þ
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
¨
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
Zug, Switzerland
|
98-0599916
|
(State or other jurisdiction of incorporation or organization)
|
(I.R.S. Employer Identification No.)
|
Chemin de Blandonnet 10
Vernier, Switzerland
|
1214
|
(Address of principal executive offices)
|
(Zip Code)
|
+41 (22) 930-9000
|
|
(Registrant’s telephone number, including area code)
|
|
PART I. FINANCIAL INFORMATION
|
Page
|
|
Item 1.
|
Financial Statements (Unaudited)
|
|
Condensed Consolidated Statements of Operations
|
1
|
|
Condensed Consolidated Statements of Comprehensive Income
|
2
|
|
Condensed Consolidated Balance Sheets
|
3
|
|
Condensed Consolidated Statements of Equity
|
4
|
|
Condensed Consolidated Statements of Cash Flows
|
5
|
|
Notes to Condensed Consolidated Financial Statements
|
6
|
|
Item
2.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
24
|
Item
3.
|
Quantitative and Qualitative Disclosures About Market Risk
|
49
|
Item
4.
|
Controls and Procedures
|
50
|
PART II. OTHER INFORMATION
|
||
Item
1.
|
Legal Proceedings
|
51
|
Item
1A.
|
Risk Factors
|
51
|
Item
2.
|
Unregistered Sales of Equity Securities and Use of Proceeds
|
55
|
Item
6.
|
Exhibits
|
55
|
PART I.
|
FINANCIAL INFORMATION
|
Three months ended June 30,
|
Six months ended June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
Operating revenues
|
||||||||||||||||
Contract drilling revenues
|
$
|
2,290
|
$
|
2,625
|
$
|
4,731
|
$
|
5,459
|
||||||||
Contract drilling intangible revenues
|
29
|
75
|
62
|
179
|
||||||||||||
Other revenues
|
186
|
182
|
314
|
362
|
||||||||||||
2,505
|
2,882
|
5,107
|
6,000
|
|||||||||||||
Costs and expenses
|
||||||||||||||||
Operating and maintenance
|
1,358
|
1,277
|
2,554
|
2,448
|
||||||||||||
Depreciation, depletion and amortization
|
400
|
360
|
801
|
715
|
||||||||||||
General and administrative
|
58
|
53
|
121
|
109
|
||||||||||||
1,816
|
1,690
|
3,476
|
3,272
|
|||||||||||||
Loss on impairment
|
—
|
(67
|
)
|
(2
|
)
|
(288
|
)
|
|||||||||
Gain (loss) on disposal of assets, net
|
268
|
(4
|
)
|
254
|
—
|
|||||||||||
Operating income
|
957
|
1,121
|
1,883
|
2,440
|
||||||||||||
Other income (expense), net
|
||||||||||||||||
Interest income
|
5
|
1
|
10
|
2
|
||||||||||||
Interest expense, net of amounts capitalized
|
(141
|
)
|
(114
|
)
|
(273
|
)
|
(250
|
)
|
||||||||
Gain (loss) on retirement of debt
|
—
|
(8
|
)
|
2
|
(10
|
)
|
||||||||||
Other, net
|
(3
|
)
|
(8
|
)
|
10
|
—
|
||||||||||
(139
|
)
|
(129
|
)
|
(251
|
)
|
(258
|
)
|
|||||||||
Income before income tax expense
|
818
|
992
|
1,632
|
2,182
|
||||||||||||
Income tax expense
|
98
|
184
|
227
|
435
|
||||||||||||
Net income
|
720
|
808
|
1,405
|
1,747
|
||||||||||||
Net income (loss) attributable to noncontrolling interest
|
5
|
2
|
13
|
(1
|
)
|
|||||||||||
Net income attributable to controlling interest
|
$
|
715
|
$
|
806
|
$
|
1,392
|
$
|
1,748
|
||||||||
Earnings per share
|
||||||||||||||||
Basic
|
$
|
2.23
|
$
|
2.50
|
$
|
4.32
|
$
|
5.43
|
||||||||
Diluted
|
$
|
2.22
|
$
|
2.49
|
$
|
4.31
|
$
|
5.42
|
||||||||
Weighted average shares outstanding
|
||||||||||||||||
Basic
|
319
|
320
|
320
|
320
|
||||||||||||
Diluted
|
320
|
321
|
321
|
321
|
Three months ended June 30,
|
Six months ended June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
Net income
|
$
|
720
|
$
|
808
|
$
|
1,405
|
$
|
1,747
|
||||||||
Other comprehensive income (loss) before income taxes
|
||||||||||||||||
Unrecognized components of net periodic benefit cost
|
—
|
—
|
(10
|
)
|
(39
|
)
|
||||||||||
Recognized components of net periodic benefit cost
|
3
|
5
|
9
|
9
|
||||||||||||
Unrealized gain (loss) on derivative instruments
|
(11
|
)
|
10
|
(17
|
)
|
9
|
||||||||||
Other, net
|
(3
|
)
|
1
|
(3
|
)
|
—
|
||||||||||
Other comprehensive income (loss) before income taxes
|
(11
|
)
|
16
|
(21
|
)
|
(21
|
)
|
|||||||||
Income taxes related to other comprehensive income (loss)
|
(1
|
)
|
(6
|
)
|
(1
|
)
|
3
|
|||||||||
Other comprehensive income (loss), net of income taxes
|
(12
|
)
|
10
|
(22
|
)
|
(18
|
)
|
|||||||||
Total comprehensive income
|
708
|
818
|
1,383
|
1,729
|
||||||||||||
Total comprehensive income (loss) attributable to noncontrolling interest
|
(9
|
)
|
13
|
(8
|
)
|
10
|
||||||||||
Total comprehensive income attributable to controlling interest
|
$
|
717
|
$
|
805
|
$
|
1,391
|
$
|
1,719
|
June 30,
2010
|
December 31, 2009
|
|||||||
(Unaudited)
|
||||||||
Assets
|
||||||||
Cash and cash equivalents
|
$
|
2,888
|
$
|
1,130
|
||||
Accounts receivable, net of allowance for doubtful accounts
of $41 and $65 at June 30, 2010 and December 31, 2009, respectively
|
2,254
|
2,385
|
||||||
Materials and supplies, net of allowance for obsolescence
of $66 at June 30, 2010 and December 31, 2009
|
467
|
462
|
||||||
Deferred income taxes, net
|
121
|
104
|
||||||
Assets held for sale
|
—
|
186
|
||||||
Other current assets
|
184
|
209
|
||||||
Total current assets
|
5,914
|
4,476
|
||||||
Property and equipment
|
27,377
|
27,383
|
||||||
Property and equipment of consolidated variable interest entities
|
2,179
|
1,968
|
||||||
Less accumulated depreciation
|
7,034
|
6,333
|
||||||
Property and equipment, net
|
22,522
|
23,018
|
||||||
Goodwill
|
8,132
|
8,134
|
||||||
Other assets
|
984
|
808
|
||||||
Total assets
|
$
|
37,552
|
$
|
36,436
|
||||
Liabilities and equity
|
||||||||
Accounts payable
|
$
|
968
|
$
|
780
|
||||
Accrued income taxes
|
154
|
240
|
||||||
Debt due within one year
|
1,580
|
1,568
|
||||||
Debt of consolidated variable interest entities due within one year
|
82
|
300
|
||||||
Other current liabilities
|
1,884
|
730
|
||||||
Total current liabilities
|
4,668
|
3,618
|
||||||
Long-term debt
|
8,862
|
8,966
|
||||||
Long-term debt of consolidated variable interest entities
|
902
|
883
|
||||||
Deferred income taxes, net
|
710
|
726
|
||||||
Other long-term liabilities
|
1,683
|
1,684
|
||||||
Total long-term liabilities
|
12,157
|
12,259
|
||||||
Commitments and contingencies
|
||||||||
Shares, CHF 15.00 par value, 502,852,947 authorized, 167,617,649 conditionally authorized,
335,235,298 issued at June 30, 2010 and December 31, 2009;
318,916,207 and 321,223,882 outstanding at June 30, 2010 and December 31, 2009, respectively
|
4,479
|
4,472
|
||||||
Additional paid-in capital
|
6,421
|
7,407
|
||||||
Treasury shares, at cost, 2,863,267 and none held at June 30, 2010 and December 31, 2009, respectively
|
(240
|
)
|
—
|
|||||
Retained earnings
|
10,400
|
9,008
|
||||||
Accumulated other comprehensive loss
|
(336
|
)
|
(335
|
)
|
||||
Total controlling interest shareholders’ equity
|
20,724
|
20,552
|
||||||
Noncontrolling interest
|
3
|
7
|
||||||
Total equity
|
20,727
|
20,559
|
||||||
Total liabilities and equity
|
$
|
37,552
|
$
|
36,436
|
Six months ended June 30,
|
|||||||
2010
|
2009
|
||||||
Shares outstanding
|
|||||||
Balance, beginning of period
|
321
|
319
|
|||||
Issuance of shares under share-based compensation plans
|
1
|
2
|
|||||
Purchases of shares held in treasury
|
(3
|
)
|
—
|
||||
Balance, end of period
|
319
|
321
|
|||||
Shares
|
|||||||
Balance, beginning of period
|
$
|
4,472
|
$
|
4,444
|
|||
Issuance of shares under share-based compensation plans
|
7
|
24
|
|||||
Balance, end of period
|
$
|
4,479
|
$
|
4,468
|
|||
Additional paid-in capital
|
|||||||
Balance, beginning of period
|
$
|
7,407
|
$
|
7,313
|
|||
Share-based compensation expense
|
53
|
43
|
|||||
Issuance of shares under share-based compensation plans
|
(9
|
)
|
16
|
||||
Obligation for cash distribution
|
(1,024
|
)
|
—
|
||||
Repurchases of convertible senior notes
|
—
|
16
|
|||||
Changes in ownership of noncontrolling interest and other, net
|
(6
|
)
|
—
|
||||
Balance, end of period
|
$
|
6,421
|
$
|
7,388
|
|||
Treasury shares, at cost
|
|||||||
Balance, beginning of period
|
$
|
—
|
$
|
—
|
|||
Purchases of shares held in treasury
|
(240
|
)
|
—
|
||||
Balance, end of period
|
$
|
(240
|
)
|
$
|
—
|
||
Retained earnings
|
|||||||
Balance, beginning of period
|
$
|
9,008
|
$
|
5,827
|
|||
Net income attributable to controlling interest
|
1,392
|
1,748
|
|||||
Balance, end of period
|
$
|
10,400
|
$
|
7,575
|
|||
Accumulated other comprehensive loss
|
|||||||
Balance, beginning of period
|
$
|
(335
|
)
|
$
|
(420
|
)
|
|
Other comprehensive loss attributable to controlling interest
|
(1
|
)
|
(29
|
)
|
|||
Balance, end of period
|
$
|
(336
|
)
|
$
|
(449
|
)
|
|
