLAZA (77046)
	POST OFFICE BOX 2765
Gregory L. Cauthen Senior Vice President, Chief Financial Officer and Treasurer	HOUSTON, TEXAS 77252-2765
February 18, 2003

BP America Production Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn:Mr. Randy Rhoads

Re:Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company predecessor in interest to Transocean Holdings Inc. (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject:Direct Payment of Invoices

CONTRACTOR-5121-2002-011

Dear Randy,

This letter is a formal request for BP to pay invoices related to the Contract referenced aboveby wire transfer to the following account:

Transocean Holdings Inc

Wells Fargo Bank

Houston, Texas

Beneficiary: Transocean Holdings Inc

Account number:

ABA Number:

SWIFTNumber:

Thank you for your cooperation. If you have any questions, please contact John Keeton at (832) 587-8533 or Chris Young at (832) 587-8506. Thank you for the opportunity to be of service.

Sincerely,

/s/ Gregory L. Cauthen

Gregory L. Cauthen

Senior Vice President, Chief

Financial Officer & Treasurer

cc:Craig Duncan

Chris Young

	TRANSOCEAN HOLDINGS INC.
	4 GREENWAY PLAZA
	HOUSTON, TX 77046
CHRISTOPHER S. YOUNG
SR. MARKETING REPRESENTATIVE

February 28, 2003

BP America Production Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn:Mr. Randy Rhoads

Re:Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company predecessor in interest to Transocean Holdings Inc. (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject:Letter of Agreement for Cost Escalation 2003

CONTRACTOR-5121-2002-011

Dear Randy,

We performed the “annual” cost analysis for the Deepwater Horizon as of January 1, 2003 in accordance with Article 2.3 “Adjustment in Dayrates” of the Contract referenced above. The following table summarizes the Baseline Cost changes detailed on the attached schedule “Basis for Cost Escalation”:

Reference	2001 Baseline Costs plus Previous Agreements		Actual Baseline Costs @ Jan. 1, 2003		Increase/ (Decrease)		Dayrate Increase/ (Decrease)
2.3.2a Base Labor Costs	$	36,008	$	36,139	$	131	*
2.3.2b Catering Costs	$	2,366	$	2,780	$	414	$	414
2.3.2c Maintenance Element	13,851		13,946		$	95	*
2.3.2d Insurance	$	1,799	$	5,137	$	3,338	$	3,338
Total	$	54,024/day	$	58,002/day			$	3,752/day

* According to Article 2.3.2, rates for each item must vary by => 5% before they can be adjusted.

Notes:

2.3.2aBase Labor rates did not change but several of our “burdens” did change on January 1. FICA limits increased as well as pension accruals and some insurance related items. We reduced the utilization bonus. The net result was a slight increase but not the 5% required to trigger an increase. Please note that the total includes all personnel added by letter agreement.

2.3.2bContractor’s cost of catering has increased from $27.20 per man per day to $31.95, an increase of 17.5%. Please note the catering cost shown on the accompanying schedule only reflects the crew complement in the contract (77 on board the rig) while we actually have 83.

PHONE: (832) 587-8506 FAX: (832) 587-8754 EMAIL:cyoung@houston.deepwater.com

E-17

BP

Horizon – Escalation 2003

TSF File #01-063

2.3.2cThe Maintenance Element of the Baseline Cost increased $95 per day based on the change on the relevant Producer Price Index. The Index number for December 2002 increased to 146.8 from 145.8 in August of 2001, an increase of .69 %. The Bureau of Labor Statistics Data for the Producer Price Index series ID: WPU119102 is attached. Since the change was less than 5% we did not include it in the rate adjustment.

2.3.2dThe insurance element increased $3,338 per day for a 186% increase and accounts for the majority of the overall cost increase. The cost of the various coverages is broken out on the accompanying schedule. Insurance costs increased dramatically throughout the industry for reasons already discussed. Please note that we lowered the insured value of the rig from $350 million to $320 million and increased the deductible from $500,000 to $10 million to reduce the H&M premium. Without the increased deductible, the premiums would have been significantly higher. Basically, we are self-insured for the first $10 million of coverage. The Marine P&I insurance cost shown on the accompanying schedule reflects a $4,832 per assigned person per year accrual determined by our insurance company for the self-insured $10 million.

