YearsTable Endedof December 31, ---------------------------- 2001 2000 1999 ---------- -------- -------- (in thousands) Drilling Equipment Sales............... $ 395,550 $283,360 $504,245 Tubular Services....................... 352,624 248,099 194,929 Drilling Services...................... 314,272 250,229 202,518 Coiled Tubing & Wireline Products...... 205,363 84,927 74,156 ---------- -------- -------- Total........................... $1,267,809 $866,615 $975,848 ========== ======== ========Contents

~~Date~~SECURITIES ofAND ~~Entity/Assets/Technology~~EXCHANGE ~~Form~~COMMISSION Product Line Transactions ------------------------ ---- ------------ -------------- Quality Tubing Inc...... Stock Purchase Coiled Tubing & Wireline January 2001 Products Angelle Construction Services, Inc......... Asset Purchase Drilling Services February 2001 Servizi Ispettivi....... Asset Purchase Tubular Services March 2001 Chimo Equipment Ltd..... Stock Purchase Drilling Services March 2001 Bradon Industries Group. Stock Purchase Coiled Tubing & Wireline March 2001 Products GeoDZ, Inc.............. Asset Purchase Tubular Services April 2001 Albin's Enterprise, Inc. Stock Purchase Coiled Tubing & Wireline May 2001 Products Alberta Insturment Ltd.. Stock Purchase Drilling Services May 2001 Maris International Limited............... Technology License Drilling Equipment Sales May 2001 Fibercast Inc........... Asset Purchase Tubular Services July 2001 Elmar Services Limited.. Stock Purchase Coiled Tubing & Wireline August 2001 Products Wagner Instrumentation 2000, Inc............. Stock Purchase Drilling Services August 2001 Morinoak International Limited............... Stock Purchase Drilling Equipment Sales September 2001 Adair Supply & Rentals.. Asset Purchase Drilling Services October 2001 ITM..................... Asset Purchase Tubular Services October 2001

~~December~~Washington ~~31, ------------------------- 2001 2000 1999 -------- -------- ------- Drilling Equipment Sales~~D.C.~~.............~~ ~~$251,531~~20549 ~~$ 88,055 $55,734 Coiled Tubing & Wireline Products...... 55,864 $ 61,200 $17,946 -------- -------- ------- Total........................... $307,395 $149,255 $73,680 ======== ======== =======~~

~~Size~~FORM (Approximate Location Description Square Feet) Owned/Leased -------- ----------- ----------------- ------------ North America: U.S.: Kenai, Alaska................. Inspection Facility (Lower Shop) 12,000 on 10 Acres Owned Inspection Facility (Upper Shop) 14,400 on 11 Acres Leased North Slope (Deadhorse) Alaska Inspection, Repair & Service Center 18,400 on 5.25 Acres Building Owned* Little Rock, Arkansas......... Fiberglass Tubular Manufacturing Plant, R&D Lab, Administrative Offices 262,784 on 44 Acres Leased Fiberglass Tubular Manufacturing Plant 45,000 Leased Bakersfield, California....... Downing St. Solids Control Facility 7,200 on 6 Acres Owned Downing Street Inspection & Storage 8,690 on 6.67 Acres Leased Fairhaven Ave. Offices & Warehouse 13,400 on 5.14 Acres Building Owned* Wear St. Inspection Reclamation Yard 5 Acres Leased Orange, California............ Administrative Offices-~~-743~~K N. Eckhoff 35,000 Leased Manufacturing & Office Facility 759 N. Eckhoff 126,000 Owned Office Facility--721 N. Eckhoff 10,000 Leased Santa Paula, California....... Inspection & Reclamation Facility 8,000 on 12 Acres Owned Wichita, Kansas............... Fiberglass Tubular Manufacturing Plant 129,746 on 15 Acres Owned Amelia, Louisiana............. Coating Plant, Inspection & Storage Facilities 102,000 on 90 Acres Building Owned* Belle Chasse, Louisiana....... Inspection & Storage Facilities 22,500 on 4 Acres Leased Evangeline, Louisiana......... Solids Control Office & Rework Facility 20,000 on 4 Acres Owned Harvey, Louisiana............. Coating Plant & Inspection Facility 53,000 on 7 Acres Owned & Leased Lafayette, Louisiana.......... Highway 90 East Complex: Solids Control Service Facility, Warehouse & Administrative Offices 12,075 on .98 Acres Owned Highway 90 East Complex: Systems Service Facility, Warehouse & Distribution Center 13,450 Leased Solids Control Office & Warehouse Facility 20,000 on 2 Acres Leased Lake Arthur, Louisiana........ Solids Control Service & Rework Facility 7,800 on 5 Acres Leased Morgan City, Louisiana........ Inspection Facility 42,400 on 3 Acres Building Owned* New Iberia, Louisiana......... Solids Control Manufacturing & Warehouse Facility 25,500 on 3.4 Acres Owned Laurel, Mississippi........... Inspection & Storage Facilities 13,000 on 4 Acres Leased Hobbs, New Mexico............. Inspection Facility 7,866 on .31 Acres Owned Duncan, Oklahoma.............. Nitrogen Units Manufacturing 67,600 on 13.28 Facility, Warehouse & Offices Acres Owned Edmond, Oklahoma.............. Coating Plant 40,000 on 19 Acres Owned Oklahoma City, Oklahoma....... Inspection Facility 6,000 on 5 Acres Owned Sand Springs, Oklahoma........ Fiberglass Tubular Manufacturing Plant 189,173 on 6.5 Acres Owned Tulsa, Oklahoma............... Nitrogen Units & Pump Manufacturing 40,700 on 4.47 Acres Leased Facility, Warehouse & Offices

~~Size~~ (~~Approximate Location Description Square Feet~~Mark One) Owned/Leased -------- ----------- ----------------- ------------ Big Spring, Texas.... Fiberglass Tubular Manufacturing Plant & 36,669 on 12 Acres Owned Administrative Offices Cedar Park, Texas.... Instrumentation Manufacturing 205,000 on 40 Acres Owned Facility,Administrative & Sales Offices Conroe, Texas........ Solids Control & Pressure Control 160,000 on 30.49 Acres Owned Manufacturing Facility, Warehouse, Administrative & Sales Offices & Engineering Labs Corpus Christi, Texas Inspection Facility 20,800 on 4 Acres Owned Fort Worth, Texas.... Coiled Tubing Manufacturing Facility, 75,200 on 9.67 Acres Owned Warehouse, Administrative & Sales Offices Houston, Texas....... Holmes Road Complex: Manufacturing, 300,000 on 50 Acres Owned Warehouse, Corporate Offices, Coating Manufacturing Plant & Pipeline Services Engineering/Technical Research Center 76,000 on 6 Acres Owned Highway 90: Coating Plant 83,000 on 43 Acres Leased Shaffer, MDT, BJ, & Systems Facility 12950 619,000 on 34 Acres Owned West Little York Sales/ Service/Repair/ Manufacturing Sheldon Road Complex: Administrative 137,000 on 94 Acres Land Owned** Offices, Inspection & Storage Facilities Building Leased Brandt/Southwest Complex: Manufacturing & 40,700 on 4.47 Acres Leased Remanufacturing Facility, Administrative & Sales Offices Hardy Road Complex: Inspection Facility, 19,734 on 14 Acres Owned Manufacturing Warehouse, Administrative Offices & Engineering Solids Control Service & Rework Facility 16,875 on 1.2 Acres Leased 12249 FM 529 QT Manufacturing Facility, Administrative & 80,000 on 11 Acres Owned Sales Offices Instrumentation Manufacturing Facility Leased Corporate Administrative Office 14,500 in Office Tower Leased Kilgore, Texas....... Inspection Facility 21,000 on 4 Acres Owned Midland, Texas....... Coating Plant, Reclamation Facility & 87,000 on 25 Acres Owned Technical Service Building Navasota, Texas...... Coating Plant 65,000 Building Owned* Odessa, Texas........ Inspection Pipe Storage Yard & Ancillary 12,000 on 23.2 Acres Leased Service Facility MDT Sales & Service Facility 8,000 on 1.5 Acres Owned San Antonio, Texas... Fiberglass Tubular Manufacturing Plant, R & D 76,529 on 19.57 Acres Owned Lab, Administrative Offices Snyder, Texas........ Inspection Facility 3,200 on .55 Acres Owned Casper, Wyoming...... Inspection Facility 91,720 on 29 Acres Owned Evanston, Wyoming.... Inspection Facility and Pipe Storage Yard 11,000 on 18 Acres Building Owned*

~~Size~~x ~~(Approximate~~ANNUAL ~~Location~~REPORT ~~Description~~PURSUANT ~~Square~~TO ~~Feet)~~SECTION ~~Owned/Leased -------- ----------- ----------------- ------------ Canada: Bonnyville, Alberta............ Solids Control & Pipe Reclamation Facility~~ 13~~,500~~ onOR 3 Acres Leased Brooks, Alberta................ Inspection Reclamation Facility 8,000 on .25 Acres Leased Calgary, Alberta............... Inspection Office & Warehouse 6,400 on .63 Acres Owned Varco Sales Offices 7,758 in Office Tower Leased Coiled Tubing Manufacturing Facility, 48,040 on 2.52 Acres Owned Administrative & Sales Offices Instrumentation Offices & Warehouse 14,103 Leased Drayton Valley, Alberta........ Inspection Office & Warehouse 6,640 on 1 Acre Leased Edmonton, Alberta.............. Tubular & Pressure Control Shop 8,100 on .5 Acres Leased Instrumentation Office Warehouse 6,330 on .79 Acres Owned Grande Prairie, Alberta........ Solids Control & Inspection Warehouse Facility 8,300 on 1.5 Acres Leased Instrumentation Shop 6,400 Leased Leduc, Alberta................. Solids Control Equipment Rental & Services Facility 41,340 on 9.36Acres Owned MDT, Shaffer & Systems Service & Warehouse 22,690 on 4.6 Acres Owned Facility Inspection Facility 10,000 on 11.8 Acres Leased Lloydminister, Alberta......... Inspection Office, Warehouse & Yard 8,750 on 10 Acres Leased Nisku, Alberta................. Coating Plant, Inspection Facility 114,000 on 30 Acres Owned Inspection Facility & Yard 10,000 on 22.23 Acres Owned Pipeline Services Facility 11,500 on 2.8 Acres Owned Shop & Maintenance, Administrative & Sales 10,000 on 2 Acres Leased Offices Instrumentation Assembly Shop 24,725 on 3.1 Acres Owned Provost, Alberta............... Inspection, Cleaning, Threading Repair Facility 8,750 on .18 Acres Leased Red Deer, Alberta.............. Inspection Office & Shop 14,800 on 15(d) ~~Acres~~OF ~~Leased~~THE ~~Slave~~SECURITIES ~~Lake,~~EXCHANGE ~~Alberta............~~ACT ~~Inspection~~OF Office & Shop 1,500 on 1 Acre Leased Estevan, Saskatchewan.......... Solids Control Rental Facility 4,320 on 1.92 Acres Leased International: Latin America: Argentina: Comodoro Rivadavi, Chubut State Reclamation & Inspection Facility 18,800 on 1.6 Acres Leased Los Perales, Santa Cruz State.. Tubing & Sucker Rod Inspection Yard 700 on 2.47 Acres Leased Plaza Huincul, Neuquen State... Reclamation & Inspection Facility 2,000 on 2.3 Acres Leased Bolivia: Santa Cruz de La Sierra, Pipe & Solids Control Yard, Warehouse, & Office 18,000 on 1.72 Acres Leased Andres Ibanez State........... Brazil: Macae, Brazil.................. Inspection Facility & Solids Control Yard 4.94 Acres Leased1934

Size (Approximate Location Description Square Feet) Owned/Leased -------- ----------- ----------------- ------------ Colombia: Neiva, Colombia................... Solids Control Yard & Warehouse 53,820 Leased Yopal, Colombia................... Solids Control Warehouse & Storage 68,890 Leased on 3.75 Acres Ecuador: Coca, Ecuador..................... Solids Control Warehouse & Service Facility 6,500 Leased Coca, Ecuador..................... Inspection Office, Warehouse & Service Facility 10,000 Leased Quito, Ecuador.................... Solids Control & Inspection Office 500 Leased Peru: Iquitos, Maynas................... Solids Control Office & Warehouse 9,187 Leased Trinidad: Couva, Trinidad................... Screens Manufacturing Facility 8,073 on Leased .5 Acres San Fernand, Trinidad............. Solids Control Sales & Service Facility 7,000 on Leased .28 Acres Venezuela: Anaco, Venezuela.................. Solids Control Offices & Warehouse 35,000 Owned on .5 Acres Inspection Facility 600 on Leased 2.5 Acres Ciudad Ojeda, Venezuala........... Solids Control Facility 1.5 Leased Acres La Candelaria, Venezuela.......... Waste Management Facility 14.8 Owned Acres La Canada, Venezuela.............. Undeveloped Land For ~~Waste~~the ~~Management~~fiscal ~~Facility~~year ~~27.9~~ended ~~Owned~~December ~~Acres Maracaibo~~31, ~~Venezuela..............~~2004 Solids Control Facility 25,000 Owned on 1 Acre San Diego Cabrutica, Venezuela.... Solids Control Facility 1.5Acres Leased Tia Juana, Venezuela.............. Inspection Facility 1.5 Leased Acres Far East: Australia: Perth, Western Australia.......... Coiled Tubing & Wireline ProductsWarehouse 11,860 Leased China: Harbin, People's Republic of China Fiberglass Tubular Manufacturing Plant 35,000 Leased

~~Size~~OR (Approximate Location Description Square Feet) Owned/Leased -------- ----------- ----------------- -------------- Singapore: Singapore.............. Systems Offices, Service &Distribution Facility 43,529 on 1.2 Acres Building Owned* Tuas, Singapore........ Coating Plant & Inspection Facility 50,644 on 8 Acres Building Owned* Tuas, Singapore........ Coiled Tubing & Wireline Products 35,300 on 1.54 Acres Building Owned* Manufacturing & Administrative Facility Europe: France: Berlaimont, France..... Coating Plant 44,000 on 16 Acres Owned Germany: Celle, Germany......... Inspection Facility, Administrative & Engineering 43,560 on 12 Acres Building Owned* Offices Gladbeck, Germany...... Coating Plant 25,635 on 4 Acres Owned Netherlands: Coevorden, Netherlands. Inspection Reclamation & Repair Facility 53,361 on 2 Acres Leased Etten-Leur, Netherlands BJ Mfg. Plant/Sales 75,000 on 6 Acres Owned Norway: Agotnes, Norway........ Inspection/Cleaning Hall 7,000 on 1 Acre Building Owned* Floro, Norway.......... Inspection/Cleaning Hall 10,000 on 1 Acre Building Owned* Kristiansund, Norway... Inspection/Cleaning Hall 14,000 on 1 Acre Leased Stavanger, Norway...... Inspection/Cleaning Hall 16,000 on 1 Acre Leased Drilling Equipment Work Shop Warehouse & 41,333 on .42 Acres Leased Customer Service Center Drilling Equipment & Solids Control 7,535 Leased Administrative & Sales United Kingdom: Bordon, England........ Pipeline Services Center 12,000 on .75 Acres Building Owned* Dorset, England........ Coiled Tubing & Pressure Control Manufacturing, 16,140 on .58 Acres Leased Administrative & Sales Great Yarmouth, England Coiled Tubing & Nitrogen Units Manufacturing, 29,000 on 1.7 Acres Leased Administrative & Sales Derrick Manufacturing Facilities, Administrative, 46,208 on 2.57 Acres Leased & Sales Derrick Manufacturing Facilities, Administrative, 21,162 on 1,323 Acres Owned & Sales Aberdeen, Scotland..... Inspection Facility, Coating Plant, Manufacturing, 45,209 on 10 Acres Owned Administrative & Sales Solids Control Manufacturing Facility Assembly, 71,200 on 6.25 Acres Leased Administrative, Sales Coiled Tubing & Pressure Control Manufacturing, 26,000 on 1.65 Acres Owned Administrative & Sales Derrick Manufacturing Facilities, Administrative 10,126 on .53 Acres Leased & Sales Tubular & Pressure Control Manufacturing, 85,152 on 7.1 Acres Leased Administrative & Sales

~~Size~~¨ ~~(Approximate~~TRANSITION ~~Location~~REPORT ~~Description~~PURSUANT ~~Square~~TO ~~Feet)~~SECTION ~~Owned/Leased~~13 ~~--------~~OR ~~-----------~~15(d) ~~-----------------~~OF ~~------------~~THE QTSECURITIES ~~Coiled~~EXCHANGE ~~Tubing~~ACT ~~Service~~OF Center 27,600 on 2 Acres Leased Badentoy, Scotland..... Systems & Shaffer Sales, Service & 63,000 on 6 Acres Owned Distribution Facility Montrose, Scotland..... Forties Road Systems Service Center & 34,000 on 3 Acres Owned Office Facility Middle East: Saudi Arabia: Al Khobar, Saudi Arabia Reclamation, Inspection Facility & 340,203 on 8 Acres Leased Offices United Arab Emirates: Jebel Ali, Dubai....... Tubular & Pressure Control 12,400 on .55 Acres Leased Manufacturing, Administrative & Sales1934

~~2001~~For ~~2000~~the ~~-----------~~transition ~~-----------~~period High Low High Low ----- ----- ----- ----- 1st Quarter............................ 24.70 17.88 19.56 12.50 2nd Quarter............................ 24.70 18.40 24.88 14.20 3rd Quarter............................ 18.75 10.92 22.95 17.00 4th Quarter............................ 16.20 11.65 21.75 15.33from to

~~Years~~VARCO ~~Ended December 31~~INTERNATIONAL, ------------------------------------------------------- 2001 2000 1999 1998 1997 ---------- ---------- ---------- ---------- ---------- (Dollars in thousands, except ratio and per share data) Statement of Income Data: RevenueINC.~~.................................~~ $1,267,809 $ 866,615 $ 975,848 $1,307,681 $1,070,318 Operating profit(1)...................... 158,126 60,911 67,348 179,062 180,412 Net income............................... $ 82,968 $ 21,055 $ 29,809 $ 102,283 $ 102,979 ========== ========== ========== ========== ========== Basic earnings per common share.......... $ .87 $ 0.23 $ 0.33 $ 1.13 $ 1.16 ========== ========== ========== ========== ========== Dilutive earnings per common share....... $ .86 $ 0.22 $ 0.32 $ 1.09 $ 1.10 ========== ========== ========== ========== ========== Other Data: EBITDA(2)................................ $ 238,271 $ 144,217 $ 134,016 $ 239,685 $ 222,865 Earnings per common share before goodwill amortization........................... $ .97 $ 0.31 $ 0.41 $ 1.18 $ 1.18 Ratio of EBITDA to interest expense(3)... 10.9x 9.4x 7.1x 12.0x 12.3x Ratio of earnings to fixed charges(4).... 5.6x 3.1x 3.3x 7.3x 8.1x Depreciation and amortization............ $ 67,900 $ 56,518 $ 57,180 $ 52,972 $ 43,081 Capital expenditures..................... $ 65,834 $ 45,463 $ 30,729 $ 78,356 $ 81,805 Balance Sheet Data (end of period): Working capital.......................... $ 423,602 $ 263,378 $ 310,175 $ 290,398 $ 218,771 Total assets............................. 1,429,110 1,076,982 1,131,313 1,259,092 1,157,296 Total debt............................... 322,614 136,507 233,335 260,692 237,897 Common stockholders' equity.............. 828,314 731,983 694,245 658,441 553,232

% % 2001 v 2000 v 2001* 2000* 1999* 2000 1999 ------ ------ ------ ------ ------ Rig Activity: U.S................................. 1,155 916 623 26.1% 47.0% Canada.............................. 342 353 246 (~~3.1)%~~Exact ~~43.5%~~name ~~International.......................~~of ~~745~~registrant ~~652~~as ~~588~~specified ~~14.3%~~in ~~10.9%~~its ------ ------ ------ ----- ---- Worldwide........................... 2,242 1,921 1,457 16.7% 31.8% Workover Rig Activity: U.S................................. 1,211 1,056 835 14.7% 26.5% Canada.............................. 342 342 253 -- 35.2% ------ ------ ------ ----- ---- North America....................... 1,553 1,398 1,088 11.1% 28.5% West Texas Intermediate Crude prices (per barrelcharter)~~.........................~~ ~~$25.93 $30.34 $19.20 (14.5)% 58.0% Natural Gas Prices ($/mbtu)............ $ 3.97 $ 4.32 $ 2.33 (8.1)% 85.4%~~

Total Rigs Canada US International W. TX Int. ($) 1Q97 2,055 395 856 804 22.86 2Q97 2,001 255 934 812 19.95 3Q97 2,197 398 990 809 19.70 4Q97 2,262 451 998 813 20.03 1Q98 2,236 459 966 811 15.88 2Q98 1,838 175 865 798 14.63 3Q98 1,725 205 794 726 14.10 4Q98 1,572 201 689 682 12.95 1Q99 1,462 290 552 620 12.97 2Q99 1,224 104 523 597 17.64 3Q99 1,462 254 643 565 21.68 4Q99 1,683 337 775 571 24.50 1Q00 1,826 480 770 576 28.82 2Q00 1,716 245 842 629 28.82 3Q00 1,988 314 980 694 31.74 4Q00 2,159 375 1073 711 31.98 1Q01 2,379 515 1140 724 28.81 2Q01 2,240 252 1237 751 27.92 3Q01 2,318 320 1241 757 26.62 4Q01 2,030 278 1004 748 20.36

Delaware

001-13309

76-0252850

(State or other jurisdiction of

incorporation or organization)

(Commission File No.)

(I.R.S.

Identification No.)

2001 2000 1999 ---------- -------- -------- Drilling Equipment Sales............... $ 395,550 $283,360 $504,245 Tubular Services....................... 352,624 248,099 194,929 Drilling Services...................... 314,272 250,229 202,518 Coiled Tubing & Wireline Products...... 205,363 84,927 74,156 ---------- -------- -------- $1,267,809 $866,615 $975,848 ========== ======== ========

One BriarLake Plaza, 2000 W. Sam Houston Pkwy

South, Suite 1700, Houston, TX

77042

(Address of principal executive offices)

(Zip Code)

~~Payments~~Registrant’s telephone Due by Period ---------------------------------------------------- Less than Total 1 Year 1-3 Years 4-5 years After 5 years -------- --------- --------- --------- ------------- Long Term Debt............. $322number,~~614~~ $including ~~7,077~~area ~~$11,372~~code: $(281) ~~3,237 $300,928 Operating Leases........... 82,887 20,193 26,019 12,696 23,979~~ 953-~~-------~~2200 ------- ------- ------- -------- Total contractual obligations.............. $405,501 $27,270 $37,391 $15,933 $324,907 ======== ======= ======= ======= ======== Standby Letters of Credit.. $ 13,963 $ 7,283 $ 3,389 $ 3,291 $ -- ======== ======= ======= ======= ========

~~Page~~Securities ~~----------~~registered ~~Report~~pursuant ofto ~~Independent~~Section ~~Auditors.............................................................~~12(b) ~~F-1 Consolidated Balance Sheets at December 31, 2001 and 2000.................................. F-2 Consolidated Statements~~ of ~~Income for~~ the ~~years~~Act: ended December 31, 2001, 2000, and 1999.... F-3 Consolidated Statements of Common Stockholders' Equity and Comprehensive Income for the years ended December 31, 2001, 2000, and 1999,........................................... F-4 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999 F-5 Notes to Consolidated Financial Statements................................................. F-6 - F-31

Exhibit No. Description Note No. ---------- ----------- --------- 3.1 Third Amended and Restated Certificate of Incorporation, dated May 30, 2000. (Note 1) 3.2 Third Amended and Restated Bylaws. (Note 1) 3.3 Certificate of Designations of Series A Junior Participating Preferred Stock, dated (Note 1) November 30, 2000. 4.1 Rights Agreement, dated as of November 29, 2000, by and between the Company and (Note 1) Chase Mellon Shareholder Services, L.L.C., as Rights Agent, which includes the form of Certificate of Designations of the Series A Junior Participating Preferred Stock of Varco International, Inc. as Exhibit A, the form of Right Certificate as Exhibit B, and the Summary of Rights to Purchase Preferred Shares as Exhibit C. 4.2 Registration Rights Agreement dated May 13, 1988 among the Company, Brentwood (Note 2) Associates, Hub Associates IV, L.P. and the investors listed therein. 4.3 Purchase Agreement dated as of October 1, 1991 between the Company and Baker (Note 3) Hughes Incorporated regarding certain registration rights. 4.4 Registration Rights Agreement dated April 24, 1996 among the Company, SCF III, (Note 9) L.P., D.O.S. Partners L.P., Panmell (Holdings), Ltd. and Zink Industries Limited. 4.5 Registration Rights Agreement dated March 7, 1997 among the Company and certain (Note 10) stockholders of Fiber Glass Systems, Inc. 4.6 Indenture, dated as of February 25, 1998, between the Company, the Guarantors (Note 11) named therein and The Bank of New York Trust Company of Florida as trustee, relating to $100,000,000 aggregate principal amount of 7 1/2% Senior Notes due 2008; Specimen Certificate of 7 1/2% Senior Notes due 2008 (private notes); and Specimen Certificate of 7 1/2% Senior Notes due 2008 (exchange notes). 4.8 Indenture, dated as of May 1, 2001, among the Company, the Guarantors named (Note 27) therein and The Bank of New York, as trustee, relating to $200,000,000 aggregate principal amount of 7 1/4% Senior Notes due 2011; Specimen Certificate of 7 1/4% Senior Notes due 2011 (private notes); Specimen Certificate of 7 1/4% Senior Notes due 2011 (exchange notes) 10.1 Credit Agreement, dated as of January 30, 2002, among Varco International, Inc., as the Borrower, Wells Fargo Bank Texas, National Association, as Administrative Agent, Bank One, NA, as Syndication Agent, Credit Suisse First Boston, Cayman Islands Branch, as Documentation Agent, and the other Banks a party thereto. 10.2* Deferred Compensation Plan dated November 14, 1994; Amendment thereto dated (Note 12) May 11, 1998. 10.3* Amended and Restated 1996 Equity Participation Plan (Note 1) 10.3.1* Form of Non-qualified Stock Option Agreement for Employees and Consultants; Form of Non-qualified Stock Option Agreement for Independent Directors. 10.4* DOS Ltd. 1993 Stock Option Plan; Form of D.O.S. Ltd. Non-Statutory Stock Option (Note 8) Agreement. 10.5* Amended and Restated Stock Option Plan for Key Employees of Tuboscope Vetco (Note 4) International Corporation; Form of Revised Incentive Stock Option Agreement; and Form of Revised Non-Qualified Stock Option Agreement. 10.6* Stock Option Plan for Non-Employee Directors; Amendment to Stock Option Plan for (Note 5) Non-Employee Directors; and Form of Stock Option Agreement.