Total controlling interest shareholders’ equity
|
|||||||
Balance, beginning of period
|
$
|
20,552
|
$
|
17,164
|
|||
Total comprehensive income attributable to controlling interest
|
1,391
|
1,719
|
|||||
Share-based compensation expense
|
53
|
43
|
|||||
Issuance of shares under share-based compensation plans
|
(2
|
)
|
40
|
||||
Purchases of shares held in treasury
|
(240
|
)
|
—
|
||||
Obligation for cash distribution
|
(1,024
|
)
|
—
|
||||
Repurchases of convertible senior notes
|
—
|
16
|
|||||
Changes in ownership of noncontrolling interest and other, net
|
(6
|
)
|
—
|
||||
Balance, end of period
|
$
|
20,724
|
$
|
18,982
|
|||
Total noncontrolling interest
|
|||||||
Balance, beginning of period
|
$
|
7
|
$
|
3
|
|||
Net income (loss) attributable to noncontrolling interest
|
13
|
(1
|
)
|
||||
Other comprehensive income (loss) attributable to noncontrolling interest
|
(21
|
)
|
11
|
||||
Changes in ownership of noncontrolling interest
|
4
|
—
|
|||||
Balance, end of period
|
$
|
3
|
$
|
13
|
|||
Total equity
|
|||||||
Balance, beginning of period
|
$
|
20,559
|
$
|
17,167
|
|||
Total comprehensive income
|
1,383
|
1,729
|
|||||
Share-based compensation expense
|
53
|
43
|
|||||
Issuance of shares under share-based compensation plans
|
(2
|
)
|
40
|
||||
Purchases of shares held in treasury
|
(240
|
)
|
—
|
||||
Obligation for cash distribution
|
(1,024
|
)
|
—
|
||||
Repurchases of convertible notes
|
—
|
16
|
|||||
Changes in ownership of noncontrolling interest and other, net
|
(2
|
)
|
—
|
||||
Balance, end of period
|
$
|
20,727
|
$
|
18,995
|
Three months ended June 30,
|
Six months ended June 30,
|
||||||||||||||||
2010
|
2009
|
2010
|
2009
|
||||||||||||||
Cash flows from operating activities
|
|||||||||||||||||
Net income
|
$
|
720
|
$
|
808
|
$
|
1,405
|
$
|
1,747
|
|||||||||
Adjustments to reconcile net income to net cash provided by operating activities
|
|||||||||||||||||
Amortization of drilling contract intangibles
|
(29
|
)
|
(75
|
)
|
(62
|
)
|
(179
|
)
|
|||||||||
Depreciation, depletion and amortization
|
400
|
360
|
801
|
715
|
|||||||||||||
Share-based compensation expense
|
18
|
24
|
53
|
43
|
|||||||||||||
Excess tax benefit from share-based compensation plans
|
(1
|
)
|
—
|
(1
|
)
|
(1
|
)
|
||||||||||
(Gain) loss on disposal of assets, net
|
(268
|
)
|
4
|
(254
|
)
|
—
|
|||||||||||
Loss on impairment
|
—
|
67
|
2
|
288
|
|||||||||||||
(Gain) loss on retirement of debt
|
—
|
8
|
(2
|
)
|
10
|
||||||||||||
Amortization of debt issue costs, discounts and premiums, net
|
51
|
57
|
100
|
109
|
|||||||||||||
Deferred income taxes
|
(12
|
)
|
20
|
(34
|
)
|
26
|
|||||||||||
Other, net
|
(6
|
)
|
14
|
(1
|
)
|
23
|
|||||||||||
Deferred revenue, net
|
7
|
49
|
158
|
43
|
|||||||||||||
Deferred expenses, net
|
(23
|
)
|
(37
|
)
|
(37
|
)
|
(35
|
)
|
|||||||||
Changes in operating assets and liabilities
|
412
|
277
|
313
|
228
|
|||||||||||||
Net cash provided by operating activities
|
1,269
|
1,576
|
2,441
|
3,017
|
|||||||||||||
Cash flows from investing activities
|
|||||||||||||||||
Capital expenditures
|
(300
|
)
|
(947
|
)
|
(679
|
)
|
(1,655
|
)
|
|||||||||
Proceeds from disposal of assets, net
|
10
|
—
|
51
|
8
|
|||||||||||||
Proceeds from insurance recoveries for loss of drilling unit
|
560
|
—
|
560
|
—
|
|||||||||||||
Proceeds from payments on notes receivable
|
11
|
—
|
21
|
—
|
|||||||||||||
Proceeds from short-term investments
|
—
|
172
|
5
|
393
|
|||||||||||||
Purchases of short-term investments
|
—
|
(234
|
)
|
—
|
(234
|
)
|
|||||||||||
Joint ventures and other investments, net
|
(1
|
)
|
—
|
(1
|
)
|
—
|
|||||||||||
Net cash provided by (used in) investing activities
|
280
|
(1,009
|
)
|
(43
|
)
|
(1,488
|
)
|
||||||||||
Cash flows from financing activities
|
|||||||||||||||||
Change in short-term borrowings, net
|
(46
|
)
|
(476
|
)
|
(177
|
)
|
(500
|
)
|
|||||||||
Proceeds from debt
|
—
|
231
|
54
|
319
|
|||||||||||||
Repayments of debt
|
(22
|
)
|
(708
|
)
|
(275
|
)
|
(1,410
|
)
|
|||||||||
Payments for warrant exercises, net
|
—
|
(13
|
)
|
—
|
(13
|
)
|
|||||||||||
Purchases of shares held in treasury
|
(180
|
)
|
—
|
(240
|
)
|
—
|
|||||||||||
Proceeds from (taxes paid for) share-based compensation plans, net
|
3
|
5
|
(1
|
)
|
22
|
||||||||||||
Excess tax benefit from share-based compensation plans
|
1
|
—
|
1
|
1
|
|||||||||||||
Other, net
|
(3
|
)
|
(1
|
)
|
(2
|
)
|
(4
|
)
|
|||||||||
Net cash used in financing activities
|
(247
|
)
|
(962
|
)
|
(640
|
)
|
(1,585
|
)
|
|||||||||
Net increase (decrease) in cash and cash equivalents
|
1,302
|
(395
|
)
|
1,758
|
(56
|
)
|
|||||||||||
Cash and cash equivalents at beginning of period
|
1,586
|
1,302
|
1,130
|
963
|
|||||||||||||
Cash and cash equivalents at end of period
|
$
|
2,888
|
$
|
907
|
$
|
2,888
|
$
|
907
|
June 30, 2010
|
December 31, 2009
|
||||||||||||||||||||||
Assets
|
Liabilities
|
Net carrying amount
|
Assets
|
Liabilities
|
Net carrying amount
|
||||||||||||||||||
Variable interest entity
|
|||||||||||||||||||||||
TPDI
|
$
|
1,600
|
$
|
806
|
$
|
794
|
$
|
1,500
|
$
|
763
|
$
|
737
|
|||||||||||
ADDCL
|
825
|
319
|
506
|
582
|
482
|
100
|
|||||||||||||||||
Total
|
$
|
2,425
|
$
|
1,125
|
$
|
1,300
|
$
|
2,082
|
$
|
1,245
|
$
|
837
|
June 30,
2010
|
December 31,
2009
|
||||||
Unrecognized tax benefits, excluding interest and penalties
|
$
|
457
|
$
|
460
|
|||
Interest and penalties
|
209
|
200
|
|||||
Unrecognized tax benefits, including interest and penalties
|
$
|
666
|
$
|
660
|
Three months ended June 30,
|
Six months ended June 30,
|
|||||||||||||||||||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||||||||||||||||||
Basic
|
Diluted
|
Basic
|
Diluted
|
Basic
|
Diluted
|
Basic
|
Diluted
|
|||||||||||||||||||||||||
Numerator for earnings per share
|
||||||||||||||||||||||||||||||||
Net income attributable to controlling interest
|
$
|
715
|
$
|
715
|
$
|
806
|
$
|
806
|
$
|
1,392
|
$
|
1,392
|
$
|
1,748
|
$
|
1,748
|
||||||||||||||||
Undistributed earnings allocable to participating securities
|
(4
|
)
|
(5
|
)
|
(5
|
)
|
(5
|
)
|
(8
|
)
|
(8
|
)
|
(10
|
)
|
(10
|
)
|
||||||||||||||||
Net income available to shareholders
|
$
|
711
|
$
|
710
|
$
|
801
|
$
|
801
|
$
|
1,384
|
$
|
1,384
|
$
|
1,738
|
$
|
1,738
|
||||||||||||||||
Denominator for earnings per share
|
||||||||||||||||||||||||||||||||
Weighted-average shares outstanding
|
319
|
319
|
320
|
320
|
320
|
320
|
320
|
320
|
||||||||||||||||||||||||
Effect of stock options and other share-based awards
|
—
|
1
|
—
|
1
|
—
|
1
|
—
|
1
|
||||||||||||||||||||||||
Weighted-average shares for per share calculation
|
319
|
320
|
320
|
321
|
320
|
321
|
320
|
321
|
||||||||||||||||||||||||
Earnings per share
|
$
|
2.23
|
$
|
2.22
|
$
|
2.50
|
$
|
2.49
|
$
|
4.32
|
$
|
4.31
|
$
|
5.43
|
$
|
5.42
|
Six months
ended
June 30,
2010
|
Through
December 31,
2009
|
Total
costs
|
||||||||||
Discoverer Luanda (a)
|
$
|
160
|
$
|
535
|
$
|
695
|
||||||
Deepwater Champion (b)
|
56
|
527
|
583
|
|||||||||
Discoverer India
|
50
|
541
|
591
|
|||||||||
Dhirubhai Deepwater KG2 (c) (d)
|
33
|
641
|
674
|
|||||||||
Discover Inspiration (c)
|
7
|
667
|
674
|
|||||||||
Capitalized interest
|
47
|
183
|
230
|
|||||||||
Mobilization costs
|
36
|
19
|
55
|
|||||||||
Total
|
$
|
389
|
$
|
3,113
|
$
|
3,502
|
(a)
|
The costs for
Discoverer Luanda
represent 100 percent of expenditures incurred since inception. ADDCL is responsible for all of these costs. We hold a 65 percent interest in ADDCL, and Angco Cayman Limited holds the remaining 35 percent interest.
|
(b)
|
These costs include our initial investment in
Deepwater Champion
of $109 million, representing the estimated fair value of the rig at the time of our merger with GlobalSantaFe Corporation (“GlobalSantaFe”) in November 2007.
|
(c)
|
The accumulated construction costs of these rigs are no longer included in construction work in progress, as their construction projects had been completed as of June 30, 2010.
|
(d)
|
The cost for
Dhirubhai Deepwater KG2
represents 100 percent of TPDI’s expenditures, including those incurred prior to our investment in the joint venture. TPDI is responsible for all of these costs. We hold a 50 percent interest in TPDI, and Pacific Drilling Limited (“Pacific Drilling”) holds the remaining 50 percent interest.
|
June 30, 2010
|
December 31, 2009
|
||||||||||||||||||||||
Transocean Ltd.
and subsidiaries
|
Consolidated variable interest entities
|
Consolidated total
|
Transocean Ltd.