The following documents are attached for reference: 1) “Basis for Cost Escalations” schedule; 2) “Adjusted Base Labor as of January 1, 2003”; 3) the Bureau of Labor Statistics Data for the relevant Producer Price Index, and 4) a statement of our annual insurance premiums.

In summary, all rates in the Contract shall increase by $3,752 per day effective January 1, 2003. Except as specifically provided herein, all other terms and conditions of the Contract shall remain in full force and effect.

Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

Sincerely,

/s/ Christopher S. Young

Christopher S. Young

Sr. Marketing Representative

On Behalf of R & B Falcon Drilling Co.

AGREED AND ACCEPTED THIS 17 DAY OF APRIL, 2003

BP AMERICA PRODUCTION COMPANY

SIGNED	/s/ J. W. Farnsworth
PRINTED	J. W. Farnsworth
TITLE	VP Exploration

E-18

2

BASIS FOR COST ESCALATIONS

DEEPWATER HORIZON

January 1, 2003

$ Per Day

		2001 Baseline Costs Plus Agreements		2001 Baseline Costs Plus Subsequent Agreements		January 2003 Actual Baseline Costs		Actual Variance			Dayrate Increase		Adjusted 2003 Baseline Costs
2.3.2a) Base Labor Cost:
	Labor & Burden (for original Contract Crew Complement)	$	25,476	$	25,476	$	25,598	$	122				$	25,476
	Training & Transportation Costs (for original Contract Crew Complement)	$	2,820	$	2,820	$	2,820	$	0				$	2,820
**	Labor & Burden for 7 Addl Personnel included in 2001 Baseline Calc.	$	2,278	NA		NA		NA					NA
**	Training & Transportation Costs (7 Addl Personnel incl. In 2001)	$	335	NA		NA		NA					NA
***	Labor & Burden (18 Addl Pers. (incl. 7 added above) @ Jan 2003)	$	0	$	6,852	$	6,860	$	9				$	6,852
***	Training & Transportation Costs (18 Addl Personnel - Onboard)	$	0	$	860	$	860	$	0				$	860
	Total Base Labor Cost	$	30,909	$	36,008	$	36,139	$	131		$	0	$	36,008
	Percentage Increase							036		%*
2.3.2b) Base Catering Cost:
	59 Contractor Personnel in Original Contract	$	1,605	$	1,605	$	1,885	$	280				$	1,885
**	7 Additional Personnel included in 2001 Baseline Cost Calculation	$	190	NA		NA		NA					NA
***	18 Additional Personnel (including the 7 Addtl. Included in 2001)	$	0	$	490	$	576	$	86				$	576
	10 Company Personnel	$	272	$	272	$	320	$	48				$	320
	Total Base Catering Costs	$	2,067	$	2,366	$	2,780	$	414		$	414	$	2,780
	Percentage Increase							17.5		%
2.3.2c) Base Maintenance Element:		$	13,851	$	13,851	$	13,946	$	95		$	0	$	13,851
	Percentage Increase							0.69		%*
2.3.2d) Base Insurance Cost:
	Hull & Machinery	$	1,289	$	1,289	$	2,422	$	1,133				$	2,422
	Marine P&I	$	343	$	343	$	2,039	$	1,695				$	2,039
	Excess Liability	$	72	$	72	$	520	$	448				$	520
	Brokers Fee	$	94	$	94	$	110	$	15				$	110
	Oil Pollution	$	0	$	0	$	46	$	46				$	46
	Total Base Insurance Cost:	$	1,799	$	1,799	$	5,137	$	3,338		$	3,338	$	5,137
	Percentage Increase							185.6		%
	Total	$	48,626	$	54,024	$	58,002	$	3,977		$	3,752	$	57,776
				Total Dayrate Increase =							$	3,752/day

*         Note: The Index did not vary by 5% so the baseline cost and index stays the same as in 2001

**       Note: The 7 Addl Personnel are shown as line items to identify that they were included in the previous (2001) escalation.