Title of each class

Name of each exchange on

which registered

Common stock, $.01 par value

Preferred Share Purchase Rights

New York Stock Exchange

~~Exhibit~~Securities registered ~~No.~~pursuant ~~Description Note No. ---------- ----------- --------- 10.7* Varco International, Inc. Supplemental Executive Retirement Plan (Note 21) 10.7.1* Amendment~~ to ~~Varco~~Section International, Inc. Supplemental Executive Retirement Plan (Note 23) 10.7.2* Second Amendment to Varco International, Inc. Supplemental Executive Retirement Plan (Note 24) 10.8 Lease dated March 7, 1985, as amended (Note 15) 10.8.1 Agreement dated as of January 1, 1982, with respect to Lease included as Exhibit 10.8 hereof (Note 16) 10.8.2 Agreement dated as of January 1, 1984, with respect to Lease included as Exhibit 10.8 hereto (Note 17) 10.8.3 Agreement dated as of February 8, 1985, with respect to Lease included as Exhibit 10.8 hereto (Note 17) 10.8.4 Agreement dated as of April 12~~, 1985, with respect to Lease included as Exhibit 10.8 hereto~~ (~~Note 18~~g) ~~10.8.5 Amendment dated as~~ of ~~January 11, 1996, with respect to Lease included as Exhibit 10.8 hereto (Note 22) 10.9 Standard Industrial Lease-Net dated September 29, 1988 for~~ the ~~premises~~Act: atNone 743 N. Eckhoff, Orange, California (Note 19) 10.9.1 First amendment dated as of January 11, 1996 to Lease included as Exhibit 10.9 hereto (Note 22) 10.10* The Varco International, Inc. 1990 Stock Option Plan, as amended (Note 20) 10.10.1* Amendments to the Varco International, Inc. 1990 Stock Option Plan (Note 25) 10.11* Varco International, Inc. 1994 Directors' Stock Option Plan (Note 22) 10.11.1* Amendment to Varco International, Inc. 1994 Directors' Stock Option Plan (Note 24) 10.12* The Varco International, Inc. Deferred Compensation Plan. (Note 25) 10.13 Master Leasing Agreement, dated December 18, 1995 between the Company and Heller Financial Leasing, Inc. (Note 6) 10.14* Form of Executive Agreement of certain members of senior management (Note 14) 10.14.1* Form of First Amendment to Executive Agreements (Note 14) 10.15* Executive Agreement of John F. Lauletta (Note 14) 10.16* Executive Agreement of Joseph C. Winkler (Note 14) 10.17* Executive Agreement of George Boyadjieff (Note 26) 10.18* Executive Agreement of Michael W. Sutherlin (Note 26) 10.19* Form of Indemnity Agreement (Note 14) 21 Subsidiaries 23 Consent of Independent Auditors

~~December~~Indicate ~~31,~~by ~~December~~check ~~31,~~mark ~~2001~~whether ~~2000~~the ~~------------~~registrant ~~------------~~ (~~in thousands~~1) ~~ASSETS~~has ~~------~~filed ~~Current~~all ~~assets:~~reports ~~Cash~~required ~~and~~to ~~cash~~be ~~equivalents....................................................~~filed $by ~~57,499~~Section $13 ~~12,176~~or ~~Accounts~~15(d) ~~receivable,~~of ~~net.....................................................~~the Securities ~~342,036~~Exchange ~~269,393~~Act ~~Inventory,~~of ~~net...............................................................~~1934 ~~229,678~~during ~~152,350~~the ~~Deferred~~preceding tax assets.......................................................... 6,618 4,889 Prepaid expenses and other................................................... 27,374 16,898 ---------- ---------- Total current assets..................................................... 663,205 455,706 ---------- ---------- Property and equipment, net..................................................... 400,416 343,673 Identified intangibles, net..................................................... 30,722 26,062 Goodwill, net................................................................... 325,135 238,641 Other assets, net............................................................... 9,632 12~~,900~~ ~~----------~~months ---------- Total assets............................................................. $1,429,110 $1,076,982 ========== ========== LIABILITIES AND EQUITY ---------------------- Current liabilities: Accounts payable............................................................. $ 102,559 $ 66,182 Accrued liabilities.......................................................... 102,315 91,423 Income taxes payable......................................................... 27,652 4,376 Current portion of long-term debt and short-term borrowings.................. 7,077 30,347 ---------- ---------- Total current liabilities................................................ 239,603 192,328 Long-term debt.................................................................. 315,537 106,160 Pension liabilities and post-retirement obligations............................. 25,834 24,556 Deferred taxes payable.......................................................... 18,604 20,867 Other liabilities............................................................... 1,218 1,088 ---------- ---------- Total liabilities........................................................ 600,796 344,999 ---------- ---------- Common stockholders' equity: Common stock, $.01 par value, 200,000,000 shares authorized, 97,402,339 shares issued and 95,977,639 shares outstanding at December 31, 2001 (~~96,245,849~~or ~~shares~~for ~~issued~~such ~~and~~shorter ~~94,821,149~~period ~~shares~~that ~~outstanding~~the atregistrant ~~December~~was ~~31,~~required ~~2000).........................................................~~to ~~974~~file ~~962~~such Paid in capital.............................................................. 514,137 498,692 Retained earnings............................................................ 347,548 264,580 Accumulated other comprehensive loss......................................... (19,015reports) ~~(16,921)~~and ~~Less: treasury stock at cost~~ (~~1,424,700 shares~~2)~~..............................~~ ~~(15,330)~~has ~~(15,330)~~been ~~----------~~subject ~~----------~~to ~~Total~~such ~~common~~filing ~~stockholders'~~requirements ~~equity........................................~~for ~~828,314~~the ~~731,983~~past ~~----------~~90 ~~---------- Total liabilities and equity~~days.~~............................................~~ ~~$1,429,110~~Yes ~~$1,076,982~~x ~~==========~~No ~~==========~~¨

~~Years~~Indicate ~~Ended~~by ~~December~~check ~~31,~~mark ~~--------------------------------------~~if ~~2001~~disclosure 2000 1999 ----------- ----------- ----------- (in thousands, except for common shares and per share data) Revenue: Sales................................................... $ 751,284 $ 463,556 $ 708,587 Services and rentals.................................... 516,525 403,059 267,261 ----------- ----------- ----------- Total............................................... 1,267,809 866,615 975,848 ----------- ----------- ----------- Cost and expenses: Cost of ~~sales...........................................~~delinquent ~~488,558~~filers ~~296,955~~pursuant ~~491,481~~to ~~Cost~~Item of405 ~~services and rentals............................ 395,257 321,647 225,436 Amortization~~ of ~~goodwill................................~~Regulation 10,457 8,444 8,431 Selling, general and administrative..................... 152,276 119,942 135,195 Research and engineering costs.......................... 46,635 32,146 40,149 Merger, transaction, and litigation costs............... 16,500 26,570 7,808 S-~~----------~~K ----------- ----------- Total............................................... 1,109,683 805,704 908,500 ----------- ----------- ----------- Operating profit........................................... 158,126 60,911 67,348 Other expense (~~income): Interest expense~~§229.~~.......................................~~405 ~~21,776~~of ~~15,282~~this ~~18,926 Interest income......................................... (2,145~~chapter) ~~(3,374)~~is ~~(2,694)~~not ~~Foreign~~contained ~~exchange loss (gain)............................ (71) 1~~herein,~~134~~ and ~~(473)~~will ~~Other...................................................~~not ~~6,471~~be 2contained,~~022~~ ~~1,527~~to ~~-----------~~the ~~-----------~~best ~~-----------~~of ~~Income~~registrant’s ~~before income taxes................................. 132~~knowledge,~~095~~ ~~45,847~~in ~~50,062~~definitive ~~Provision~~proxy ~~for~~or ~~income~~information ~~taxes.................................~~statements ~~49,127~~incorporated ~~24,792~~by ~~20,253~~reference ~~-----------~~in ~~-----------~~Part ~~-----------~~III Net income................................................. $ 82,968 $ 21,055 $ 29,809 =========== =========== =========== Earnings per common share: Basic earnings per common share......................... $ 0.87 $ 0.23 $ 0.33 =========== =========== =========== Dilutive earnings per common share...................... $ 0.86 $ 0.22 $ 0.32 =========== =========== =========== Weighted average number of ~~common~~this ~~shares~~Form ~~outstanding:~~10-K ~~Basic...................................................~~or ~~95,732,897~~any ~~92,773,815~~amendment ~~90,659,770~~to ~~===========~~this ~~===========~~Form ~~=========== Dilutive~~10-K.~~...............................................~~ ~~96,675,294~~¨ ~~95,355,904 92,693,264 =========== =========== ===========~~

~~Accumulated~~Indicate ~~Total~~by ~~Common~~check ~~Other~~mark ~~Common~~whether ~~Shares~~the ~~Stock~~registrant ~~$.01~~is ~~Paid~~an inaccelerated ~~Retained~~filer ~~Comprehensive Treasury Stockholders' Outstanding Par Value Capital Earnings Income~~ (~~loss)~~as ~~Stock~~defined ~~Equity ----------- ---------- -------- -------- ------------- -------- ------------- (~~in ~~thousands)~~Rule ~~Balance at December 31, 1998................ 90,150 $917 $466,302 $213,716 $ (7,164) $(15,330) $658,441 1999 Comprehensive income: Net income...............................~~ 12b-- -- -- 29,809 -- -- 29,809 Foreign currency translation adjustment.. -- -- -- -- (3,487) -- (3,487) Unrealized gains on investments.......... -- -- -- -- 41 -- 41 ------ ---- -------- -------- -------- -------- -------- 1999 Comprehensive income................ -- -- -- 29,809 (3,446) -- 26,363 Common stock issued......................... 1,028 9 8,595 -- -- -- 8,604 Tax benefit of options exercised............ -- -- 837 -- -- -- 837 ------ ---- -------- -------- -------- -------- -------- Balance at December 31, 1999................ 91,178 926 475,734 243,525 (10,610) (15,330) 694,245 2000 Comprehensive income: Net income............................... -- -- -- 21,055 -- -- 21,055 Foreign currency translation adjustment.. -- -- -- -- (6,311) -- (6,311) ------ ---- -------- -------- -------- -------- -------- 2000 Comprehensive income................ -- -- -- 21,055 (6,311) -- 14,744 Common stock issued......................... 1,297 13 12,212 -- -- -- 12,225 Common stock issued executive match program.................................... 323 3 6,428 -- -- -- 6,431 Conversion of stock warrants................ 2~~,023~~ ~~20 (20) -- -- -- -- Tax benefit~~ of ~~options~~the ~~exercised............ -- -- 4,338 -- -- -- 4,338 ------ ---- -------- -------- -------- -------- -------- Balance at December 31, 2000................ 94,821 962 498,692 264,580 (16,921~~Act) ~~(15,330) 731,983 2001 Comprehensive income: Net income~~.~~..............................~~ --Yes --x --No ~~82,968~~¨ -- -- 82,968 Foreign currency translation adjustment.. -- -- -- -- (2,094) -- (2,094) ------ ---- -------- -------- -------- -------- -------- 2001 Comprehensive income................ -- -- -- 82,968 (2,094) -- 80,874 Common stock issued......................... 1,101 11 10,806 -- -- -- 10,817 Common stock issued in exchange for convertible debt........................... 56 1 833 -- -- -- 834 Tax benefit of options exercised............ -- -- 3,806 -- -- -- 3,806 ------ ---- -------- -------- -------- -------- -------- Balance at December 31, 2001................ 95,978 $974 $514,137 $347,548 $(19,015) $(15,330) $828,314 ====== ==== ======== ======== ======== ======== ========

~~Years~~The ~~Ended~~aggregate ~~December~~market ~~31,~~value ~~-------------------------------~~of the ~~2001~~voting ~~2000~~stock ~~1999~~held --------- --------- --------- (in thousands) Cash flows from operating activities: Net income................................................................ $ 82,968 $ 21,055 $ 29,809 Adjustments to reconcile net income to net cash provided by ~~operating activities: Depreciation and amortization...................................... 67,900 56,518 57,180 Non-cash merger and transaction costs.............................. -- 12,101 -- Other~~ non-~~cash~~affiliates ~~charges.............................................~~of ~~10,081~~the 18registrant,~~317~~ ~~11,349~~as ~~Changes in current assets and liabilities, net~~ of ~~effects~~the ~~from~~registrant’s ~~acquisitions:~~most ~~Accounts~~recently ~~receivable.............................................~~completed ~~(51,872)~~second ~~(15,904)~~fiscal 50quarter,~~722~~ ~~Inventory.......................................................~~was ~~(60,914) (9,852) 100,230 Prepaid expenses and other assets............................... (9,520) 481~~ $2,~~104 Accounts payable~~046, ~~accrued liabilities and other................. 19~~641,~~954~~296 ~~(6,552)~~based ~~(124,416)~~on ~~Income~~the ~~taxes~~closing ~~payable............................................~~sales ~~25,398~~price 5,623 (7,914) --------- --------- --------- Net cash provided by operating activities.......................... 83,995 81,787 119,064 --------- --------- --------- Cash flows used for investing activities: Capital expenditures................................................... (65,834) (45,463) (30,729) Business acquisitions, net of ~~cash~~such acquired............................ (145,953) (21,685) (13,120) Other.................................................................. (1,121) 2,276 211 --------- --------- --------- Net cash used for investing activities............................. (212,908) (64,872) (43,638) --------- --------- --------- Cash flows provided by (used for) financing activities: Borrowings under financing agreements, net............................. 302,600 16,953 55,192 Principal payments under financing agreements.......................... (137,832) (113,720) (90,708) Proceeds from sale of common stock, net................................ 10,132 10,049 5,625 --------- --------- --------- Net cash provided by (used for) financing activities............... 174,900 (86,718) (29,891) --------- --------- --------- Effect of exchange rate changes on ~~cash...................................~~such ~~(664) (1,138) (291) Net increase (decrease) in cash and cash equivalents~~date.~~.....................~~ 45,323 (70,941) 45,244 Cash and cash equivalents: Beginning of period.................................................... 12,176 83,117 37,873 --------- --------- --------- End of period.......................................................... $ 57,499 $ 12,176 $ 83,117 ========= ========= ========= Supplemental disclosure of cash information: Cash paid during the year for: Interest........................................................... $ 19,350 $ 17,473 $ 20,302 ========= ========= ========= Taxes.............................................................. $ 31,740 $ 12,643 $ 25,389 ========= ========= =========

~~2000~~The ~~1999~~number ~~--------~~of ~~--------~~shares ~~Revenues:~~outstanding ~~Tuboscope.........................................................~~of $224,730 $385,474 Varco............................................................. 184,866 590,374 -------- -------- Total......................................................... $409,596 $975,848 ======== ======== Net income before merger & transaction costs related to the ~~merger:~~registrant’s ~~Tuboscope.........................................................~~common ~~$ 5~~stock,~~838~~ $as ~~(7,156)~~of February ~~Varco............................................................. 10~~11,~~106~~ ~~36,965~~2005 ~~--------~~was ~~-------- Total......................................................... $ 15~~98,~~944 $ 29~~468,~~809~~554 ~~======== ========~~

~~Quality~~DOCUMENTS ~~All~~INCORPORATED ~~Other~~BY ~~Tubing~~REFERENCE Acquisitions Total ------- ------------ -------- Current assets......................... $15,377 $ 41,200 $ 56,777 Property, plant and equipment.......... 8,049 33,494 41,543 Intangible assets...................... 146 7,398 7,544 Goodwill............................... 40,639 57,228 97,867 ------- -------- -------- Total assets acquired............... 64,211 139,320 203,531 ------- -------- -------- Current liabilities.................... 7,291 32,948 40,239 Long term debt......................... 1,107 10,711 11,818 Other liabilities...................... 793 2,680 3,473 ------- -------- -------- Total liabilities................... 9,191 46,339 55,530 ------- -------- -------- Net assets acquired................. $55,020 $ 92,981 $148,001 ======= ======== ========

~~2001~~Portions ~~-------~~of ~~Drilling~~the ~~Equipment~~registrant’s ~~Sales...............~~Proxy ~~$10,118~~Statement ~~Tubular~~for ~~Services.......................~~its ~~651~~2005 ~~Drilling~~Annual ~~Services......................~~Meeting ~~11,923~~are ~~Coiled~~incorporated ~~Tubing~~by &this ~~Wireline...............~~reference 75into Part III,~~175~~ ~~-------~~as ~~Total~~set ~~goodwill~~forth ~~acquired~~herein.~~...............~~ ~~$97,867 =======~~

2001Table 2000 1999 --------- -------- -------- Fair value of assets acquired.............................. $ 201,483 $ 26,045 $ 21,327 Cash paid.................................................. (145,953) (21,685) (13,120) --------- -------- -------- Liabilities assumed and debt issued........................ $ 55,530 $ 4,360 $ 8,207 ========= ======== ======== Excess purchase price over fair value of assets acquired... $ 97,867 $ 5,175 $ 2,434 ========= ======== ========Contents

~~2001~~ITEM ~~2000 ---------- ---------- Revenue..................................... $~~1~~,320,748 $1,034,656 ========== ========== Net income~~.~~.................................~~ ~~$ 83,427 $ 21,774 ========== ========== Dilutive earnings per common share.......... $ .86 $ .23 ========== ==========~~BUSINESS

~~2001~~General 2000 -------- -------- Raw materials............................... $ 89,477 $ 66,138 Work in progress............................ 56,785 35,445 Finished goods.............................. 97,090 63,665 Excess of current cost over LIFO value...... (13,674) (12,898) -------- -------- Inventory, net........................... $229,678 $152,350 ======== ========

~~2001~~Varco International, ~~2000~~Inc. ~~---------~~(“Varco” or the “Company”) is a leading provider of highly engineered drilling and well-~~--------~~servicing ~~Land~~equipment, products and ~~buildings~~services to the world’s oil and gas industry.~~.........................~~ $With ~~138,330~~operations $in ~~128~~over 350 locations in over 40 countries across six continents,~~991~~ ~~Operating~~the Company manufactures and supplies innovative drilling equipment~~.........................~~ ~~353~~and rig instrumentation; performs inspection and internal coating of oilfield tubular products; provides drill cuttings separation,~~548~~ ~~295~~management and disposal systems and services; and manufactures coiled tubing,~~067~~ ~~Rental~~wireline, and pressure control equipment for land and offshore drilling and well stimulation operations.~~...........................~~ ~~198,169~~The ~~154~~Company also manufactures coiled tubing,~~000~~ provides in-~~--------~~service ~~---------~~pipeline ~~690~~inspections,~~047~~ ~~578~~manufactures high pressure fiberglass and composite tubing,~~058~~ ~~Less~~and ~~accumulated~~sells ~~depreciation~~and rents advanced in-line inspection equipment to makers of oil country tubular goods.~~..............~~ ~~(289~~The Company has a long tradition of pioneering innovations which improve the efficiency,~~631)~~ ~~(234~~safety,~~385)~~ ~~---------~~cost ~~---------~~and $environmental ~~400,416~~impact $of ~~343,673~~oil ~~=========~~and ~~=========~~gas operations.

~~2001~~The ~~2000~~Company’s ~~--------~~common ~~-------~~stock ~~Compensation.....................................~~is $traded ~~26,279~~on ~~$28,862~~the ~~Warranty.........................................~~New ~~8,037~~York ~~6,012~~Stock ~~Interest~~Exchange under the symbol “VRC.~~........................................~~” ~~6,674~~The ~~3,278~~Company ~~Taxes~~operates ~~(non~~through ~~income)...............................~~four ~~7,666~~business ~~5,569~~groups: ~~Insurance........................................~~Drilling 8Equipment,~~211~~ 6Tubular Services,~~617~~ ~~Other............................................~~Drilling 45Services,~~448~~ and ~~41,085~~Coiled ~~--------~~Tubing ~~-------~~& ~~$102,315~~Wireline ~~$91,423~~Products. ~~======== =======~~

~~2001~~The ~~2000~~Drilling Equipment ~~1999~~group ~~--------~~manufactures ~~-------~~and ~~-------~~sells ~~U.S....................................~~equipment $for ~~59,866~~rotating $and ~~8,390~~handling ~~$33~~pipe on offshore and land drilling rigs,~~099~~ ~~Foreign~~including conventional drilling rig tools and equipment; pipe handling tools; hoisting and rotary equipment; pressure control and motion compensation equipment; and flow devices. The group also provides after-market service and sales of spares parts for its drilling equipment.~~..............................~~ ~~72,229~~Customers ~~37,457~~include 16onshore and offshore drilling contractors,~~963~~ ~~--------~~major ~~-------~~oil ~~-------~~and ~~$132~~gas companies,~~095~~ ~~$45~~independent producers,~~847~~ ~~$50~~national oil companies,~~062~~ ~~========~~and ~~=======~~oilfield ~~=======~~distributors.

~~2001~~The ~~2000~~Tubular ~~1999~~Services ~~-------~~group ~~-------~~provides ~~-------~~internal ~~Current~~coating ~~provision:~~products ~~U.S........................................~~and ~~$27~~services,~~809~~ $inspection 3services,~~346~~ $and ~~2,549~~quality ~~Foreign~~assurance services for oil country tubular goods.~~...................................~~ 29Oil country tubular goods (“OCTG”) include drill pipe,~~464~~ 15tubing,~~612~~ 14casing,~~928~~ sucker ~~-------~~rods, ~~-------~~and ~~-------~~flowlines. ~~Total~~Additionally, ~~current~~this ~~provision................~~group ~~57,273~~sells 18and rents proprietary equipment used to inspect tubular products at steel mills,~~958~~ 17and designs,~~477~~ ~~-------~~manufactures ~~-------~~and sells corrosion-~~------~~resistant ~~Deferred~~high ~~provision~~pressure ~~(benefit):~~fiberglass ~~U.S........................................~~and ~~(3,162)~~composite 5tubular goods for oilfield,~~045~~ 8industrial,~~744~~ ~~Foreign~~and marine applications.~~...................................~~ ~~(4,984)~~The ~~789~~Tubular ~~(5,968)~~Services ~~-------~~group ~~-------~~also provides technical inspection services and quality assurance services for in-~~------~~service ~~Total~~pipelines ~~deferred~~used ~~provision~~to ~~(benefit)~~transport oil and gas.~~....~~ ~~(8,146)~~Customers 5include major oil and gas companies,~~834~~ 2independent producers,~~776~~ ~~-------~~national ~~-------~~oil ~~-------~~companies, ~~Total~~drilling ~~provision........................~~contractors, ~~$49~~oilfield supply stores,~~127~~ ~~$24~~industrial plant operators,~~792~~ ~~$20~~pipeline operators,~~253~~ ~~=======~~and ~~=======~~steel ~~=======~~mills.

~~2001~~The ~~2000~~Drilling ~~1999~~Services ~~-------~~group ~~-------~~sells ~~-------~~and ~~Tax~~rents ~~expense~~technical atequipment ~~federal~~used ~~statutory~~in, ~~rate...........................~~and ~~$46,232~~provides ~~$16,046~~services ~~$17~~related to,~~522~~ ~~Incremental~~the ~~effect~~separation and management of ~~foreign~~drill ~~operations........................~~cuttings ~~4,446~~(solids) ~~1,892~~from ~~695~~fluids ~~Nondeductible~~used ~~goodwill~~in ~~amortization~~the oil and ~~merger~~gas ~~related~~drilling ~~costs~~process (“Solids Control”).~~...~~ ~~1,621~~The ~~8,906~~Drilling ~~3,280~~Services ~~State~~group ~~income~~also ~~taxes,~~sells ~~net~~and ofrents ~~federal~~data ~~benefit......................~~collection --and ~~488~~monitoring ~~612~~systems ~~FSC~~used ~~benefit.....................................................~~to ~~(3,490)~~manage ~~(940)~~the ~~(676)~~drilling ~~Change~~process on insite ~~valuation~~(“Rig ~~allowance~~Instrumentation”).~~..................................~~ --Customers ~~(271)~~include --major ~~Other,~~oil ~~net......................................................~~and ~~318~~gas (1companies,~~329)~~ (1independent producers,~~180)~~ ~~-------~~national ~~-------~~oil ~~------- $49~~companies,~~127~~ ~~$24,792~~drilling ~~$20,253~~fluids ~~=======~~providers ~~=======~~and ~~=======~~drilling contractors.

~~2001~~The ~~2000~~Coiled ~~-------~~Tubing ~~-------~~& ~~Gross~~Wireline ~~deferred~~Products ~~tax~~group ~~assets: Receivables............................................. $ 1~~designs,~~492~~ ~~$ 2~~manufactures,~~106~~ ~~U.S.~~ and sells ~~foreign~~highly-engineered ~~net~~coiled ~~operating losses................... 1~~tubing,~~708~~ ~~1,910~~coiled ~~Accrued~~tubing ~~liabilities~~units and ~~other~~related ~~reserves..................~~equipment ~~2,565~~as ~~6,466~~well ~~Inventory~~as ~~reserves~~pressure ~~and~~control ~~intercompany~~equipment ~~profit~~and ~~elimination..~~equipment ~~8,019~~used ~~3,635~~in ~~Tax~~pressure ~~credit~~pumping ~~carry~~and ~~forwards...............................~~wireline ~~6,576 2,368 Post retirement benefit obligation~~operations.~~.....................~~ ~~5,099~~These ~~3,967~~products ~~-------~~are ~~-------~~used ~~Subtotal~~in ~~gross~~oil ~~deferred~~and ~~tax~~gas ~~assets..................~~well 25drilling,~~459~~ ~~20,452~~completion and ~~Valuation~~remediation ~~allowance~~operations.~~....................................~~ ~~(913)~~Customers ~~(967)~~include ~~-------~~oil ~~------- Net deferred tax assets.................................... 24,546 19,485 ------- ------- Gross deferred tax liabilities: Property~~ and ~~equipment..................................~~gas ~~26,606~~coiled ~~25,339~~tubing ~~Intangible~~service ~~assets....................................... 2~~companies,~~615~~ ~~2,094~~pressure ~~Reserve~~pumping ~~for unremitted foreign earnings................. 6~~companies,~~500~~ ~~6,500~~national ~~All~~oil ~~other............................................... 811 1~~companies,~~530~~ ~~-------~~major ~~-------~~oil ~~Gross deferred tax liabilities............................. 36~~companies,~~532~~ ~~35,463~~and ~~-------~~independent ~~------- Total net deferred tax liability~~producers.~~..........................~~ ~~$11,986 $15,978 ======= =======~~

~~2001~~In ~~2000~~January ~~--------~~2004, ~~--------~~the ~~(in~~Company ~~thousands)~~announced ~~$200,000,000~~its ~~Senior~~plans ~~Subordinated~~to ~~Notes,~~discontinue ~~interest~~its atMorinoak International ~~7.25%~~Ltd ~~payable~~(MIL) ~~semiannually,~~rig ~~principal~~fabrication ~~due~~operation onin ~~May~~England. 1,The ~~2011.....................~~MIL ~~$201,524~~rig $fabrication --business ~~$100,000,000~~was ~~Senior~~closed ~~Subordinated~~during ~~Notes,~~the ~~interest~~first atquarter 7of 2004.5% ~~payable~~As ~~semiannually~~a result, ~~principal~~the ~~due~~prior onyear ~~February~~MIL ~~15,~~results ~~2008...............~~have ~~99,118~~been ~~100,000~~reclassified ~~$130,000,000~~to ~~Term~~report ~~Notes~~this ~~payable~~operation toas ~~lenders~~discontinued, ~~interest~~and 2001, at2002, ~~7.825%~~and at2003 ~~December~~results ~~31,~~have ~~2000..............................................~~been --restated ~~26,832~~herein ~~Other~~to reflect the reclassification.~~...........................................................~~ ~~21,972~~There ~~9,675~~is ~~--------~~no ~~--------~~impact ~~Total~~on ~~debt.......................................................~~2000 ~~322,614~~results ~~136,507~~as ~~Less:~~MIL ~~Current~~was ~~maturities~~purchased in 2001.~~........................................~~ ~~7,077~~Previously ~~30,347~~these ~~--------~~results ~~--------~~were ~~Long-term~~included ~~debt................................................~~as ~~$315,537~~part ~~$106,160~~of ~~========~~the ~~========~~Drilling Equipment group operations.

~~2001~~2 2000 1999 ----- ------ ----- Interest cost............................... $ 701 $ 733 $ 669 Amortization of transition obligation....... 763 763 763 Amortization of gain........................ (485) (471) (534) ----- ------ ----- $ 979 $1,025 $ 898 ===== ====== =====

2001Table 2000 -------- -------- Benefit obligation at beginning of year..... $ 10,134 $ 10,634 Interest cost............................... 701 733 Benefits paid............................... (932) (908) Actuarial loss (gain)....................... 1,108 (325) -------- -------- Benefit obligation at end of year........... $ 11,011 $ 10,134 ======== ======== Funded status............................... $(11,011) $(10,134) Unrecognized actuarial (gain)............... (4,564) (6,158) Unrecognized transition obligation.......... 8,380 9,143 -------- -------- Accrued postretirement benefit obligation... $ (7,195) $ (7,149) ======== ========Contents

~~2001~~The ~~2000~~following ~~1999~~table ~~-----~~sets ~~-----~~forth ~~-----~~the ~~Service~~contribution ~~cost................................~~to $the ~~204~~Company’s $total ~~186~~revenues $of ~~202~~its ~~Interest~~four operating ~~cost...............................~~groups: ~~567 529 557 Net amortization............................ (350) (352) (352) ----- ----- ----- Pension expense.......................... $ 421 $ 363 $ 407 ===== ===== =====~~

2001 2000 ------ ------ Projected benefit obligation at beginning of year..... $7,543 $7,950 Service cost.......................................... 204 186 Interest cost......................................... 567 529 Benefits paid......................................... (211) (197) Exchange rate change.................................. 2 (925) ------ ------ Projected benefit obligation at the end of the year... 8,105 7,543 Unrecognized net gain................................. 203 553 ------ ------ Pension liability..................................... 8,308 8,096 Less--amount included in current liabilities.......... 211 197 ------ ------ Noncurrent portion of pension liability............... $8,097 $7,899 ====== ======


	Years Ended December 31,
	2004		2003 (restated)		2002 (restated)
	(in millions)
Drilling Equipment	$	445.4	$	462.2	$	474.0
Tubular Services		536.9		455.9		356.0
Drilling Services		338.9		292.6		278.6
Coiled Tubing & Wireline Products		246.9		226.9		213.8

Total	$	1,568.1	$	1,437.6	$	1,322.4

~~Years~~On ~~Ended~~August ~~December~~11, 312004, the ~~-----------------------------------~~Company ~~2001~~entered ~~2000~~into ~~1999~~an ~~----------~~Agreement ~~-----------~~and Plan of Merger with National-~~---------~~Oilwell, ~~Shares~~Inc. ~~under~~(National ~~option~~Oilwell) atwhereby ~~beginning~~the ofCompany ~~year....~~will ~~4,520,618~~merge ~~5,068,068~~with ~~3,582,989~~and ~~Granted~~into National Oilwell.~~....................................~~ ~~1,176,241~~Under ~~687,443~~the 2terms of the agreement,~~100,112~~ ~~Cancelled~~each outstanding share of the Company’s common stock will be converted into the right to receive 0.~~..................................~~8363 ~~(125,958)~~of ~~(182,918)~~a ~~(114,288)~~share ~~Exercised~~of National Oilwell common stock.~~..................................~~ ~~(837,032)~~National ~~(1,051,975)~~Oilwell ~~(500,745)~~will ~~----------~~assume ~~-----------~~all ~~----------~~options ~~Shares~~outstanding under the Company’s stock option atplans ~~end~~and ofeach ~~year..........~~outstanding ~~4,733,869~~option ~~4,520,618~~to 5purchase the Company’s common stock will be converted into an option to purchase National Oilwell common stock,~~068,068~~ ~~----------~~subject ~~-----------~~to ~~----------~~certain ~~Average~~adjustments to the exercise price and the number of ~~outstanding~~shares ~~options........~~issuable $upon ~~14.47~~exercise $of ~~11.88~~those $options 8to reflect the exchange ratio.05 ~~==========~~In ~~===========~~the ~~==========~~event ~~Exercisable~~of ata ~~end~~termination of ~~year..................~~the ~~2,766,843~~agreement ~~3,087,409~~under 2certain circumstances,~~123,147~~ ~~==========~~Varco ~~===========~~may ~~==========~~be required to pay National Oilwell a termination fee of $75 million.

~~Options~~The ~~Outstanding~~completion ~~Options~~of ~~Exercisable~~the ~~Weighted-Avg.~~merger ~~------------------------~~is ~~------------------------~~subject ~~Remaining~~to ~~Weighted-Avg.~~several ~~Weighted-Avg.~~conditions, ~~Range~~including the approval of ~~Exercise~~the ~~Price~~merger ~~Contractual~~agreement ~~Life~~by ~~Shares~~the stockholders ~~Exercise~~of ~~Price~~the ~~Shares~~Company ~~Exercise~~and ~~Price~~National ~~-----------------------~~Oilwell ~~----------------~~and ~~---------~~the ~~--------------~~expiration ~~---------~~or termination of the applicable waiting period under the Hart-Scott-~~------------~~Rodino $Antitrust 3Improvements Act of 1976.21 National Oilwell and Varco have responded to $the 7Antitrust Division of the U.~~5625~~S... ~~4.99~~Department ~~1,651,454~~of $Justice’s ~~6.62~~request ~~1,492,361~~for $additional ~~6.52~~information ~~11.10~~issued tounder ~~18.21.....~~the ~~6.80~~Hart-Scott-Rodino 1Antitrust Improvements Act of 1976,~~441,716~~ ~~14.83~~as ~~836~~amended,~~890~~ ~~14.99~~and ~~20.00~~continue to ~~32.55.....~~work ~~8.21~~with ~~1,640,699~~the ~~22.06~~Justice ~~437,592~~Department 24regarding the proposed merger between the companies.17 ~~----~~Closing ~~---------~~of ~~------~~the ~~---------~~proposed ~~------~~merger ~~Totals...............~~is ~~6.66~~expected ~~4,733,869~~to ~~$14.47~~occur ~~2,766,843~~as ~~$11~~quickly as possible after regulatory clearance and stockholder approvals are received.87 ~~====~~A ~~=========~~special ~~======~~meeting ~~=========~~of ~~======~~the stockholders of Varco to approve the merger has been scheduled for March 11, 2005.