and subsidiaries
|
Consolidated variable interest entities
|
Consolidated total
|
||||||||||||||||||
ODL Loan Facility
|
$
|
10
|
$
|
—
|
$
|
10
|
$
|
10
|
$
|
—
|
$
|
10
|
|||||||||||
Commercial paper program (a)
|
104
|
—
|
104
|
281
|
—
|
281
|
|||||||||||||||||
6.625% Notes due April 2011 (a)
|
168
|
—
|
168
|
170
|
—
|
170
|
|||||||||||||||||
5% Notes due February 2013
|
254
|
—
|
254
|
247
|
—
|
247
|
|||||||||||||||||
5.25% Senior Notes due March 2013 (a)
|
509
|
—
|
509
|
496
|
—
|
496
|
|||||||||||||||||
TPDI Credit Facilities due March 2015
|
—
|
595
|
595
|
—
|
581
|
581
|
|||||||||||||||||
ADDCL Credit Facilities due August 2017
|
—
|
241
|
241
|
—
|
454
|
454
|
|||||||||||||||||
TPDI Notes due October 2019
|
—
|
148
|
148
|
—
|
148
|
148
|
|||||||||||||||||
6.00% Senior Notes due March 2018 (a)
|
997
|
—
|
997
|
997
|
—
|
997
|
|||||||||||||||||
7.375% Senior Notes due April 2018 (a)
|
247
|
—
|
247
|
247
|
—
|
247
|
|||||||||||||||||
Capital lease obligation due July 2026
|
—
|
—
|
—
|
15
|
—
|
15
|
|||||||||||||||||
8% Debentures due April 2027 (a)
|
57
|
—
|
57
|
57
|
—
|
57
|
|||||||||||||||||
7.45% Notes due April 2027 (a)
|
96
|
—
|
96
|
96
|
—
|
96
|
|||||||||||||||||
7% Senior Notes due June 2028
|
312
|
—
|
312
|
313
|
—
|
313
|
|||||||||||||||||
Capital lease contract due August 2029
|
703
|
—
|
703
|
711
|
—
|
711
|
|||||||||||||||||
7.5% Notes due April 2031 (a)
|
598
|
—
|
598
|
598
|
—
|
598
|
|||||||||||||||||
1.625% Series A Convertible Senior Notes due December 2037 (a)
|
1,281
|
—
|
1,281
|
1,261
|
—
|
1,261
|
|||||||||||||||||
1.50% Series B Convertible Senior Notes due December 2037 (a)
|
2,093
|
—
|
2,093
|
2,057
|
—
|
2,057
|
|||||||||||||||||
1.50% Series C Convertible Senior Notes due December 2037 (a)
|
2,014
|
—
|
2,014
|
1,979
|
—
|
1,979
|
|||||||||||||||||
6.80% Senior Notes due March 2038 (a)
|
999
|
—
|
999
|
999
|
—
|
999
|
|||||||||||||||||
Total debt
|
10,442
|
984
|
11,426
|
10,534
|
1,183
|
11,717
|
|||||||||||||||||
Less debt due within one year
|
|||||||||||||||||||||||
ODL Loan Facility
|
10
|
—
|
10
|
10
|
—
|
10
|
|||||||||||||||||
Commercial paper program (a)
|
104
|
—
|
104
|
281
|
—
|
281
|
|||||||||||||||||
6.625% Notes due April 2011 (a)
|
168
|
—
|
168
|
—
|
—
|
—
|
|||||||||||||||||
TPDI Credit Facilities due March 2015
|
—
|
70
|
70
|
—
|
52
|
52
|
|||||||||||||||||
ADDCL Credit Facilities due August 2017
|
—
|
12
|
12
|
—
|
248
|
248
|
|||||||||||||||||
Capital lease contract due August 2029
|
17
|
—
|
17
|
16
|
—
|
16
|
|||||||||||||||||
1.625% Series A Convertible Senior Notes due December 2037 (a)
|
1,281
|
—
|
1,281
|
1,261
|
—
|
1,261
|
|||||||||||||||||
Total debt due within one year
|
1,580
|
82
|
1,662
|
1,568
|
300
|
1,868
|
|||||||||||||||||
Total long-term debt
|
$
|
8,862
|
$
|
902
|
$
|
9,764
|
$
|
8,966
|
$
|
883
|
$
|
9,849
|
(a)
|
Transocean Inc., a wholly owned subsidiary of Transocean Ltd., is the issuer of the notes and debentures, which have been guaranteed by Transocean Ltd. Transocean Ltd. has also guaranteed borrowings under the commercial paper program and the Five-Year Revolving Credit Facility. Transocean Ltd. has no independent assets or operations, its guarantee of debt securities of Transocean Inc. is full and unconditional and its only other subsidiaries not owned indirectly through Transocean Inc. are minor. Transocean Ltd. is not subject to any significant restrictions on its ability to obtain funds from its consolidated subsidiaries or entities accounted for under the equity method by dividends, loans or return of capital distributions.
|
Transocean
Ltd.
and subsidiaries
|
Consolidated
variable
interest
entities
|
Consolidated
total
|
||||||||||
Twelve months ending June 30,
|
||||||||||||
2011
|
$
|
1,595
|
$
|
82
|
$
|
1,677
|
||||||
2012
|
2,218
|
96
|
2,314
|
|||||||||
2013
|
2,969
|
98
|
3,067
|
|||||||||
2014
|
21
|
99
|
120
|
|||||||||
2015
|
23
|
346
|
369
|
|||||||||
Thereafter
|
3,909
|
263
|
4,172
|
|||||||||
Total debt, excluding unamortized discounts, premiums and fair value adjustments
|
10,735
|
984
|
11,719
|
|||||||||
Total unamortized discounts, premiums and fair value adjustments
|
(293
|
)
|
—
|
(293
|
)
|
|||||||
Total debt
|
$
|
10,442
|
$
|
984
|
$
|
11,426
|
June 30, 2010
|
December 31, 2009
|
||||||||||||||||||||||
Principal amount
|
Unamortized discount
|
Carrying amount
|
Principal amount
|
Unamortized discount
|
Carrying amount
|
||||||||||||||||||
Carrying amount of liability component
|
|||||||||||||||||||||||
Series A Convertible Senior Notes due 2037
|
$
|
1,299
|
$
|
(18
|
)
|
$
|
1,281
|
$
|
1,299
|
$
|
(38
|
)
|
$
|
1,261
|
|||||||||
Series B Convertible Senior Notes due 2037
|
2,200
|
(107
|
)
|
2,093
|
2,200
|
(143
|
)
|
2,057
|
|||||||||||||||
Series C Convertible Senior Notes due 2037
|
2,200
|
(186
|
)
|
2,014
|
2,200
|
(221
|
)
|
1,979
|
June 30,
2010
|
December 31,
2009
|
||||||||
Carrying amount of equity component
|
|||||||||
Series A Convertible Senior Notes due 2037
|
$
|
215
|
$
|
215
|
|||||
Series B Convertible Senior Notes due 2037
|
275
|
275
|
|||||||
Series C Convertible Senior Notes due 2037
|
352
|
352
|
Three months ended
June 30,
|
Six months ended
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
Interest expense
|
||||||||||||||||
Series A Convertible Senior Notes due 2037
|
$
|
15
|
$
|
22
|
$
|
30
|
$
|
47
|
||||||||
Series B Convertible Senior Notes due 2037
|
26
|
25
|
52
|
50
|
||||||||||||
Series C Convertible Senior Notes due 2037
|
26
|
25
|
52
|
50
|
Three months ended June 30, 2010
|
Three months ended June 30, 2009
|
|||||||||||||||||||||||||||||||
U.S.
Plans
|
Non-U.S.
Plans
|
OPEB
Plans
|
Total
|
U.S.
Plans
|
Non-U.S.
Plans
|
OPEB
Plans
|
Total
|
|||||||||||||||||||||||||
Net periodic benefit costs
|
||||||||||||||||||||||||||||||||
Service cost
|
$
|
11
|
$
|
4
|
$
|
1
|
$
|
16
|
$
|
11
|
$
|
4
|
$
|
1
|
$
|
16
|
||||||||||||||||
Interest cost
|
14
|
5
|
—
|
19
|
13
|
4
|
—
|
17
|
||||||||||||||||||||||||
Expected return on plan assets
|
(15
|
)
|
(3
|
)
|
—
|
(18
|
)
|
(14
|
)
|
(4
|
)
|
—
|
(18
|
)
|
||||||||||||||||||
Settlements and curtailments
|
2
|
—
|
—
|
2
|
—
|
—
|
—
|
—
|
||||||||||||||||||||||||
Actuarial losses, net
|
3
|
1
|
—
|
4
|
5
|
—
|
—
|
5
|
||||||||||||||||||||||||
Prior service cost, net
|
(1
|
)
|
—
|
—
|
(1
|
)
|
(1
|
)
|
1
|
—
|
—
|
|||||||||||||||||||||
Net periodic benefit costs
|
$
|
14
|
$
|
7
|
$
|
1
|
$
|
22
|
$
|
14
|
$
|
5
|
$
|
1
|
$
|
20
|
||||||||||||||||
Funding contributions
|
$
|
49
|
$
|
4
|
$
|
1
|
$
|
54
|
$
|
45
|
$
|
—
|
$
|
1
|
$
|
46
|
Six months ended June 30, 2010
|
Six months ended June 30, 2009
|
|||||||||||||||||||||||||||||||
U.S.
Plans
|
Non-U.S.
Plans
|
OPEB
Plans
|
Total
|
U.S.
Plans
|
Non-U.S.
Plans
|
OPEB
Plans
|
Total
|
|||||||||||||||||||||||||
Net periodic benefit costs
|
||||||||||||||||||||||||||||||||
Service cost
|
$
|
21
|
$
|
10
|
$
|
1
|
$
|
32
|
$
|
22
|
$
|
8
|
$
|
1
|
$
|
31
|
||||||||||||||||
Interest cost
|
27
|
8
|
1
|
36
|
25
|
8
|
1
|
34
|
||||||||||||||||||||||||
Expected return on plan assets
|
(29
|
)
|
(8
|
)
|
—
|
(37
|
)
|
(27
|
)
|
(7
|
)
|
—
|
(34
|
)
|
||||||||||||||||||
Settlements and curtailments
|
2
|
1
|
—
|
3
|
2
|
—
|
—
|
2
|
||||||||||||||||||||||||
Actuarial losses, net
|
7
|
4
|
—
|
11
|
9
|
—
|
—
|
9
|
||||||||||||||||||||||||
Prior service cost, net
|
(1
|
)
|
—
|
(1
|
)
|
(2
|
)
|
(1
|
)
|
1
|
—
|
—
|
||||||||||||||||||||
Net periodic benefit costs
|
$
|
27
|
$
|
15
|
$
|
1
|
$
|
43
|
$
|
30
|
$
|
10
|
$
|
2
|
$
|
42
|
||||||||||||||||
Funding contributions
|
$
|
51
|
$
|
8
|
$
|
3
|
$
|
62
|
$
|
47
|
$
|
1
|
$
|
2
|
$
|
50
|
§
|
the actual responsibility attributed to us and the other PRPs at the site;
|
§
|
appropriate investigatory or remedial actions; and
|
§
|
allocation of the costs of such activities among the PRPs and other site users.
|
§
|
the volume and nature of material, if any, contributed to the site for which we are responsible;
|
§
|
the numbers of other PRPs and their financial viability; and
|
§
|
the remediation methods and technology to be used.