***    18 Addtl. Personnel represent all addtl. Personnel added to the crew complement since the original contract.

E-19

3

DEEPWATER HORIZON

Adjusted Labor as of

January 1, 2003

			A	B		C	D
			GOM Base Labor			GOM Overtime Rates
No. Of Personnel			Daily Rate per			Daily
On Board	Assigned To Rig	JOB CLASSIFICATION	person (inc. TT&C)	Total Daily on Board Cost		Overtime Rates	Hourly  Overtime Rates
1	2	OIM	965.59	871.93		824.67	68.72
1	2	OSA - Horizon	889.04	795.38		748.12	62.34
3	6	Toolpusher	786.15	2,077.48		645.23	53.77
2	4	Driller	662.47	1,137.62		621.66	51.81
4	8	Assistant Driller	511.05	1,669.57		441.18	36.76
2	4	Pumpman	430.72	674.11		345.42	28.79
12	24	Floorman	386.35	3,901.75		342.26	28.52
14	28	Roustabouts	346.81	3,998.53		295.13	24.59
1	2	Welder	494.23	400.57		421.13	35.09
4	8	Crane Operator	511.05	1,009.57		441.10	36.76
2	4	Chief Mechanic	595.17	1,003.03		541.45	45.12
1	2	Mechanic	490.02	396.36		416.11	34.68
2	4	Motor Operator	386.77	651.13		342.76	28.56
1	2	Electrical Supervisor	675.09	581.43		534.17	44.51
2	4	Chief Electrician	595.17	1,003.03		541.45	45.12
1	2	Electrician	490.02	396.36		416.11	34.68
2	4	Chief Electronic Technician	603.59	1,019.85		551.47	45.96
1	2	Senior Sub Sea Sup	777.26	683.60		636.35	53.03
1	2	Assistant Subsea	561.53	467.87		501.34	41.78
2	4	Material Co-Ordinator	456.37	725.43		376.00	31.33
1	2	Master	863.11	769.45		722.19	60.18
1	2	Chief Mate	687.71	594.05		651.74	54.31
1	2	Chief Engineer	803.26	709.59		662.34	55.19
1	2	1st Assistant Engineer	645.65	551.99		601.61	50.13
2	4	2nd Assistant Engineer	612.00	1,036.68		561.50	46.79
2	4	DP Operator	561.53	935.73		501.34	41.78
2	4	Assistant Dp Operator	477.40	767.49		401.07	33.42
2	4	Deck Pusher	497.81	873.21		475.11	39.59
1	2	Bosun	477.40	383.74		401.07	33.42
3	6	AB Seaman	403.59	1,027.17		362.81	30.23
1	2	RSTT	485.82	392.16		411.10	34.26
1	2	Medic	385.88	292.22		291.98	24.33
0	0	-	—	—		—	—
0	0	-	—	—		—	—
0	0	-	—	—		—	—
0	0	-	—	—		—	—
0	0	-	—	—		—	—
0	0	-	—	—		—	—
0	0	-	—	—		—	—
0	0	-	—	—		—	—
77	154	Total Labor Costs =		$	32,458.08

The figures in column “A” are to be used as the basis for adding personnel to the permanent crew and for determining the credit for crew members short. This includes all Training, Transportation and Catering costs.

The figures in column “B” are the daily cost of all crew members excluding Training, Transportation and Catering costs.

The figures in column “C” are the daily cost of overtime excluding Training, Transportation and Catering costs (assuming a daily schedule of 12 hours)

The figures in column “D” are the hourly cost of overtime excluding Training, Transportation and Catering costs.

E-20

4

	TRANSOCEAN OFFSHORE DEEPWATER DRILLING INC.
BETSY KELLY	4 GREENWAY PLAZA
MANAGER-INSURANCE	HOUSTON, TX 77046

Chris Young

Transocean Holdings, Inc.