~~Coiled~~The ~~Drilling~~Company’s ~~Tubing~~principal &executive ~~Equipment~~offices are ~~Tubular~~located ~~Drilling~~at ~~Wireline~~2000 ~~Other~~West ~~Sales~~Sam ~~Services~~Houston ~~Services~~Parkway ~~Products Unallocated Total --------- -------- -------- -------- ----------- ---------- (in thousands) 2001 Revenue....................... $395~~South,~~550~~ ~~$352,624~~Suite ~~$314~~1700,~~272~~ ~~$205~~Houston,~~363~~ $Texas ~~-- $1~~77042,~~267,809~~ ~~Operating~~its ~~profit..............~~telephone ~~39,162~~number ~~67,740~~is ~~70,502 44,902~~ (~~47,680~~281) ~~174~~953-2200,~~626~~ ~~Total~~and ~~assets..................~~its ~~324,741~~Internet ~~366,390~~web ~~442,018~~site ~~253,246~~address ~~42,715~~is ~~1,429,110 Capital expenditures~~http://www.varco.com.~~.......~~ ~~13,992~~The ~~12,645~~Company’s ~~34,248~~annual ~~3,408~~reports ~~1,541~~on 65Form 10-K,~~834~~ ~~Depreciation~~quarterly reports ~~and~~on ~~amortization.~~Form ~~16,168~~10-Q ~~15,783~~and ~~21,791~~current ~~4,623~~reports ~~9,535~~on 67Form 8-K,~~900~~ ~~2000~~and ~~Revenue.......................~~all ~~$283,360~~amendments ~~$248~~thereto,~~099~~ ~~$250,229~~are $available ~~84,927~~free $of --charge $on ~~866,615~~its ~~Operating~~Internet ~~profit~~website.~~.............~~ ~~30,193~~These ~~39,666~~reports ~~39,673~~are ~~13,895~~posted ~~(35,946)~~on ~~87,481~~its ~~Total~~website ~~assets..................~~as ~~223,369~~soon ~~336,243~~as ~~391,310~~reasonably ~~106,675~~practicable ~~19,385~~after ~~1,076,982~~such ~~Capital~~reports ~~expenditures..........~~are ~~9,750~~electronically filed ~~11,178~~with ~~22,413~~the ~~999~~Securities ~~1,123~~and ~~45,463~~Exchange ~~Depreciation~~Commission ~~and amortization~~(SEC). ~~14,966 13,221 20,345 1,722 6,264 56,518~~

~~Coiled~~The Company ~~Drilling~~has ~~Tubing~~included &a ~~Equipment~~glossary ~~Tubular~~of ~~Drilling~~technical ~~Wireline~~terms ~~Other~~at ~~Sales~~the ~~Services~~end ~~Services~~of ~~Products~~Item Unallocated Total --------- -------- -------- -------- ----------- ---------- (in thousands) 1999 Revenue....................... $504,245 $194,929 $202,518 $ 74,156 $ -- $ 975,848 Operating profit.............. 77,662 21,076 8,547 7,084 (39,213) 75,156 Total assets.................. 254,534 300,672 378,053 92,148 105,906 1~~,131,313~~ ~~Capital~~of ~~expenditures..........~~this ~~10,488~~Annual ~~4,046 13,047 1,645 1,503 30,729 Depreciation and amortization~~Report. ~~15,904 14,565 18,018 2,186 6,507 57,180~~

~~2001~~Influence ~~2000~~of ~~1999~~Oil ~~----------~~and ~~--------~~Gas ~~--------~~Activity ~~(in~~Levels ~~thousands)~~on ~~U.S.....................~~the $Company’s ~~527,060~~Business $351,252 $448,950 Canada.................. 102,817 66,916 50,915 Latin America........... 167,253 140,589 104,416 United Kingdom.......... 86,163 55,056 58,797 Other Europe............ 153,916 89,781 139,752 Far East................ 100,274 75,330 91,064 Other................... 130,326 87,691 81,954 ---------- -------- -------- Total................... $1,267,809 $866,615 $975,848 ========== ======== ========

~~2001~~The ~~2000~~oil ~~1999~~and ~~--------~~gas ~~--------~~industry ~~-------- (~~in ~~thousands)~~which ~~U.S....................................~~the ~~$224,118~~Company ~~$195,695~~participates ~~$192,995~~has ~~Latin~~historically ~~America~~experienced significant volatility.~~.........................~~ ~~48,468~~Demand ~~47,368~~for ~~43,205~~the ~~Canada.................................~~Company’s ~~43,006~~services ~~25,886~~and products ~~25,799~~depends ~~United~~primarily ~~Kingdom.........................~~upon ~~48,226~~the ~~38,983~~general ~~40,110~~level ~~Netherlands............................~~of ~~9,278~~activity 9in the oil and gas industry worldwide,~~842~~ 11including the number of drilling rigs in operation,~~345~~ ~~Other~~the ~~Europe...........................~~number 12of oil and gas wells being drilled,~~491~~ 13the depth and drilling conditions of these wells,~~014~~ the 11volume of production,~~853~~ ~~Far~~the ~~East~~number of well completions and the level of well remediation activity.~~..............................~~ ~~13,213~~Oil 11and gas activity is in turn heavily influenced by,~~966~~ 11among other factors,~~958~~ ~~Middle~~oil ~~East~~and gas prices worldwide.~~...........................~~ ~~1,616~~High ~~919~~levels ~~1,999~~of ~~--------~~drilling and well-~~-------~~remediation ~~--------~~activity ~~Total~~generally spur demand for the Company’s products and services used to drill and remediate oil and gas wells.~~.................................~~ ~~$400~~Additionally,~~416~~ ~~$343~~high levels of oil and gas activity increase cash flows available for drilling contractors,~~673~~ well-remediation ~~$339~~service companies,~~264~~ ~~========~~and ~~========~~manufacturers ~~========~~of oil country tubular goods to invest in capital equipment which the Company sells.

~~Year~~In ~~Ended December 31~~2004, ~~2001~~approximately ~~-----------------------------------------------------------------~~40% ~~Varco~~of ~~Non-~~the ~~International,~~Company’s ~~Guarantor~~Drilling ~~Guarantor~~Equipment ~~Inc.~~group’s ~~Subsidiaries~~revenues ~~Subsidiaries~~resulted ~~Eliminations~~from ~~Consolidated~~capital ~~--------------~~expenditures ~~------------~~of ~~------------~~drilling ~~------------~~contractors ~~------------ (In thousands) CONDENSED CONSOLIDATING BALANCE SHEET Current assets: Cash~~ and oil ~~cash~~companies ~~equivalents.................~~on $equipment ~~5,562~~for $new ~~25,137~~drilling $rig ~~26,800~~fabrication $or --drilling $rig ~~57,499~~refurbishment ~~Accounts receivable, net~~projects.~~.................~~ ~~274,127~~Capital ~~609,398~~expenditures ~~883,931~~are ~~(1,425,420)~~influenced ~~342,036~~by ~~Inventory,~~cash ~~net............................~~flows --these ~~167,157~~contractors ~~62,521~~generate --from ~~229,678~~drilling ~~Other current assets...................... -- 27~~activity,~~516~~ ~~6,476~~but --also ~~33,992~~by ~~----------~~the ~~----------~~availability ~~----------~~of ~~----------- ---------- Total current assets.................. 279~~financing,~~689~~ ~~829,208~~the outlook ~~979,728~~for ~~(1,425,420)~~future ~~663,205~~drilling ~~Investment in subsidiaries................... 984~~activity,~~501~~ ~~456,972 -- (1,441,473) -- Property~~ and ~~equipment,~~other ~~net~~factors.~~.................~~ --Generally ~~267,819~~the ~~132,597~~Company --believes ~~400,416~~the ~~Identifiable~~demand ~~intangibles,~~for ~~net................~~more --drilling ~~29,586~~capital ~~1,136~~equipment --lags ~~30,722~~increases ~~Goodwill,~~in ~~net................................~~the --level ~~192,822~~of ~~132,313~~drilling ~~-- 325,135 Other assets, net~~activity.~~...........................~~ ~~5,420~~Approximately ~~3,386~~60% 826 -- 9,632 ---------- ---------- ---------- ----------- ---------- Total assets.......................... $1,269,610 $1,779,793 $1,246,600 $(2,866,893) $1,429,110 ========== ========== ========== =========== ========== Current liabilities: Accounts payable.......................... $ 117,995 $ 697,155 $ 712,829 $(1,425,420) $ 102,559 Accrued liabilities....................... 5,255 61,694 35,366 -- 102,315 Income taxes.............................. -- 16,716 10,936 -- 27,652 Current portion of ~~long-term~~the ~~debt.........~~Drilling --Equipment ~~3,058~~group’s 4,019 -- 7,077 ---------- ---------- ---------- ----------- ---------- Total current liabilities............. 123,250 778,623 763,150 (1,425,420) 239,603 Long-term debt............................... 300,642 7,362 7,533 -- 315,537 Pension liabilities.......................... 17,404 -- 8,430 -- 25,834 Deferred taxes payable....................... -- 9,307 9,297 -- 18,604 Other liabilities............................ -- -- 1,218 -- 1,218 ---------- ---------- ---------- ----------- ---------- Total liabilities..................... 441,296 795,292 789,628 (1,425,420) 600,796 Common stock................................. 974 -- -- -- 974 Paid revenue in ~~capital..............................~~2004 ~~514,137~~was ~~579,352~~related ~~244,777~~to ~~(824,129)~~the ~~514,137~~sale ~~Retained~~of ~~earnings............................~~drilling ~~347,548~~equipment ~~405,149~~spare ~~231,210~~parts ~~(636,359)~~and ~~347~~consumables,~~548~~ ~~Cumulative~~the ~~translation~~provision ~~adjustment............~~of ~~(19,015)~~ equipment--repair ~~(19~~services,~~015)~~ ~~19,015~~and ~~(19,015)~~the ~~Treasury~~rental ~~stock...............................~~of ~~(15,330)~~drilling ~~-- -- -- (15~~equipment,~~330)~~ ~~----------~~which ~~----------~~the ~~----------~~Company ~~-----------~~believes ~~----------~~are ~~Total~~generally ~~common~~determined ~~stockholders'~~directly ~~equity.....~~by ~~828,314~~the ~~984,501~~level ~~456,972~~of drilling ~~(1,441,473) 828,314 ---------- ---------- ---------- ----------- ---------- Total liabilities and equity~~activity.~~.........~~ ~~$1,269,610 $1,779,793 $1,246,600 $(2,866,893) $1,429,110 ========== ========== ========== =========== ==========~~

Year Ended December 31, 2000 ----------------------------------------------------------------- Varco Non- International, Guarantor Guarantor Inc. Subsidiaries Subsidiaries Eliminations Consolidated -------------- ------------ ------------ ------------ ------------ (In thousands) CONDENSED CONSOLIDATING BALANCE SHEET Current assets: Cash and cash equivalents................. $ -- $ (2,729) $ 14,905 $ -- $ 12,176 Accounts receivable, net.................. 224,554 375,505 361,106 (691,772) 269,393 Inventory, net............................ -- 118,552 33,798 -- 152,350 Other current assets...................... 1,174 13,823 6,790 -- 21,787 -------- ---------- -------- ----------- ---------- Total current assets.................. 225,728 505,151 416,599 (691,772) 455,706 Investment in subsidiaries................... 736,507 357,804 -- (1,094,311) -- Property and equipment, net.................. -- 229,557 114,116 -- 343,673 Identifiable intangibles, net................ -- 26,062 -- -- 26,062 Goodwill, net................................ -- 124,489 114,152 -- 238,641 Other assets, net............................ -- 11,379 1,521 -- 12,900 -------- ---------- -------- ----------- ---------- Total assets.......................... $962,235 $1,254,442 $646,388 $(1,786,083) $1,076,982 ======== ========== ======== =========== ========== Current liabilities: Accounts payable.......................... $101,330 $ 415,795 $240,829 $ (691,772) $ 66,182 Accrued liabilities....................... 3~~,117~~ 65,732 22,574 -- 91,423 Income taxes.............................. -- (1,673) 6,049 -- 4,376 Current portion of long-term debt......... 26,832 3,014 501 -- 30,347 -------- ---------- -------- ----------- ---------- Total current liabilities............. 131,279 482,868 269,953 (691,772) 192,328 Long-term debt............................... 98,973 7,018 169 -- 106,160 Pension liabilities.......................... -- 14,085 7,899 -- 21,984 Deferred taxes payable....................... -- 11,410 9,457 -- 20,867 Other liabilities............................ -- 2,554 1,106 -- 3,660 -------- ---------- -------- ----------- ---------- Total liabilities..................... 230,252 517,935 288,584 (691,772) 344,999 Common stock................................. 962 -- -- -- 962 Paid in capital.............................. 498,692 434,976 205,747 (640,723) 498,692 Retained earnings............................ 264,580 301,531 168,978 (470,509) 264,580 Cumulative translation adjustment............ (16,921) -- (16,921) 16,921 (16,921) Treasury stock............................... (15,330) -- -- -- (15,330) -------- ---------- -------- ----------- ---------- Total common stockholders' equity..... 731,983 736,507 357,804 (1,094,311) 731,983 -------- ---------- -------- ----------- ---------- Total liabilities and equity.......... $962,235 $1,254,442 $646,388 $(1,786,083) $1,076,982 ======== ========== ======== =========== ==========

YearTable Ended December 31, 2001 -------------------------------------- Varco Guarantor Non-Guarantor International, Inc. Subsidiaries Subsidiaries Eliminations Consolidated ------------------- ------------ ------------- ------------ ------------ (In thousands) CONDENSED CONSOLIDATING STATEMENT OF INCOME Revenue............................. $ -- $943,231 $485,548 $(160,970) $1,267,809 Operating costs..................... -- 874,302 396,351 (160,970) 1,109,683 -------- -------- -------- --------- ---------- Operating profit.................... -- 68,929 89,197 -- 158,126 Other expenses...................... 926 1,947 1,382 -- 4,255 Interest expense.................... 19,724 949 1,103 -- 21,776 -------- -------- -------- --------- ---------- Income (loss) before income taxes... (20,650) 66,033 86,712 -- 132,095 Provision for income taxes.......... -- 24,647 24,480 -- 49,127 Equity in net income of subsidiaries 103,618 62,232 -- (165,850) -- -------- -------- -------- --------- ---------- Net income.......................... $ 82,968 $103,618 $ 62,232 $(165,850) $ 82,968 ======== ======== ======== ========= ========== Year Ended December 31, 2000 -------------------------------------- Varco Guarantor Non-Guarantor International, Inc. Subsidiaries Subsidiaries Eliminations Consolidated ------------------- ------------ ------------- ------------ ------------ (In thousands) CONDENSED CONSOLIDATING STATEMENT OF INCOME Revenue............................. $ -- $599,683 $377,444 $(110,512) $ 866,615 Operating costs..................... -- 589,802 316,712 (100,810) 805,704 -------- -------- -------- --------- ---------- Operating profit.................... -- 9,881 60,732 (9,702) 60,911 Other expenses (income)............. 5,785 4,017 (318) (9,702) (218) Interest expense.................... 13,333 1,437 512 -- 15,282 -------- -------- -------- --------- ---------- Income (loss) before income taxes... (19,118) 4,427 60,538 -- 45,847 Provision for income taxes.......... -- 8,391 16,401 -- 24,792 Equity in net income of subsidiaries 40,173 44,137 -- (84,310) -- -------- -------- -------- --------- ---------- Net income.......................... $ 21,055 $ 40,173 $ 44,137 $ (84,310) $ 21,055 ======== ======== ======== ========= ========== Year Ended December 31, 1999 -------------------------------------- Varco Guarantor Non-Guarantor International, Inc. Subsidiaries Subsidiaries Eliminations Consolidated ------------------- ------------ ------------- ------------ ------------ (In thousands) CONDENSED CONSOLIDATING STATEMENT OF INCOME Revenue............................. $ -- $687,049 $386,462 $ (97,663) $ 975,848 Operating costs..................... -- 666,861 339,302 (97,663) 908,500 -------- -------- -------- --------- ---------- Operating profit.................... -- 20,188 47,160 -- 67,348 Other expenses (income)............. 568 (1,150) (1,058) -- (1,640) Interest expense.................... 16,691 1,605 630 -- 18,926 -------- -------- -------- --------- ---------- Income (loss) before income taxes... (17,259) 19,733 47,588 -- 50,062 Provision for income taxes.......... -- 11,292 8,961 -- 20,253 Equity in net income of subsidiaries 47,068 38,627 -- (85,695) -- -------- -------- -------- --------- ---------- Net income.......................... $ 29,809 $ 47,068 $ 38,627 $ (85,695) $ 29,809 ======== ======== ======== ========= ==========Contents

~~Year~~The ~~Ended~~majority ~~December~~of ~~31,~~the ~~2001~~Company’s ~~-----------------------------------------------------------------~~Tubular ~~Varco~~Service ~~Non-~~group’s ~~International,~~revenues ~~Guarantor~~are ~~Guarantor~~directly ~~Inc.~~related ~~Subsidiaries~~to ~~Subsidiaries~~the level ~~Eliminations~~of ~~Consolidated~~demand ~~--------------~~for ~~------------~~oil ~~------------~~country ~~------------~~tubular ~~------------~~goods, ~~(In~~which ~~thousands)~~is ~~CONDENSED~~determined ~~CONSOLIDATING STATEMENT OF CASH FLOWS Net cash provided~~ by ~~(used~~the ~~for)~~level ~~operating~~of ~~activities............................... $ (38~~drilling,~~262)~~ ~~$ 196~~completion,~~610~~ $and ~~70,023~~well ~~$(144,376)~~servicing $activity ~~83,995 Net cash provided by~~ (~~used~~which ~~for)~~use ~~investing~~oil ~~activities:~~country ~~Capital~~tubular ~~expenditures~~goods).~~......................~~ --A ~~(38,566)~~portion ~~(27,268) -- (65,834) Business acquisitions, net~~ of ~~cash~~Tubular ~~acquired~~Services --sales ~~(109,290)~~are ~~(36,663)~~related --to (~~145,953~~1) ~~Investments~~demand infor ~~subsidiaries................ (144~~pipeline inspections,~~376)~~ --which --is ~~144,376~~generally --unrelated ~~Other......................................~~to --drilling --or ~~(1,121)~~well --remediation ~~(1,121)~~activity ~~---------~~and ~~---------~~may ~~--------~~be ~~---------~~adversely ~~---------~~affected ~~Net cash provided~~ by ~~(used~~high ~~for)~~commodity ~~investing~~prices ~~activities...............................~~that ~~(144,376)~~cause ~~(147,856)~~operators ~~(65,052)~~to ~~144,376~~defer ~~(212,908)~~inspections; ~~Net cash provided by~~ (~~used for~~2) ~~financing~~the ~~activities:~~sale ~~Net~~of ~~payments~~fiberglass ~~under~~and ~~financing~~composite ~~agreements....~~tubing ~~178,068~~to ~~(20~~industrial customers,~~888)~~ ~~7,588~~which --is ~~164,768~~generally ~~Net~~unrelated ~~proceeds~~to ~~from~~drilling ~~sale~~or ofwell ~~common~~remediation ~~stock.....~~activity ~~10,132~~but --may --be --tied ~~10,132~~somewhat ~~---------~~to ~~---------~~oil ~~--------~~and ~~---------~~gas ~~---------~~prices; ~~Net~~and ~~cash provided by~~ (~~used for~~3) ~~financing~~the ~~activities...............................~~sale ~~188,200~~of ~~(20,888)~~pipe ~~7,588~~inspection --equipment ~~174,900~~to ~~Effect~~the manufacturers of ~~exchange~~oil ~~rate~~country ~~changes~~tubular ongoods, ~~cash....~~which --is --indirectly related ~~(664)~~to --drilling ~~(664)~~activity, ~~Net increase~~ in ~~cash~~the ~~and~~Company’s ~~cash equivalents~~view.. ~~5,562~~Since ~~27,866~~the ~~11,895~~services --provided ~~45,323~~by ~~Cash~~this ~~and~~group ~~cash~~tend ~~equivalents:~~to ~~Beginning~~prolong ofthe ~~period.....................~~useful --life ~~(2,729) 14,905 -- 12,176 --------- --------- -------- --------- --------- End~~ of ~~period...........................~~steel $tubular 5products,~~562~~ $demand ~~25,137~~for $the ~~26,800~~services $may --be $impacted ~~57,499~~by ~~=========~~steel ~~=========~~costs. ~~======== ========= =========~~

~~Year~~The ~~Ended~~Company’s ~~December~~Drilling ~~31,~~Services ~~2000~~group’s ~~-----------------------------------------------------------------~~revenues ~~Varco~~are ~~Non-~~closely ~~International,~~tied to ~~Guarantor~~drilling Guarantor Inc. Subsidiaries Subsidiaries Eliminations Consolidated -------------- ------------ ------------ ------------ ------------ (In thousands) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS Net cash provided by (used for) operating activities................................... $ 55activity,~~689~~ ~~$(26,395)~~although $a ~~37,231~~portion ~~$ 15,262 $ 81,787 Net cash provided by (used for) investing activities: Capital expenditures........................... -- (21,420) (24,043) -- (45,463) Business acquisitions, net~~ of ~~cash~~Drilling ~~acquired....~~Services --revenues ~~(15,423)~~are ~~(6,262)~~related --to ~~(21,685)~~the Investments in subsidiaries.................... 15,262 -- -- (15,262) -- Other.......................................... -- -- 2,276 -- 2,276 -------- -------- -------- -------- -------- Net cash provided by (used for) investing activities................................... 15,262 (36,843) (28,029) (15,262) (64,872) Net cash used for financing activities: Net payments under financing agreements........ (81,000) (13,935) (1,832) -- (96,767) Net proceeds from sale of ~~common~~capital ~~stock.........~~equipment ~~10,049~~to --drilling ~~-- -- 10~~contractors,~~049~~ ~~--------~~which ~~--------~~is ~~--------~~indirectly ~~--------~~related ~~--------~~to ~~Net~~the ~~cash~~level ~~used~~of ~~for~~drilling ~~financing activities~~activity.~~........~~ ~~(70,951)~~The ~~(13,935)~~Company’s ~~(1,832)~~Drilling --Services ~~(86,718)~~sales ~~Effect~~ of consumables, ~~exchange~~such ~~rate~~as ~~changes~~shaker ~~on cash........ -- -- (1~~screens,~~138)~~ ~~-- (1,138) Net increase (decrease) in cash~~ and ~~cash~~spare ~~equivalents..................................~~parts --for ~~(77,173)~~its 6equipment,~~232~~ --are ~~(70,941)~~generally ~~Cash~~determined ~~and~~directly ~~cash~~by ~~equivalents:~~the ~~Beginning~~level of ~~period.........................~~drilling ~~-- 74~~activity,~~444~~ ~~8,673~~in --the ~~83,117~~Company’s ~~-------- -------- -------- -------- -------- End of period~~view.~~..............................~~ ~~$ -- $ (2,729) $ 14,905 $ -- $ 12,176 ======== ======== ======== ======== ========~~

~~Year~~The ~~Ended~~Company’s ~~December~~Coiled ~~31,~~Tubing ~~1999~~& ~~-----------------------------------------------------------------~~Wireline ~~Varco~~Products ~~Non-~~group’s ~~International,~~revenues ~~Guarantor~~are ~~Guarantor~~generally ~~Inc.~~driven ~~Subsidiaries Subsidiaries Eliminations Consolidated -------------- ------------ ------------ ------------ ------------ (In thousands) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS Net cash provided~~ by ~~(used~~the ~~in) operating activities............................... $ (5,229) $ 95,125 $ 10,145 $ 19,023 $119,064 Net cash provided by (used for) investing activities: Capital~~ capital expenditures~~.......................~~ ~~-- (19,704) (11,025) -- (30,729) Business acquisitions, net~~ of ~~cash~~well ~~acquired~~service ~~-- (11,373) (1,747) -- (13,120) Investments in subsidiaries~~contractors.~~...............~~ ~~19,023~~These --capital --expenditures ~~(19,023)~~are --influenced ~~Other...................................... -- 211 -- -- 211 -------- -------- -------- -------- -------- Net cash provided~~ by ~~(used~~the ~~for) investing activities............................... 19,023 (30,866) (12,772) (19,023) (43,638) Net~~ cash ~~used~~flows ~~for~~these ~~financing~~contractors ~~activities:~~generate ~~Net~~from ~~payments~~well ~~under~~completion ~~financing~~and ~~agreements....~~remediation ~~(19~~activity,~~419)~~ ~~(14,429)~~but ~~(1,668)~~also --by ~~(35,516)~~the ~~Net~~availability ~~proceeds from sale~~ of ~~common stock..... 5~~financing,~~625~~ --the --outlook ~~-- 5,625 -------- -------- -------- -------- -------- Net cash used~~ for ~~financing~~future ~~activities.....~~well remediation ~~(13~~activity,~~794)~~ ~~(14,429)~~and ~~(1,668)~~other --factors. ~~(29,891)~~A ~~Effect~~portion of ~~exchange~~the ~~rate~~Coiled ~~changes~~Tubing on& ~~cash....~~Wireline --Products --revenue ~~(291)~~is --determined ~~(291)~~by ~~Net~~the ~~increase~~demand ~~(decrease)~~for inspare ~~cash~~parts and ~~cash~~consumables, ~~equivalents..............................~~the --provision ~~49,830~~of ~~(4,586)~~equipment --repair 45services,~~244~~ ~~Cash~~ and ~~cash~~the ~~equivalents:~~rental ~~Beginning~~ of ~~period.....................~~well ~~-- 24~~servicing equipment,~~614~~ ~~13,259~~which --the ~~37,873~~Company ~~--------~~believes ~~--------~~are ~~--------~~generally ~~--------~~determined ~~--------~~directly ~~End~~by ofthe ~~period...........................~~level $of --well $completion ~~74,444~~and $remediation ~~8,673~~activity. ~~$ -- $ 83,117 ======== ======== ======== ======== ========~~

~~Basic~~Drilling ~~Dilutive~~and ~~Earnings~~well ~~Earnings~~servicing ~~(Loss)~~activity ~~(Loss)~~can ~~Operating~~fluctuate ~~Net~~significantly ~~Per~~in ~~Per~~a ~~Profit~~short ~~Income~~period ~~Common~~of ~~Common~~time. ~~Revenue~~The ~~(Loss)~~willingness ~~(Loss)~~of ~~Share~~oil ~~Share~~and ~~----------~~gas ~~---------~~operators ~~--------~~to ~~--------~~make ~~--------~~capital investments ~~(In~~to ~~thousands,~~explore ~~except~~ for ~~share~~and ~~data)~~produce ~~2001~~oil ~~First~~and ~~Quarter................~~natural $gas ~~274,213~~will $continue ~~36,644~~to $be ~~19,127~~influenced $by ~~0.20~~numerous $factors ~~0.20~~over ~~Second~~which ~~Quarter...............~~the ~~303,875~~Company ~~25,940~~has 11no control,~~747~~ ~~0.12~~including: ~~0.12~~the ~~Third~~ability ~~Quarter................~~of ~~327,472~~the ~~46,334~~members ~~24,898~~of ~~0.26~~the ~~0.26~~Organization ~~Fourth~~of ~~Quarter...............~~Petroleum ~~362,249~~Exporting ~~49,208~~Countries (“OPEC”) ~~27,196~~to ~~0.28~~maintain ~~0.28~~oil ~~----------~~price ~~--------~~stability ~~--------~~through ~~------~~voluntary ~~------~~production ~~Total~~limits ~~Year................~~of ~~$1,267,809~~oil; ~~$158,126~~the $level ~~82,968~~of $oil ~~0.87~~production $by ~~0.86~~non-OPEC ~~==========~~countries; ~~========~~supply ~~========~~and ~~======~~demand ~~======~~for ~~2000~~oil ~~First~~and ~~Quarter................~~natural $gas; ~~203,775~~general $economic ~~18,602~~and $political ~~8,768~~conditions; $costs ~~0.10~~of exploration $and ~~0.09~~production; ~~Second~~and ~~Quarter...............~~the ~~205,821~~availability ~~(7,233)~~of ~~(12,593)~~new ~~(0.14)~~leases ~~(0.14)~~and ~~Third~~concessions; ~~Quarter................~~and ~~211,393~~governmental ~~21,141~~regulations 10regarding,~~815~~ ~~0.12~~among ~~0.11~~other ~~Fourth~~things, ~~Quarter...............~~environmental ~~245~~protection,~~626~~ 28taxation,~~401~~ ~~14,065~~price ~~0.15~~controls 0and product allocations.15 ~~----------~~The ~~--------~~willingness ~~--------~~of ~~------~~drilling contractors ~~------~~and ~~Total~~well ~~Year................~~remediation $contractors ~~866,615~~to $make ~~60,911~~capital $expenditures ~~21,055~~for $the ~~0.23~~type $of ~~0.22~~specialized ~~==========~~equipment ~~========~~the ~~========~~Company ~~======~~provides ~~======~~is ~~1999~~also ~~First~~influenced ~~Quarter................~~by $numerous ~~247,095~~factors $over ~~22,197~~which $the ~~12,039~~Company $has ~~0.13~~no $control, ~~0.13~~including: ~~Second~~the ~~Quarter...............~~general ~~248,084~~level ~~19,609~~of ~~9,689~~oil and ~~0.11~~gas ~~0.10~~well ~~Third~~drilling ~~Quarter................~~and ~~235,710~~well ~~19,071~~remediation; ~~8,823~~access ~~0.10~~to ~~0.09~~external ~~Fourth~~financing; ~~Quarter...............~~outlook ~~244,959~~for ~~6,471~~future ~~(742)~~increases ~~(0.01)~~in ~~(0.01)~~well ~~----------~~drilling ~~--------~~and ~~--------~~well ~~------~~remediation ~~------~~activity; ~~Total~~steel ~~Year................~~prices $and ~~975,848~~fabrication $costs; ~~67,348~~and $government 29regulations regarding,~~809~~ $among ~~0.33~~other $things, environmental ~~0.32~~protection, ~~==========~~taxation, ~~========~~and ~~========~~price ~~======~~controls. ~~======~~

~~December~~Drilling ~~31,~~activity ~~December~~was ~~31,~~generally high in 2001, ~~2000~~but ~~------------~~began ~~------------~~to (decline in ~~thousands)~~the ~~ASSETS~~second ~~------~~half ~~Cash~~due to lower oil and ~~cash~~gas ~~equivalents~~prices.~~................................................~~ $Beginning 5in late 2002,~~562~~ $higher --gas ~~Amounts~~prices ~~due~~in ~~from~~the ~~affiliates~~U.S.~~.............................................~~ ~~272,851~~led ~~222,267~~to ~~Accounts~~rising ~~receivable.......................................................~~gas ~~1,276~~drilling ~~2,287~~activity ~~Other~~in ~~assets~~Canada and most U.S. onshore areas throughout 2003.~~...........................................................~~ ~~5,420~~Higher ~~1,174~~oil ~~Investment~~prices led to higher oil drilling activity levels in ~~subsidiaries................................................~~2003 ~~984~~in several international markets,~~501~~ ~~736~~including the Middle East,~~507~~ ~~----------~~the ~~--------~~Far ~~Total~~East ~~assets~~and several key Latin American markets.~~......................................................~~ $1However,~~269,610~~ ~~$962,235~~other ~~==========~~historically ~~========~~important markets ~~LIABILITIES~~for ~~AND~~the ~~EQUITY~~Company ~~----------------------~~remained ~~Amounts~~slow ~~due~~in to2003, ~~affiliates.................................................~~including $the ~~117~~Gulf of Mexico,~~995~~ ~~$101~~the North Sea,~~330~~ ~~Interest~~and ~~payable~~Venezuela.~~.........................................................~~ ~~5,255~~Markets ~~3,117~~for ~~Pension~~the ~~liabilities~~capital ~~and~~equipment ~~post~~the ~~retirement~~Company ~~obligations.......................~~sells ~~17,404~~generally --weakened ~~Notes~~in ~~payable.............................................................~~2003 ~~300,642~~resulting ~~125,805~~in ~~Common~~declining ~~stockholders'~~backlogs ~~equity:~~for ~~Common~~Drilling ~~stock,~~Equipment ~~$.01~~and Coiled ~~par~~Tubing ~~value~~& ~~200,000,000~~Wireline ~~shares~~products ~~authorized,~~through ~~97,402,339~~the ~~shares~~year. ~~issued~~High oil and ~~95,927,639~~gas ~~shares~~prices ~~outstanding~~led ~~(96,245,849~~to ~~shares~~steadily ~~issued~~rising ~~and~~levels ~~94,821,149~~of ~~outstanding~~drilling atactivity ~~December~~generally 31in 2004, ~~2000)~~driving the world-wide rig count up 10% compared to the prior year.~~...............................................................~~ ~~974~~Drilling ~~962~~activity ~~Paid-~~increased in the ~~capital~~U.S.~~......................................................~~ ~~514~~land market,~~137~~ ~~498~~Latin America,~~692~~ ~~Retained~~the ~~earnings......................................................~~Middle ~~347,548~~East ~~264,580~~and ~~Cumulative~~the ~~translation~~Far ~~adjustment~~East.~~.....................................~~ ~~(19~~However,~~015)~~ ~~(16~~the Gulf of Mexico,~~921)~~ ~~Less:~~Canada, ~~treasury~~Africa, ~~stock~~and atthe ~~cost~~North ~~(1,424,700~~Sea ~~shares)........................~~saw ~~(15,330)~~Drilling ~~(15,330)~~activity ~~----------~~decline ~~--------~~in ~~Total~~2004 ~~common~~compared ~~stockholders'~~to ~~equity~~2003.~~.................................~~ ~~828,314~~As ~~731,983~~a ~~----------~~result ~~--------~~of ~~Total~~higher ~~liabilities~~cash flows realized by many drilling contractors and ~~equity.......................................~~other $1oilfield service companies,~~269,610~~ ~~$962~~market conditions for capital equipment purchases improved significantly in 2004,~~235~~ ~~==========~~resulting ~~========~~in higher backlogs for the Company at the end of 2004 compared to the end of 2003.