|
June 30, 2010
|
December 31, 2009
|
||||||||||||||
Carrying
amount
|
Fair
value
|
Carrying
amount
|
Fair
value
|
||||||||||||
Long-term debt, including current maturities
|
$
|
10,442
|
$
|
9,751
|
$
|
10,534
|
$
|
11,218
|
|||||||
Long-term debt of consolidated variable interest entities, including current maturities
|
984
|
997
|
1,183
|
1,178
|
Item 2.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
§
|
the impact of the Macondo well incident and related matters,
|
§
|
the offshore drilling market, including the impact of the drilling moratorium in the United States (“U.S.”) Gulf of Mexico, supply and demand, utilization rates, dayrates, customer drilling programs, commodity prices, stacking of rigs, reactivation of rigs, effects of new rigs on the market and effects of declines in commodity prices and the downturn in the global economy or market outlook for our various geographical operating sectors and classes of rigs,
|
§
|
customer contracts, including contract backlog, force majeure provisions, contract commencements, contract extensions, contract terminations, contract option exercises, contract revenues, contract awards and rig mobilizations,
|
§
|
newbuild, upgrade, shipyard and other capital projects, including completion, delivery and commencement of operation dates, expected downtime and lost revenue, the level of expected capital expenditures and the timing and cost of completion of capital projects,
|
§
|
liquidity and adequacy of cash flow for our obligations, including our ability and the expected timing to access certain investments in highly liquid instruments,
|
§
|
our results of operations and cash flow from operations, including revenues and expenses,
|
§
|
uses of excess cash, including the payment of dividends and other distributions, debt retirement and share repurchases under our share repurchase program,
|
§
|
the cost and timing of acquisitions and the proceeds and timing of dispositions,
|
§
|
tax matters, including our effective tax rate, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues, including those associated with our activities in Brazil, Norway and the U.S.,
|
§
|
legal and regulatory matters, including results and effects of legal proceedings and governmental audits and assessments, outcomes and effects of internal and governmental investigations, customs and environmental matters,
|
§
|
insurance matters, including adequacy of insurance, renewal of insurance, insurance proceeds and cash investments of our wholly owned captive insurance company,
|
§
|
debt levels, including impacts of the financial and economic downturn,
|
§
|
effects of accounting changes and adoption of accounting policies, and
|
§
|
investments in recruitment, retention and personnel development initiatives, pension plan and other postretirement benefit plan contributions, the timing of severance payments and benefit payments.
|
§
“anticipates”
|
§
“estimates”
|
§
“may”
|
§
“projects”
|
§
“believes”
|
§
“expects”
|
§
“might”
|
§
“scheduled”
|
§
“budgets”
|
§
“forecasts”
|
§
“plans”
|
§
“should”
|
§
“could”
|
§
“intends”
|
§
“predicts”
|
§
|
those described under “Item 1A. Risk Factors” included herein and in our annual report on Form 10-K for the year ended December 31, 2009,
|
§
|
the adequacy of and access to sources of liquidity,
|
§
|
our inability to obtain contracts for our rigs that do not have contracts,
|
§
|
the cancellation of contracts currently included in our reported contract backlog,
|
§
|
the effect and results of litigation, tax audits and contingencies, and
|
§
|
other factors discussed in this quarterly report and in our other filings with the U.S. Securities and Exchange Commission (“SEC”), which are available free of charge on the SEC website at
www.sec.gov
.
|
2010
|
2011
|
2012
|
2013
|
|||||||||
Uncommitted fleet rate
|
||||||||||||
High-Specification Floaters
|
8
|
%
|
20
|
%
|
36
|
%
|
48
|
%
|
||||
Midwater Floaters
|
30
|
%
|
60
|
%
|
80
|
%
|
95
|
%
|
||||
High-Specification Jackups
|
46
|
%
|
52
|
%
|
81
|
%
|
100
|
%
|
||||
Standard Jackups
|
52
|
%
|
72
|
%
|
87
|
%
|
95
|
%
|
Three months ended
June 30,
|
Six months ended
June 30,
|
||||||||||||||||||||||||||
2010
|
2009
|
Change
|
2010
|
2009
|
Change
|
||||||||||||||||||||||
Performance indicators
|
|||||||||||||||||||||||||||
Average daily revenue (a)(b)
|
$
|
284,200
|
$
|
255,900
|
$
|
28,300
|
$
|
291,300
|
$
|
256,200
|
$
|
35,100
|
|||||||||||||||
Utilization (b)(c)
|
64
|
%
|
84
|
%
|
n/a
|
65
|
%
|
87
|
%
|
n/a
|
|||||||||||||||||
Statement of operations data
|
|||||||||||||||||||||||||||
Operating revenues
|
$
|
2,505
|
$
|
2,882
|
$
|
(377
|
)
|
$
|
5,107
|
$
|
6,000
|
$
|
(893
|
)
|
|||||||||||||
Operating and maintenance expense
|
1,358
|
1,277
|
81
|
2,554
|
2,448
|
106
|
|||||||||||||||||||||
Operating income
|
957
|
1,121
|
(164
|
)
|
1,883
|
2,440
|
(557
|
)
|
|||||||||||||||||||
Net income attributable to controlling interest
|
715
|
806
|
(91
|
)
|
1,392
|
1,748
|
(356
|
)
|
June 30,
2010
|
December 31,
2009
|
Change
|
||||||||||||
Balance sheet data
|
||||||||||||||
Cash and cash equivalents
|
$
|
2,888
|
$
|
1,130
|
$
|
1,758
|
||||||||
Total assets
|
37,552
|
36,436
|
1,116
|
|||||||||||
Total debt
|
11,426
|
11,717
|
(291
|
)
|
|
“n/a” means not applicable.
|
(a)
|
Average daily revenue is defined as contract drilling revenue earned per revenue earning day. A revenue earning day is defined as a day for which a rig earns dayrate after commencement of operations. Stacking rigs, such as Midwater Floaters, High-Specification Jackups and Standard Jackups, has the effect of increasing the average daily revenue since these rig types are typically contracted at lower dayrates compared to the High-Specification Floaters. Average daily revenue includes our rigs that are operating on standby rates located in the U.S. Gulf of Mexico.
|
(b)
|
Calculation excludes results for
Joides Resolution
, a drillship engaged in scientific geological coring activities that is owned by an unconsolidated joint venture in which we have a 50 percent interest and for which we apply the equity method of accounting.
|
(c)
|
Utilization is the total actual number of revenue earning days as a percentage of the total number of calendar days in the period. Idle and stacked rigs are included in the calculation and reduce the utilization rate to the extent these rigs are not earning revenues. Newbuilds are included in the calculation upon acceptance by the customer.
|
July 15,
2010
|
March 31,
2010
|
June 30,
2009
|
||||||||||
Contract backlog
|
(in millions)
|
|||||||||||
High-Specification Floaters
|
$
|
22,969
|
$
|
24,293
|
$
|
27,022
|
||||||
Midwater Floaters
|
2,767
|
2,933
|
4,272
|
|||||||||
High-Specification Jackups
|
391
|
315
|
356
|
|||||||||
Standard Jackups
|
1,374
|
1,323
|
2,234
|
|||||||||
Other Rigs
|
62
|
72
|
91
|
|||||||||
Total
|
$
|
27,563
|
$
|
28,936
|
$
|
33,975
|
Three months ended
|
||||||||||||
June 30,
2010
|
March 31,
2010
|
June 30,
2009
|
||||||||||
Average daily revenue
|
||||||||||||
High-Specification Floaters
|
||||||||||||
Ultra-Deepwater Floaters
|
$
|
482,100
|
$
|
486,000
|
$
|
450,500
|
||||||
Deepwater Floaters
|
395,800
|
383,800
|
339,600
|
|||||||||
Harsh Environment Floaters
|
428,500
|
400,100
|
374,500
|
|||||||||
Total High-Specification Floaters
|
447,800
|
443,200
|
397,600
|
|||||||||
Midwater Floaters
|
319,000
|
331,600
|
302,700
|
|||||||||
High-Specification Jackups
|
146,100
|
166,000
|
161,400
|
|||||||||
Standard Jackups
|
117,100
|
133,100
|
149,200
|
|||||||||
Other Rigs
|
72,000
|
72,700
|
48,300
|
|||||||||
Total fleet average daily revenue
|
284,200
|
298,300
|
255,900
|
Three months ended
|
||||||||||||
June 30,
2010
|
March 31,
2010
|
June 30,
2009
|
||||||||||
Utilization
|
||||||||||||
High-Specification Floaters
|
||||||||||||
Ultra-Deepwater Floaters
|
76
|
%
|
88
|
%
|
91
|
%
|
||||||
Deepwater Floaters
|
66
|
%
|
71
|
%
|
82
|
%
|
||||||
Harsh Environment Floaters
|
85
|
%
|
98
|
%
|
93
|
%
|
||||||
Total High-Specification Floaters
|
74
|
%
|
83
|
%
|
88
|
%
|
||||||
Midwater Floaters
|
69
|
%
|
67
|
%
|
84
|
%
|
||||||
High-Specification Jackups
|
70
|
%
|
63
|
%
|
87
|
%
|
||||||
Standard Jackups
|
53
|
%
|
53
|
%
|
82
|
%
|
||||||
Other Rigs
|
50
|
%
|
50
|
%
|
59
|
%
|
||||||
Total fleet average utilization
|
64
|
%
|
66
|
%
|
84
|
%
|
Three months ended June 30,
|
|||||||||||||||||||
2010
|
2009
|
Change
|
% Change
|
||||||||||||||||
(In millions, except day amounts and percentages)
|
|||||||||||||||||||
Revenue earning days
|
8,057
|
10,261
|
(2,204
|
)
|
(21)
|
%
|
|||||||||||||
Utilization
|
64
|
%
|
84
|
%
|
n/a
|
n/m
|
|||||||||||||
Average daily revenue
|
$
|
284,200
|
$
|
255,900
|
$
|
28,300
|
11
|
%
|
|||||||||||
Contract drilling revenues
|
$
|
2,290
|
$
|
2,625
|
$
|
(335
|
)
|
(13)
|
%
|
||||||||||
Contract drilling intangible revenues
|
29
|
75
|
(46
|
)
|
(61)
|
%
|
|||||||||||||
Other revenues
|
186
|
182
|
4
|
2
|
%
|
||||||||||||||
2,505
|
2,882
|
(377
|
)
|
(13)
|
%
|
||||||||||||||
Operating and maintenance expense
|
1,358
|
1,277
|
81
|
6
|
%
|
||||||||||||||
Depreciation, depletion and amortization
|
400
|
360
|
40
|
11
|
%
|
||||||||||||||
General and administrative expense
|
58
|
53
|
5
|
9
|
%
|
||||||||||||||
1,816
|
1,690
|
126
|
7
|
%
|
|||||||||||||||
Loss on impairment
|
—
|
(67
|
)
|
67
|
n/m
|
||||||||||||||
Gain (loss) on disposal of assets, net
|
268
|
(4
|
)
|
272
|
n/m
|
||||||||||||||
Operating income
|
957
|
1,121
|
(164
|
)
|
(15)
|
%
|
|||||||||||||
Other income (expense), net
|
|||||||||||||||||||
Interest income
|
5
|
1
|
4
|
n/m
|
|||||||||||||||
Interest expense, net of amounts capitalized
|
(141
|
)
|
(114
|
)
|
(27
|
)
|
24
|
%
|
|||||||||||
Gain (loss) on retirement of debt
|
—
|
(8
|
)
|
8
|
n/m
|
||||||||||||||
Other, net
|
(3
|
)
|
(8
|
)
|
5
|
63
|
%
|
||||||||||||
Income before income taxes
|
818
|
992
|
(174
|
)
|
(18)
|
%
|
|||||||||||||
Income tax expense
|
98
|
184
|
(86
|
)
|
(47)
|
%
|
|||||||||||||
Net income
|
720
|
808
|
(88
|
)
|
(11)
|
%
|
|||||||||||||
Net income attributable to noncontrolling interest