1311 Broadfield

Houston, TX 77083

Re: Annual Premiums for Deepwater Horizon 2003

Chris,

Current Insurance as of January 1, 2003:

Coverage: Insured Value: Deductible: NET ANNUAL PREMIUM:	All Risk Hull & Machinery $ 320,000,000 $10,000,000 $ 883,943
Coverage: Deductible: NET ANNUAL COST:	Primary Marine Protection & Indemnity $10,000,000 per occurrence $ 744,235*
Coverage: Insured Value: Deductible: NET ANNUAL PREMIUM:	Excess Liability $452,000,000 XS of Primary Marine P & I $ 189,799
Coverage: NET ANNUAL PREMIUM:	Oil Pollution $ 16,820
U.S. Broker: Annual Fee:	McGriff, Seibels & Williams, Inc $ 40,024

* Based on Self Insured Accrual of $4,832 per person x 154 people assigned

(713) 232-7766 FAX (713) 232-7630 TEL BKELLY@HOUSTON.DEEPWATER.COM

E-21

Public Data Query

U. S. Department of Labor Bureau of Labor Statistics Bureau of Labor Statistics Data

www.bls.gov Search | A-Z Index

BLS Home | Programs & Surveys | Get Detailed Statistics | Glossary | What’s New | Find It! In DOL

Change
Output	From: 1992 To 2002 Go
Options:

include graphs NEW! More Formatting Options

Data extracted on: January 31, 2003 (12:09:59 PM)

Producer Price Index-Commodities

Series Id:              WPU119102

Not Seasonally Adjusted

Group:Machinery and equipment

Item:Oil field and gas field drilling machinery

Base Date:8200

Year	Jan	Feb	Mar	Apr	May	Jun	Jul	Aug	Sep		Oct		Nov		Dec		Annual
1992	110.1	110.1	110.1	110.1	110.2	110.4	110.6	110.6	110.6		110.8		112.4		112.5		110.7
1993	112.8	112.9	113.3	112.1	112.0	112.2	112.3	112.3	113.4		113.4		113.4		114.6		112.9
1994	114.6	114.6	114.6	114.6	114.7	114.9	115.4	115.4	115.9		117.8		117.8		117.8		115.7
1995	118.3	118.6	119.2	119.2	119.3	119.6	120.4	120.4	120.4		122.0		122.2		122.2		120.1
1996	124.0	124.0	124.0	124.3	124.2	124.8	125.3	125.3	125.3		126.2		126.6		127.1		125.1
1997	127.7	127.9	128.6	129.1	129.2	129.3	129.3	129.5	129.7		130.3		131.4		132.0		129.5
1998	133.1	132.9	133.1	133.0	133.0	133.0	132.9	132.9	132.9		133.6		133.6		133.6		133.1
1999	133.8	133.7	133.7	133.9	133.9	134.0	134.0	133.7	133.7		133.7		134.4		134.6		133.9
2000	134.9	136.3	136.3	136.3	136.5	136.5	136.5	136.6	136.7		138.7		138.7		138.7		136.9
2001	143.5	143.9	144.0	144.0	144.0	145.5	145.6	145.8	145.7		146.1		146.1		146.1		145.0
2002	146.2	146.2	146.6	146.6	146.4	146.4	146.4	146.4	146.8	(P)	146.8	(P)	146.8	(P)	146.8	(P)	146.5	(P)

(P): Preliminary. All indexes are subject to revision four months after original publication.

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E-22

1

TRANSOCEAN OFFSHORE DEEPWATER DRILLING INC.

1311 BROADFIELD, SUITE 400

HOUSTON, TX 77084

CHRISTOPHER S. YOUNG

SR. MARKETING REPRESENTATIVE

March 3, 2003

BP America Production Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn:Mr. Randy Rhoads

Re:Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company predecessor in interest to Transocean Holdings Inc. (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject:Letter of Agreement for Rental of 6 5/8” HWDP

CONTRACTOR-5121-2002-011

Dear Randy,

This letter is to reflect our agreement to purchase 23 joints of 6 5/8” drill pipe (per Smith’s Quote No. D03-0557) and rent it to BP over the remaining term of the Contract referenced above. The total rental amount will be 1.27418155 times the cost of the pipe. The pipe cost $107,311.56 including inspection. Therefore, the total rental payment will be $136,734.40 over the remaining term of the contract. We received the pipe on March 3, 2003. Therefore, the rental rate will be $242.01 per day starting March 4, 2003 and ending September 18, 2004. If the Contract should be terminated for any reason, BP agrees to pay the difference between $136,734.40 and the total rental paid up to that time. BP will be responsible for all inspections during the term of the rental. The pipe shall be treated as Contractor’s in-hole equipment per Article 22 of the Contract.

Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

Sincerely,

/s/ Christopher S. Young

Christopher S. Young

Sr. Marketing Representative

AGREED AND ACCEPTED THIS 14th DAY OF APRIL, 2003

BP AMERICA PRODUCTION COMPANY

SIGNED	/s/ Jerry R Rhoads
PRINTED	Jerry R Rhoads
TITLE	Contracts Specialist

PHONE: (832) 587-8506 FAX: (832) 587-8754 EMAIL:cyoung@houston.deepwater.com

TRANSOCEAN OFFSHORE DEEPWATER DRILLING INC.

1311 BROADFIELD, SUITE 400

HOUSTON, TX 77084

CHRISTOPHER S. YOUNG

SR. MARKETING REPRESENTATIVE

March 20, 2003

BP America Production Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn:Mr. Randy Rhoads

Re:Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject:Letter of Agreement for 6 5/8” Drill Pipe Rental dated November 1, 2002

CONTRACTOR-5121-2002-011

Dear Randy,

This letter is to document the actual cost and daily rental rate for the 6 5/8” drill pipe referenced in our November 1, 2002 letter agreement.

According to the November 1, 2002 Agreement, the total rental amount will be 1.27418155 times the actual cost of the pipe. The pipe cost $1,352,110.27 including trucking and inspection so the total rental payment will be $1,722,833.96 over the remaining term of the contract. Therefore, the daily rental rate will be $3,208.26 per day starting on April 1, 2003 and continuing through September 18, 2004 (537 days). If the contract is terminated for any reason prior to September 18, 2004, BP agrees to pay the difference between $1,722,833.96 and the total rental paid up to the time of termination.

BP will be responsible for all inspections during the term of the rental. The pipe shall be treated as Contractor’s in-hole equipment per Article 22 of the Contract.

If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

Sincerely,

/s/ Christopher S. Young

Christopher S. Young

Sr. Marketing Representative

AGREED AND ACCEPTED THIS 14th DAY OF APRIL, 2003

BP AMERICA PRODUCTION COMPANY

SIGNED	/s/ Jerry R Rhoads
PRINTED	Jerry R Rhoads
TITLE	Contracts Specialist

PHONE: (832) 587-8506 FAX: (832) 587-8754 EMAIL:cyoung@houston.deepwater.com

TRANSOCEAN OFFSHORE DEEPWATER DRILLING INC.

1311 BROADFIELD, SUITE 400

HOUSTON, TX 77084

CHRISTOPHER S. YOUNG

SR. MARKETING REPRESENTATIVE

November 1, 2002

BP America Production Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn:Mr. Randy Rhoads

Re:Drilling Contract No. 980249 dated December 9, 1998 (“Contract”) by and between R&B Falcon Drilling Company predecessor in interest to Transocean Holdings, Inc,(“Contractor or TODDI”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject:Letter of Agreement for 6 5/8” Drill Pipe Rental

CONTRACTOR-5121-2002-011

Dear Randy,

This letter is to document the agreement between Transocean Offshore Deepwater Drilling Inc. (TODDI) and Company for the rental of 18,000 feet of 6 5/8” R-3 drill pipe for use on the Deepwater Horizon.

Company and TODDI hereby agree to the following terms and conditions:

1.TODDI shall purchase the following pipe and rent it to Company over the remaining term of the Contract referenced above. Specifications of the pipe are as follows:

Footage	18,000	Joints	439
Pipe OD	6 5/8”	Connection	6 5/8 FH
Weight	34.01	OD	8 1/4”
Grade	S-135	ID	4 1/4”
Upset	IEU	Pin Tong	10”
Range	3	Box Tong	13”
Internal Coating	TK34 XT*	Hardfacing Pin	None
Inspection	Truscope AS	Hardfacing Box	Armacor M
Delivery	16 weeks*
Make & Break & 95% wall included

* Changes from Grant Prideco quote 30726

2.Tooljoints (Pin & Box) shall be manufactured long enough to provide for a minimum of two full recuts and still have sufficient tong space excluding proud hardbanded area. Company’s coating, hardbanding and make & break specifications are attached and made a part of this Agreement.