~~Years~~Oil ~~Ended~~and ~~December~~Gas ~~31,~~Well ~~----------------------------~~Drilling ~~2001~~and ~~2000~~Remediation ~~1999~~Processes -------- -------- -------- (in thousands) Equity in net earnings of subsidiaries...... $103,618 $ 40,173 $ 47,068 Interest expense............................ (19,724) (13,333) (16,691) Other....................................... (926) (5,785) (568) -------- -------- -------- Net income.................................. $ 82,968 $ 21,055 $ 29,809 ======== ======== ========

~~Years~~Oil ~~Ended~~and ~~December~~gas ~~31,~~wells ~~-----------------------------~~are ~~2001~~usually ~~2000~~drilled ~~1999~~by ~~---------~~drilling ~~--------~~contractors ~~--------~~using ~~(in~~a drilling ~~thousands) Cash flows from operating activities: Net income~~rig.~~............................................................~~ $A ~~82,968~~bit $is ~~21,055~~attached ~~$ 29,809 Adjustments~~ to ~~reconcile~~the ~~net~~end ~~income to net cash provided by (used for) operating activities: Equity in net earnings~~ of ~~subsidiaries.............................~~a ~~(103,618)~~drill ~~(40~~stem,~~173)~~ ~~(47,068)~~which ~~Changes~~is inassembled ~~current~~by ~~assets~~the ~~and~~drilling ~~liabilities:~~rig Accounts receivable............................................. 1,011 (2,265) (22) Income tax receivable........................................... -- -- 3,154 Other assets.................................................... (4,246) -- -- Pension liabilities and ~~post-retirement~~its ~~obligations.............~~crew ~~17,404 -- -- Interest payable................................................ 2,138 (2,050) (1,075) Amounts due~~ from ~~(to) affiliates, net........................... (33,919) 79,122 9,973~~ 30-~~--------~~foot ~~--------~~joints ~~--------~~of ~~Net~~drillpipe ~~cash~~and ~~provided~~specialized bydrilling ~~(used for) operating activities~~components.~~..................~~ ~~(38,262)~~Using ~~55,689~~the ~~(5,229)~~conventional ~~---------~~rotary ~~--------~~drilling ~~-------- Cash flows provided by (used for) investing activities: Investment in subsidiaries............................................. (144~~method,~~376)~~ ~~15,262~~the ~~19,023~~drill ~~---------~~stem ~~--------~~is turned ~~--------~~from ~~Cash~~the ~~flows~~rotary ~~provided~~table by (used for) financing activities: Borrowings (payments) under financing agreements, net.................. 174,837 (88,055) (18,655) Other.................................................................. 3,231 7,055 (764) Proceeds from sale of ~~common~~the ~~stock.....................................~~drilling ~~10,132~~rig ~~10,049 5,625 --------- -------- -------- Net cash provided~~ by ~~(used~~torque ~~for)~~applied ~~financing~~to ~~activities...................~~the ~~188~~kelly,~~200~~ ~~(70,951)~~which ~~(13,794)~~is ~~---------~~screwed ~~--------~~into ~~--------~~the ~~Net~~top ~~change in cash and cash equivalents................................... 5,562 -- -- Beginning~~ of the ~~year..................................................~~drill ~~-- -- -- --------- -------- -------- End of year~~stem.~~...........................................................~~ ~~$ 5,562 $ -- $ -- ========= ======== ========~~

~~Additions~~During ~~(Deductions)~~drilling, ~~Charge~~heavy ~~Balance~~drilling ~~Charged~~fluids toor ~~offs~~“drilling ~~Balance~~muds” ~~Beginning~~are ~~Costs~~pumped ~~and~~down ~~and~~the ~~End~~drill ofstem ofand ~~Year~~forced ~~Expenses~~out ~~Other~~through ~~Year~~jets ~~--------- ------------ -------- ------- (~~in ~~thousands)~~the ~~Allowance for doubtful accounts: 2001~~bit.~~......................................................~~ ~~$10,199~~The ~~$6,326~~drilling mud $returns ~~(5,008)~~to ~~$11,517~~the ~~2000.......................................................~~surface $through ~~8,373~~the ~~$4,895~~hole $area ~~(3,069)~~surrounding ~~$10,199~~the ~~1999.......................................................~~drill ~~$ 8~~stem,~~293~~ ~~$2,148~~carrying $with ~~(2,068)~~it $the ~~8,373~~drill ~~Allowance~~cuttings ~~for~~drilled ~~excess~~out ~~and~~by ~~obsolete~~the ~~inventory~~bit. ~~reserves~~The ~~(excludes~~drill ~~Lifo):~~cuttings ~~2001.......................................................~~are ~~$23,333~~removed ~~$9,507~~from $the ~~(1,812)~~mud ~~$31,028~~by ~~2000.......................................................~~a ~~$26,933~~solids ~~$5,772~~control $system (~~9,372)~~which ~~$23,333~~can ~~1999.......................................................~~include ~~$37~~shakers,~~148~~ ~~$6,868~~centrifuges and ~~$(17,083~~other specialized equipment) ~~$26,933~~and ~~Valuation~~disposed ~~allowance~~of ~~for~~in ~~deferred~~an ~~tax~~environmentally ~~assets:~~sound ~~2001~~manner.~~......................................................~~ $The ~~967~~solids $control --system $permits ~~(54)~~the $mud, ~~913~~which ~~2000.......................................................~~is $often ~~1,238~~comprised $of ~~(271)~~expensive $chemicals, --to $be ~~967~~continuously ~~1999.......................................................~~reused $and ~~2,208~~recirculated $back --into $the ~~(970) $ 1,238~~hole.

Through its Drilling Services business, the Company sells and rents solids control equipment, and provides solids control services. Many operators internally coat the drill stem to protect it from corrosive fluids sometimes encountered during drilling, and inspect and assess the integrity of the drill pipe from time to time. Through its Tubular Services business, the Company provides drillpipe inspection and coating services, and applies “hardbanding” material to drillpipe to improve its wear characteristics.

As the hole depth increases, the kelly must be removed frequently so that additional 30-foot joints of drill pipe can be added to the drill stem. When the bit becomes dull or the equipment at the bottom of the drill stem otherwise requires servicing, the entire drill stem is pulled out of the hole and disassembled by disconnecting the joints of drillpipe. These are set aside or “racked,” the old bit is replaced or service is performed, and the drill stem is reassembled and lowered back into the hole (a process called “tripping”). During drilling and tripping operations, joints of drill pipe must be screwed together and tightened (“made up”), and loosened and unscrewed (“spun out”). The Company’s Drilling Equipment business provides drilling equipment to manipulate and maneuver the drill pipe in this manner. When the hole has reached certain depths, all of the drill pipe is pulled out of the hole and larger diameter pipe known as casing is lowered into the hole and permanently cemented in place in order to protect against collapse and contamination of the hole. The casing is typically inspected before it is lowered into the hole, a service the Company’s Tubular Services business provides. The Company’s Coiled Tubing & Wireline Products Group manufactures pressure pumping equipment that is used to cement casing in place.

The raising and lowering of the drill stem while drilling or tripping, and the lowering of casing into the wellbore, are accomplished with the rig’s hoisting system. A conventional hoisting system is a block and tackle mechanism that works within the drilling rig’s derrick. The Company’s Drilling Equipment Group sells and installs pipe hoisting systems.

During the course of normal drilling operations, the drill stem passes through different geological formations, which exhibit varying pressure characteristics. If this pressure is not contained, oil, gas and/or water would flow out of these formations to the surface. The two means of containing these pressures are (i) primarily the circulation of drilling muds while drilling and (ii) secondarily the use of blowout preventers should the mud prove inadequate and in an emergency situation. The Company’s Drilling Equipment group sells and services blowout preventers.

Drilling muds are carefully designed to exhibit certain qualities that optimize the drilling process. In addition to containing formation pressure, they must (i) cool the drill bit, (ii) carry drilled solids to the surface, and (iii) protect the drilled formations from being damaged. Achieving these objectives often requires a formulation specific to a given well and can involve the use of expensive chemicals as well as natural materials such as certain types of clay. The fluid itself is often oil or more-expensive synthetic mud. Given this expense, it is highly desirable to reuse as much of the drilling mud as possible. Solids control equipment such as shale shakers, centrifuges, cuttings dryers, and mud cleaners help accomplish this objective. The Company’s Drilling Services group rents, sells, operates and services this equipment. Drilling muds are formulated based on expected drilling conditions. However, as the hole is drilled, the drill stem may encounter a high pressure zone where the mud density is inadequate to maintain sufficient pressure. Should efforts to “weight up” the mud in order to contain such a pressure kick fail, a blowout could result, whereby reservoir fluids would flow uncontrolled into the well. To prevent blowouts to the surface of the well, a series of high-pressure valves known as blowout preventers (“BOPs”) are positioned at the top of the well and, when activated, form tight seals that prevent the escape of fluids. When closed, conventional BOPs prevent normal rig operations. Therefore, the BOPs are activated only if drilling mud and normal well control procedures cannot safely contain the pressure. BOPs have been designed to contain pressure of up to 20,000 psi.

The operations of the rig and the condition of the drilling mud are closely monitored by various sensors, which measure operating parameters such as the weight on the rig’s hook, the incidence of pressure kicks, the operation of the drilling mud pumps, etc. Through its Drilling Services business, the Company sells and rents drilling rig instrumentation packages that perform these monitoring functions.

After the well has reached its total depth and the final section of casing has been set, the drilling rig is moved off of the well and the well is prepared to begin producing oil or gas in a process known as “well completion.” Well completion usually involves installing production tubing concentrically in the casing. Due to the corrosive nature of many produced fluids, production tubing is often inspected and coated, which are services offered by the Company’s Tubular Services business. Sometimes operators choose to use corrosion resistant composite materials (which the Company offers through its Tubular Services business), or corrosion-resistant alloys, or operators sometimes pump fluids into wells to inhibit corrosion.

From time to time, a producing well may undergo workover procedures to extend its life and increase its production rate. Workover rigs are used to disassemble the wellhead, tubing and other completion components of an existing well in order to stimulate or remediate the well. Workover rigs are similar to drilling rigs in their capabilities to handle tubing, but are usually smaller and somewhat less sophisticated. Tubing and sucker rods removed from a well during a well remediation operation is

often inspected to determine its suitability to be reused in the well, which is a service the Company’s Tubular Services business provides.

Frequently coiled tubing units or wireline units are used to accomplish certain well remediation operations or well completions. Coiled tubing is a recent advancement in petroleum technology consisting of a continuous length of reeled steel tubing which can be injected concentrically into the production tubing all the way to the bottom of most wells. It permits many operations to be performed without disassembling the production tubing, and without curtailing the production of the well. Wireline winch units are devices that utilize single-strand or multistrand wires to perform well-remediation operations, such as lowering tools and transmitting data to the surface. Through its Coiled Tubing & Wireline Products business, the Company sells and rents various types of coiled tubing equipment, coiled tubing pipe, wireline equipment and tools.

Drilling Equipment Group

The Company has a long tradition of pioneering innovations in drilling equipment which improve the efficiency, safety, and cost of drilling operations. The Drilling Equipment group designs, manufactures and sells a wide variety of top drives, automated pipe racking systems, motion compensation systems, rig controls, BOPs, handling tools, drawworks, risers, rotary tables, and other drilling equipment for both the onshore and offshore markets. The Drilling Equipment group sells directly to drilling contractors, rig fabricators, national oil companies, major and independent oil and gas companies, supply stores, and pipe-running service providers. Demand for its products, several of which are described below, is strongly dependent upon capital spending plans by oil and gas companies and drilling contractors, and the level of oil and gas well drilling activity.

In 2004, approximately 14 percent of the Drilling Equipment group’s sales were of equipment for newly constructed drilling rigs, 20 percent were for upgrades and refurbishments of existing rigs, 60 percent were for aftermarket spares and services, and 6 percent were for production chokes and other.

Top Drives. The Top Drive Drilling System (“TDS”), originally introduced by Varco in 1982, significantly alters the traditional drilling process. The TDS rotates the drill stem from its top, rather than by the rotary table, with a large electric motor affixed to rails installed in the derrick that traverses the length of the derrick to the rig floor. Therefore, the TDS eliminates the use of the conventional rotary table for drilling. Components of the TDS also are used to connect additional joints of drill pipe to the drill stem during drilling operations.

The TDS combines elements of pipe handling tools, as well as hoisting and rotary equipment, into a single system. During drilling operations, the TDS performs functions such as making-up joints of drill pipe, maneuvering joints of drill pipe into position to be added to the drill stem when drilling, and holding and hoisting the entire drill stem. Drilling with a TDS provides several advantages over conventional drilling. It enables drilling with three joints of drill pipe, often reducing by two-thirds the time spent in making connections of drill pipe. In addition, it facilitates “horizontal” and “extended reach” drilling (the practice of drilling wells which deviate substantially from vertical) by providing the ability to rotate the pipe as it is removed from, or placed into, the well, thus reducing the likelihood of the drill stem becoming stuck in the wellbore – a phenomenon that may occur when drill pipe remains stationary in the wellbore for a prolonged period. By facilitating extended reach drilling, the TDS increases the area which can be drilled from a given location, such as a fixed platform. Thus, the production from a given reservoir of oil can be increased, and the number of costly fixed platforms required to develop the field can be minimized. Over the past few years the Company began targeting TDS sales into the land drilling market. Between 2001 and 2004, approximately 171 TDS units, or 74% of total top drive sales, were sold by the Company into land drilling applications.

Pipe Racking Systems. Pipe racking systems are used to handle drill pipe, casing and tubing on a drilling rig. Vertical pipe racking systems move drill pipe and casing between the well and a storage (“racking”) area on the rig floor. Horizontal racking systems are used to handle tubulars while stored horizontally (for example, on the pipe deck of an offshore rig) and transport tubulars up to the rig floor and into a vertical position for use in the drilling process.

Vertical pipe racking systems are used predominantly on offshore rigs and are found on almost all floating rigs. Mechanical vertical pipe racking systems greatly reduce the manual effort involved in pipe handling. The Pipe Handling Machine (“PHM”), introduced by Varco in 1985, provides a fully automated mechanism for handling and racking drill pipe during drilling and tripping operations, spinning and torquing drill pipe, and automatic hoisting and racking of disconnected joints of drill pipe. These functions can be integrated via computer controlled sequencing, and operated by a driller in an environmentally secure cabin. An important element of this system is the Iron Roughneck, which was originally introduced by Varco in 1976 and is an automated device that makes pipe connections on the rig floor and requires less direct involvement of rig floor personnel in potentially dangerous operations. The Automated Roughneck is an automated microprocessor-controlled version of the Iron Roughneck. In late 2002 the Company introduced its new ST-80 Iron Roughneck to expand into the land rig market. Through 2004 the Company has sold approximately 174 units.

Horizontal pipe racking systems were introduced by Varco in 1993. They include the Pipe Deck Machine (“PDM”), which is used to manipulate and move tubulars while stored in a horizontal position; the Pipe Transfer Conveyor (“PTC”), which transports sections of pipe to the rig floor; and a Pickup Laydown System (“PLS”), which raises the pipe to a vertical position for transfer to a vertical racking system. These components may be employed separately, or incorporated together to form a complete horizontal racking system, known as the Pipe Transfer System (“PTS”).

Hoisting systems are used to raise or lower the drill stem while drilling or tripping, and to lower casing into the wellbore. During 1999, Varco introduced its first “Automated Hoisting System” (“AHS”), which uses an AC-powered motor and a braking system that offers very precise control. The AHS automates the repetitive hoisting and drilling operations through the user-friendly, touch-screen Electronic Driller interface. The AHS is smaller and lighter than conventional hoisting systems. The Company received its first order for an AHS in 2000 and delivered the first AHS in 2001. Most of the AHS systems sold by the Company have been for the land rig market.

Blow-out Preventers. BOPs are devices used to seal the space (“annulus”) between the drill pipe and the borehole to prevent blow-outs (uncontrolled flows of formation fluids and gases to the surface). The Drilling Equipment group manufactures BOPs under the registered trademark Shaffer^{^®}. Ram and annular BOPs are back-up devices and are activated only if other techniques for controlling pressure in the wellbore are inadequate. When closed, these devices prevent normal rig operations. Ram BOPs seal the wellbore by hydraulically closing rams (thick heavy blocks of steel) against each other across the wellbore. Specially designed packers seal around specific sizes of pipe in the wellbore, shear pipe in the wellbore or close off an open hole. Annular BOPs seal the wellbore by hydraulically closing a rubber packing unit around the drill pipe or kelly or by sealing against itself if nothing is in the hole. Varco’s Pressure Control While Drilling (“PCWD”) BOP, introduced in 1995, allows operators to drill at pressures up to 2,000 psi without interrupting normal operations, and can act as a normal spherical BOP at pressures up to 5,000 psi.

In 1998 Varco introduced the NXT^{^®} ram type BOP which eliminates door bolts, providing significant weight, rig-time, and space savings. Its unique features make subsea operation more efficient through faster ram configuration changes without tripping the BOP stack. In 2004, Varco introduced the LXT, which features many of the design elements of the NXT, but is targeted at the land market. During 2004, the Company shipped 7 LXTs and received orders for 47 LXTs.

The conventional BOP control system is hydraulically activated and is used to operate BOPs and associated valves remotely for both land systems and offshore systems. With the recent increase in deep-water drilling depths, traditional hydraulic control systems are inadequate to activate BOPs, which rest on the ocean floor and may be 5,000 feet or more below the surface. In 1997, Varco introduced the IVth Subsea Generation MUX, an electronic control system designed specifically for deep-water applications. In 2001, the Company acquired technology from Maris International related to a continuous circulation device the Company plans to commercialize in 2005. This device enables drilling contractors to make and break drill pipe connections without stopping the circulation of drilling fluids. This in turn increases drilling efficiency.

Motion Compensation Systems. The Drilling Equipment Group sells motion compensation equipment under the registered trademark Shaffer^{^®}. Motion compensation equipment stabilizes the bit on the bottom of the hole, increasing drilling effectiveness of floating offshore rigs by compensating for wave and wind action. Tensioners provide continuous axial tension to the marine riser pipe (larger diameter pipe which connects floating drilling rigs to the well on the ocean floor) and guide lines on floating drilling rigs, tension leg platforms and jack-up drilling rigs. In 1996 Varco introduced the Riser Recoil System, which provides a safe disconnect when the floating rig encounters an unanticipated need to leave location, for example during severe weather.

Pipe Handling Tools. The Company’s pipe handling tools are designed to enhance the safety, efficiency and reliability of pipe handling operations. Many of these tools have provided innovative methods of performing the designated task through mechanization of functions previously performed manually. The Drilling Equipment group manufactures various tools used to grip, hold, raise, and lower pipe, and in the making up and breaking out of drill pipe, workstrings, casing and production tubulars including spinning wrenches, manual tongs, torque wrenches and kelly spinners.

The Drilling Equipment group also manufactures other tools used in various pipe handling functions. Slips are gripping devices which hold pipe or casing in suspension while in the hole. Other products, which include safety clamps, casing bushings and casing bowls, are used to hold and guide drill pipe or casing while in the hole, prevent tool strings from being dropped down the well accidentally, and ensure that the casing is centered in the hole.

Rotary Equipment. Rotary equipment products consist of kelly bushings and master bushings. The kelly bushing applies torque to the kelly to rotate the drill stem and fits in the master bushing which is turned by the rotary table on the floor of the rig. The Drilling Equipment group produces kelly bushings and master bushings for most sizes of kellys and makes of rotary tables.

In 1998, Varco introduced the Rotary Support Table for use on rigs with Top Drive Drilling Systems. The Rotary Support Table is used in concert with the TDS to completely eliminate the need for the larger conventional rotary table.

Derricks and substructures. The Company began offering design, fabrication and repair services for derricks and substructures through its September 2001 acquisition of Morinoak International Ltd., with engineering and fabrication facilities in Great Yarmouth, England and Aberdeen, Scotland. MIL represented the Company’s first entrance into the business of designing and fabricating large drilling rig structural components such as masts and substructures. In 2003 the Company experienced significant cost over runs on a sophisticated land rig it had contracted to supply on a turnkey basis, for a customer in the Middle East, for approximately $31 million. The cost overruns were attributable to errors in the original design of the rig, underestimation of the costs of rig-up and commissioning, cost due to delays of the project, and adverse foreign currency exchange changes related to the strengthening of the British Pound against the U.S. Dollar. As a result of the losses on the turnkey rig fabrication project, and continuing operating losses from the MIL business, the Company exited the rig fabrication business of MIL in 2004. Accordingly, the financial results of MIL are reported as a discontinued operation.

Service & Spares. Approximately 60 percent of the sales of the Drilling Equipment group consist of spare and replacement parts, consumables, provision of drilling equipment repair services, and rental of drilling systems.

Facilities. The Company conducts Drilling Equipment manufacturing operations at major facilities in Orange, California; Houston, Texas; Mexicali, Mexico; and Etten-Leur, Netherlands. The Drilling Equipment group maintains sales and service offices in most major oilfield markets, either directly or through agents. The Company expanded its market presence in Norway when it acquired its agent, Scana IOS Desco AS, in December 2000, and expanded its drilling equipment repair business through the acquisition of Church Oil Tools in early 2003.

Competition. The products of the Drilling Equipment group are sold in highly competitive markets and its sales and earnings can be affected by competitive actions such as price changes, new product development or improved availability and delivery. The group’s primary competitors are Access Oil Tools; Aker Kvaerner AS American Block; Canrig (a division of Nabors Industries); Cavins Oil Tools; Cooper Cameron Corporation; DenCon Oil Tools; Hydril Company; LEWCO (a division of Rowan Companies); National-Oilwell, Inc.; Tesco Corporation; Wirth M&B GmbH; and Weatherford International, Inc. Management believes that the principal competitive factors affecting its Drilling Equipment business are performance, quality, reputation, customer service, availability of products, spare parts, and consumables, and breadth of product line and price.

See the Company’s Executive Summary and Drilling Equipment Group Restructuring and MIL Impairment Charge in Management’s Discussion and Analysis of Results of Operations and Financial Condition.

Tubular Services Group

The Company’s Tubular Services group provides a variety of tubular services and composite tubing to oil and gas producers, national oil companies, drilling contractors, well servicing companies, pipeline operators, and tubular processors, manufacturers and distributors. The Tubular Services group provides inspection and reclamation services for drill pipe, casing, production tubing, sucker rods and line pipe at drilling and workover rig locations, at yards owned by its customers, at steel mills and processing facilities that manufacture tubular goods, and at facilities which it owns. The Tubular Services group also provides internal coating of tubular goods at several coating plants worldwide. The Company also conducts tubular coating operations through licensees in certain locations. Additionally, the Company designs, manufactures and sells high pressure fiberglass and composite tubulars for use in corrosive applications, and provides in-service inspection of oil, gas and product transmission pipelines through its application of instrumented survey tools (“smart pigs”) which it engineers, manufactures and operates.

The Company’s Tubular Services business was increased significantly through its acquisition of substantially all of the assets of the oilfield services business of ICO, Inc., including the stock of its Canadian operating subsidiary, on September 6, 2002. The ICO oilfield services business provides tubular inspection, coating and reclamation; sucker rod inspection and reclamation; tubular transport and logistics management; and beam pump engine repair. Operations are primarily conducted in North America. Since the acquisition the Company has effected efficiency gains and consolidation savings by combining the oilfield service business of ICO into its original operations.

The Company’s customers rely on tubular inspection services to avoid failure of tubing, casing, flowlines, pipelines and drill pipe. Such tubular failures are expensive and in some cases catastrophic. The Company’s customers rely on internal coatings of tubular goods to prolong the useful lives of tubulars and to increase the volumetric throughput of in-service tubular goods. The Company’s customers sometimes use fiberglass or composite tubulars in lieu of conventional steel tubulars, due to the corrosion-resistant properties of fiberglass and other composite materials. Tubular inspection and coating services are used most frequently in operations in high-temperature, deep, corrosive oil and gas environments. In selecting a provider of tubular inspection and

tubular coating services, oil and gas operators consider such factors as reputation, experience, technology of products offered, reliability and price.

Tubular Coating. The Company develops, manufactures and applies its proprietary tubular coatings, known as Tube-Kote^{^®} coatings, to new and used tubulars. Tubular coatings help prevent corrosion of tubulars by providing a tough plastic shield to isolate steel from corrosive oilfield fluids such as CO₂, H₂S and brine. Delaying or preventing corrosion extends the life of existing tubulars, reduces the frequency of well remediation and reduces expensive interruptions in production. In addition, coatings are designed to increase the fluid flow rate through tubulars by decreasing or eliminating paraffin and scale build-up, which can reduce or block oil flow in producing wells. The smooth inner surfaces of coated tubulars often increase the fluid through-put on certain high-rate oil and gas wells by reducing friction and turbulence.

The Company has a history of introducing new coating products that are custom-engineered to address increasingly corrosive environments encountered in oil and gas drilling and production operations. In 1998, the Company introduced TK^{^®}Liner, a fiberglass liner product which offers the strength of steel tubing and the corrosion resistance of fiberglass, and which supplements its traditional plastic coating lines. The Company’s reputation for supplying quality internal coatings is an important factor in its business, since the failure of coatings can lead to expensive production delays and premature tubular failure.

Fiberglass & Composite Tubulars. When compared to conventional carbon steel and even corrosion-resistant alloys, resin-impregnated fiberglass and other modern plastic composites often exhibit superior resistance to corrosion. Some producers manage the corrosive fluids sometimes found in oil and gas fields by utilizing composite or fiberglass tubing, casing and line pipe in the operations of their fields. In 1997, the Company acquired Fiber Glass Systems, a leading provider of high pressure fiberglass tubulars used in oilfield applications, to further serve the tubular corrosion prevention needs of its customers. Fiber Glass Systems has manufactured fiberglass pipe since 1968 under the name “Star^{^®},” and was the first manufacturer of high-pressure fiberglass pipe to be licensed by the API in 1992. The Company acquired two fiberglass and composite tubing manufacturing facilities in the U.S. and one in China from A.O. Smith in December 2000. The Company also acquired U.S. fiberglass tubing manufacturing facility from Fibercast in July 2001, and acquired a small fiberglass business in China in early 2004. These acquisitions have extended the Company’s fiberglass and composite tubing offering into industrial and marine applications, in addition to its oilfield market.