|
5
|
2
|
3
|
n/m
|
|||||||||||||||
Net income attributable to controlling interest
|
$
|
715
|
$
|
806
|
$
|
(91
|
)
|
(11)
|
%
|
|
“n/a” means not applicable
|
|
“n/m” means not meaningful
|
Six months ended June 30,
|
|||||||||||||||||||
2010
|
2009
|
Change
|
% Change
|
||||||||||||||||
(In millions, except day amounts and percentages)
|
|||||||||||||||||||
Revenue earning days
|
16,241
|
21,311
|
(5,070
|
)
|
(24)
|
%
|
|||||||||||||
Utilization
|
65
|
%
|
87
|
%
|
n/a
|
n/m
|
|||||||||||||
Average daily revenue
|
$
|
291,300
|
$
|
256,200
|
$
|
35,100
|
14
|
%
|
|||||||||||
Contract drilling revenues
|
$
|
4,731
|
$
|
5,459
|
$
|
(728
|
)
|
(13)
|
%
|
||||||||||
Contract drilling intangible revenues
|
62
|
179
|
(117
|
)
|
(65)
|
%
|
|||||||||||||
Other revenues
|
314
|
362
|
(48
|
)
|
(13)
|
%
|
|||||||||||||
5,107
|
6,000
|
(893
|
)
|
(15)
|
%
|
||||||||||||||
Operating and maintenance expense
|
2,554
|
2,448
|
106
|
4
|
%
|
||||||||||||||
Depreciation, depletion and amortization
|
801
|
715
|
86
|
12
|
%
|
||||||||||||||
General and administrative expense
|
121
|
109
|
12
|
11
|
%
|
||||||||||||||
3,476
|
1,690
|
126
|
6
|
%
|
|||||||||||||||
Loss on impairment
|
(2
|
(288
|
)
|
286
|
(99)
|
||||||||||||||
Gain on disposal of assets, net
|
254
|
—
|
254
|
n/m
|
|||||||||||||||
Operating income
|
1,883
|
2,440
|
(557
|
)
|
(23)
|
%
|
|||||||||||||
Other income (expense), net
|
|||||||||||||||||||
Interest income
|
10
|
2
|
8
|
n/m
|
|||||||||||||||
Interest expense, net of amounts capitalized
|
(273
|
)
|
(250
|
)
|
(23
|
)
|
9
|
%
|
|||||||||||
Gain (loss) on retirement of debt
|
2
|
(10
|
)
|
12
|
n/m
|
||||||||||||||
Other, net
|
10
|
—
|
10
|
n/m
|
%
|
||||||||||||||
Income before income taxes
|
1,632
|
2,182
|
(550
|
)
|
(25)
|
%
|
|||||||||||||
Income tax expense
|
227
|
435
|
(208
|
)
|
(48)
|
%
|
|||||||||||||
Net income
|
1,405
|
1,747
|
(342
|
)
|
(20)
|
%
|
|||||||||||||
Net income (loss) attributable to noncontrolling interest
|
13
|
(1
|
)
|
14
|
n/m
|
||||||||||||||
Net income attributable to controlling interest
|
$
|
1,392
|
$
|
1,748
|
$
|
(356
|
)
|
(20)
|
%
|
|
“n/a” means not applicable
|
|
“n/m” means not meaningful
|
Six months ended June 30,
|
||||||||||||||
2010
|
2009
|
Change
|
||||||||||||
Cash flows from operating activities
|
(In millions)
|
|||||||||||||
Net income
|
$
|
1,405
|
$
|
1,747
|
$
|
(342
|
)
|
|||||||
Amortization of drilling contract intangibles
|
(62
|
)
|
(179
|
)
|
117
|
|||||||||
Depreciation, depletion and amortization
|
801
|
715
|
86
|
|||||||||||
Loss on impairment
|
2
|
288
|
(286
|
)
|
||||||||||
Gain on disposal of assets, net
|
(254
|
)
|
—
|
(254
|
)
|
|||||||||
Other non-cash items
|
236
|
218
|
18
|
|||||||||||
Changes in operating assets and liabilities
|
313
|
228
|
85
|
|||||||||||
$
|
2,441
|
$
|
3,017
|
$
|
(576
|
)
|
Six months ended June 30,
|
||||||||||||||
2010
|
2009
|
Change
|
||||||||||||
Cash flows from investing activities
|
(In millions)
|
|||||||||||||
Capital expenditures
|
$
|
(679
|
)
|
$
|
(1,655
|
)
|
$
|
976
|
||||||
Proceeds from disposal of assets, net
|
51
|
8
|
43
|
|||||||||||
Proceeds from insurance recoveries for loss of drilling unit
|
560
|
—
|
560
|
|||||||||||
Proceeds from payments on notes receivable
|
21
|
—
|
21
|
|||||||||||
Proceeds from short-term investments
|
5
|
393
|
(388
|
)
|
||||||||||
Purchases of short-term investments
|
—
|
(234
|
)
|
234
|
||||||||||
Joint ventures and other investments, net
|
(1)
|
—
|
(1
|
)
|
||||||||||
$
|
(43
|
)
|
$
|
(1,488
|
)
|
$
|
1,445
|
Six months ended June 30,
|
||||||||||||||
2010
|
2009
|
Change
|
||||||||||||
Cash flows from financing activities
|
(In millions)
|
|||||||||||||
Change in short-term borrowings, net
|
$
|
(177
|
)
|
$
|
(500
|
)
|
$
|
323
|
||||||
Proceeds from debt
|
54
|
319
|
(265
|
)
|
||||||||||
Repayments of debt
|
(275
|
)
|
(1,410
|
)
|
1,135
|
|||||||||
Payments for warrant exercise, net
|
—
|
(13
|
)
|
13
|
||||||||||
Purchases of shares held in treasury
|
(240
|
)
|
—
|
(240
|
)
|
|||||||||
Proceeds from (taxes paid for) share-based compensation plans, net
|
(1
|
)
|
22
|
(23
|
)
|
|||||||||
Excess tax benefit from share-based compensation plans
|
1
|
1
|
—
|
|||||||||||
Other, net
|
(2
|
)
|
(4
|
)
|
2
|
|||||||||
$
|
(640
|
)
|
$
|
(1,585
|
)
|
$
|
945
|
Total costs through
June 30,
2010
|
Expected costs for the remainder of 2010
|
Estimated
costs
thereafter
|
Total estimated
cost at
completion
|
|||||||||||||
Discoverer Luanda (a)
|
$
|
695
|
$
|
10
|
$
|
—
|
$
|
705
|
||||||||
Discoverer Inspiration (b)
|
674
|
4
|
—
|
678
|
||||||||||||
Dhirubhai Deepwater KG2 (b) (c)
|
674
|
5
|
—
|
679
|
||||||||||||
Discoverer India
|
591
|
139
|
—
|
730
|
||||||||||||
Deepwater Champion (d)
|
583
|
167
|
5
|
755
|
||||||||||||
Capitalized interest
|
230
|
37
|
16
|
283
|
||||||||||||
Mobilization costs
|
55
|
56
|
3
|
114
|
||||||||||||
Total
|
$
|
3,502
|
$
|
418
|
$
|
24
|
$
|
3,944
|
(a)
|
The costs for
Discoverer Luanda
represent 100 percent of expenditures incurred since inception. Angola Deepwater Drilling Company Limited (“ADDCL”) is responsible for all of these costs. We hold a 65 percent interest in ADDCL, and Angco Cayman Limited holds the remaining 35 percent interest.
|
(b)
|
The accumulated construction costs of these rigs are no longer included in construction work in progress, as their construction projects had been completed as of June 30, 2010.
|
(c)
|
The cost for
Dhirubhai Deepwater KG2
represents 100 percent of TPDI’s expenditures, including those incurred prior to our investment in the joint venture. TPDI is responsible for all of these costs. We hold a 50 percent interest in Transocean Pacific Drilling Inc. (“TPDI”), and Pacific Drilling holds the remaining 50 percent interest.
|
(d)
|
These costs include our initial investment in
Deepwater Champion
of $109 million, representing the estimated fair value of the rig at the time of our merger with GlobalSantaFe in November 2007.
|
Scheduled Maturity Date (a)
|
Fair Value
|
|||||||||||||||
2011
|
2012
|
2013
|
2014
|
2015
|
Thereafter
|
Total
|
6/30/10
|
|||||||||
Total debt
|
||||||||||||||||
Fixed rate
|
$1,561
|
$ 2,288
|
$ 2,289
|
$ 91
|
$ 320
|
$ 3,909
|
$ 10,458
|
$9,547
|
||||||||
Average interest rate
|
2.2%
|
1.6%
|
1.2%
|
3.6%
|
2.7%
|
6.9%
|
3.5%
|
|||||||||
Variable rate
|
$ 116
|
$ 26
|
$ 778
|
$ 29
|
$ 49
|
$ 263
|
$1,261
|
$1,201
|
||||||||
Average interest rate
|
1.0%
|
1.4%
|
3.4%
|
1.4%
|
1.8%
|
2.0%
|
2.5%
|
(a)
|
Expected maturity amounts are based on the face value of debt.
|
|
In preparing the scheduled maturities of our debt, we assume the noteholders will exercise their options to require us to repurchase the 1.625% Series A Convertible Senior Notes, 1.50% Series B Convertible Senior Notes and 1.50% Series C Convertible Senior Notes in December 2010, 2011 and 2012, respectively.
|
|
We have engaged in certain hedging activities designed to reduce our exposure to interest rate risk, and the effect of our derivative instruments is included in the table above (see Notes to Condensed Consolidated Financial Statements—Note 10—Derivatives and Hedging).
|
PART II.
|
OTHER INFORMATION
|
Period
|
(a) Total Number of Shares Purchased (1)
|
(b) Average
Price Paid
Per Share
|
(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)
|
(d) Maximum Number
(or Approximate Dollar Value)
of Shares that May Yet Be Purchased Under the Plans or Programs (2)
(in millions)
|
||||||||
April 2010
|
1,369,233
|
$
|
87.60
|
1,369,000
|
$
|
3,020
|
||||||
May 2010
|
778,198
|
$
|
77.08
|
777,267
|
$
|
2,960
|
||||||
June 2010
|
173
|
$
|
47.70
|
—
|
$
|
2,960
|
||||||
Total
|
2,147,604
|
$
|
83.78
|
2,146,267
|
$
|
2,960
|
(1)
|
Total number of shares purchased in the second quarter of 2010 includes 1,337 shares withheld by us in satisfaction of withholding taxes due upon the vesting of restricted shares granted to our employees under our Long-Term Incentive Plan and 2,146,267 shares repurchased under the share repurchase program described in (2) below.
|
(2)
|
In May 2009, at the annual general meeting of Transocean Ltd., our shareholders approved and authorized our board of directors, at its discretion, to repurchase an amount of our shares for cancellation with an aggregate purchase price of up to CHF 3.5 billion (which is equivalent to approximately U.S. $3.2 billion at an exchange rate as of the close of trading on June 30, 2010 of USD 1.00 to CHF 1.08). On February 12, 2010, our board of directors authorized our management to implement the share repurchase program. We may decide, based upon our ongoing capital requirements, the price of our shares, matters relating to the Macondo well
incident, regulatory and tax considerations, cash flow generation, the relationship between our contract backlog and our debt, general market conditions and other factors, that we should retain cash, reduce debt, make capital investments or otherwise use cash for general corporate purposes, and consequently, repurchase fewer or no shares under this program. Decisions regarding the amount, if any, and timing of any share repurchases would be made from time to time based upon these factors. Through June 30, 2010, we have repurchased a total of 2,863,267 of our shares under this share repurchase program at a total cost of $240 million ($83.74 per share). We have agreed not to repurchase any additional shares under our share repurchase program without 30 days notice to the DOJ. See “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Sources and Uses of Liquidity—Overview.”
|
Number
|
Description
|
|
†
|
3.1
|
Articles of Association of Transocean Ltd.
|
|
† *
|
10.1
|
Drilling Contract between Vastar Resources, Inc. and R&B Falcon Drilling Co. dated December 9, 1998 with respect to the
Deepwater Horizon,
as amended
|
|
†
|
31.1
|
CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
†
|
31.2
|
CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
†
|
32.1
|
CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
†
|
32.2
|
CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
†
|
101.