PHONE: (832) 587-8506 FAX: (832) 587-8754 EMAIL:cyoung@houston.deepwater.com

3.The rental rate will be approximately $3,000/day assuming that 18 months will be remaining on the contract at time of pipe delivery and that the total cost of the pipe is approximately $1.29 million. The exact calculation will be made when the pipe is delivered and the total cost (based on good footage) and the remaining number of days in the term are known. The total rental amount to be recovered will be calculated at 1.27418155 times the total cost of the pipe. The total cost of the pipe will include inspection and transportation.

4.The rental rate shall begin upon delivery of the pipe to TODDI following acceptance in accordance with Company’s QA/QC specifications and inspection criteria. These specifications and criteria are made a part of this Agreement. The rental rate shall cease when the total rental paid equals 1.27418155 times the final cost of the pipe. The rental agreement will continue as long the Contract is in force however the rental rate will be zero after the total rental paid equals 1.27418155 times the final cost of the pipe.

5.Contractor shall furnish all handling equipment required for this pipe during the term of the rental at no cost to Company.

6.Initial inspection is included in the cost of the pipe. Company reserves the right to re-inspect the pipe at Company’s cost. Company will be responsible for all inspections during the term of the rental.

7.The pipe shall be treated as Contractor’s in-hole equipment per Article 22.3 of the Contract except for the cost of inspections.

8.During the term of the rental, Company will have the option of moving the pipe to another Transocean Rig at Company’s option and expense.

If you are in agreement with the above, please sign in the space provided below and return one fully executed copy of this letter to me for our files.

If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

Sincerely,

/s/ Christopher S. Young

Christopher S. Young

Sr. Marketing Representative

AGREED AND ACCEPTED THIS 3RD DAY OF FEBRUARY, 2003

BP AMERICA PRODUCTION COMPANY

SIGNED	/s/ Jerry R Rhoads
PRINTED	Jerry R Rhoads
TITLE	Contracts Specialist

TRANSOCEAN HOLDINGS INC.

1311 BROADFIELD, SUITE 400

HOUSTON, TX 77084

CHRISTOPHER S. YOUNG

SR. MARKETING REPRESENTATIVE

November 12, 2003

BP Deepwater Development Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn:Mr. Jon Sprague – Atlantis Wells Delivery Leader

Re:Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company predecessor in interest to Transocean Holdings Inc. (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject:Letter of Agreement for adding Tool Pusher in BP’s Office

CONTRACTOR-5121-2002-011

Dear Mr. Sprague:

Upon execution of this Letter Agreement by COMPANY, CONTRACTOR agrees to provide one (1) Tool Pusher to work in BP’s offices in addition to those specified in Exhibit F-1 of the Contract as amended.

COMPANY has requested and CONTRACTOR agrees that CONTRACTOR will provide one (1) additional Sr. Toolpusher to work in COMPANY’s offices during the Atlantis Project. The Sr. Toolpusher will be shore based and work at COMPANY’s offices as required to support the Atlantis Project on an even rotating schedule. Work will commence on or about December 1, 2003.

CONTRACTOR shall invoice COMPANY at the rate of US$786 (Seven Hundred Eighty Six) per day worked and for all documented reasonable and necessary travel costs and living (room and board) expenses (at no mark-up to actual costs). The Sr. Toolpusher will be available for work seven days a week on 14 day on and 14 day off schedule and COMPANY shall be billed monthly for every day available for work during the month. CONTRACTOR will supply supporting documentation with each monthly invoice as evidence of days available for work.

COMPANY reserves the right to release the services of the Sr. Toolpusher at anytime upon thirty (30) days prior written notice to CONTRACTOR. COMPANY and CONTRACTOR will document when the Sr. Toolpusher is released from duty for services on this special Atlantis Project assignment, thus ending the applicability of this contract amendment.

Except as specifically provided herein, all other terms and conditions of the Contract shall remain in full force and effect. Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files.

If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

PHONE: (832) 587-8506 FAX: (832) 587-8754 EMAIL:cyoung@houston.deepwater.com

BP

Horizon – TP in BP’s office

TSF File #01-063

Sincerely,

/s/ Christopher S. Young

Christopher S. Young

Sr. Marketing Representative

On Behalf of Transocean Holdings Inc.,

AGREED AND ACCEPTED THIS 1st DAY OF DECEMBER, 2003

BP DEEPWATER DEVELOPMENT COMPANY

SIGNED	/s/ Jerry R Rhoads
PRINTED	Jerry R Rhoads
TITLE	Contracts Specialist

2

TRANSOCEAN HOLDINGS INC.