Tubular Inspection. Newly manufactured pipe sometimes contains serious defects that are not detected at the mill. In addition, pipe can be damaged in transit and during handling prior to use at the well site. As a result, exploration and production companies often have new tubulars inspected before they are placed in service to reduce the risk of tubular failures during drilling, completion, or production of oil and gas wells. Used tubulars are inspected by the Company to detect service-induced flaws after the tubulars are removed from operation. Used drill pipe and used tubing inspection programs allow operators to replace defective lengths, thereby prolonging the life of the remaining pipe and saving the customer the cost of unnecessary tubular replacements and expenses related to tubular failures.

The Tubular Services group’s tubular inspection services employ all major non-destructive inspection techniques, including electromagnetic, ultrasonic, magnetic flux leakage and gamma ray. These inspection services are provided both by mobile units which work at the wellhead as used tubing is removed from a well, and at fixed site tubular inspection locations. The group provides an ultrasonic inspection service for detecting potential fatigue cracks in the end area of used drill pipe, the portion of the pipe that traditionally has been the most difficult to inspect. Tubular inspection facilities also offer a wide range of related services, such as API thread inspection, ring and plug gauging, and a complete line of reclamation services necessary to return tubulars to useful service, including tubular cleaning and straightening, hydrostatic testing and re-threading.

In addition, the Company applies hardbanding material to drillpipe, to enhance its wear characteristics and reduce downhole casing wear as a result of the drilling process. In 2002, the Company introduced its proprietary line of hardbanding material, TCS - 8000^™.

In 1998, the Company acquired three tubular services businesses to enhance its competitive positions in Norway, Egypt, and the west coast of the United States. Additionally, these acquisitions provided opportunities to achieve consolidation cost savings. In 1999, the Company completed acquisitions of Geo-Ray Oilfield Inspections Ltd. in Canada, and the tubular services business of AGR Services AS in Floro, Norway. In 2001, the Company acquired the assets of Servizi Ispettivi, a small tubular services business in Italy, and in 2002, the Company acquired the assets of A&A Tubular Inspection in California, and substantially all of the oilfield services business of ICO, Inc. In early 2003, the Company acquired the tubular services assets of Petroleum Tubular Inspection in South America, and the Company’s exclusive tubular services agent in Mexico, Tecnicos Tubulares. In 2004, the Company acquired the assets of Total Premier Services, a pipe-threading operation in Houston, Texas.

In addition to its new and used tubular inspection and reclamation services, the Company also offers a comprehensive proprietary tubular inventory management system (E-Track^™ and Gold^™) which permits the real-time tracking of customer’s tubular inventories within the Company’s facilities. The system permits customers to remotely access and monitor tubular inspection and coating progress.

The Company has pioneered many tubular inspection technologies used in the oilfield, and continues to expand its product offering. In 1996, the Company installed its first proprietary high-speed full-body ultrasonic tubular inspection unit (Truscope^{^®}). The new service provides 100% ultrasonic coverage of tubulars at a rate of up to 200 feet per minute. In 1997, the Company began offering a proprietary, patented external tubular connection integrity test, the ISO-Gator,^TM for use at the rig site. The technology was obtained through the Company’s acquisition of the operating assets of Gator Hawk, Inc. In 1998, the Company introduced a new coiled tubing inspection service with its electromagnetic CT Scope^{^®}.

Mill Systems and Sales. The Company engineers and fabricates inspection equipment for steel mills, which it sells and rents. The equipment is used for quality control purposes to detect defects in the pipe during the high-speed manufacturing process. Each piece of mill inspection equipment is designed to customer specifications and is installed and serviced by the Company. Since 1962, the Company has installed more than 80 units worldwide, in most major pipe mills. Equipment is manufactured at the Company’s Houston, Texas and Celle, Germany facilities. Revenue for Mill Systems and Sales fluctuates significantly from year to year due to the timing of negotiating large domestic and export sales contracts, arranging financing and manufacturing equipment.

Sucker Rod Inspection & Reclamation. The 2002 acquisition of the oilfield services business of ICO, Inc. provided the Tubular Services group a significant sucker rod services business. The Tubular Services group cleans, straightens, inspects and coats sucker rods at 11 facilities throughout the Western Hemisphere. Additionally, new sucker rods are inspected before they are placed into service, to avoid premature failure, which can cause the oil well operator to have to pull and replace the sucker rod. The Company further strengthened its position in this market with the acquisition of Patco Rod Service, Inc. in California in 2003.

Pipeline Inspection. In-place inspection services for oil and gas pipelines identify anomalies in pipelines without removing or dismantling the pipelines or stopping the product flow, giving customers a convenient and cost-effective method of identifying potential defects. The Tubular Services group inspects pipelines by launching a sophisticated survey instrument into the pipeline. Propelled by the product flow, the instrument uses electromagnetics, ultrasonics, and mechanical measurements received on digital and analog media to monitor the severity and location of internal and external pitting-type corrosion as well as other mechanical anomalies in the pipeline, providing a basis for evaluation and repair by the customer. Once the test is complete, the survey instrument is returned to the Company, refurbished and used for future pipeline inspections.

Management believes the major competitive factors for Pipeline Services are reputation for quality, service, reliability of obtaining a successful survey on the first run, product technology, price, and technical support on survey interpretation. Demand for the Company’s pipeline services is somewhat dependent on commodity prices, which affect funds available for discretionary pipeline inspection and maintenance expenditures by many pipeline operators. This dependence is most pronounced in international markets. Additionally, significant consolidation in the pipeline industry has caused many pipeline operators to defer inspections in recent years as they re-evaluate their pipeline maintenance programs following mergers and acquisitions. Management believes there are growth opportunities for the Company’s Pipeline Services due to the aging of the worldwide pipeline network, construction of new pipelines, and recent changes in U.S. regulatory requirements. In 2001, the Company acquired certain assets of Geodz, Inc., a software engineering firm, to enhance its pipeline position survey software, and in 2002 it acquired the assets of Marr Associates Pipeline Integrity, Ltd, a Canadian provider of data management and direct pipeline assessment services. Additionally, in 2002 the Company acquired approximately 24 percent of NDT Systems & Services, AG, a German firm which provides ultrasonic pipeline inspection technology. As part of the investment the Company obtained certain exclusive rights to market a new ultrasonic pipeline inspection service, which was introduced commercially in late 2003 and which contributed significantly to the Pipeline Services Group’s 2004 results.

Customers and Competition. The Tubular Services group’s customers include major and independent oil and gas companies, national oil companies, drilling and workover contractors, oilfield equipment and product distributors and manufacturers, oilfield service companies, pipeline operators, steel mills, and other industrial companies. The Company’s competitors in Tubular Services include, among others, Ameron International Corp, EDO Corporation, Pipeline Integrity International Ltd. (a division of General Electric), ShawCor Ltd., Smith International, Inc., Frank’s International, Inc., H. Rosen Engineering, GmbH; T.D. Williamson, Inc.; Baker Hughes; Diascan; Magpie; Weatherford; and Patterson Tubular Services. In addition, the Tubular Services group competes with a number of smaller regional competitors in tubular inspection. Certain foreign jurisdictions and government-owned petroleum companies located in some of the countries in which this group operates have adopted policies or regulations which may give local nationals in these countries certain competitive advantages. Within the

Company’s corrosion control products, certain substitutes such as non-metallic tubulars, inhibitors, corrosion resistant alloys, cathodic protection systems, and non-metallic liner systems also compete with the Company’s products. Management believes that the principal competitive factors affecting its Tubular Services business are performance, quality, reputation, customer service, availability of products, spare parts, and consumables, and breadth of product line and price.

Drilling Services Group

The Company’s Drilling Services group is engaged in the provision of highly-engineered equipment, products and services which separate and manage drill cuttings produced by the drilling process (“Solids Control Services”). Drill cuttings are usually contaminated with petroleum or drilling fluids, and must be disposed of in an environmentally sound manner. Additionally, efficient separation of drill cuttings enables the re-use of often costly drilling fluids. The Drilling Services group also rents and sells proprietary drilling rig instrumentation packages (“Drilling Rig Instrumentation”) and drilling rig control systems (“V-ICIS”) which monitor various processes throughout the drilling operation, under the name MD/Totco. The group’s Rig Instrumentation packages collect and analyze data through both analog and digital media, enabling rig personnel to maintain safe and efficient drilling operations.

Solids Control. The Drilling Services group uses a variety of technologies to separate drill cuttings from drilling fluids, and to transport, dry and refine drill cuttings for safe disposal under the Brandt brand name. The Company believes the regulatory and industry trends toward minimizing the environmental impact of drilling operations in a number of environmentally sensitive oil and gas producing regions will lead to greater demand for solids control products and closed loop drilling systems. A closed loop drilling system is a solids control system in which the drilling mud is reconditioned and recycled throughout the drilling process on the rig itself. The Company further believes the trend towards more technically complex drilling, including highly deviated directional wells and slim-hole completions, will favorably impact the demand for solid controls technology because of its ability to reduce costly downhole problems. As environmental constraints are increased and as awareness of environmental protection grows, the Company believes that its drill cuttings separation and treating processes will experience increased demand. In certain markets the Company’s Solid Control business has been adversely affected by recent customer trends toward awarding contracts which combine both Solids Control services and Drilling Fluids provision. In such instances, which primarily occur in certain international areas the Company bids to Drilling Fluid providers, or bids jointly with Drilling Fluids providers.

The Company has a history of introducing new solids control products and services obtained both through its internal development and through acquiring or licensing technologies from others. A shale shaker is the primary device on a drilling rig for removing drill solids from drilling mud. The Company also provides “screens” which are mounted on shale shakers and act as a filter. Screens are consumables which must be replaced every several days. The Company recycles certain screen components for reuse. The Company’s VSM 300^™, introduced in 1996, was the first shale shaker which offered a balanced elliptical vibratory motion, which improves cuttings conveyance and reduces oil on cuttings. The Company also introduced its new Cobra^{^®} shale shaker in 1998. The Cobra^{^®} has a small footprint and a lightweight design, and is priced to compete in the more price-sensitive segment of the market. The Company began offering the King Cobra^™ shale shaker in 1999. The King Cobra^™ is approximately one-third larger than the Cobra^® Shaker, and also targets both the offshore and land markets.

The Company acquired the Gumbo Chain from Nu-Tec, Inc. in 1997, a product to remove sticky shale or “gumbo,” which is encountered in certain geologic environments, from drilling fluid. In 1998, the Company initiated operations with a proprietary unit which removes hydrocarbons from drill cuttings using heat, a process called “Thermal Desorption”. The processed cuttings are usually rendered inert and can be disposed of with minimal environmental impact. The Company has commenced operation of additional thermal desorption units in South America and Africa, and acquired the thermal desorption operations of Maersk Contractors Environmental Division in Scotland and Kazakhstan in 2003. The Company acquired Recovery Systems, Ltd., a provider of thermal desorption cuttings processing services in Lowestoft, England, in 2004.

The Company acquired M.S.D. Inc. in 1998 in order to enhance its cuttings slurrification and injection capabilities. In 1999, the Company acquired Manufacturas Rowi, C.A. (Rowica), a Venezuelan solids control company, and the solids control assets of Newpark Resources, Inc. (“Newpark”). In early 2001, the Company acquired certain assets of Angelle Construction, Inc. to enhance its cuttings transport business, and in 2002 it acquired the assets of Environmental Rig Solutions, L.P., a Texas-based provider of waste management equipment for drilling operations. In early 2003, the Company made an equity investment in a small start-up company engaged in the development of new solids control technology. As part of the investment, the Company obtained exclusive marketing rights to new solids control technology for oilfield applications, obtained warrants to purchase additional equity, and agreed to invest additional equity if the company achieves certain technical milestones. In late 2003, the Company acquired Rocky Mountain Fluid Technologies, Inc. in Colorado, and Mud Rentals Ltd. in the UK. In 2004, the Company acquired the business of JB Equipment, a provider of drying units in the Gulf of Mexico.

The Drilling Services group manufactures conventional and linear motion shale shakers and shale shaker screens, high speed and conventional centrifuges, desanders (which remove large drill solids from drilling mud), desilters (which remove small drill solids from drilling mud), degassers (which remove air and gasses from drilling mud) and closed loop drilling fluids systems at its facilities in Conroe, Texas; Houston, Texas; Aberdeen, Scotland; Leduc, Alberta; and Trinidad. The group markets solids control equipment under the Brandt^{^®} brand name. For the year ended December 31, 2004, approximately 39 percent of the Drilling Services group’s solids control revenue was generated from the sale of solids control equipment and inventory, and approximately 61 percent of such revenue was generated from rentals and services.

Drilling Rig Instrumentation. The Drilling Services group’s rig instrumentation systems provide drilling rig operators real time measurement and monitoring of critical parameters required to improve rig safety and efficiency. Systems are both sold and rented, and are typically comprised of several sensors placed throughout the rig to measure parameters such as weight on bit, hookload, standpipe pressure, mud pump strokes, drilling mud levels, torque, and others, all networked back to a central command station for review, recording and interpretation. Additionally, the rig instrumentation packages typically provide multiple CRT screens around the rig for various rig personnel to perform individual jobs more effectively, and cameras for certain areas to permit remote monitoring. The Company offers proprietary touch-screen displays, interpretive software, and data archival and retrieval capabilities. In 1999, the Company introduced its RigSense^{^™} product, which combines leading hardware and software technologies into an integrated drilling rig package. This product permits access of drilling data from offsite locations, enabling company personnel to monitor drilling operations from an office environment, through a secure link. In 2001, the Company completed the acquisitions of Chimo Equipment Ltd. in Canada; Alberta Instruments Ltd. in Canada; Adair Supply & Rentals, Inc. in Corpus Christi, TX; and Wagner Instrumentation Inc. in Houston, TX; which were all engaged in drilling rig instrumentation business. In 2003, the Company made an equity investment in a small start-up company engaged in the development of software to enhance RigSense with rig “back office” information such as payroll and purchasing. In 2004, the Company acquired the rig instrumentation businesses of Wildcat Services and Wellsite Gas Detection, Inc.

Drilling consoles, and recently, the Company’s V-ICIS^{^™}, are typically sold as an integral part of a new rig, or as a major upgrade component for an existing rig. In the United States and Canada, most other drilling instrumentation products are usually rented to the drilling contractor or oil company when necessary, and are therefore not permanently installed on the rig. Internationally, most instrumentation equipment is sold to the rig owner and becomes a permanent part of the drilling rig.

Customers and Competition. The group’s customers for Drilling Services include major and independent oil and gas companies, national oil companies, and drilling contractors. Competitors in Drilling Services include Smith International (“SWACO”); Derrick Manufacturing Corp.; Fluid System; Oil Tools Pte. Ltd; Peak Energy Services, Ltd.; National-Oilwell Inc.; Petron Industries, Inc.; Epoch (a division of Nabors Industries); Pason Systems, Inc.; Kem-tron, Inc.; Double Life Corporation, Inc. and a number of regional competitors. The Company’s Drilling Services group operates in highly competitive markets. Management believes that on-site service is becoming an increasingly important competitive element in the Drilling Services market. Management believes that, in addition to on-site services, the principal competitive factors affecting its Drilling Services business are performance, quality, reputation, customer service, product availability and technology, breadth of product line and price.

Coiled Tubing & Wireline Products Group

The Company’s Coiled Tubing & Wireline Products group sells and rents capital equipment, and sells spare parts, repair services and consumables, to oilfield service providers who use the Company’s products to remediate, workover and, to a lesser extent, drill oil and gas wells. The Company, through its January 2001 acquisition of Quality Tubing, Inc., also manufactures steel coiled tubing used by well remediation contractors and oil and gas producers. Demand for the group’s Coiled Tubing & Wireline Products is strongly dependent upon the capital spending plans of coiled tubing and wireline service companies, and the general level of well completion and remediation activity.

Coiled Tubing Products. Coiled tubing consists of flexible steel tubing manufactured in a continuous string and spooled on a reel. It can extend several thousand feet in length and is run in and out of the wellbore at a high rate of speed by a hydraulically operated coiled tubing unit. A coiled tubing unit is typically mounted on a truck or skid (steel frames on which portable equipment is mounted to facilitate handling with cranes or flatbed trucks) and consists of a hydraulically operated tubing reel or drum, an injector head which pushes or pulls the tubing in or out of the wellbore, and various power and control systems. Coiled tubing is typically used with sophisticated pressure control equipment which permits the operator to continue to safely produce the well. The Coiled Tubing & Wireline Products group manufactures and sells both coiled tubing units and the ancillary pressure control equipment used in these operations.

Coiled tubing provides a number of significant functional advantages over the principal alternatives of conventional drill pipe and workover pipe. Coiled tubing allows faster “tripping,” since the coiled tubing can be reeled very quickly on and off a

drum and in and out of a wellbore. In addition, the small size of the coiled tubing unit compared to an average workover rig or drilling rig reduces preparation time at the well site. Coiled tubing permits a variety of workover and other operations to be performed without having to pull the existing production tubing from the well and allows ease of operation in horizontal or highly deviated wells. Thus, operations using coiled tubing can be performed much more quickly and, in many instances, at a significantly lower cost. Finally, use of coiled tubing generally allows continuous production of the well, eliminating the need to temporarily stop the flow of hydrocarbons. As a result, the economics of a workover are improved because the well can continue to produce hydrocarbons and thus produce revenues while the well treatments are occurring. Continuous production also reduces the risk of formation damage which can occur when the flow of fluids is stopped or isolated.

Currently, most coiled tubing units are used in well remediation and completion applications. The Company believes that advances in the manufacturing process of coiled tubing, tubing fatigue protection and the capability to manufacture larger diameter and increased wall thickness coiled tubing strings have resulted in increased uses and applications for coiled tubing products. For example, some well operators are now using coiled tubing in drilling applications such as slim hole reentries of existing wells. The Company engineered and manufactured the first coiled tubing units built specifically for coiled tubing drilling in 1996.

There are certain limitations to the use of coiled tubing. Coiled tubing generally is made of high strength, alloy steel which wears down or fatigues over time as a result of internal pressure, acidic operating environments and normal bending cycles. Thus, operators must carefully monitor the use of the tubing. In addition, coiled tubing will buckle if the weight of the coiled tubing being conveyed in the well becomes too great or if the tube becomes inhibited by some obstacle or irregularity in the wellbore. Buckling has not proven to be a significant obstacle in most well remediation applications, and the Company believes it will become less of an issue as a result of the availability of stronger and larger diameter coiled tubing.

Generally, the Coiled Tubing & Wireline Products group supplies customers with the equipment and components necessary to use coiled tubing, which the customers typically purchase separately. The group’s coiled tubing product line consists of coiled tubing units, coiled tubing pressure control equipment, pressure pumping equipment, snubbing units (which are units that force tubulars into a well when pressure is contained within the wellbore), nitrogen pumping equipment and cementing, stimulation and blending equipment. The group markets its coiled tubing equipment under the Hydra Rig^{^®} brand name primarily to providers of coiled tubing drilling and workover services. The Company’s primary coiled tubing unit production facilities are located at its Hydra Rig facility in Fort Worth, Texas. In addition, the group markets coiled tubing pressure control equipment under the Texas Oil Tools^{^®} brand name and manufactures this equipment at its facility in Conroe, Texas.

The Company’s quality tubing business manufactures coiled tubing at its mill in Houston, Texas. In 2003, Quality Tubing introduced a new corrosion-resistant alloy coiled tubing used primarily for velocity string recompletions (“hang-off” applications) of lower pressure gas wells (QT-16Cr). In addition to hang-off coiled tubing strings, Quality Tubing designs, manufactures, and sells conventional coiled tubing work strings used in well remediation and drilling operations.

The Company began offering its “TEM^{^™}” cementing equipment and fabricating nitrogen pumping units in Tulsa, Oklahoma, in December 1997, when it acquired Tulsa Equipment Manufacturing Company. Additionally, the Company acquired Weston Oilfield Engineering Limited in Norwich, United Kingdom, in December 1998, which strengthened its coiled tubing unit refurbishing, servicing and spare parts business, as well as added new cryogenic nitrogen technologies. The Company’s 2001 acquisition of Bradon Industries added a significant manufacturing plant in Canada, where it sells equipment now under the brand name Hydra Rig Canada. The Company acquired Quality Tubing, Inc. in 2001. It also added additional nitrogen-pumping products and technologies through its 2001 acquisition of Albin’s Enterprises in Duncan, Oklahoma. In early 2004, the Company completed the acquisition of Texas Equipment and Service Co, which manufactures coiled tubing equipment.

Wireline Products. Through its 1996 acquisitions of SSR (International) Ltd. and Pressure Control Engineering Ltd., its 1998 acquisition of Hydrolex and Eastern Oil Tools Pte. Ltd, and its 2001 acquisition of Elmar Services, Ltd., the Company offers a comprehensive line of wireline units and related pressure control products. Its manufacturing facilitiesare located in Poole and Aberdeen, in the United Kingdom; Perth, Australia; Dubai; Houston, Texas; and Singapore. The Company’s acquisition of Eastern Oil Tools Pte. Ltd. in June, 1998 and Elmar Services Ltd. in August, 2001 also added perforating gun and sand control screen manufacturing to the Company’s business.

The Company’s wireline products include wireline drum units, which consist of a spool or drum of wireline cable, mounted in a mobile vehicle or skid, which works in conjunction with a source of power (an engine mounted in the vehicle or within a separate “power pack” skid). The wireline drum unit is used to spool wireline cable into or out of a well, in order to perform surveys inside the well, sample fluids from the bottom of the well, retrieve or replace components from inside the well, or to perform other well remediation or survey operations. The wireline used may be “slickline,” which is conventional steel cable used to convey tools in or out of the well, or “electric line,” which contains an imbedded single-conductor or multi-conductor electrical

line which permits communication between the surface and electronic instruments attached to the end of the wireline at the bottom of the well.

Wireline units are usually used in conjunction with a variety of other pressure control equipment which permit safe access into wells while they are flowing and under pressure at the surface. The company engineers and manufactures a broad range of pressure control equipment for wireline operations, including wireline blow out preventers, strippers, packers, lubricators and grease injection units. Additionally, the Company makes wireline rigging equipment such as mast trucks, sheaves, and other items, and offers wireline tools through its Pressure Control Engineering Ltd. business.

The Company has a history of engineering new technologies and products for its Coiled Tubing & Wireline Products markets. It recently introduced the DSH “Sidedoor” Stripper/Packer, which allows packer and bushing replacement while the operator has coiled tubing in the wellbore, and the CT Slimhole BHA Jetting Tool Assembly, a small diameter jetting tool which can traverse small diameter well completion configurations.

Customers and Competition. The Company’s customers for Coiled Tubing & Wireline Products include major oil and gas coiled tubing service companies, as well as major oil companies, national oil companies, and small independents. Competitors in Coiled Tubing & Pressure Control Products include Stewart & Stevenson Inc.; Precision Tube Technology (a division of Maverick Tube Corporation); ASEP; National-Oilwell Inc.; Crown Energy Technologies; Baker Hughes Industries; Foremost Group; FID Group; Rolligon; Cromar, Ltd.; Hunt & Hunt; The Titan Group; Vanoil; Parveen Industries; and several smaller competitors.

2004 Acquisitions

In 2004, the Company made the following acquisitions and outside investments:


Acquisition	Form	Operating Segment	Date of Transactions
Texas Equipment & Services Co., LP	Asset	Coiled Tubing & Wireline	January 2004
Suzhou City Muyi Ship Equipment Co., Ltd.	Asset	Tubular Services	January 2004
Comprehensive Power, Inc.	Convertible Note	Drilling Equipment	March 2004
JB Equipment, Inc.	Asset	Drilling Services	April 2004
Recovery Systems, Ltd.	Asset	Drilling Services	April 2004
Wildcat Services, LP	Asset	Drilling Services	June 2004
Wellsite Gas Detection, Inc.	Stock	Drilling Services	July 2004
Threading business of Total Premier Services, Inc.	Asset	Tubular Services	October 2004

The Company paid an aggregate purchase price of $43.7 million ($33.2 million in cash and $10.5 million of notes payable) for acquisitions and outside investments in 2004, and paid $3.8 million in cash in 2004 related to transactions closed before 2004.

Seasonal Nature of the Company’s Business

Historically, the level of some of the Company’s businesses has followed seasonal trends to some degree. In general the Drilling Equipment group has not experienced significant seasonal fluctuation. However, there can be no guarantee that seasonal effects will not influence future drilling equipment sales.

The Company’s Tubular Services (specifically, tubular inspection and tubular coating) and Drilling Services (both solids control and rig instrumentation) businesses in Canada typically realized high first quarter activity levels, as operators took advantage of the winter freeze to help gain access to remote drilling and production areas. In the past years these businesses declined during the second quarter due to warming weather conditions which resulted in thawing, softer ground, difficulty accessing drill sites, and road bans that curtailed drilling activity (“Canadian Breakup”). In 2004, the business declined approximately $10.5 million in revenue and $6.8 million in operating profit from the first quarter to the second quarter. In past years, the business rebounded in the third and fourth quarter. Tubular Services activity in both the United States and Canada sometimes increased during the third quarter and then peaked in the fourth quarter as operators spent the remaining drilling and/or production capital budgets for the year.

The pipeline inspection portion of Tubular Services has typically experienced reduced activity during the first quarter of the calendar year. The high winter demand for gas and petroleum products in the northern states and the consequent curtailment of pipeline maintenance and inspection programs has resulted in less opportunity to perform pipeline inspection during this time. The Company’s Fiberglass & Composite Tubulars business in China has typically declined in the first quarter due to the impact of weather on manufacturing and installation operations, and due to business slow downs associated with the Chinese New Year.

The Company anticipates that the seasonal trends described above will continue. However, there can be no guarantee that spending by the Company’s customers will continue to follow patterns seen in the past or that spending by other customers will remain the same as in prior years.

Marketing & Distribution Network

The Company’s products are marketed through a sales organization and a network of agents and distributors, which spans most major oilfield markets.

The Company’s Drilling Equipment customers include private and government-owned oil companies; drilling contractors’ drilling rig manufacturers; rental tool companies; tubular installation service providers; and supply companies, which supply oilfield products to the end users of the Company’s products. Drilling Equipment purchases can represent significant capital expenditures, and are often sold as part of a rig fabrication or major rig refurbishment package. Sometimes these packages cover multiple rigs, and often the Company bids jointly with other related product and services providers, such as rig fabrication yards and rig design firms.

The Company’s Tubular Services customers include major and independent oil and gas companies; national oil companies; oilfield equipment and product distributors and manufacturers; drilling and workover contractors; oilfield service companies; pipeline operators; pipe mills; manufactures and processors; and other industrial companies. Certain tubular inspection and tubular coating products and services often are incorporated as a part of a tubular package sold by tubular supply stores to end users. Tubular Services primarily has direct operations in the international marketplace, but operates through agents in certain markets.

The Company’s Drilling Services customers are predominantly major and independent oil and gas companies; national oil companies; drilling contractors; providers of drilling fluids; and other oilfield service companies. The Drilling Services group operates sales and distribution facilities at strategic locations worldwide to service areas with high drilling activity. The Company’s worldwide solids control and instrumentation sales employees are complemented by service and engineering facilities which provide specialty repair and maintenance services to customers. Sales of capital equipment are sometimes made through rig fabricators, and often are bid as part of a rig fabrication package or rig refurbishment package. Sometimes these packages cover multiple rigs, and often the Company bids jointly with other related service providers.

The Company’s Coiled Tubing and Wireline Products customers include major oil and gas coiled tubing service companies, as well as major oil companies; national oil companies; and small independent providers of pressure pumping and well remediation services. The products are sold directly to end users through a worldwide Coiled Tubing & Wireline Products sales organization or through the Company’s sales agents. The Company also has in place certain exclusive alliances with major oilfield services companies to provide pressure control equipment.

The Company’s foreign operations, which include significant operations in Canada, Europe, the Far East, the Middle East and Latin America, are subject to the risks normally associated with conducting business in foreign countries, including foreign currency exchange risks and uncertain political and economic environments, which may limit or disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or the taking of property without fair compensation. Government-owned petroleum companies located in some of the countries in which the Company operates have adopted policies (or are subject to governmental policies) giving preference to the purchase of goods and services from companies that are majority-owned by local nationals. As a result of such policies, the Company relies on joint ventures, license arrangements and other business combinations with local nationals in these countries. In addition, political considerations may disrupt the commercial relationship between the Company and such government-owned petroleum companies. Although the Company has not experienced any significant problems in foreign countries arising from nationalistic policies, political instability, economic instability or currency restrictions, there can be no assurance that such a problem will not arise in the future. See Note 12 of the Notes to the Consolidated Financial Statements for information regarding geographic revenue information.

Research and New Product Development and Intellectual Property

The Company believes that it has been a leader in the development of new technology and equipment to enhance the safety and productivity of drilling and well servicing processes and that its sales and earnings have been dependent, in part, upon the successful introduction of new or improved products. Additionally, the Company believes that its market position in its major businesses is enhanced by its leading technologies and reputation for innovation and expertise. Through its internal development programs and certain acquisitions, the Company has assembled an extensive array of technologies protected by a substantial number of trade and service marks, patents, trade secrets, and other proprietary rights.

As of December 31, 2004, the Company held a substantial number of United States patents and had several patent applications pending. Expiration dates of such patents range from 2005 to 2020. As of this date, the Company also had foreign patents and patent applications pending relating to inventions covered by the United States patents. Additionally, the Company maintains a substantial number of trade and service marks and maintains a number of trade secrets.

Although the Company believes that this intellectual property has value, competitive products with different designs have been successfully developed and marketed by others. The Company considers the quality and timely delivery of its products, the service it provides to its customers and the technical knowledge and skills of its personnel to be more important than its intellectual property in its ability to compete. While the Company stresses the importance of its research and development programs, the expense and market uncertainties associated with the development and successful introduction of new products are such that there can be no assurance that the Company will realize future revenues from new products.