ins
|
XBRL Instance Document
|
|
†
|
101.
sch
|
XBRL Taxonomy Extension Schema
|
|
†
|
101.
cal
|
XBRL Taxonomy Extension Calculation Linkbase
|
|
†
|
101.
def
|
XBRL Taxonomy Extension Definition Linkbase
|
|
†
|
101.
lab
|
XBRL Taxonomy Extension Label Linkbase
|
|
†
|
101.
pre
|
XBRL Taxonomy Extension Presentation Linkbase
|
|
†
|
Filed herewith.
|
|
*
|
Compensatory plan or arrangement.
|
Zug,
14. Mai 2010
|
Zug,
May 14, 2010
|
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
|
CONTRACT NO. 980249
|
DATE: DECEMBER 9, 1998
|
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
|
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
|
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
|
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)
|
|||||
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
|
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.
|
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.
|
Metric Units
|
U.S. Units
|
|||
Pipe Racks
|
871 m
2
|
9,376 ft
2
|
||
Riser (90’ joints)
|
3,048.5 m
|
10,000 ft
|
||
Total Open Deck
|
2,005 m
2
|
21,578 ft
2
|
||
Bulk Cement
|
232 m
3
|
8,205 ft
3
|
||
Bulk Barite
|
387 m
3
|
13,675 ft
3
|
||
Cement Day Tank
|
62 m
3
|
2,200 ft
3
|
||
Barite Day Tank
|
68 m
3
|
2,400 ft
3
|
||
Total Bulk Storage
|
750 m
3
|
26,480 ft
3
|
||
Sack Storage
|
10,000 Sx
|
10,000 Sx
|
||
Drilling Mud Deck
|
750 m
3
|
4,434 bbl.
|
||
Drilling Mud (Column)
|
908 m
3
|
5,710 bbl.
|
||
Base Oil
|
480 m
3
|
3,019 bbl
|
||
Column Brine Storage
|
480 m
3
|
3,019 bbl.
|
||
Pontoon Brine Storage *)
|
3,975 m
3
|
25,000 bbl.
|
||
DW-Col.
|
1,736 m
3
|
10,918 bbl.
|
||
DW-pontoons
|
1424 m
3
|
8,956 bbl.
|
||
Fuel Oil
|
3,468 m
3
|
21,811 bbl
|
||
Potable Water
|
644 m
3
|
4,050 bbl
|
||
Helicopter Fuel
|
TBD
|
TBD
|
||
Refrigeration Storage
|
45 m
2
|
484 ft.
2
|
||
Dry Storage
|
60 m
2
|
646 ft.
2
|
||
SWB — pontoons *)
|
16,308 m
3
|
102,565 bbl
|
||
Quarters
|
130 Persons
|
130 Persons
|
||
Heliport
|
S-61, Super Puma
|
S-61, Super Puma
|
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)
|
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
|
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
|
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
|
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
|
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
|
SECTION M - POLLUTION PREVENTION EQUIPMENT
|
|
Ml
|
Sewage Treatment
|
M2
|
Garbage Compaction
|
M3
|
Garbage Disposal/Grinder
|
SECTION N - THIRD PARTY EQUIPMENT (SPACE PROVIDED)
|
Test load
|
:
|
||
Control locations (local/remote/both)
|
:
|
||
Emergency release (type/location)
|
:
|
||
A.7.2
FAIRLEADS
|
Foundations to be installed in shipyard
|
||
Quantity
|
no:
|
||
Make
|
:
|
||
Free rotating range
|
degrees:
|
||
A.7.3
ANCHORS
|
Company Supplied
|
||
A.7.3.1
ANCHORS - Primary
|
Company Supplied
|
||
A.7.3.2
ANCHORS - Spare
|
Company Supplied
|
||
A.7.4
ANCHOR LINES
|
Company Supplied to be installed at later date
|
||
A.7.5
ANCHOR LINE RUNNING / RETRIE’
|
N/A
|
||
A.7.5.1
PENNANT LINES
|
N/A
|
||
A.7.5.2
ANCHOR BUOYS
|
N/A
|
||
A.7.5.3
CHASER
|
N/A
|
||
A.7.6
TOWING 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.7.7
SUPPLY VESSEL MOORING LINES
|
:
|
||
Quantity
|
no.:
|
4
|
|
System
|
mt:
|
TO BE EVALUATED BY TEAM
|
|
Rating
|
lt:
|
TBA
|
|
A.8
MARINE LOADING HOSES
|
|||
Location of loading manifolds (port/stbd
|
:
|
BOTH
|
|
A.8.1
POTABLE WATER HOSE
|
|||
Quantity
|
no.:
|
2 x 150’
|
|
Size
|
inch:
|
3
|
|
Make/Type
|
:
|
TBA
|
|
Color coding
|
yes/no:
|
YES
|
|
Make/Type/Connection
|
TBA
|
||
A.8.2
DRILLING WATER HOSE
|
|||
Quantity
|
no.:
|
2 x 150’
|
|
Size
|
inch:
|
4
|
|
Make/Type
|
:
|
TBA
|
|
Color coding
|
yes/no:
|
YES
|
|
Make/Type connection
|
:
|
TBA
|
|
A.8.3
GAS OIL HOSE
|
|||
Quantity
|
no.:
|
2 x 150’
|
|
Size
|
inch:
|
4
|
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
|
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. 9.2
CRANES, 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. 9.3
FORKLIFTS
|
|||||
Quantity
|
no.:
|
1
|
|||
Make/Type
|
:
|
TBA
|
|||
Rated capacity
|
lt:
|
TBA
|
|||
Explosion proof
|
yes/no:
|
YES
|
|||
A. 9.4
MONORAIL OVERHEAD CRANES
|
|||||
Quantity
|
no.:
|
1
|
|||
Make
|
:
|
MARITIME HYDRAULICS
|
|||
Type
|
:
|
GANTRY TYPE
|
|||
Rated capacity
|
mt
|
36
|
|||
Location
|
:
|
AFT RISER DECK
|
|||
A. 9.5
BOP 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
|
A. 9.6
AIR HOISTS/DERRICK WINCHES
|
|||
A. 9.6.1
RIG 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. 9.6.2
MONKEY 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. 9.6.3
RIG 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. 9.6.4
UTILITY WINCH (i.e. Deck Winch)
|
N/A
|
||
A. 9.6.5
CELLAR 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.10
HELICOPTER 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
|
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
|
D.1.3
DRILL 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.1.4
DRILL PIPE PUP JOINTS ( Integral)
|
||||
O.D
|
5.5”
|
|||
Grade/Yield
|
:
|
4145 H Equiv. To 120K
|
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.1.7
DRILL 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.1.8
SHORT DRILL COLLARS
|
Company Supplied
|
|||
D.1.9
NON-MAGNETIC DRILL COLLARS
|
Company Supplied
|
|||
D.1.10
CORE BARRELS
|
Company Supplied
|
D.1.11
STABILIZERS
|
Company Supplied
|
|||
D.1.12
ROLLER REAMERS
|
Company Supplied
|
|||
D.1.13
SHOCK ABSORBERS (Damping Sub)
|
Company Supplied
|
|||
D.1.14
DRILLING JARS
|
Company Supplied
|
|||
D.1.15
INSIDE 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.1.16
FULL 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.1.17
CIRCULATION HEAD
|
N/A
|
|||
D.1.18
TOP 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.1.19
CIRCULATION SUBS
|
Company Supplied
|
|||
D.1.20
CUP TYPE TESTERS
|
Company Supplied
|
|||
D.1.21
PLUG TYPE TESTERS
|
Company Supplied
|
|||
D.1.22
DROP-IN VALVES
|
Company Supplied
|
D.1.23
NEAR-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.1.24
CROSSOVER 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
|
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
|
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
|
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
|
||
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
|
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.3.6
SAFETY 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.2
PRIMARY 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
|
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)
|
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
|
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
|
Remote panel
|
|||
Make
|
: CAMERON
|
||
Model
|
: MULTIPLEX
|
||
Location
|
: CONTROL ROOM
|
||
Locking/unclocking control
|
yes/no
|
: YES
|
|
E.9
SUBSEA SUPPORT SYSTEM
|
|||
E.9.1
RISER 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.9.2
GUIDELINE SYSTEM
|
N/A
|
||
E.9.3 REMOTE GUIDELINE REPL. TOOL
|
N/A
|
||
E.9.4
REMOTE GUIDELINE CUTTING TOOL
|
N/A
|
||
E.9.5
POD LINE TENSIONERS
|
TURN DOWN SHEAVE’S COMPLETE WITH STORM LOOP WITHIN MOONPOOL INCLUDED WITHIN DESIGN LAYOUT
|
||
E.9.6
TENSIONER/COMPENSATOR AIR PRESSURE VESSELS
|
|||
Quantity
|
no.:
|
30
|
|
Total capacity
|
ft3:
|
2747
|
|
Rated working pressure
|
psi:
|
3000
|
|
Pressure relief valve installed
|
yes/no:
|
YES
|
|
E.10
BOP 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.10.1
SURFACE 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
|
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.10.2
ACCUMULATOR 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.10.3
DRILLER’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
|
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
|
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
|
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
|
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
|
Categories:
|
I. Furnished by CONTRACTOR, paid by CONTRACTOR.
|
II. Furnished by COMPANY, paid by COMPANY.
|
|
III. Furnished by CONTRACTOR, paid by COMPANY.
|
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.
|
1.19
|
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
|
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.
|
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”.
|
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.
|
Name:
|
Ron Tafery
|
|
Title:
|
Vice President
|
|
Signature:
|
/s/ Ron Tafery
|
|
Date:
|
December 9, 1998
|
(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.
|
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
|
||||
2
nd
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.
|
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
|
||||||
2
nd
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
|
·
|
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
|
·
|
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
|
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
|
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
|
Sincerely yours,
|
|
R&B Falcon Drilling Co.
|
|
/s/ W.L. Ellis
|
|
W.L. Ellis
|
|
Regional Operations Manager
|
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)
|
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)
|
Exchange Rate: US $1.00 =1 U.S. $
|
[15EXTRAV]
|
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)
|
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
|
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)
|
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)
|
|
Data Home Pag
e
|
|
BLS Home Page
|
|
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
|
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
|
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
|
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
|
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
|
/s/ Mike Roth
|
|
Mike Roth
|
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
|
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
|
|
|
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.
|
|
|
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
|
Sincerely,
|
|
/s/ Terry Bonno
|
|
Terry Bonno
|
|
Sr. Marketing Representative
|
|
On Behalf of R & B Falcon Drilling Co.
|
SIGNED
|
/s/ R. Kevin Guerre
|
|
PRINTED
|
R. Kevin Guerre
|
|
TITLE
|
TL - SCM
|
Drill Crew
|
Total
|
On Board
|
|||
Drilling Rig Supt
/OIM
|
2
|
1
|
|||
Toolpusher
|
4
|
2
|
|||
Driller
|
4
|
2
|
|||
Asst. Driller
|
8
|
4
|
|||
Pump
hand
|
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
|
|||
2
nd
Asst.