4 GREENWAY PLAZA

HOUSTON, TX 77046

CHRISTOPHER S. YOUNG

SR. MARKETING REPRESENTATIVE

February 28, 2004

BP America Production Company

501 WestLake Park Blvd.

Houston, TX 77079

Attn:Mr. Randy Rhoads

Re:Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company predecessor in interest to Transocean Holdings Inc. (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject:Letter of Agreement for Cost Escalation 2003

Transocean Ref: 5121-2001063-027

Dear Randy,

We performed the “annual” cost analysis for the Deepwater Horizon as of January 1, 2004 in accordance with Article 2.3 “Adjustment in Dayrates” of the Contract referenced above. The following table summarizes the Baseline Cost changes detailed on the attached schedule “Basis for Cost Escalation”:

Reference	2003 Baseline Costs plus Previous Agreements		Actual Baseline Costs @ Jan. 1, 2003		Increase/ (Decrease)			Dayrate Increase/ (Decrease)
2.3.2a Base Labor Costs	$	36,008	$	36,099	$	91		*
2.3.2b Catering Costs	$	2,780	$	2,650	$	(130	)	$	(130	)
2.3.2c Maintenance Element	$	13,851	$	14,589	$	738		$	738
2.3.2d Insurance	$	5,137	$	5,137	0
Total	$	57,776/day	$	58,475/day				$	608day

* According to Article 2.3.2, rates for each item must vary by => 5% before they can be adjusted.

Notes:

2.3.2aBase Labor rates changed by the adjustment of the utilization bonus and pension accruals. The net result was a slight increase but not the 5% required to trigger an increase.

2.3.2bWe have changed catering companies on the Horizon which has provided a decrease from $31.95 per man per day to $30.45, a decrease of 6.3%. Please note the catering cost shown on the accompanying schedule only reflects the crew complement in the contract (77 on board the rig) while we actually have 83.

PHONE: (832) 587-8506 FAX: (832) 587-8754 EMAIL:cyoung@houston.deepwater.com

E-23

BP

Horizon – Escalation 2004

TSF File #01-063

2.3.2cThe Maintenance Element of the Baseline Cost increased $738 per day based on the change on the relevant Producer Price Index. The Index number for December 2003 increased to 153.8 from 145.8 in August of 2001, an increase of 5.33%. The Bureau of Labor Statistics Data for the Producer Price Index series ID: WPU119102 is attached.

2.3.2dCosts of insurance premiums have not changed due to the fact that our Risk Department negotiated a 14 month agreement for the previous increases. We will keep you advised of any increases regarding insurance.

The following documents are attached for reference: 1) “Basis for Cost Escalations” schedule; 2) “Adjusted Base Labor as of January 1, 2004”; and 3) the Bureau of Labor Statistics Data for the relevant Producer Price Index.

In summary, the following adjustments will be made:

Paragraph 2.3.2b	(130		)
Paragraph 2.3.2c	738
Total Increase	$	608	net increase effective January 1, 2004

Except as specifically provided herein, all other terms and conditions of the Contract shall remain in full force and effect.

Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

Sincerely,

/s/ Christopher S. Young

Christopher S. Young

Sr. Marketing Representative

On Behalf of R & B Falcon Drilling Co.