Engineering and Manufacturing

The manufacturing processes for the Company’s products generally consist of machining, welding and fabrication, heat treating, assembly of manufactured and purchased components and testing. Most equipment is manufactured primarily from alloy

steel, and the availability and price of alloy steel castings, forgings, purchased components and bar stock is critical to the production and timing of shipments. Within the Drilling Equipment group, automated Roughnecks, Top Drive Drilling Systems, and pipe handling systems are manufactured in Orange, California; pressure control and motion compensation equipment, riser pipe and riser tensioners are manufactured at facilities in Houston, Texas; rotating and handling tools are manufactured at facilities in Etten-Leur, the Netherlands, and Mexicali, Mexico.

The Company’s Drilling Services group manufactures or assembles the equipment and products which it rents and sells to customers, and which it uses in providing solids control services. In addition to producing new solids control and instrumentation equipment and products, Drilling Services also produces spare parts for sale. Drilling Services manufactures screens used in its solids control operations and for sale to others at its facilities in New Iberia, Louisiana; Conroe, Texas; Aberdeen, Scotland; Canada; Trinidad; and Brazil. The Company manufactures solids control equipment at its facilities in Houston, Texas; Conroe, Texas; and Aberdeen, Scotland; and manufactures instrumentation equipment at its Cedar Park, Texas; and Houston, Texas facilities.

The Tubular Services group manufactures tubular inspection equipment and instrumented pipeline inspection tools at its Houston, Texas facility for resale, and renovates and repairs equipment at its manufacturing facilities in Houston, Texas; Bordon, England; Celle, Germany; Nisku, Alberta and Aberdeen, Scotland. Fiberglass and composite tubulars and fittings are manufactured at its San Antonio, Texas; Big Spring, Texas; Little Rock, Arkansas; Tulsa, Oklahoma; Wichita, Kansas; and Harbin and Suzhou, China facilities, while tubular coatings are manufactured in its Houston, Texas facility, or through restricted sale agreements with third party manufacturers.

The Coiled Tubing and Wireline Products group manufactures coiled tubing units, coiled tubing, wireline units, pressure pumping equipment, pressure control equipment; sand control screens and perforating guns at its Fort Worth, Texas; Conroe, Texas; Houston, Texas; Duncan, Oklahoma; Tulsa, Oklahoma; Calgary, Canada; Aberdeen, Scotland; Singapore; Perth, Australia; and Poole, England facilities.

Certain of the Company’s manufacturing facilities and certain of the Company’s products have various certifications, including, ISO 9001, API and ASME.

Raw Materials

The Company believes that materials and components used in its servicing and manufacturing operations and purchased for sales are generally available from multiple sources. The prices paid by the Company for its raw materials may be affected by, among other things, energy, steel and other commodity prices; tariffs and duties on imported materials; and foreign currency exchange rates. The Company experienced higher steel prices and greater difficulty securing necessary steel supplies in 2004 than it experienced during the preceding several years. The Company has generally been successful in its effort to mitigate the financial impact of higher raw materials costs on its operations by applying surcharges to and adjusting prices on the products it sells. However, higher prices and lower availability of steel and other raw material the Company uses in its business may adversely impact future periods.

Backlog

Sales of the Company’s products are made on the basis of written purchase orders or contracts and, consistent with industry practice, by e-mail, fax, letter or oral commitment later confirmed by a written order. In accordance with industry practice, orders and commitments generally can be cancelled by customers at any time. In addition, orders and commitments are sometimes modified before or during manufacture of the products. The Company’s backlog is based upon anticipated revenues from customer orders that the Company believes are firm. The level of backlog at any particular time is not necessarily indicative of the future operating performance of the Company. Almost all of the Company’s backlog is for capital equipment orders. Although aftermarket spares, services and consumables for Drilling Equipment and Coiled Tubing and Wireline products are included in the Company’s order intake and backlog, these are typically turned quickly, and comprise a small portion of the backlog.

Backlog at December 31, 2004, 2003, and 2002 was as follows (in millions):


	December 31,
	2004		2003		2002
Drilling Equipment Group	$	140.8	$	83.3	$	178.0
Coiled Tubing & Wireline Products		98.1		37.0		49.1

Total Backlog From Continuing Operations		238.9		120.3		227.1
Discontinued MIL Operations		—		43.2		40.1

Total	$	238.9	$	163.5	$	267.2

The Company expects that most of the backlog as of December 31, 2004 will be shipped by December 31, 2005.

Environmental Matters

The Company’s manufacturing processes and its inspection, coating and solids control services routinely involve the handling and disposal of chemical substances and waste materials, some of which may be considered to be hazardous wastes. These potential hazardous wastes result primarily from the manufacturing and testing processes and the use of mineral spirits to clean pipe threads during the tubular inspection process and from the coating process, and the handling of and, in normal cases, the disposal of drilling fluids and cuttings on behalf of the drillers and/or producers.

The Company’s operations are subject to numerous local, state and federal laws and regulations, including the regulations promulgated by the Occupational Safety and Health Administration, the United States Environmental Protection Agency (EPA), the Nuclear Regulatory Commission and the United States Department of Transportation. These laws and regulations include the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), the Resource Conservation and Recovery Act (RCRA), the Clean Air Act (CAA), the Clean Water Act (CWA), the Superfund Amendments and Reauthorization Act (SARA) including SARA Title III toxic release reporting, the Safe Drinking Water Act (SDWA) and the Toxic Substance Control Act (TSCA). Management believes that the Company is in substantial compliance with these laws and regulations, and that the compliance and remedial action costs associated with these laws and regulations have not had a material adverse effect on its results of operations, financial condition or competitive position, to date.

The Company cannot predict the effect on it of new laws and regulations with respect to radioactive hazardous wastes caused by naturally occurring radioactive materials or with respect to other environmental matters. Circumstances or developments which are not currently known as well as the future cost of compliance with environmental laws and regulations could be substantial and could have a material adverse effect on the results of operations and financial condition of the Company.

CERCLA imposes liability, without regard to fault or the legality of the original conduct, for the release of hazardous substances into the environment. Persons subject to CERCLA include the owner and operator of the disposal site or sites where the release occurred and companies that generated, disposed or arranged for the disposal of the hazardous wastes found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the resulting contamination and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Certain third-party owned disposal facilities used by the Company or its subsidiaries have been investigated under state and federal Superfund statutes, and the Company is currently named as a potentially responsible party for cleanup at four such sites. Although the Company’s level of involvement varies at each site, in general, the Company is one of numerous parties named and will be obligated to pay an allocated share of the cleanup costs. While it is not feasible to predict the outcome of these matters with certainty, management believes that their ultimate resolution should not result in material costs to the Company or otherwise materially and adversely affect the Company’s operations or financial position.

Employees

At December 31, 2004, the Company had a total of 10,572 employees (of which 1,651 were temporary employees). The Company considers its relations with its employees to be good. Approximately 122 employees in the Company’s Fiberglass & Composite Tubulars plants in Little Rock, Arkansas, are subject to collective bargaining agreements. Additionally, certain of the Company’s employees in certain foreign locations, principally Norway and Argentina, are subject to collective bargaining agreements.

GLOSSARY OF OILFIELD TERMS


		(Sources: Varco management; “A Dictionary for the Petroleum Industry,” The University of Texas at Austin, 2001.)

API		Abbr: American Petroleum Institute

Annular Blowout Preventer		A large valve, usually installed above the ram blowout preventers, that forms a seal in the annular space between the pipe and the wellbore or, if no pipe is present, in the wellbore itself.

Annulus		The open space around pipe in a wellbore through which fluids may pass.

Automatic Pipe Handling Systems (Automatic Pipe Racker)		A device used on a drilling rig to automatically remove and insert drill stem components from and into the hole. It replaces the need for a person to be in the derrick or mast when tripping pipe into or out of the hole.

Automatic Roughneck		A large, self-contained pipe-handling machine used by drilling crew members to make up and break out tubulars. The device combines a spinning wrench, torque wrench, and backup wrenches.

Beam pump		Surface pump that raises and lowers sucker rods continually, so as to operate a downhole pump.

Bit		The cutting or boring element used in drilling oil and gas wells. The bit consists of a cutting element and a circulating element. The cutting element is steel teeth, tungsten carbide buttons, industrial diamonds, or polycrystalline diamonds (PDCs). These teeth, buttons, or diamonds penetrate and gouge or scrape the formation to remove it. The circulating element permits the passage of drilling fluid and utilizes the hydraulic force of the fluid stream to improve drilling rates. In rotary drilling, several drill collars are joined to the bottom end of the drill pipe column, and the bit is attached to the end of the drill collars. Drill collars provide weight on the bit to keep it in firm contact with the bottom of the hole. Most bits used in rotary drilling are roller cone bits, but diamond bits are also used extensively.

Blowout		An uncontrolled flow of gas, oil or other well fluids into the atmosphere. A blowout, or gusher, occurs when formation pressure exceeds the pressure applied to it by the column of drilling fluid. A kick warns of an impending blowout.

Blowout Preventer (BOP)		Series of valves installed at the wellhead while drilling to prevent the escape of pressurized fluids.

Blowout Preventer (BOP) Stack		The assembly of well-control equipment including preventers, spools, valves, and nipples connected to the top of the wellhead.

Closed Loop Drilling Systems		A solids control system in which the drilling mud is reconditioned and recycled through the drilling process on the rig itself.

Coiled Tubing		A continuous string of flexible steel tubing, often hundreds or thousands of feet long, that is wound onto a real, often dozens of feet in diameter. The reel is an integral part of the coiled tubing unit, which consists of several devices that ensure the tubing can be safely and efficiently inserted into the well from the surface. Because tubing can be lowered into a well without having to make up joints of tubing, running coiled tubing into the well is faster and less expensive than running conventional tubing. Rapid advances in the use of coiled tubing make it a popular way in which to run tubing into and out of a well. Also called reeled tubing.

Cuttings		Fragments of rock dislodged by the bit and brought to the surface in the drilling mud. Washed and dried cutting samples are analyzed by geologist to obtain information about the formations drilled.

Directional Well		Well drilled in an orientation other than vertical in order to access broader portions of the formation.


Drawworks		The hoisting mechanism on a drilling rig. It is essentially a large winch that spools off or takes in the drilling line and thus raises or lowers the drill stem and bit.

Drill Pipe Elevator (Elevator)		On conventional rotary rigs and top-drive rigs, hinged steel devices with manual operating handles that crew members latch onto a tool joint (or a sub). Since the elevators are directly connected to the traveling block, or to the integrated traveling block in the top drive, when the driller raises or lowers the block or the top-drive unit, the drill pipe is also raised or lowered.

Drilling Mud		A specially compounded liquid circulated through the wellbore during rotary drilling operations.

Drilling riser		A conduit used in offshore drilling through which the drill bit and other tools are passed from the rig on the water’s surface to the sea floor.

Drill Stem		All members in the assembly used for rotary drilling from the swivel to the bit, including the Kelly, the drill pipe and tool joints, the drill collars, the stabilizers, and various specialty items.

Formation		A bed or deposit composed throughout of substantially the same kind of rock; often a lithologic unit. Each formation is given a name, frequently as a result of the study of the formation outcrop at the surface and sometimes based on fossils found in the formation.

Hardbanding		A special wear-resistant material often applied to tool joints to prevent abrasive wear to the area when the pipe is being rotated downhole.

Iron Roughneck		A floor-mounted combination of a spinning wrench and a torque wrench. The Iron Roughneck moves into position hydraulically and eliminates the manual handling involved with suspended individual tools.

Jack-up rig		A mobile bottom-supported offshore drilling structure with columnar or ope-truss legs that support the deck and hull. When positioned over the drilling site, the bottoms of the legs penetrate the seafloor.

Joint		1) In drilling, a single length (from 16 feet to 45 feet, or 5 meters to 14.5 metres, depending on its range length) of drill pipe, drill collar, casing or tubing that has threaded connections at both ends. Several joints screwed together constitute a stand of pipe. 2) In pipelining, a single length (usually 40 feet-12 metres) of pipe. 3) In sucker rod pumping, a single length of sucker rod that has threaded connections at both ends.

Kelly		The heavy steel tubular device, four- or six-sided, suspended from the swivel through the rotary table and connected to the top joint of drill pipe to turn the drill stem as the rotary table returns. It has a bored passageway that permits fluid to be circulated into the drill stem and up the annulus, or vice versa. Kellys manufactured to API specifications are available only in four- or six-sided versions, are either 40 or 54 feet (12 to 16 metres) long, and have diameters as small as 2 1/2 inches (6 centimetres) and as large as 6 inches (15 centimetres).

Kelly Bushing		A special device placed around the kelly that mates with the kelly flats and fits into the master bushing of the rotary table. The kelly bushing is designed so that the kelly is free to move up or down through it. The bottom of the bushing may be shaped to fit the opening in the master bushing or it may have pins that fit into the master bushing. In either case, when the kelly bushing is inserted into the master bushing and the master bushing is turned, the kelly bushing also turns. Since the kelly bushing fits onto the kelly, the kelly turns, and since the kelly is made up to the drill stem, the drill stem turns. Also called the drive bushing.

Kelly Spinner		A pneumatically operated device mounted on top of the kelly that, when actuated, causes the kelly to turn or spin. It is useful when the kelly or a joint of pipe attached to it must be spun up, that is, rotated rapidly for being made up.

Kick		An entry of water, gas, oil, or other formation fluid into the wellbore during drilling. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. If prompt action is not taken to control the kick, or kill the well, a blowout may occur.


Making-up		1. To assemble and join parts to form a complete unit (e.g., to make up a string of drill pipe). 2. To screw together two threaded pieces. Compare break out. 3. To mix or prepare (e.g., to make up a tank of mud). 4. To compensate for (e.g., to make up for lost time).

Manual Tongs (Tongs)		The large wrenches used for turning when making up or breaking out drill pipe, casing, tubing, or other pipe; variously called casing tongs, pipe tongs, and so forth, according to the specific use. Power tongs or power wrenches are pneumatically or hydraulically operated tools that serve to spin the pipe up tight and, in some instances to apply the final makeup torque.

Master Bushing		A device that fits into the rotary table to accommodate the slips and drive the kelly bushing so that the rotating motion of the rotary table can be transmitted to the kelly. Also called rotary bushing.

Motion Compensation Equipment		Any device (such as a bumper sub or heave compensator) that serves to maintain constant weight on the bit in spite of vertical motion of a floating offshore drilling rig.

Plug Gauging		The mechanical process of ensuring that the inside threads on a piece of drill pipe comply with API standards.

Pressure Control Equipment		1. The act of preventing the entry of formation fluids into a wellbore. 2. The act of controlling high pressures encountered in a well.

Pressure Pumping		Pumping fluids into a well by applying pressure at the surface.

Ram Blowout Preventer		A blowout preventer that uses rams to seal off pressure on a hole that is with or without pipe. Also called a ram preventer.

Ring Gauging		The mechanical process of ensuring that the outside threads on a piece of drill pipe comply with API standards.

Riser		A pipe through which liquids travel upward.

Riser Pipe		The pipe and special fitting used on floating offshore drilling rigs to established a seal between the top of the wellbore, which is on the ocean floor, and the drilling equipment located above the surface of the water. A riser pipe serves as a guide for the drill stem from the drilling vessel to the wellhead and as a conductor or drilling fluid from the well to the vessel. The riser consists of several sections of pipe and includes special devices to compensate for any movement of the drilling rig caused by waves. Also called marine riser pipe, riser joint.

Rotary table		The principal piece of equipment in the rotary table assembly; a turning device used to impart rotational power to the drill stem while permitting vertical movement of the pipe for rotary drilling. The master bushing fits inside the opening of the rotary table; it turns the kelly bushing, which permits vertical movement of the kelly while the stem is turning.

Rotating Blowout Preventer (Rotating Head)		A sealing device used to close off the annular space around the kelly in drilling with pressure at the surface, usually installed above the main blowout preventers. A rotating head makes it possible to drill ahead even when there is pressure in the annulus that the weight of the drilling fluid is not overcoming; the head prevents the well from blowing out. It is used mainly in the drilling of formations that have low permeability. The rate of penetration through such formations is usually rapid.

Safety Clamps		A clamp placed very tightly around a drill collar that is suspended in the rotary table by drill collar slips. Should the slips fail, the clamp is too large to go through the opening in the rotary table and therefore prevents the drill collar string from falling into the hole. Also called drill collar clamp.

Shaker		See “Shale Shaker”

Shale Shaker		A piece of drilling rig equipment that uses a vibrating screen to remove cuttings from the circulating fluid in rotary drilling operations. The size of the openings in the screen should be selected carefully to be the smallest size possible to allow 100 per cent flow of the fluid. Also called a shaker.


Slim-Hole Completions (Slim-hole Drilling)		Drilling in which the size of the hole is smaller than the conventional hole diameter for a given depth. This decrease in hole size enables the operator to run smaller casing, thereby lessening the cost of completion.

Slips		Wedge-shaped pieces of metal with serrated inserts (dies) or other gripping elements, such as serrated buttons, that suspend the drill pipe or drill collars in the master bushing of the rotary table when it is necessary to disconnect the drill stem from the kelly or from the top-drive unit’s drive shaft. Rotary slips fit around the drill pipe and wedge against the master bushing to support the pipe. Drill collar slips fit around a drill collar and wedge against the master bushing to support the drill collar. Power slips are pneumatically or hydraulically actuated devices that allow the crew to dispense with the manual handling of slips when making a connection.

Solids		See “Cuttings”

Spinning Wrench		Air-powered or hydraulically powered wrench used to spin drill pipe in making or breaking connections.

Spinning-in		The rapid turning of the drill stem when one length of pipe is being joined to another. “Spinning-out” refers to separating the pipe.

Stand		The connected joints of pipe racked in the derrick or mast when making a trip. On a rig, the usual stand is about 90 feet (about 27 metres) long (three lengths of drill pipe screwed together), or a thribble.

String		The entire length of casing, tubing, sucker rods, or drill pipe run into a hole.

Sucker rod		A special steel pumping rod. Several rods screwed together make up the link between the pumping unit on the surface and the pump at the bottom of the well.

Tensioner		A system of devices installed on a floating offshore drilling rig to maintain a constant tension on the riser pipe, despite any vertical motion made by the rig. The guidelines must also be tensioned, so a separate tensioner system is provided for them.

Thermal Desorption		The process of removing drilling mud from cuttings by applying heat directly to drill cuttings.

Top Drive		A device similar to a power swivel that is used in place of the rotary table to turn the drill stem. It also includes power tongs. Modern top drives combine the elevator, the tongs, the swivel, and the hook. Even though the rotary table assembly is not used to rotate the drill stem and bit, the top-drive system retains it to provide a place to set the slips to suspend the drill stem when drilling stops.

Torque Wrench		Spinning wrench with a gauge for measuring the amount of torque being applied to the connection.

Trouble Cost		Costs incurred as a result or unanticipated complications while drilling a well. These cost are often referred to as contingency costs during the planning phase of a well.

Well Completion		1. The activities and methods of preparing a well for the production of oil and gas or for other purposes, such as injection; the method by which one or more flow paths for hydrocarbons are established between the reservoir and the surface. 2. The system of tubulars, packers, and other tools installed beneath the wellhead in the production casing; that is, the tool assembly that provides the hydrocarbon flow path or paths.

Well stimulation		Any of several operations used to increase the production of a well, such as acidizing or fracturing.

Well Workover		The performance of one or more of a variety of remedial operations on a producing oilwell to try to increase production oilwell to try to increase production. Examples of workover jobs are deepening, plugging back, pulling and resetting liners, and squeeze cementing.

Wellbore		A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole.

Wireline		A slender, rodlike or threadlike piece of metal usually small in diameter, that is used for lowering special tools (such as logging sondes, perforating guns, and so forth) into the well. Also called slick line.

ITEM 2.

PROPERTIES

The Company operates in over 40 countries. The following table describes the major manufacturing, sales, service, distribution, and administrative facilities:


Location	Description	Building Size (Square Feet)	Property Size (Acres)	Owned/Leased	Lease Termination Date

DRILLING EQUIPMENT GROUP:

Houston, Texas	West Little York Manufacturing Facility, Repair, Service, Administrative & Sales Offices	619,000	34.00	Owned

Orange, California	Manufacturing & Office Facility - 759 N. Eckhoff	126,000	8.90	Building Owned*	04/30/12

Aberdeen, Scotland	Pressure Control Manufacturing, Administrative & Sales	107,974	7.50	Leased	08/31/19

Mexicali, Mexico	Mfg. Plant	76,402		Leased	04/01/14

Etten-Leur, Netherlands	Mfg. Plant/Sales	75,000	6.00	Owned

Houston, Texas	Brittmore Shaffer Repair & Service Facility	66,500	5.79	Leased	11/01/11

Aberdeen, Scotland	Systems & Shaffer Sales, Service & Distribution Facility	63,000	6.00	Owned

Stavanger, Norway	Drilling Equipment Work Shop, Warehouse & Customer Service Center	41,333	0.42	Leased	06/01/09

Singapore	Systems Offices, Service & Distribution Facility	35,079	1.20	Building Owned*	07/01/40

Orange, California	Administrative Offices—743 N. Eckhoff	35,000	1.60	Leased	12/31/05

TUBULAR SERVICES:

Al Khobar, Saudi Arabia	Reclamation, Inspection Facility & Offices	340,203	8.00	Leased	12/31/04

Houston, Texas	Sheldon Road: Inspection Facility	335,993	192.00	Owned

Houston, Texas	Holmes Road Complex: Manufacturing, Warehouse, Corporate Offices, Coating Manufacturing Plant & Pipeline Services	300,000	50.00	Owned

Little Rock, Arkansas	Fiberglass Tubular Manufacturing Plant, R&D Lab, Administrative Offices	262,784	44.00	Leased	Yr. to Yr.

Yopal, Colombia	Inspection and Solids Control Warehouse & Storage	215,280	4.94	Owned

Sand Springs, Oklahoma	Fiberglass Tubular Manufacturing Plant	189,173	6.50	Owned

Amelia, Louisiana	Coating Plant & Inspection Facility	179,574	84.00	Leased	12/31/16

Houston, Texas	Coating Plant & Inspection Facility	168,683	49.00	Owned

Wichita, Kansas	Fiberglass Tubular Manufacturing Plant	129,746	15.00	Owned

Nisku, Alberta	Trucking, Rod Plant, Inspection & Storage Facility	121,545	155.00	Owned

Nisku, Alberta	Coating Plant, Inspection & Drill Pipe Facility	114,000	47.00	Owned

Amelia, Louisiana	Coating Plant, Inspection & Storage Facilities	102,000	90.00	Building Owned*	05/30/06

Casper, Wyoming	Inspection Facility	91,720	29.00	Owned


Midland, Texas	Coating Plant	87,000	25.00	Owned

Houston, Texas	Highway 90: Coating Plant	83,000	43.00	Leased	07/31/11

San Antonio, Texas	Fiberglass Tubular Manufacturing Plant, R & D Lab, Administrative Offices	82,700	19.57	Owned

Big Spring, Texas	Fiberglass Tubular Manufacturing Plant & Administrative Offices	78,600	12.00	Owned

Houston, Texas	Engineering/Technical Research Center	76,000	6.00	Owned

Navasota, Texas	Coating Plant, Inspection Pipe Storage	65,000		Building Owned*	06/30/13

Su Zhou, People’s Republic of China	Fiberglass Tubular Manufacturing Plant	60,000	4.00	Owned

Lone Star, Texas	Inspection Facility	56,700	80.00	Owned

Neiva, Columbia	Inspection Yard & Warehouse	54,898	1.26	Leased	01/31/05

Aberdeen, Scotland	Inspection Facility, Coating Plant, Manufacturing, Administrative & Sales	53,425	10.00	Owned

Coevorden, Netherlands	Inspection Reclamation & Repair Facility	53,361	2.00	Leased	12/04/04

Harvey, Louisiana	Coating Plant & Inspection Facility	53,000	7.00	Owned & Leased	09/30/04

Tuas, Singapore	Coating Plant & Inspection Facility	50,644	8.00	Building Owned*	06/09/09

Odessa, Texas	Coating Plant & Inspection Facility	45,332	10.00	Owned

Little Rock, Arkansas	Fiberglass Tubular Manufacturing Plant	45,000		Leased	10/01/09

Berlaimont, France	Coating Plant	44,000	16.00	Owned

Celle, Germany	Inspection Facility, Administrative & Engineering Offices	43,560	12.00	Building Owned*	2049

Morgan City, Louisiana	Inspection Facility	42,400	3.00	Building Owned*	Mo. to Mo.

Casper, Wyoming	Inspection Facility	41,030	40.00	Owned

Edmond, Oklahoma	Coating Plant	40,000	19.00	Owned

Farmington, New Mexico	Inspection Storage Facilities	37,725	50.00	Leased	03/31/14

Harbin, People’s Republic of China	Fiberglass Tubular Manufacturing Plant	35,000	5.00	Leased	12/31/07

Odessa, Texas	Inspection Facility	33,910	50.00	Owned

Edmonton, Alberta	Sucker Rod Inspection & Oilwell Engine Reclamation	32,550	10.00	Leased	12/31/05

DRILLING SERVICES:

Cedar Park, Texas	Instrumentation Manufacturing Facility, Administrative & Sales Offices	260,000	40.00	Owned

Conroe, Texas	Solids Control & Pressure Control Manufacturing Facility, Warehouse, Administrative & Sales Offices & Engineering Labs	160,000	30.49	Owned

Aberdeen, Scotland	Solids Control Manufacturing Facility Assembly, Administrative & Sales	77,400	6.25	Owned

Bogota, Colombia	Solids Control & Inspection Yard & Warehouse	69,966		Leased	08/01/04

Leduc, Alberta	MDT, Shaffer, Chimo, Alberta Instruments, Varco Services & Warehouse Facility	64,056	4.60	Owned


Leduc, Alberta	Solids Control Equipment Rental & Services Facility	41,340	9.36	Owned

Montrose, Scotland	Forties Road Systems Service Center & Office Facility	34,000	3.00	Owned

COILED TUBING / WIRELINE:

Fort Worth, Texas	Coiled Tubing Manufacturing Facility, Warehouse, Administrative & Sales Offices	167,999	30.92	Leased	01/31/14

Houston, Texas	QT Coiled Tubing Manufacturing Facility, Warehouse and Offices	101,250	14.00	Owned

Duncan, Oklahoma	Nitrogen Units Manufacturing Facility, Warehouse & Offices	67,600	13.28	Owned

Calgary, Alberta	Coiled Tubing Manufacturing Facility, Administrative & Sales Offices	48,040	2.52	Owned

Tulsa, Oklahoma	Pumping Manufacturing Facility, Warehouse & Offices	40,700	4.47	Leased	12/31/07

Tuas, Singapore	Coiled Tubing & Wireline Products Manufacturing & Administrative Facility	35,300	1.50	Building Owned*	04/15/14

Great Yarmouth, England	Coiled Tubing & Nitrogen Units Manufacturing, Administrative & Sales Offices	29,000	1.70	Leased	08/22/11

CORPORATE:

Houston, Texas	Corporate Administrative Office	14,500	Office Tower	Leased	08/31/11

*	Building owned but real estate leased.

The Company owns undeveloped acreage next to several of its facilities, including over 100 acres of undeveloped property located in Houston, Texas. Machinery, equipment, buildings, and other facilities owned and leased are considered by management to be adequately maintained and adequate for the Company’s operations.

ITEM 3.

LEGAL PROCEEDINGS

The following discussion contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements relate to the Company’s legal proceedings described below. Litigation is inherently uncertain and may result in adverse rulings or decisions. Additionally, the Company may enter into settlements or be subject to judgments which may, individually or in the aggregate, have a material adverse effect on the Company’s results of operations. Accordingly, actual results could differ materially from those projected in the forward-looking statements.

The Company is involved in numerous legal proceedings which arise in the ordinary course of its business. The Company is unable to predict the outcome of these proceedings; however, management believes that none of these legal proceedings will have a material adverse effect on the results of operations or financial condition of the Company. There can be no absolute assurance that the indemnity from Minstar Inc. (“Minstar”) discussed below or the Company’s insurance coverage will be sufficient to protect the Company from incurring substantial liability as a result of these proceedings.

The Company has been party to two lawsuits that allege wrongful death or injury of former employees resulting from exposure to silica and silica dust during employment with the Company, both of which have been settled. These settlements have been made on the Company’s behalf by the Company’s and Minstar’s insurance carriers without financial loss to the Company. The Company is aware of the possibility that suits may be brought against it by other former employees alleging exposure to silica and silica dust during their employment with the Company. These suits may involve claims for wrongful death under a theory of gross negligence and claims for punitive damages, the amounts of which could be substantial but cannot be predicted. Additionally, the Company has been sued in the past for claims arising out of allegations of exposure to silica, asbestos, benzene and certain other substances alleged to have been used primarily during its processes in the 1960s, 1970s, and early 1980s. The Company believes that, based upon insurance and indemnification from Minstar, any such potential claims, if asserted, would not have a material adverse effect on the Company’s results of operations or financial condition.

Pursuant to an agreement executed in connection with the acquisition of the Company in 1988, Minstar agreed to hold the Company harmless from and against any and all losses, liabilities, damages, deficiencies and expenses (in excess of $1.5 million in the aggregate) arising out of product and/or general liability claims arising out of occurrences on or prior to the closing of the acquisition. In addition, Minstar agreed to hold the Company harmless from any and all losses, liabilities and damages, deficiencies and expenses related to any action, suit, litigation, proceeding or governmental investigation existing or pending on or prior to the closing of the acquisition. Minstar’s obligations to indemnify the Company are subject to limitations concerning the time for submitting claims and the amount of losses to be covered. There is a dispute with Minstar concerning whether the indemnification referenced above is applicable only if the claim is the type that would be covered by a product or general liability insurance policy. The Company firmly maintains that all suits or claims are the responsibility of Minstar when the event giving rise to liability occurred prior to the closing of the acquisition. No assurance can be given, however, that Minstar will not contest responsibility for future suits, including those filed under theories of gross negligence. Management believes that Minstar is responsible for indemnifying it with respect to all of the aforementioned lawsuits subject in certain instances to the $1.5 million basket. In addition, while management believes certain liability arising from certain of the above described suits will be covered by insurance, such suits may be subject to a reservation of rights and the coverage could be contested by the carriers providing such insurance.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of stockholders during the fourth quarter of 2004.

PART II

ITEM 5.