Engineer
|
4
|
2
|
|||
Motor
hand
|
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
|
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
|
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
·
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·
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·
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·
Glossary
·
What’s New
|
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)
|
Security Statement
·
Accessibility Information
|
Search: GO
|
|
Advanced Search
|
Bureau of Labor Statistics
|
Phone: (202) 691-5200
|
|
Square Building
|
Fax-on-demand: (202) 691-6325
|
|
2 Massachusetts Ave., NE
|
Data questions:
blsdata_staff@bls.gov
|
|
Washington, DC 20212-0001
|
Technical (web) questions:
webmaster@bls.gov
|
|
Other comments:
feedback@bls.gov
|
|
Memo
|
|||||
To:
|
Terry Bonno
|
Date:
|
December 6, 2001
|
|||
From:
|
James Mitchell, Director of Risk Management
|
|||||
Subject:
|
Estimated Annual Premium – Deepwater Horizon
|
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
|
%
|
R & B FALCON DRILLNG CO.
|
||
1311 BROADFIELD BLVD., SUITE 400
HOUSTON, TEXAS 77084
|
||
JOHN KEETON
RIG MANAGER
|
|
Reference:
Deepwater Horizon Letter Agreement
—
Additional Personnel for Mad Dog Project CONTRACTOR-5121-2002-005
|
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
|
Sincerely,
|
|
/s/ John Keeton
|
|
John Keeton
|
|
R & B Falcon Drilling Co.
|
SIGNED
|
/s/ Allen Cook
|
|
PRINTED
|
Allen Cook
|
|
TITLE
|
MD Well Delivery TL
|
R & B FALCON DRILLNG CO.
|
||
1311 BROADFIELD BLVD., SUITE 400
HOUSTON, TEXAS 77084
|
||
TERRY BONNO
|
||
SR. MARKETING REPRESENTATIVE
|
|
Attn:
Mr. Jon Sprague
|
|
Mr. Charles Taylor
|
|
Reference:
Deepwater Horizon Letter Agreement — Additional Personnel for Deepwater Horizon CONTRACTOR-5121-2002-006
|
|
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
|
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
|
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
|
Sincerely,
|
|
/s/ Terry Bonno
|
|
Terry Bonno
|
|
R & B Falcon Drilling Co.
|
SIGNED
|
/s/ R Kevin Guerre
|
|
PRINTED
|
R Kevin Guerre
|
|
TITLE
|
TL-SCM
|
|
R & B FALCON DRILLNG CO.
1311 BROADFIELD BLVD., SUITE 400
HOUSTON, TEXAS 77084
|
Reference:
|
Deepwater Horizon Letter Agreement
–
Cameron Variable Bore Rams Deepwater Horizon
|
|
CONTRACTOR-5121-2002-007
|
|
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
|
Sincerely,
|
|
/s/ Terry Bonno
|
|
Terry Bonno
|
|
R & B Falcon Drilling Co.
|
SIGNED
|
/s/ Jerry R Rhoads
|
|
PRINTED
|
Jerry R Rhoads
|
|
TITLE
|
Contracts Specialist
|
|
R & B FALCON DRILLNG CO.
1311 BROADFIELD BLVD., SUITE 400
HOUSTON, TEXAS 77084
|
Reference:
|
Deepwater Horizon Letter Agreement -
|
|
CONTRACTOR-5121-2002-010
|
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
|
SIGNED
|
/s/ Jerry R Rhoads
|
|
PRINTED
|
Jerry R Rhoads
|
|
TITLE
|
Contracts Specialist
|
|
R&B FALCON DRILLING COMPANY
1311 BROADFIELD, SUITE 400
HOUSTON, TX 77084
|
|
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
|
|
|
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
|
|||||
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
|
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.
|
|
1.0
Effective 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.
|
|
2.0
RBFDC agrees to notify and provide reasonably requested documentation to the other party to the Drilling Contract to effect the assignment.
|
|
3.0
Written 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.
|
|
|
|
4.0
Any 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.
|
|
5.0
This Agreement is to be governed by and construed in accordance with the governing law provisions of the Drilling Contract.
|
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
|
|
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
|
|
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
|
|
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.
|
/s/ Christopher S. Young
|
|
Christopher S. Young
|
|
Sr. Marketing Representative
|
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
|
Approved By:
|
Date:
|
|
1.0
Scope
.
|
|
1.1
This 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.
|
|
|
|
1.2
This 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.
|
|
2.0
Referenced Documents
.
|
|
2.1
The following documents are used as references for establishing this procedure.
|
|
2.1.1
NACE TM-01-70
|
|
|
|
2.1.2
NACE TM-03-89
|
|
|
|
2.1.3
BP GoM OCTG Inspection Procedures and Requirements.
|
|
|
|
2.1.4
The Coating Contractor’s Standard Operating Procedures manual for the application and inspection of internal coatings.
|
|
|
|
3.0
Contractors Internal Coating Operating Procedures And Equipment Capabilities
.
|
|
3.1
The 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.
|
|
4.0
Requirements For Material And Equipment
.
|
|
4.1
All 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.
|
|
5.0
Preparation
.
|
|
|
|
5.1
Thread protectors shall be removed cleaned and stored until they are re-applied after final inspection.
|
|
|
|
5.2
All threaded connections shall be cleaned with steam cleaners, soapy water, varsol or other mineral spirits.
|
|
|
|
5.3
The 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).
|
|
|
|
5.4
The 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.
|
|
|
|
5.5
In 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).
|
|
|
|
5.6
After 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.
|
|
|
|
|
|
5.7
The abrasive blasting operation will be repeated until the proper “white metal” surface condition is achieved.
|
|
|
|
5.8
The Material must be dry before abrasive blasting begins.
|
|
|
|
5.9
The 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.
|
|
|
|
5.10
The 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.
|
|
|
|
5.11
Prior to abrasive blasting, the material shall have protector masks installed to protect threads, seal areas and shoulders from damage.
|
|
|
|
5.12
After 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.
|
|
|
|
5.13
The 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.
|
|
5.14
After 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.
|
|
6.0
Internal Plastic Coating Application
.
|
|
6.1
Application of the coating material, as designated by BP, will be performed so that the required film thickness and coating properties are attained.
|
|
|
|
6.2
Coating, 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.
|
|
|
|
6.3
Individual 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.
|
|
|
|
6.4
Prior to coating, the material shall be properly masked to protect the threads, seal areas and shoulders from coating overspray or damage.
|
|
|
|
6.5
When 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.
|
|
|
|
6.6
Different coating batches will not be mixed on individual lengths of material.
|
|
|
|
6.7
The 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.
|
|
|
|
6.8
The 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.
|
|
|
|
6.9
The 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.
|
|
|
|
6.10
Coating 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.
|
|
6.11
Coating 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).
|
|
6.12
Minor 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.
|
|
6.13
The Contractor will conduct a sufficient number of visual and film thickness checks on the material in order to assure conformity to final product specifications.
|
|
7.0
Final Inspection
.
|
|
7.1
After 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.
|
|
7.2
The 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.
|
|
7.3
The 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.
|
|
7.4
The 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.
|
|
7.5
Coatings on the face of the pipe ends are exempted from the standard minimum coating thickness requirements.
|
|
8.0
Holiday Testing
.
|
|
8.1
Holiday 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.
|
|
|
|
9.0
Full Length Drifting
.
|
|
9.1
After 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.
|
|
10.0
Visual Thread Inspection
.
|
|
10.1
After 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.
|
|
11.1
Marking and Stenciling
.
|
|
11.1
The 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.
|
|
12.1
Documentation, Records And Reporting
.
|
|
12.1
At 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.
|
|
12.2
Documentation, records and reporting requirements as listed in BP-DEIP-P005 shall apply.
|
|
13.0
Health, Safety And Environmental
.
|
|
13.1
Health, safety and environmental requirements as listed in BP-DEIP-P001 shall apply.
|
|
14.0
Visual Inspection Of Used Internal Plastic Coatings
.
|
HARDBANDING OF DRILL PIPE TOOLJOINTS,
|
Procedure: BP-DEIP-P002
|
Revision: 0
|
||
HEAVYWEIGHT DRILL PIPE AND DRILL COLLARS
|
Date: 7/2/902
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Approved By:
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Date:
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1.0
Scope
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1.1
This 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.
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1.2
The application of proud wear resistant alloy hardfacing bands onto tooljoints, heavyweight drill pipe and drill collars significantly reduces external wear and casing wear.
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2.0
Referenced Documents
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2.1
The following documents were used as reference for establishing this procedure.
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2.1.1
Part 1 BP Drill-string Hardbanding Specification for General Release (4/6/2000).
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2.1.2
ISO 9002 Quality Systems – Model for quality assurance in production and installation.
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2.1.3
ISO 9003 Quality Systems – Model for quality assurance in final inspection and test.
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2.1.4
API Q1 – Specification for Quality Programs.
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2.1.5
ASME IX – ASME Boiler and Pressure Vessel Code. Welding and Brazing Qualifications.
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2.1.6
ASTM E 709 – Standard Guide for Magnetic Particle Examination.
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2.1.7
ASTM E 165 – Standard Test Method for Liquid Penetrant Examination.
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2.1.8
API Specification 7 - Rotary Drill Stem Elements.
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2.1.9
API Recommended Practice 7G - Drill Stem Design and Operating Limits.
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3.0
Quality Assurance
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3.1
The 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.
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3.2
The 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.
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3.3
The effectiveness of the Applicator’s Quality System will be subject to monitoring by BP and may be audited following and agreed period of notice.
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4.0
Hardbandinq Types
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4.1
There 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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4.2
Wear 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.
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4.3
Tungsten 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.
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5.0
Welding Issues
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5.1
Welding 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.
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5.2
Preheat 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.
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5.3
Post Weld Thermal Regime.
Immediately on completion of welding, the component shall be subjected to one of the following alternative thermal regimes:
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5.3.1
The 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.
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5.3.2
The 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.
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5.4
Welding 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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5.5
Welding 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.
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·
The application of flush and proud hardbanding. A separate WPS is required for each type of hard metal consumable.
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The application of mild steel.
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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.
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5.6
Welding 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.
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5.7
Manufacturing 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.
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5.8
Welder/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.
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5.9
Production 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.
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6.0
Hardbandinq Configurations
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6.1
Definitions.
When applying new hardbanding and for the purposes of this procedure the following definitions shall apply.
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“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.
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“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.
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6.2
Drill Pipe Tooljoints.
Hardbanding (Wear Resistant Alloy Overlay) shall be applied in the following locations:
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A three (3”) inch wide band on the box tooljoint OD next to the taper. These bands shall be applied proud.
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One
3
/
4
” wide band on the box tooljoint 18° taper. This band shall be applied flush.
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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.
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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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6.3
Heavy Weight Drill Pipe.
Hardbanding (Wear Resistant Alloy Overlay) shall be applied in the following locations:
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One 4” inch wide band on the box and pin tooljoint OD next to the taper. These bands shall be applied proud.
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One 1” wide band on the tapered section of the box tooljoint. This band shall be applied flush.
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Two 3” wide bands on each end of the center wear pad. These bands shall be applied proud.
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6.4
Drill Collars With Slip Recess Groove.
Hardbanding (Wear Resistant Alloy Overlay) shall be applied in the following locations:
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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.
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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.
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6.5
Drill Collars With Slip And Elevator Recess Grooves.
Hardbanding (Wear Resistant Alloy Overlay) shall be applied in the following locations:
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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.
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One, 1” wide band on the wear pad OD between the two recess grooves. This band shall be applied proud.
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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.
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7.0
Pre-Hardbandinq Considerations
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7.1
Mill 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.
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7.2
Internal 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.
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7.3
Pre-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.
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8.0
Hardbanding Procedure
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8.1
Machining.
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.
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8.2
Surface 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.
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8.3
Preheat.
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.
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8.4
Hardbanding Application.
Apply hardbanding to the material in accordance with the BP approved WPS (See section 5.0 for more details).