AGREED AND ACCEPTED THIS 31 DAY OF MARCH, 2004

BP AMERICA PRODUCTION COMPANY

SIGNED	/s/ Scott Sigurdson
PRINTED	Scott Sigurdson
TITLE	Wells Manager

E-24

2

BASIS FOR COST ESCALATIONS

DEEPWATER HORIZON

January 1, 2004

$ Per Day

Clause No.:		January 2003 Actual Baseline Costs		January 2004 Actual Baseline Costs		Variance			Adjusted 2004 Baseline Costs
2.3.2a)	Base Labor Cost:
	Labor & Burden (per schedule)	$	25,476	$	25,626	$	150		$	25,476
	Training & Transportation Costs	$	2,820	$	3,024	$	204		$	2,820
**	Labor & Burden (18 Addl Personnel - Onboard)	$	6,852	$	6,792	$	-59		$	6,852
**	(Training & Transportation Costs (18 Addl Personnel - Onboard)	$	860	$	656	$	-204		$	860
	Total Base Labor Cost	$	36,008	$	36,099	$	91		$	36,008
	Percentage Increase					0.25		%*
2.3.2b)	Base Catering Cost:
	59 Contractor Personnel	$	1,885	$	1,797	$	-88		$	1,797
**	18 Additional Personnel	$	576	$	549	$	-27		$	549
	10 Company Personnel	$	320	$	305	$	-15		$	305
	Total Base Catering Costs	$	2,780	$	2,650	$	-130		$	2,650
	Percentage Increase					-6.3		%
2.3.2c)	Base Maintenance Element:	$	13,851	$	14,589	$	738		$	14,589
	Percentage Increase					5.33		%
2.3.2d)	Base Insurance Cost:
	Hull & Machinery	$	2,422	$	2,422	$	0		$	2,422
	Marine P&I	$	2,039	$	2,039	$	0		$	2,039
	Excess Liability	$	520	$	520	$	0		$	521
	Brokers Fee	$	110	$	110	$	0		$	110
	Oil Pollution	$	46	$	46	$	0		$	46
	Total Base Insurance Cost:	$	5,137	$	5,137	$	0		$	5,137
	Percentage Increase					0.0		%
Total Baseline Operating Costs		$	57,776	$	58,475	$	608		$	58,384
Total Dayrate Increase =									$	608/day

* Note: The Index did not vary by 5% so the baseline cost and index stays the same as in 2003

**Note: The 7 Addl Personnel are included as line items to identify that they were included in the previous escalation.

The 18 Addl Personnel includes all personnel added to the contract and these lines indicate the increases on all Addl Personnel.

E-25

DEEPWATER HORIZON

Adjusted Labor as of

January 1, 2004

			A	B	C	D
			GOM Base Labor		GOM Overtime Rates
No. of Personnel			Daily Rate per		Daily
On Board	Assigned To Rig	JOB CLASSIFICATION	person (inc. TT&C)	Total Daily on Board Cost	Overtime Rates	Hourly Overtime Rates
1	2	OIM	958.32	866.16	818.90	68.24
1	2	OSA - Horizon	868.26	776.10	728.84	60.74
3	6	Toolpusher	793.31	2,103.44	653.89	54.49
2	4	Driller	659.31	1,134.31	619.69	51.64
4	8	Assistant Driller	508.91	1,667.01	440.42	36.70
2	4	Pumpman	427.86	671.40	343.80	28.65
12	24	Floorman	383.58	3,886.55	340.75	28.40
14	28	Roustabouts	342.07	3,953.17	291.27	24.27
1	2	Welder	483.29	391.13	409.87	34.16
4	8	Crane Operator	499.66	1,630.00	429.39	35.78
2	4	Chief Mechanic	591.28	998.23	538.59	44.88
1	2	Mechanic	493.19	401.03	421.68	35.14
2	4	Motor Operator	397.26	675.10	357.04	29.75
1	2	Electrical Supervisor	659.31	567.15	519.90	43.32
2	4	Chief Electrician	589.72	995.12	536.74	44.73
1	2	Electrician	488.44	396.28	416.02	34.67
2	4	Chief Electronic Technician	597.91	1,011.50	546.50	45.54
1	2	Senior Sub Sea Sup	759.49	667.32	620.07	51.67
1	2	Assistant Subsea	559.02	466.86	500.14	41.68
2	4	Material Co-Ordinator	451.60	718.88	372.10	31.01
1	2	Master	852.37	760.21	712.95	59.41
1	2	Chief Mate	671.59	579.43	634.32	52.86
1	2	Chief Engineer	759.56	667.40	620.14	51.68
1	2	1st Assistant Engineer	658.33	566.17	618.52	51.54
2	4	2nd Assistant Engineer	653.50	1,122.68	612.76	51.06
2	4	DP Operator	561.07	937.81	502.58	41.88
2	4	Assistant Dp Operator	475.10	765.88	400.11	33.34