MARKETS FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

The Company’s common stock is traded on the New York Stock Exchange (NYSE) under the symbol “VRC”. The following table sets forth, for the calendar periods indicated, the range of high and low closing prices for the common stock, as reported by the NYSE:


	2004				2003
	High		Low		High		Low
1st Quarter	$	22.77	$	17.50	$	19.42	$	16.18
2nd Quarter		21.89		18.00		22.26		17.45
3rd Quarter		27.21		21.75		20.16		16.33
4th Quarter		30.39		26.24		21.10		16.25

The closing price of the Company’s common stock on February 11, 2005 was $33.70. The approximate number of stockholders of record on February 11, 2005 was 1,004.

Holders of the Company’s common stock are entitled to such dividends as may be declared from time to time by the Company’s Board of Directors out of funds legally available therefore. The Company has not declared or paid any dividends on its common stock since its inception and does not currently plan to declare or pay any dividends.

ITEM 6.

SELECTED FINANCIAL DATA

The information below is presented in order to highlight significant trends in the Company’s results from operations and financial condition.


	Years Ended December 31,
	2004			2003			2002			2001			2000
				(restated) (1)
	(dollars in millions, except ratio and per share data)
Statement of Income Data:
Revenue	$	1,568.1		$	1,437.6		$	1,322.4		$	1,261.8		$	866.6
Operating profit (2)		198.4			166.0			158.2			158.0			60.9
Net income from continuing operations(3)		107.4			88.8			81.3			82.9			21.1
Net income	$	97.8		$	67.2		$	79.8		$	83.0		$	21.1

Basic earnings per common share(3):
Continuing operations	$	1.10		$	0.91		$	0.84		$	0.87		$	0.23

Net Income	$	1.00		$	0.69		$	0.83		$	0.87		$	0.23

Dilutive earnings per common share(3):
Continuing operations	$	1.09		$	0.90		$	0.83		$	0.86		$	0.22

Net Income	$	0.99		$	0.68		$	0.82		$	0.86		$	0.22

Balance Sheet Data (end of period):
Working capital	$	657.8		$	559.0		$	529.6		$	423.6		$	263.4
Total assets		1,901.7			1,764.3			1,661.1			1,429.1			1,077.0
Total debt		461.8			457.0			467.9			322.6			136.5
Common stockholders’ equity		1,118.6			994.2			920.3			828.3			732.0

Other Data:
Net cash provided by operating activities	$	114.2		$	100.7		$	101.8		$	84.0		$	81.8
Cash flows used for investing activities	$	(89.8	)	$	(106.6	)	$	(202.3	)	$	(211.1	)	$	(64.9	)

Cash flows provided by (used for) financing activities	$	6.3		$	(15.1	)	$	148.3		$	173.1		$	(86.7	)
Earnings per common share before goodwill amortization(3)	$	0.99		$	0.68		$	0.82		$	0.97		$	0.31

Ratio of earnings to fixed charges(4)		5.2x			4.5x			4.8x			5.6x			3.1x
Depreciation and amortization	$	75.5		$	67.2		$	59.2		$	67.9		$	56.5
Capital expenditures	$	51.9		$	67.1		$	49.4		$	65.8		$	45.5

(1)	In the first quarter of 2004, the Company discontinued its Morinoak International Ltd (MIL) rig fabrication operation. Results for 2003, 2002, and 2001 have been restated to report this operation as discontinued. There is no impact on the 2000 results as MIL was purchased in 2001.

(2)

Operating profit and earnings per common share from continuing operations for the fiscal years ended December 31, 2000 through 2004 includes: Drilling Equipment Group restructuring costs, and merger, transaction, and litigation costs. The following table discloses operating profit and earnings per common share from continuing operations excluding these costs in the years 2000 through 2004. The Company believes that reporting operating profit and dilutive EPS from continuing operations excluding Drilling Equipment Group restructuring costs, and merger, transaction and litigation costs provides useful supplemental information regarding the Company’s on-going economic performance and, therefore, uses this financial measure internally to evaluate and manage the Company’s operations. The Company has chosen to provide this information to investors to enable them to perform more meaningful comparisons of operating results and as a means to emphasize the results of on-going operations.


	Years Ended December 31,
	2004			2003		2002		2001		2000
	(in millions)
Operating Profit	$	198.4		$	166.0	$	158.2	$	158.0	$	60.9
National Oilwell merger costs		5.0			—		—		—		—
Drilling Equipment Group restructure costs		5.7			0.9		—		—		—
ICO acquisition costs		—			—		3.7		—		—
Litigation settlements/costs		(3.8	)		—		—		16.5		—
Cost associated with Varco/Tuboscope merger		—			—		2.8		—		26.5

Operating profit before Drilling Equipment Group restructuring, merger, transaction, and litigation costs	$	205.3		$	166.9	$	164.7	$	174.5	$	87.4


	Years Ended December 31,
	2004			2003		2002		2001		2000
Dilutive earnings per share from continuing operations	$	1.09		$	0.90	$	0.83	$	0.86	$	0.22
National Oilwell merger costs		0.05			—		—		—		—
Drilling Equipment Group restructure costs		0.04			0.01		—		—		—
ICO acquisition costs		—			—		0.02		—		—
Litigation settlements/costs		(0.03	)		—		—		0.11		—
Cost associated with Varco/Tuboscope merger		—			—		0.02		—		0.13

Dilutive earnings per share from continuing operations before Drilling Equipment Group restructuring, merger, transaction, and litigation costs	$	1.15		$	0.91	$	0.88	$	0.97	$	0.35

(3)

The Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (SFAS 142), effective January 1, 2002. The effects of not amortizing goodwill and other intangible assets in periods prior to the adoption of SFAS 142 would have resulted in net income of $93.4 million and $29.5 million for the years ended December 31, 2001 and 2000, respectively; basic earnings per common share of $.98 and $.32 for the years ended December 31, 2001 and 2000, respectively; and diluted earnings per common share of $.97 and $0.31, for the years ended December 31, 2001 and 2000, respectively.

(4)

For the purpose of this calculation, “earnings” consist of net income (loss) from continuing operations before income taxes, extraordinary items, and fixed charges. “Fixed charges” consist of interest expense and amortization of debt discount and related expenses believed by management to be representative of the interest factor thereon.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

Executive Summary

The Company’s business showed steadily strengthening results throughout the year in 2004, due primarily to rising drilling and workover activity in the oilfield markets it serves; an improving level of investment in capital equipment by drilling contractors and other oilfield service firms; and the financial impact of a significant restructuring of the Company’s Drilling Equipment Group which commenced in the second half of 2003. Overall the Company generated a record level of revenue ($1,568.1 million) and operating profit ($198.4 million) from continuing operations in 2004.

The count of rigs actively drilling around the world increased each quarter of 2004, as compared to the corresponding quarter of 2003, which led the Company’s Tubular Service and Drilling Services Groups to post higher year-over-year revenues each quarter. The effect of eight acquisitions in 2004 and 13 acquisitions in 2003 also contributed to the higher sales level. Order levels and revenues for the Company’s Drilling Equipment Group moved up significantly from recent lows set in the fourth quarter of 2003, as drilling contractors increased levels of spending on aftermarket spare parts and services to support their operations, and new equipment to refurbish or upgrade rigs. These drilling contractors generally increased their purchases in response to the higher drilling activity levels and dayrates they received for their rigs in 2004. Likewise, the Company’s Coiled Tubing & Wireline Products Group also experienced generally rising demand for its equipment and consumables throughout 2004. The Coiled Tubing & Wireline Products Group set new order rate records in three out of the four quarters of 2004, and ended the year with a record level of backlog.

The following table summarizes the Company’s revenue from continuing operations by operating segment in 2004 and 2003 (in million):


	2004		2003		Variance
			(restated)		$			%
Drilling Equipment	$	445.4	$	462.2	$	(16.8	)	(3.6	%)
Tubular Services		536.9		455.9		81.0		17.8	%
Drilling Services		338.9		292.6		46.3		15.8	%
Coiled Tubing & Wireline Products		246.9		226.9		20.0		8.8	%

Total	$	1,568.1	$	1,437.6	$	130.5		9.1	%

Results for the year included the exit and closure of the Company’s Morinoak International Ltd. (“MIL”) rig fabrication business in early 2004, due to large losses on a rig fabrication project, and continuing losses from the operation generally. The Company’s 2001 through 2003 results have been restated to account for MIL as a discontinued operation. The Company’s consolidated results reflect significant charges associated with the completion of the land rig fabrication project, the completion of other projects at MIL, and the final closure of the business in the first quarter of 2004. The Company’s third quarter 2004 results reflect a gain in its discontinued operation related to the favorable negotiation of a contractual issue associated with the land rig fabrication project.

The Company’s fourth quarter 2004 results include $5.0 million in charges related to the Company’s proposed merger with National Oilwell. Unallocated overhead expenses for the Company increased approximately $7.5 million in 2004 compared to 2003, primarily due to higher levels of incentive compensation expense, which increased $8.0 million from the prior year.

Each of the four quarters of 2004 include charges related to the Company’s restructuring of its Drilling Equipment Group, commenced in mid-2003. These charges totaled $5.7 million in 2004 and $0.9 million in 2003, and consist primarily of severance obligations.

Drilling Equipment Group: Operating profit from the continuing operations of the Group, excluding restructuring charges of $5.7 million, improved $11.8 million in 2004 from the prior year, primarily as a result of the Company’s reduction of fixed costs in the business due to the restructuring. This improvement was accomplished in spite of a decline in revenue from continuing operations of the Group of $16.8 million or four percent compared to the prior year.

Group continuing operations revenue in 2003 compared to 2004 was higher due primarily to the Company’s 2003 shipments of equipment ordered between 2001 and 2002. These older orders were generally more complex than recent orders, due to the Company’s more recent strategic decision to standardize a number of product designs, and better manage technical design and manufacturing risk. Despite the higher volume of continuing operating revenue in 2003, the Group’s operating margin fell short of the Company’s stated 15 percent goal. As a result, the Company undertook a restructuring of the Group, which was executed between the third quarter of 2003 and the fourth quarter of 2004.

Compared to 2003, engineering, sales and administrative expenses declined $18.0 million, excluding restructuring charges. On an annualized basis the savings are expected to be approximately $20 million. The overhead cost reduction initiatives were complemented by initiatives to reduce manufacturing costs by moving certain assembly and machining functions related to the Group’s pipe handling equipment line into the Company’s lower cost manufacturing operation in Mexicali, Mexico.

The operating margin of the Drilling Equipment Group’s continuing operations, excluding restructuring charges, moved up steadily through 2004 as these initiatives were executed, and as demand grew. Operating margins from continuing operations and excluding Group restructuring charges increased from 8.0 percent in the fourth quarter of 2003, to 9.2 percent, 14.0 percent, 16.2 percent and 18.1 percent through the four quarters of 2004, respectively. The Company was able to exceed its stated operating margin goal of 15 percent by the third quarter of 2004, approximately six months earlier than its original plan. While the Group experienced sharply higher steel costs in 2004, it has generally been successful in mitigating the impact by charging surcharges on the products it sells. Nevertheless, continued increases in steel prices or other commodities could adversely impact the Group’s margins in the future. Backlog for the Group at year end was $140.8 million, compared to $83.3 million at the end of 2003, indicative of the improving market conditions benefiting the Drilling Equipment Group.

The Drilling Equipment Group benefited from the Company’s strategy enacted a few years ago to improve the availability of aftermarket spare parts and services for its customers. The Group’s 2004 results reflect a 15 percent improvement in its aftermarket business as a result of this strategy and of higher drilling activity levels. Varco has also continued to invest heavily in new products, and expects to introduce a new product which will alleviate the need to break circulation while making drillpipe connections. This device, called the Continuous Circulation System, has tested well in field trials, and promises to permit the drilling of wells through high pressure zones with minimal formation damage and lower risk. Other new products the Group has introduced over the last several quarters continue to find high demand in the marketplace, such as the ST-80 iron roughneck and the LXT blowout preventer.

Tubular Services: The Group set records for revenue and operating profit in 2004, as it benefited from brisk drilling and workover activity in several major markets; high production levels by drillpipe makers, pipe mills and pipe processors; recent acquisitions; and higher demand for used pipe and sucker rod reclamation services driven by sharply higher steel pipe prices. As a result of these, the Company’s OCTG inspection and coating businesses posted record levels of revenue and operating profit in 2004. Group results also benefited from record revenue results from both its pipeline inspection business, and its fiberglass and composite pipe sales business. Sales of the Company’s mill equipment also reported strong results, as steel pipe mills in the Eastern Hemisphere and Latin America invested in new equipment to support their expanding operations.

Tubular Services Group revenue grew 18 percent or $81.0 million from 2003 to 2004. Group operating profit improved $24.8 million, representing 31 percent operating leverage (incremental operating profit divided by incremental revenue) year-over-year.

The year started slowly following an extended shutdown of pipe mills over the holiday season in late 2003. Production levels for many domestic pipe mills and pipe processors remained slow through January and February, but rebounded sharply in March, benefiting the Group’s business. Pipe mill and pipe processor business continued to strengthen through the year, as levels of drilling and workover activity improved, which fueled demand for OCTG around the globe. Additionally, the market for new drillpipe began improving in early 2004 as drilling contractors increased capital investment in new drillstrings to support their operations. The Group inspects, and applies internal coating and hardbanding to much of the new drillpipe manufactured around the world. Margins in the Group’s Eastern Hemisphere inspection business were adversely impacted by the weaker U.S. dollar.

Stronger year-over-year sales of fiberglass and composite tubulars were primarily the result of higher sales of linepipe into corrosive oilfield applications. Sales of composite pipe into other industrial applications was up slightly. The Group’s margins in this business have recently been adversely impacted by higher raw material pricing, which the Group is seeking to mitigate through higher product pricing. The Group’s pipeline inspection business benefited from the introduction of its new ultrasonic inspection technology in late 2003, and from higher revenues from its pipeline logistics business. This business also posted higher revenues from its high-resolution MFL inspection services in the Western Hemisphere.

Drilling Services: The Drilling Services Group also generated record revenue in 2004, due to greater levels of drilling activity and the effect of acquisitions. Compared to 2003, revenues increased $46.2 million or 16 percent. Operating profit improved $4.2 million, representing nine percent operating leverage on the incremental revenue performance.

Year-over-year results benefited from sharply higher results across its North America operations, particularly in its rig instrumentation sales and services business, and the Company’s acquisition of two rig instrumentation businesses. Group results were also adversely impacted by the lower sales of high margin solids control equipment in Latin America; losses on an equipment sale in the Eastern Hemisphere; the Company’s acquisition of two thermal desorption drill-cuttings treatment businesses at lower margins; and the weakening of the US dollar against the British Pound and Euro. Sales of solids control and rig instrumentation equipment were down compared to 2003, primarily as a result of lower sales of the Group’s V-ICIS product.

Solids control results in North America generally strengthened through the year, particularly in the Mid-continent and Rocky Mountain areas. Canada operations were adversely impacted by wet weather in the third quarter, but recovered strongly in the fourth quarter. Latin America solids control operations strengthened in the second half, following the termination of a handful of large contracts in the first half. Improving results from Venezuela offset declines in Mexico. The Group’s solids control operations have been impacted by trends in certain Latin American and Eastern Hemisphere markets by some customers awarding solids control contracts in conjunction with drilling fluids services, which the Company does not offer in those markets. The Group has addressed this development by bidding to or with other providers of drilling fluids on certain tenders, and by offering the highest quality solids control technology and services.

Coiled Tubing & Wireline Products: The Coiled Tubing & Wireline Products Group achieved record levels of revenue, operating profit, orders and backlog during 2004. Revenues improved $20.0 million or 9 percent compared to 2003. Operating profit increased $5.0 million, representing 25 percent operating leverage on the revenue increase.

The Coiled Tubing & Wireline Products Group benefited from higher levels of orders for its nitrogen pumping equipment to North America and the Middle East; higher sales of coiled tubing to support increased well remediation activity around the world, higher levels of coiled tubing drilling in Canada, and North American gas completions; and higher sales of tubing-conveyed perforating gun bodies. Additionally, the Group’s new QT-16Cr corrosion-resistant coiled tubing product contributed to the year-over-year increase. Demand for the Group’s products generally continued to rise through the year as major pressure pumping contractors increased purchases of equipment.

The Group’s strong results were partly due to higher levels of coalbed methane drilling in North America, which often utilizes high-rate nitrogen vaporization and pumping equipment to dewater wells and initiate gas production. Group margins were somewhat adversely impacted by the weakening U.S dollar against the British Pound, which generally increased the costs of the Group’s Elmar manufacturing plant in the U.K. Additionally, the Group has been adversely impacted by longer component delivery times, and higher steel costs year-over-year, but has for the most part mitigated the effects by increasing the prices of the products it sells. Nevertheless, continuing increases in steel prices or other commodities could adversely affect margins in the future.

Outlook: Based upon the sustained high levels of commodity prices as compared to the last two decades, increasing dayrates for onshore and offshore rigs in recent months, and plans to increase spending by many oil and gas companies, the Company believes that the high level of oilfield activity should continue into 2005. Additionally, the beginning level of backlog in 2005 is strong for both the Company’s Drilling Equipment Group (which increased 69 percent during 2004) and Coiled Tubing & Wireline Products Group (which increased 165 percent during 2004). Consequently, the Company believes that its sales of capital equipment to drilling contractors and oilfield service companies should continue to strengthen into the coming year as well. Additionally, the Company believes that higher cashflows to drilling contractors as a result of higher rig dayrates may improve the environment for new rig construction.

The Company’s business will likely continue to be impacted by certain seasonal factors in its business in 2005. Specifically, its pipeline inspection business will likely decline significantly in the first quarter, since most of its customers across the Northern Hemisphere curtail their pipeline inspection activities during the winter to permit them to maximize the volumes of gas and fuel through their pipeline systems to satisfy winter heating demand. First quarter results will probably also be adversely affected by seasonal declines in the Company’s fiberglass pipe manufacturing operation in China. Second quarter results are likely to be impacted by seasonal “breakup” in the Company’s Canadian inspection, coating, solids control and rig instrumentation businesses.

Although important markets for the Company such as the Gulf of Mexico, the North Sea, and Venezuela continue to operate at activity levels well below previous peaks, the Company believes that some or all of these markets may improve in 2005, given the overall strength of the industry as we enter the new year.

Operating Environment Overview

The Company’s results are dependent on among other things, the level of worldwide oil and gas drilling, well remediation activity, the prices of oil and gas, capital spending by other oilfield service companies and drilling contractors, pipeline maintenance activity, and worldwide oil and gas inventory levels. Key industry indicators for the past three years include the following:


	2004*		2003*		2002*		% 2004 v 2003		% 2004 v 2002
Active Drilling Rigs:
U.S.		1,190		1,032		831	15.3	%	43.2	%
Canada		369		372		266	(0.8	)%	38.7	%
International		836		771		732	8.4	%	14.2	%

Worldwide		2,395		2,175		1,829	10.1	%	30.9	%

Active Workover Rigs:
U.S.		1,236		1,130		1,010	9.4	%	22.4	%
Canada		615		350		261	75.7	%	135.6	%

North America		1,851		1,480		1,271	25.1	%	45.6	%
West Texas Intermediate Crude prices (per barrel)	$	41.44	$	30.89	$	26.13	34.2	%	58.6	%
Natural Gas Prices ($/mbtu)	$	5.88	$	5.49	$	3.35	7.1	%	75.5	%

*	Averages for the years indicated. The source for rig activity information was Baker Hughes Incorporated (‘BHI”) (www.bakerhguhes.com), and the source for oil and gas prices was Department of Energy, Energy Information Administration (www.eia.doe.gov).

The following table details the U.S., Canadian, and international rig activity and West Texas Intermediate Oil prices for the three years ended December 31, 2004 on a quarterly basis:

LOGO

Source: Rig count: Baker Hughes, Inc. (www.bakerhughes.com);

West Texas Intermediate Crude Price: Department of Energy, Energy Information Administration (www.eia.doe.gov).

Oil and natural gas prices continued to be strong in 2004. The average price per barrel of West Texas Intermediate Crude reached historic heights in 2004 rising sharply throughout the four quarters of 2004 finishing with the highest ever-annual average oil price for the year of $41.44 per barrel, an increase of 34.2% over the average for 2003. Natural gas prices were $5.88 per mbtu, an increase of 7.1% compared to the 2003 average. High commodity prices led to stronger rig activity in the U.S. and international markets. U.S. and international rig activity increased 15.3% and 8.4%, respectively, for the full year in 2004 compared to 2003. The Canadian rig activity, while down slightly compared to 2003, continued to be strong with an average rig count of 369 rigs in 2004. On a combined basis, worldwide rig activity increased 10.1% in 2004 compared to the prior year average. However, rig activity in several key operating locations including the Gulf of Mexico and North Sea have remained sluggish. The Gulf of Mexico rig activity declined from an average of 104 rigs in 2003 to 93 rigs in 2004, while the North Sea average rig count dropped from a 2003 average of 46 rigs to an average of 39 rigs in 2004.

At January 28, 2005 there were 1,256 rigs actively drilling in the U.S., compared to 1,243 rigs at December 31, 2004. The Company believes that current industry projections are forecasting commodity prices to remain strong, and, as a result, U.S., Canada, and international drilling rig activity is expected to continue at a high level. However, numerous events could significantly alter these projections including political tensions in the Middle East, the acceleration or deceleration of the recovery of the U.S. and world economies, a build up in world oil inventory levels, or numerous other events or circumstances.

Merger with National Oilwell

On August 11, 2004, the Company entered into an Agreement and Plan of Merger with National-Oilwell, Inc. whereby the Company will merge with and into National Oilwell. Under the terms of the agreement, each outstanding share of the Company’s common stock will be converted into the right to receive 0.8363 of a share of National Oilwell common stock. National Oilwell will assume all options outstanding under the Company’s stock option plans and each outstanding option to purchase the Company’s common stock will be converted into an option to purchase National Oilwell common stock, subject to certain adjustments to the exercise price and the number of shares issuable upon exercise of those options to reflect the exchange ratio. In the event of a termination of the agreement under certain circumstances, Varco may be required to pay National Oilwell a termination fee of $75 million.

The completion of the merger is subject to several conditions, including the approval of the merger agreement by the stockholders of the Company and National Oilwell and the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. National Oilwell and Varco have responded to the Antitrust Division of the U.S. Department of Justice’s request for additional information issued under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and continue to work with the Justice Department regarding the proposed merger between the companies. Closing of the proposed merger is expected to occur as quickly as possible after regulatory clearance and stockholder approvals are received. A special meeting of the stockholders of Varco to approve the merger has been scheduled for March 11, 2005.

Drilling Equipment Group Restructuring and MIL Discontinued Operations

Due to the softening market for capital drilling equipment in 2003 and into the first part of 2004, the Company began a significant restructuring of its Drilling Equipment Group operations in the second half of 2003. The Company has consolidated certain sales, engineering and administrative functions of the Drilling Equipment Group from California into Houston, and has moved certain labor intensive manufacturing operations from its plant in Orange, California to Mexico. During 2004 and 2003, the Company incurred $5.7 million and $0.9 million of restructuring charges, respectively. The restructuring, which began in the second half of 2003, began to show a positive impact on operating profit margins in the second quarter of 2004 and continued into the second half of 2004. Operating profit from Drilling Equipment Group operations were $41.9 million on $244.2 million of revenue during the second half of 2004, representing an operating profit margin of 17.1%. These results compared to operating profit of $20.8 million on revenue of $207.5 million for an operating profit margin of 10.0% for the second half of 2003.

In January 2004, the Company announced its plans to discontinue its Morinoak International Ltd (MIL) rig fabrication operation in England. During the first quarter of 2004, MIL completed its last rig, a $31 million land rig which is presently drilling in the Middle East. The first quarter 2004 after-tax loss of $11.7 million from MIL is included in discontinued operations. In addition, the Company recognized an after-tax gain of $2.1 million in the third quarter of 2004 due to the favorable resolution of an outstanding contractual issue. The prior year MIL results have been reclassified to report this operation as discontinued. Previously these results were included as part of the Drilling Equipment Group operations.

Results of Operations

Year Ended December 31, 2004 vs Year Ended December 31, 2003 (restated)

Revenue. The Company’s total revenue from continuing operations was $1,568.1 million in 2004, an increase of $130.5 million (9.1%) over 2003 revenue of $1,437.6 million. The increase was due mainly to increases in the Company’s services business due to the increase in worldwide oilfield activity discussed above. The Company’s Tubular Services revenue increased $81.0 million (17.8%) and Drilling Services revenue increased $46.3 million (15.8%) in 2004 compared to 2003. In addition, the Company’s Coiled Tubing and Wireline business was also positively impacted by the increase in oilfield service capital spending as revenue increased $20.0 million (8.8%) in 2004 compared to 2003. These results were offset to some extent by a decrease in Drilling Equipment Group revenue of $16.8 million (3.6%) in 2004 compared to 2003.

The following table summarizes the Company’s revenue from continuing operations by operating segment in 2004 and 2003 (in millions):


	2004		2003		Variance
			(restated)		$			%
Drilling Equipment Group	$	445.4	$	462.2	$	(16.8	)	(3.6	%)
Tubular Services		536.9		455.9		81.0		17.8	%
Drilling Services		338.9		292.6		46.3		15.8	%
Coiled Tubing & Wireline Products		246.9		226.9		20.0		8.8	%

Total Revenue	$	1,568.1	$	1,437.6	$	130.5		9.1	%

Revenue from continuing operations of the Company’s Drilling Equipment Group in 2004 was $445.4 million, a decrease of $16.8 million (3.6%) compared to 2003. The decline in revenue was due to decreases in shipments of capital equipment including rig floor equipment and pressure control equipment of $74 million, primarily as a result of fewer new rig construction projects carried into 2004 in the Group’s backlog. However, the Group’s backlog generally improved throughout the year as new rig construction and rig refurbishment projects were commenced. The Company shipped 41 top drives in 2004 compared to 56 in 2003. These declines were offset by increases in aftermarket revenue including spares, service, repair and rental of $47.1 million. New orders for 2004 were $496.9 million compared to $367.6 million (excluding discontinued operations) for the same period of 2003, while backlog at December 31, 2004 was $140.8 million compared to $83.3 million (excluding discontinued operations) at December 31, 2003. The increase in orders and backlog was reflective of increased rig construction projects and higher capital investment in rig upgrades and refurbishments by drilling contractors in 2004 compared to 2003. In accordance with industry practice, orders and commitments generally are cancelable by customers at any time.

Revenue from the Company’s Tubular Services was $536.9 million in 2004, an increase of $81.0 million (17.8%) over 2003 results. The increase was due to greater revenue from the Company’s U.S., Latin America, Europe, and Canadian inspection operations; greater U.S. and Europe coating revenue; greater Pipeline inspection revenue; and an increase in worldwide Fiberglass pipe revenue. U.S. inspection and coating revenue combined to increase $24.8 million primarily as a result of a 15% increase in U.S. rig activity in 2004 compared to 2003. Latin America inspection revenue increased $11.5 million in 2004 compared to 2003 due primarily to two acquisitions of Latin America inspection operations in the second half of 2003. Europe, Africa, and Middle East inspection and coating revenue increased a combined $13.5 million due to an increase in international market activity. The Canadian market remained strong in 2004 as Canada Inspection revenue increased $3.7 million in 2004 over 2003. Pipeline inspection revenue increased $16.3 million due to strengthening market demand throughout the Western Hemisphere and increased revenue from the Company’s new ultrasonic pipeline inspection tools which were introduced to the market in the first quarter of 2004. Fiberglass pipe revenue was up $8.8 million for 2004 compared to 2003 due to strong sales of Fiberglass pipe into large international projects in the Middle East, the Caspian region, and Africa.

Revenue from the Company’s Drilling Services was $338.9 million in 2004, an increase of $46.3 million (15.8%) compared to 2003 results. The increase was primarily driven by greater revenue from the Company’s North America Instrumentation and Solid Control businesses, which increased a combined $38.2 million in 2004 compared to 2003. The increase was due to acquisitions made in the second half of 2003, several acquisitions made throughout 2004, and increases in market activity. The North America rig activity increased 11.0% in 2004 compared to 2003. In addition, Drilling Services revenue increased due to greater revenue from the Company’s Eastern Hemisphere and Latin America Solids Control divisions, which also benefited from greater market activity.

Coiled Tubing and Wireline Products revenue was $246.9 million in 2004, an increase of $20.0 million (8.8%) in 2004 compared to 2003. The increase was due to greater revenue from the Company’s Quality Tubing and Coiled Tubing & Wireline operations, which were up $7.6 million and $12.4 million, respectively, in 2004 as a result of the increased oilfield activity discussed above. The Coiled Tubing and Wireline operations benefited from a strong demand for Nitrogen Pumping units in Canada. Coiled Tubing and Wireline Products backlog at December 31, 2004 was at an historical record of $98.1 million, an increase of $61.1 million (164.9%) compared to December 31, 2003. In accordance with industry practice, orders and commitments generally are cancelable by customers at any time.

Gross Profit. Gross profit was $423.3 million (27.0% of revenue) in 2004 compared to $405.0 million (28.2% of revenue) in 2003. The increase in gross profit dollars was due to the $130.5 million (9.1%) increase in revenue discussed above. The decrease in gross profit percent was due to $5.7 million of restructuring charges related to the Drilling Equipment Group operations in 2004 compared to $0.9 million of Drilling Equipment Group restructuring charges in 2003. In addition, margins were lower in the Drilling Services operations as a result of several adverse revenue mix issues including: a lower percent of the Company’s revenue and activity from the Company’s Solids Control operations in the Gulf of Mexico, greater revenue from high margin capital sales in Mexico in 2003, greater revenue from lower margin operations in Venezuela in 2004, the impact of the weaker U.S. dollar, and a large solids control equipment sale delivered at a loss in 2004.

Selling, General, and Administrative Costs. Selling, general, and administrative costs were $166.1 million in 2004, a decrease of $11.7 million (6.6%) compared to 2003 costs of $177.8 million. The decrease was due to several factors including; a reduction in costs related to the Company’s Drilling Equipment Group operations as a result of the restructuring discussed above, a $3.8 million gain related to a litigation matter in the second quarter of 2004, lower insurance premiums and a one-time $2.9 million insurance gain in the fourth quarter of 2004. These cost reductions were offset to some degree by higher incentive compensation, allowance for doubtful accounts, and outside services costs. As a percent of revenue, selling, general, and administrative costs were 10.6% of revenue in 2004 compared to 12.4% in 2003.