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8.5
Interpass 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.
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8.6
Post 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).
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8.7
Surface 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.
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8.8
Inspection.
Perform a dimensional inspection on each hardbanded area to insure the requirements outlined in section 6.0 have been met.
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8.8.1
Perform a visual inspection on each hardbanded area. Acceptance and rejection criteria shall be per section 10.0.
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8.8.2
Clean all connections and perform a visual inspection on the threaded and sealing surfaces in accordance with procedure BP-DEIP-P004.
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8.8.3
Perform 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.
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8.9
Finishing.
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.
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9.0
Removal of Existing Hardbanding and Application of Mild Steel
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9.1
Removal 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.
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9.1.1
After removal of the existing hardbanding with plasma arc gouging techniques, the excavated area shall be machined smooth to provide a suitable surface for WMPI.
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9.2
Inspection.
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.
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9.2.1
Perform 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.
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9.3
Application 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).
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9.4
Machining.
Machine the areas where mild steel has been applied back to the original OD or taper of the area.
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9.5
Inspection.
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.
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10.0
Acceptance Criteria
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10.1
Mild 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.
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10.2
Wear 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.
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11.0
Documentation, Records and Reporting
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11.1
The 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:
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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).
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A copy of all NDE reports.
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11.2
Documentation, records and reporting requirements as listed in procedure BP-DEIP-P005 shall apply.
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12.0
General Requirements
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12.1
General requirements as listed in procedure BP-DEIP-P001 shall apply.
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13.0
Marking And Stenciling
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13.1
Marking and stenciling requirements as listed in procedure BP-DEIP-P001 shall apply.
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14.0
Documentation, Records and Reporting
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14.1
Documentation, records and reporting requirements as listed in procedure BP-DEIP-P005 shall apply.
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15.0
Health
,
Safety And Environmental
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15.1
Health, safety and environmental requirements as listed in BP-DEIP-P001 shall apply.
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MAKE AND BREAK OF DRILL PIPE AND
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Procedure: BP-DEIP-MB001
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Revision: 0
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WORKSTRING TOOLJOINTS
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Date: 6/6/02
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Approved By:
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Date:
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1.0
Scope
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1.1
This procedure describes the processes established to make and break new drill pipe and workstring tooljoints, both, affixed or loose.
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1.2
Since 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.
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2.0
Personnel Qualifications
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2.1
Personnel performing make and break operations must be trained and experienced in the operation of the make and break unit.
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3.0
Required Materials & Equipment
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3.1
Hydraulic 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.
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3.1.1
The unit shall be equipped with load cells and gauges capable of indicating the torque values obtained in Ft./Lbs.
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3.1.2
Calibration 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.
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3.1.3
The make and break unit shall be equipped with the properly sized power and backup tongs.
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3.1.4
Power and backup tongs will utilize low stress, large contact surface area dies to reduce grip marks.
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3.2
Additional 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.
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4.0
Make And Break Procedures
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4.1
Remove the thread protectors and stack them off the ground to prevent contamination with dirt, grit, grass etc.
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4.2
Visually 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.
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4.3
Verify 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.
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4.4
Recommended 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.
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4.5
The make and break process shall consist of and be performed in the order listed below.
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1.
Make up a box and pin connection to 100% of the specified optimum torque value. Break out the box and pin connections.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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5.1
Visual and dimensional requirements as listed in procedure BP-DEIP-P004 shall apply.
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6.1
General requirements as listed in procedure BP-DEIP-P001 shall apply.
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7.1
Marking and stenciling requirements as listed in procedure BP-DEIP-P001 shall apply.
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8.0
Documentation, Records and Reporting.
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8.1
Documentation, records and reporting requirements as listed in procedure BP-DEIP-P005 shall apply.
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9.1
Health, safety and environmental requirements as listed in BP-DEIP-P001 shall apply.
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CHRISTOPHER S. YOUNG
SR. MARKETING REPRESENTATIVE
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TRANSOCEAN HOLDINGS INC.
1311 BROADFIELD, SUITE 400
HOUSTON, TX 77084
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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
)
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Subject:
Letter of Agreement for adding Offshore Safety Assistant
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Title
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On Board
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Assigned
to Rig
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Daily Rate per
Person w/ Burden
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Hourly Overtime
Rate w/Burden
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||||||
Offshore Safety Advisor
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1
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2
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$
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930.23
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NA
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/s/ Christopher S. Young
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Christopher S. Young
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Sr. Marketing Representative
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On Behalf of Transocean Holdings Inc..
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PHONE: (832) 587-8506
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FAX: (832) 587-8754
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EMAIL: cyoung@houston.deepwater.com
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SIGNED
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/s/ Jerry R Rhoads
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PRINTED
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Jerry R Rhoads
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TITLE
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Contracts Specialist
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CHRISTOPHER S. YOUNG
SR. MARKETING REPRESENTATIVE
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TRANSOCEAN HOLDINGS INC.
1311 BROADFIELD, SUITE 400
HOUSTON, TX 77084
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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
)
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Subject:
Letter of Agreement for Recycling program — Deepwater Horizon
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Sincerely,
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/s/ Christopher S. Young
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Christopher S. Young
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Sr. Marketing Representative
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On Behalf of Transocean Holdings Inc..
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SIGNED
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/s/ Jerry R Rhoads
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PRINTED
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Jerry R Rhoads
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TITLE
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Contracts Specialist
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PHONE: (832) 587-8506
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FAX: (832) 587-8754
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EMAIL: cyoung@houston.deepwater.com
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1.
Provide a recycling service to reduce and separate the waste on the Rig.
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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
|
|
|
|
|
Recycle the Gulf Bags — New
|
5.5 cuft Tri-2 Bags
|
$ 10.35/each
|
||
14 cuft 6 x 2 bags
|
$ 10.15/each
|
Model 4000 Trash Compactor Bags
|
$ 10.20/each
|
|||
Processing Fee (per bag of recycled material)
|
$ 1.85/bag
|
|
|
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
|
|
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
)
|
Sincerely,
|
|
/s/ Gregory L. Cauthen
|
|
Gregory L. Cauthen
|
|
Senior Vice President, Chief
|
|
Financial Officer & Treasurer
|
|
cc:
Craig Duncan
|
|
|
TRANSOCEAN HOLDINGS INC.
|
|
4 GREENWAY PLAZA
|
|
HOUSTON, TX 77046
|
|
CHRISTOPHER S. YOUNG
|
|
SR. MARKETING REPRESENTATIVE
|
|
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
)
|
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
|
|
2.3.2a
Base 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.
|
|
2.3.2b
Contractor’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
|
|
2.3.2c
The 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.
|
|
|
|
2.3.2d
The 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.
|
|
|
Sincerely,
|
|
/s/ Christopher S. Young
|
|
Christopher S. Young
|
|
Sr. Marketing Representative
|
|
On Behalf of R & B Falcon Drilling Co.
|
SIGNED
|
/s/ J. W. Farnsworth
|
|
PRINTED
|
J. W. Farnsworth
|
|
TITLE
|
VP Exploration
|
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
|
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
|
||||||||||
TRANSOCEAN OFFSHORE DEEPWATER DRILLING INC.
|
|
BETSY KELLY
|
4 GREENWAY PLAZA
|
MANAGER-INSURANCE
|
HOUSTON, TX 77046
|
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
|
(713) 232-7766 FAX
|
(713) 232-7630 TEL
|
BKELLY@HOUSTON.DEEPWATER.COM
|
|
U. S. Department of Labor
Bureau of Labor Statistics
Bureau of Labor Statistics Data
|
|
www.bls.gov
|
Search | A-Z Index
|
Change
|
|
Output
|
From: 1992 To 2002 Go
|
Options:
|
include graphs
NEW!
|
More Formatting Options
|
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)
|
|
TRANSOCEAN OFFSHORE DEEPWATER DRILLING INC.
1311 BROADFIELD, SUITE 400
HOUSTON, TX 77084
|
|
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
)
|
Sincerely,
|
|
/s/ Christopher S. Young
|
|
Christopher S. Young
|
|
Sr. Marketing Representative
|
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
|
|
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
)
|
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
|
|
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
)
|
|
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
|
|
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.
|
/s/ Christopher S. Young
|
SIGNED
|
/s/ Jerry R Rhoads
|
|
PRINTED
|
Jerry R Rhoads
|
|
TITLE
|
Contracts Specialist
|
|
TRANSOCEAN HOLDINGS INC.
1311 BROADFIELD, SUITE 400
HOUSTON, TX 77084
|
|
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)
|
|
|
PHONE: (832) 587-8506
|
FAX: (832) 587-8754
|
EMAIL:cyoung@houston.deepwater.com
|
Sincerely,
|
|
/s/ Christopher S. Young
|
|
Christopher S. Young
|
|
Sr. Marketing Representative
|
|
On Behalf of Transocean Holdings Inc.,
|
SIGNED
|
/s/ Jerry R Rhoads
|
|
PRINTED
|
Jerry R Rhoads
|
|
TITLE
|
Contracts Specialist
|
|
TRANSOCEAN HOLDINGS INC.
4 GREENWAY PLAZA
HOUSTON, TX 77046
|
|
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)
|
|
|
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
|
|
2.3.2a
Base 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.
|
|
2.3.2b
We 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
|
|
2.3.2c
The 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.
|
|
|
|
2.3.2d
Costs 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.
|
|
|
Paragraph 2.3.2b
|
(130
|
)
|
||
Paragraph 2.3.2c
|
738
|
|||
Total Increase
|
$
|
608
|
net increase effective January 1, 2004
|
|
Sincerely,
|
|
/s/ Christopher S. Young
|
|
Christopher S. Young
|
|
Sr. Marketing Representative
|
|
On Behalf of R & B Falcon Drilling Co.
|
SIGNED
|
/s/ Scott Sigurdson
|
|
PRINTED
|
Scott Sigurdson
|
|
TITLE
|
Wells Manager
|
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
|
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
|
||||||||
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules
13a-15(e)
and
15d-15(e))
and internal control over financial reporting (as defined in Exchange Act Rules
13a-15(f)
and
15d-15(f))
for the registrant and we have:
|
|
a)
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and
|
|
b)
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and
|
|
c)
|
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
|
d)
|
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
|
|
a)
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
|
b)
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Dated: August 4, 2010
|
/s/ Steven L. Newman
Name: Steven L. Newman
President and Chief Executive Officer
|
1.
|
I have reviewed this report on Form 10-Q of Transocean Ltd.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules
13a-15(e)
and
15d-15(e))
and internal control over financial reporting (as defined in Exchange Act Rules
13a-15(f)
and 15d-15(f))
for the registrant and we have:
|
|
a)
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and
|
|
b)
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and
|
|
c)
|
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
|
d)
|
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
|
|
a)
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
|
b)
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Dated: August 4, 2010
|
/s/ Ricardo H. Rosa
Name: Ricardo H. Rosa
Senior Vice President and Chief Financial Officer
|
|
(1)
|
the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (the “Report”) fully complies with the requirements of Section 13(a)
or 15(d)
of the Securities Exchange Act of 1934; and
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|
(2)
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information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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Dated: August 4, 2010
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/s/ Steven L. Newman
Name: Steven L. Newman
President and Chief Executive Officer
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|
(1)
|
the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (the “Report”) fully complies with the requirements of Section 13(a)
or 15(d)
of the Securities Exchange Act of 1934; and
|
|
(2)
|
information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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Dated: August 4, 2010
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/s/ Ricardo H. Rosa
Name: Ricardo H. Rosa
Senior Vice President and Chief Financial Officer
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