Research and Engineering Costs. Research and engineering costs were $53.8 million in 2004, a decrease of $7.4 million (12.1%) compared to 2003 results. The 2004 decrease was due primarily to lower research and engineering costs from the Company’s Drilling Equipment Group operations (as a result of the restructuring discussed above) and Drilling Services Group operations.

Transaction Costs. The Company incurred $5.0 million of transaction costs in 2004 related to the National-Oilwell, Inc. transaction. No similar costs were recognized in 2003.

Operating Profit. Operating profit from continuing operations was $198.4 million for 2004 compared to $166.0 million for 2003. Excluding transaction costs, operating profit was $203.4 million (13.0% of revenue) for 2004 compared to $166.0 million (11.5% of revenue) for 2003. The improvement in operating profit dollars was reflected in all four major business segments. Excluding transaction costs and Drilling Equipment Group restructuring charges, operating profit margins improved in the Drilling Equipment Group (11.6% to 14.7%), Tubular Services (15.2% to 17.5%), and Coiled Tubing & Wireline Products (19.1% to 19.6%). Drilling Services operating profit margins declined from 18.6% in 2003 to 17.3% in 2004 – this decline in Drilling Services margins is discussed above under “Gross Profit”.

Interest Expense. Interest expense was $31.1 million in 2004 compared to $30.2 million in 2003. The increase in interest expense was due mainly to greater outstanding debt due to the 2004 acquisitions. In the second quarter of 2003, the Company entered into three interest rate swap agreements with a combined notional amount of $100.0 million associated with the Company’s 2008 notes. Under these agreements, the Company receives interest at a fixed rate of 7.5% and pays interest at a floating rate of six-month LIBOR plus a weighted average spread of approximately 4.675%. The swap agreements will settle semi-annually and will terminate in February 2008. An increase in outside market interest rates of 1% would result in a $1.0 million increase to the Company’s interest expense.

Other Expense (Income). Other expense includes interest income, foreign exchange losses and gains, and other expense (income). Net other expense was $3.1 million in 2004 compared to $2.2 million in 2003.

Provision for Income Taxes. The Company recorded a tax provision of $56.8 million (34.6% of pre-tax income from continuing operations) and $44.8 million (33.5% of pre-tax income from continuing operations) for the years ended December 31, 2004 and 2003, respectively. The 2004 and 2003 tax provisions were lower than the domestic tax rate of 35% due to benefit from its utilization of the extraterritorial income provisions, and the resolution of prior year tax audits. This benefit was partially offset by deductions not allowed under domestic and foreign jurisdictions and to foreign earnings subject to tax rates differing from domestic rates. As described in Note 7 to the Consolidated Financial Statements, our 2004 results do not reflect the impact of the American Jobs Creation Act of 2004 (the “Jobs Act”). We have not completed the process of reevaluating our position with respect to the indefinite reinvestment of foreign earnings to take into account the possible election of the repatriation provisions contained in the Jobs Act.

Income From Continuing Operations. Net income from continuing operations was $107.4 million and $88.8 million for 2004 and 2003, respectively. The increase in income from continuing operations was due to the factors discussed above.

Loss From Discontinued Operations. In January 2004, the Company announced its plans to discontinue its Morinoak International Ltd (MIL) rig fabrication operation in England. During the first quarter of 2004, MIL completed its last rig, a $31 million land rig which is presently drilling in the Middle East. The Company recognized a loss from discontinued operations of $9.6 million and $21.6 million in 2004 and 2003, respectively. The prior year MIL results have been reclassified to report this operation as discontinued. Previously these results were included as part of the Drilling Equipment Group operations.

Net Income. The Company recognized net income of $97.8 million and $67.2 million in 2004 and 2003, respectively. The increase in net income was due to the factors discussed above.

Year Ended December 31, 2003 vs Year Ended December 31, 2002 (restated)

Revenue. The Company’s total revenue from continuing operations was $1,437.6 million in 2003, an increase of $115.2 million (8.7%) over 2002 revenue of $1,322.4 million. The increase was due mainly to the acquisition of ICO’s oilfield services business in September 2002 and increases in the Company’s services business due to the increase in rig activity discussed above. The Company’s Tubular Services revenue increased $99.9 million (28.1%) and Drilling Services revenue increased $14.0 million (5.0%) in 2003 compared to 2002. In addition, the Company’s Coiled Tubing and Wireline revenue was also positively impacted by the increase in activity as revenue increased $13.1 million (6.1%) in 2003 compared to 2002. These results were offset to some extent by a decrease in Drilling Equipment Group revenue of $11.8 million (2.5%) in 2003 compared to 2002, which was primarily related to a decline in the sale of drilling units.

The following table summarizes the Company’s revenue from continuing operations by operating segment in 2003 and 2002 (in millions):


	2003 (restated)		2002 (restated)		Variance
	2003 (restated)		2002 (restated)		$			%
Drilling Equipment Group	$	462.2	$	474.0	$	(11.8	)	(2.5	%)
Tubular Services		455.9		356.0		99.9		28.1	%
Drilling Services		292.6		278.6		14.0		5.0	%
Coiled Tubing & Wireline Products		226.9		213.8		13.1		6.1	%

Total Revenue	$	1,437.6	$	1,322.4	$	115.2		8.7	%

Revenue from the Company’s Drilling Equipment Group in 2003 was $462.2 million, a decrease of $11.8 million (2.5%) compared to 2002. The decrease was due to declines in shipments of capital equipment, including rig floor equipment, and handling tools of $48.0 million. The Company shipped 56 top drives in 2003 compared to 75 top drives shipped in 2002. These declines were offset by increases in capital equipment sales of pressure control equipment of $19.0 million and increases in aftermarket revenue including spares, service, repair and rental of $17.2 million. New orders (excluding discontinued operations) for 2003 were $367.6 million compared to $405.5 million for the same period of 2002, while backlog (excluding discontinued operations) at December 31, 2003 was $83.3 million compared to $178.0 million at December 31, 2002. The decline in orders and backlog was reflective of fewer new rig construction projects and reduced capital investment in rig upgrades and refurbishments by drilling contractors in 2003 compared to 2002. In accordance with industry practice, orders and commitments generally are cancelable by customers at any time.

Revenue from the Company’s Tubular Services was $455.9 million in 2003, an increase of $99.9 million (28.1%) over 2002 results. Acquisitions for 2003 and 2002 resulted in an estimated incremental increase in revenue of approximately $79.8 million in 2003 compared to 2002. The largest acquisition was ICO’s oilfield services business on September 6, 2002. Excluding the impact from these acquisitions, Tubular Services revenue would have increased $21.0 million (5.9%) in 2003 compared to the prior year. The increase in U.S., Canada, and Worldwide oilfield activity resulted in greater non-acquisition revenue from the Company’s Inspection, Coating, and Fiberglass operations in 2003. These increases were slightly offset by lower capital sales from the Company’s Mill equipment sales operations and lower revenue from Pipeline services.

Revenue from the Company’s Drilling Services was $292.6 million in 2003, an increase of $14.0 million (5.0%) compared to 2002 results. The increase was primarily driven by greater revenue from the Company’s U.S. and Canadian Instrumentation and Solid Control businesses, which increased a combined $24.9 million in 2003 compared to 2002. The U.S. and Canadian rig activity was up 24.2% and 39.8%, respectively, in 2003 compared to 2002. These increases were partially offset by lower revenue from the Company’s Solids Control and Instrumentation capital equipment sales divisions, and lower revenue from Venezuela operations which was a result of economic and political troubles in that country.

Coiled Tubing and Wireline Products revenue was $226.9 million in 2003, an increase of $13.1 million (6.1%) in 2003 compared to 2002. The increase was primarily due to greater revenue from Company’s Quality Tubing operations, which were up $9.2 million in 2003 as a result of the increased oilfield activity discussed above. In addition, the Company’s Coiled Tubing and Wireline business was up $3.9 million in revenue also benefiting from increased activity. Coiled Tubing and Wireline Products backlog at December 31, 2003 was $37.0 million, a decline of $12.1 million (24.6%) compared to December 31, 2002.

Gross Profit. Gross profit was $405.0 million (28.2% of revenue) in 2003 compared to $382.0 million (28.9% of revenue) in 2002. The increase in gross profit dollars was due to the $115.2 million (8.7%) increase in revenue. The decrease in gross profit percent was due to lower margins in the Drilling Equipment Group discussed above.

Selling, General, and Administrative Costs. Selling, general, and administrative costs were $177.8 million in 2003, an increase of $17.6 million (11.0%) over 2002 costs of $160.2 million. The increase was due primarily to the acquisitions in 2003 and 2002. In addition, the Company’s insurance costs, legal expenses, and fringe benefit costs were also greater in 2003 than 2002. As a percent of revenue, selling, general, and administrative costs were 12.4% of revenue in 2003 compared to 12.1 % of revenue in 2002.

Research and Engineering Costs. Research and engineering costs were $61.2 million in 2003, an increase of $4.1 million (7.2%) compared to 2002 results. The increase was spread out between all four major operating segments and was primarily related to new product development and integration, and acquisitions completed in 2003 and 2002.

Merger, Transaction, Impairment and Litigation Costs. Merger, transaction, impairment, and litigation costs were $6.5 million for 2002. The 2002 costs consisted of two components; $3.7 million of transaction costs associated with the acquisition of substantially all of the oilfield services business of ICO (see Note 3 of Notes to Consolidated Financial Statements) and $2.8 million of severance costs. There were no merger, transaction, impairment, and litigation costs in 2003.

Operating Profit. Operating profit was $166.0 million (11.5% of revenue) for 2003 compared to $158.2 million (12.0% of revenue) for 2002. Excluding 2002 merger, transaction, impairment and litigation costs, operating profit was $164.7 million (12.5% of revenue). The decline in operating profit percent in 2003 compared to 2002 was due to weak margins in the Drilling Equipment Group discussed above. Operating profit percents in Drilling Services and Coiled Tubing and Wireline both improved in 2003, while Tubular Services was approximately flat as compared to 2002.

Interest Expense. Interest expense was $30.2 million in 2003 compared to $25.6 million in 2002. The increase in interest expense was due to greater average outstanding debt balances as a result of the $150.0 million Senior Notes issued in November 2002.

Other Expense (Income). Other expense includes interest income, foreign exchange losses and gains, and other expense (income). Net other expense was $2.2 million in 2003 compared to $7.6 million in 2002. The improvement in other expense in 2003 was primarily due to $5.2 million in foreign exchange losses in 2002 compared to a $1.1 million gain in 2003. The 2002 losses occurred in the third quarter of 2002 due mostly to foreign exchange losses in Venezuela, the second quarter of 2002 due mostly to the weakening of the U.S. dollar against the euro dollar and UK pound sterling, and the first quarter 2002 due mostly to foreign exchange losses in Argentina as a result of the devaluation of the Argentine peso in the first quarter of 2002.

Provision for Income Taxes. The Company recorded a tax provision of $44.8 million (33.5% of pre-tax income) and $43.6 million (34.9% of pre-tax income) for the years ended December 31, 2003 and 2002, respectively. The 2003 and 2002 tax provisions were lower than the domestic tax rate of 35% due to benefit from its utilization of the extra territorial income provisions, increased research and development credits and the resolution of a prior year audit.

Income From Continuing Operations. Net income from continuing operations was $88.8 million and $81.3 million for 2003 and 2002, respectively. The increase in income from continuing operations was due to the factors discussed above.

Loss From Discontinued Operations. The Company recognized a loss from its discontinued rig fabrication business (MIL) of $21.6 million and $1.5 million in 2003 and 2002, respectively.

Net Income. The Company reported net income of $67.2 million and $79.8 million in 2003 and 2002, respectively. The decrease in net income for 2003 compared to 2002 was due to the factors discussed above.

Financial Condition and Liquidity

At December 31, 2004, the Company had cash and cash equivalents of $118.5 million, and total debt of $461.8 million. At December 31, 2003 cash and cash equivalents were $85.7 million, and total debt was $457.0 million. The Company’s outstanding debt at December 31, 2004 consisted of $201.0 million of 7¼% Senior Notes due 2011, $149.4 million of 5½% Senior Notes due 2012, $96.1 million of 7 ½% Senior Notes due 2008, and other debt of $15.3 million.

For the fiscal year ended December 31, 2004, cash provided by operating activities was $114.2 million compared to $100.7 million for 2003. Cash was provided by operations primarily through net income of $97.8 million plus non-cash charges of $88.3 million. In addition, cash was provided by an increase in income taxes payable of $17.7 million. These items were offset by an increase in accounts receivable of $71.4 million, an increase in inventory of $6.7 million, an increase in prepaid expenses of $1.7 million, and a decrease in accounts payable and accrued liabilities of $9.8 million. The increase in accounts receivable was due to a $92.8 million increase in revenue in the fourth quarter of 2004 compared to the fourth quarter of 2003 which was offset to some extent by a reduction in days sales outstanding from 87.3 days at December 31, 2003 to 83.4 days at December 31, 2004. Inventory increased due to the greater backlog on hand at December 31, 2004 compared to 2003 in the Drilling Equipment Group (up $57.5 million) and Coiled Tubing & Wireline Products (up $61.1 million). Accounts payable and accrued liabilities decreased due to lower customer deposits.

For the fiscal year ended December 31, 2004, cash used for investing activities was $89.8 million compared to $106.6 million for the same period of 2003. The Company used approximately $37.0 million of cash for 8 acquisitions during 2004 and cash paid in 2004 for 2003 acquisitions. See Note 3 of Notes to the Consolidated Financial Statements. Capital spending of $51.9 million was primarily related to the Company’s services businesses including Solids Control, Instrumentation, Inspection, Coating, and Pipeline.

For the fiscal year ended December 31, 2004, the Company generated $6.3 million of cash from financing activities compared to cash used of $15.1 million in 2003. The Company generated $29.2 million of cash from the sale of 2.1 million shares of common stock. These proceeds were offset by net debt payments of $6.5 million and the purchase of 829,100 shares of treasury stock for $16.0 million.

On June 30, 2004, the Company entered into a credit agreement with a syndicate of banks that provides up to $150.0 million of funds under a revolving credit facility. The facility expires on July 1, 2009. The company has the right to increase the aggregate commitments under the facility to an aggregate amount of up to $200.0 million.

The facility is currently undrawn and includes a subfacility of $75.0 million for standby and commercial letters of credit. The interest rate on the revolver is based on the Company’s rating by S&P and Moody’s which at the time of the agreement resulted in an interest rate of LIBOR +0.375%, or the prime rate. Facility fees range from 0.1% to 0.25% depending on the Company’s debt rating.

On January 14, 2005, the Company amended the revolving credit facility and received consents and waivers from its lenders that will allow the credit facility to remain outstanding subsequent to the merger with National Oilwell. The amendments include various market condition changes as well as the ability to increase the aggregate facility up to $500 million conditioned upon the merger with National Oilwell.

At December 31, 2004, there were $136.5 million of funds available under the revolving credit facility and $0.4 million of funds available under the bilateral letter of credit facility, with $13.5 million and $4.6 million being used for letters of credit, respectively. The Company also has $26.5 million of additional outstanding letters of credit at December 31, 2004 that are not secured by the Company’s senior credit facility.

The Company believes that its December 31, 2004 cash and cash equivalents, its outstanding credit facility, and cash flow from operations will be sufficient to meet its capital expenditures and its operating cash needs for the foreseeable future.

A summary of the Company’s outstanding contractual obligations at December 31, 2004 is as follows (in millions):


			Payment Due by Period
	Total		Less than 1 Year		2-3 Years		4-5 Years		After 5 Years
Total Debt	$	461.8	$	3.7	$	5.9	$	98.4	$	353.8
Operating leases		94.0		25.4		29.6		14.3		24.7

Total contractual obligations	$	555.8	$	29.1	$	35.5	$	112.7	$	378.5

Standby letters of Credit	$	44.6	$	34.6	$	10.0		—		—

As of December 31, 2004, the Company has outstanding non-cancelable purchase order commitments of approximately $13.4 million related to special order raw materials due in 2005. Purchase order commitments subsequent to 2005 are less than $0.5 million on an annual basis. The Company’s projected post-retirement cash payments are expected to approximate $1.5 million to $2.5 million annually for the next five years.

Critical Accounting Policies and Estimates

In preparing the financial statements, we make assumptions, estimates and judgments that affect the amounts reported. We periodically evaluate our estimates and judgments related to allowance for doubtful accounts; inventory reserves; impairments of long-lived assets (including goodwill); warranty accruals; pensions and other postretirement benefits; and income taxes. Note 2 to the consolidated financial statements contain the accounting policies governing each of these matters. Our estimates are based on historical experience and on our future expectations that we believe are reasonable; the combination of these factors forms the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results are likely to differ from our current estimates and those differences may be material.

Revenue Recognition

reasonably assured and the product has been delivered. Customer advances or deposits are deferred and recognized as revenue when the Company has completed all of its performance obligations related to the sale. The Company also recognizes revenue as services are performed. The amounts billed for shipping and handling cost are included in revenue and related costs are included in costs of sales.

In addition, the Company enters into transactions that include multiple-element arrangements, which may include any combination of equipment products, services, hardware, and software. When some elements are delivered prior to others in an arrangement and certain criteria are met, revenue for the delivered element is recognized upon delivery of such item. Otherwise, revenue is deferred until the delivery of the last element. The criteria for revenue recognition includes: vendor-specific objective evidence (“VSOE”) of fair value of the undelivered elements; the functionality of the delivered elements is not dependent on the undelivered elements; delivery of the delivered element represents the culmination of the earnings process. VSOE is the price charged by the Company to an external customer for the same element when such element is sold separately.

Allowance for Doubtful Accounts

Allowance for doubtful accounts are determined on a specific identification basis when we believe that the required payment of specific amounts owed to us is not probable. A substantial portion of the Company’s revenues come from international oil companies, international oilfield service companies, and government-owned or government-controlled oil companies. Therefore, the Company has significant receivables in many foreign jurisdictions. If worldwide oil and gas drilling activity or changes in economic conditions in foreign jurisdictions deteriorate, our customers may be unable to repay these receivables, and additional allowances could be required.

Inventory Reserves

Reserves for inventory are determined based on our historical usage of inventory on-hand as well as our future expectations related to requirements to provide spare parts for our substantial installed base and new products. Changes in worldwide oil and gas drilling activity and the development of new technologies associated with the drilling industry could require the Company to record additional allowances to reduce the value of inventory to the lower of its cost or net realizable value.

Warranty Accruals

Accruals for warranty claims are provided based on historical experience at the time of sale. Most product warranties cover periods from one to three years. Our accruals for warranty claims are affected by the size of our installed base of products currently under warranty, as well as new products delivered to the market. If actual experience proves different from historical estimates, changes to the Company’s provision rates may be required.

Impairment of Long-Lived Assets (Including Goodwill)

Long-lived assets, which include property and equipment, goodwill, and identified intangible assets, comprise a significant amount of the Company’s total assets. The Company makes judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods and useful lives. Additionally, the carrying values of these assets are reviewed for impairment periodically or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires the Company to make long-term forecasts of its future revenues and costs related to the assets subject to review. These forecasts require assumptions about demand for the Company’s products and services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions or the intended use of these assets could require a provision for impairment in a future period.

In accordance with SFAS 142, the Company performs a review of goodwill for impairment annually, or earlier if indicators of potential impairment exist. The annual impairment tests are performed during the fourth quarter of each year. If it is determined that goodwill is impaired, that impairment is measured based on the amount by which the book value of goodwill exceeds its implied fair value. The implied fair value of goodwill is determined by deducting the fair value of a reporting unit’s identifiable assets and liabilities from the fair value of that reporting unit as a whole. Additional impairment assessments may be performed on an interim basis if the Company encounters events or changes in circumstances that would indicate that, more likely than not, the carrying amount of goodwill has been impaired. Fair value of the reporting units is determined based on internal management estimates, using the average of three methods: discounted cash flow, comparable companies, and representative transactions.

Income Taxes

Our tax provision is determined in accordance with Financial Accounting Standards Board No. 109 (“FAS 109”) which requires the use of the liability method. Under the liability method the current and deferred tax assets and liabilities are recorded based on the expected taxable income and statutory tax rates as applicable to each country in which we operate. Deferred tax assets and liabilities are recognized for differences between the book and tax basis of the net assets of the Company.

Because of the number of tax jurisdictions in which we operate our effective tax rate can fluctuate as our operations, product mix and the local country tax rates change from period to period. Determination of taxable income in any jurisdiction requires the interpretation of each local tax jurisdictions laws and the use of estimates and assumptions on future events.

The Company is subject to audits by federal, state and foreign jurisdictions which may result in proposed assessments. We believe we have adequately provided for any reasonably foreseeable outcome related to these matters. Our future tax provision will reflect any favorable or unfavorable adjustments to our estimated tax liabilities when resolved, as a result our effective tax rate may fluctuate on a quarterly basis.

Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred assets will not be realized in the future. In determining the need for valuation allowances, we have made judgments and estimates regarding future events and feasible tax planning strategies. Any changes to these estimates, assumptions or tax strategies could require us to adjust the valuation allowance in the period of the change.

Pensions and Other Postretirement Benefits

The Company sponsors several pension and postretirement plans. The Company has two defined benefit pension plans covering substantially all of its employees in Germany (German Plans), a plan providing healthcare and life insurance benefits to certain executives and former retired employees (Retiree Medical Plan) and a supplemental executive retirement plan (SERP). These plans are unfunded. See additional disclosure in Note 9 to the Consolidated Financial Statements.

The Company accounts for its defined benefit pension plans and its nonpension postretirement benefit plans using actuarial models required by Statement of Financial Accounting Standards (SFAS) No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” respectively.

A significant element in determining the Company’s expense in accordance with SFAS No. 87 and SFAS No. 106 is the discount rate. The discount rate is an estimate of the current interest rate at which the pension and postretirement liabilities could be effectively settled at the end of the year. In estimating this rate, the Company looks to rates of return on high-quality, fixed-income investments currently available and expected to be available during the period to maturity of the pension and postretirement benefit obligation. Changes in the discount rates over the past three years have not materially affected pension expense and the net effect of changes in the discount rate, as well as the net effect of other changes in actuarial assumptions and experience, have been deferred in accordance with SFAS No. 87 and SFAS No. 106. The Company’s discount rate was 6.0% at December 31, 2004. A change in discount rate assumptions of 1% in either direction would have less than a $2.0 million impact on the accumulated postretirement benefit obligation and less than a $0.3 million impact on net income. For 2005, the Company does not expect any changes in its discount rates.

Additionally, the health care cost trend rate can have a significant effect on the Company’s expense for the Retiree Medical plan. The Company, in conjunction with its actuary reviews external data and its own historical trends for health care costs to determine the health care cost trend rates. The assumed health care cost trend rate for 2005 is 10% and is assumed to decrease gradually to 5% for 2010 and remain at that level thereafter. An increase of the health care cost trend rates by one percentage point each year would increase the accumulated postretirement benefit obligation as of December 31, 2004 by $753,752 and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 2004 by $50,878.

Pension and postretirement benefit expense for these plans was $3.4 million, $3.6 million, and $3.0 million for the years ended December 31, 2004, 2003, and 2002, respectively. Cash payments for these plans were $1.6 million, $1.7 million, and $0.9 million for the years ended December 31, 2004, 2003, and 2002, respectively.

Recent Accounting Pronouncements

In January 2003, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (“FIN 46”). FIN 46 requires the consolidation of each variable interest entity (“VIE”) in which an enterprise absorbs a majority of the entity’s expected losses or receives a majority of the entity’s expected residual returns, or

both, as a result of ownership, contractual or other financial interests in the entity. The Company’s adoption of FIN 46 on January 1, 2004 did not have a material effect on the Company’s financial statements.

In April 2003, the FASB issued Statement of Financial Accounting Standards 149 (“SFAS 149”), “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS 149 amends and clarifies accounting and reporting of derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities.” This statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The Company’s adoption of SFAS 149 did not have a material impact on the Company’s financial position or results of operations.

In May 2003, the FASB issued Statement of Financial Accounting Standards 150 (“SFAS 150”), “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability. For all financial instruments entered into or modified after May 31, 2003, SFAS 150 is effective immediately. For all other instruments, SFAS 150 goes into effect at the beginning of the first interim period beginning after June 15, 2003. The Company’s adoption of SFAS 150 did not have a material impact on the Company’s financial position or results of operations.

In December 2003, the FASB revised Statement of Financial Accounting Standards No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (“Revised SFAS 132”). Revised SFAS 132 revises employers’ required disclosures about pension plans and other postretirement benefit plans. It does not change the measurement or recognition of those plans required by FASB Statements No. 87, “Employers’ Accounting for Pensions,” No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” and No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (“Statement 106”). Revised SFAS 132 requires disclosures in addition to those in the original FASB Statement No. 132. Revised SFAS 132 is effective for financial statements with fiscal years ending after December 15, 2003. The interim-period disclosures required by Revised Statement 132 are effective for interim periods beginning after December 15, 2003. The Company’s adoption of Revised SFAS 132 did not have a material effect on the Company’s financial statements or related footnotes.

In May 2004, the FASB issued Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-2”). FSP 106-2 provides guidance on accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”) for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 is effective for the first interim or annual period beginning after June 15, 2004. The adoption of FSP 106-2 did not have a material effect on the Company’s financial position, results of operations or cash flows.

In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151, “Inventory Costs – an amendment of ARB 43, Chapter 4” (“SFAS 151”). SFAS 151 clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. Paragraph 5 of Accounting Research Bulletin (“ARB”) 43, Chapter 4 “Inventory Pricing,” previously stated that “...under certain circumstances, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs may be so abnormal as to require treatment as current-period charges...” SFAS 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition, SFAS 151 requires that the allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS 151 is effective for fiscal years beginning after June 15, 2005. The Company does not believe the implementation of SFAS 151 will have a material impact on the Company’s financial position, results of operations or cash flows.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123-Revised 2004 (“Revised SFAS 123”), “Share-Based Payment.” This is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes APB No. 25, “Accounting for Stock Issued to Employees.” Currently, the Company does not record compensation expense for stock-based compensation. Under Revised SFAS 123, the Company will be required to measure the cost of employee services received in exchange for stock based on the grant-date fair value (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award (usually the vesting period). The fair value will be estimated using an option-pricing model. Excess tax benefits, as defined in Revised SFAS 123, will be recognized as an addition to paid-in capital. This is effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. The Company is currently in the process of evaluating the impact of Revised SFAS 123 on its financial statements, including different option-pricing models. The pro forma table in Note 10 of the Notes to Consolidated

Financial Statements illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123.

In December 2004, the FASB issued FASB Staff Position No. FAS 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” (“FSP 109-1”) and FASB Staff Position No. FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004” (“FSP 109-2”). FSP 109-1 clarifies the guidance in FASB Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“Statement 109”) that applies to the new deduction for qualified domestic production activities under the American Jobs Creation Act of 2004 (the “Act”). FSP 109-1 clarifies that the deduction should be accounted for as a special deduction under Statement 109, not as a tax-rate reduction, because the deduction is contingent on performing activities identified in the Act. As a result, companies qualifying for the special deduction will not have a one-time adjustment of deferred tax assets and liabilities in the period the Act is enacted. FSP 109-2 addresses the effect of the Act’s one-time deduction for qualifying repatriations of foreign earnings. FSP 109-2 allows additional time for companies to determine whether any foreign earnings will be repatriated under the Act’s one-time deduction for repatriated earnings and how the Act affects whether undistributed earnings continue to qualify for Statement 109’s exception from recognizing deferred tax liabilities. FSP 109-1 and FSP 109-2 were both effective upon issuance. The Company implemented FSP 109-1 and FSP 109-2 in the quarter ended December 31, 2004 and have included the required disclosures in Note 7 of the Notes to Consolidated Financial Statements.

Other

The Company has executed acquisitions over the past few years as part of its growth strategy. The Company seeks, where possible, to effect consolidation cost savings by integrating acquired businesses with its own. As a consequence, the financial results of acquired businesses may not be separable from the Company’s existing businesses, and therefore may not be readily measurable. Accordingly, the impact of acquisitions on the Company’s overall financial results are difficult to measure. Where the Company provides estimates of incremental revenue and operating profit from acquired businesses, these estimates are based upon management’s judgment.

Factors Affecting Future Operating Results

This Annual Report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The forward looking statements are those that do not state historical facts and are inherently subject to risk and uncertainties. The forward-looking statements contained herein are based on current expectations and entail various risks and uncertainties that could cause actual results to differ materially from those projected in the forward-looking statements. Such risks and uncertainties are set forth below.

The oil and gas industry in which the Company participates historically has experienced significant volatility. Demand for the Company’s services and products depends primarily upon the number of oil and gas wells being drilled, the depth and drilling conditions of such wells, the volume of production, the number of well completions, the capital expenditures of other oilfield service companies and drilling contractors, the level of pipeline construction and maintenance expenditures, and the level of workover activity. Drilling and workover activity can fluctuate significantly in a short period of time, particularly in the United States and Canada.

The willingness of oil and gas operators to make capital expenditures for the exploration and production of oil and natural gas will continue to be influenced by numerous factors over which the Company has no control, including the prevailing and expected market prices for oil and natural gas. Such prices are impacted by, among other factors, the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) to maintain price stability through voluntary production limits, the level of production of non-OPEC countries, worldwide demand for oil and gas, general economic and political conditions, costs of exploration and production, availability of new leases and concessions, and governmental regulations regarding, among other things, environmental protection, taxation, price controls and product allocations. In addition, political tensions in the Middle East may have an impact on market prices for oil and natural gas. No assurance can be given as to the level of future oil and gas industry activity or demand for the Company’s services and products.

The Company’s foreign operations, which include significant operations in Canada, Europe, Africa, the Far East, the Middle East and Latin America, are subject to the risks normally associated with conducting business in foreign countries, including foreign exchange fluctuations, and uncertain political and economic environments, which may limit or disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or the taking of property without fair compensation. Government-owned petroleum companies located in some of the countries in which the Company operates have adopted policies (or are subject to governmental policies) giving preference to the purchase of goods and services from companies that are

majority-owned by local nationals. As a result of such policies, the Company relies on joint ventures, license arrangements and other business combinations with local nationals in these countries. In addition, political considerations may disrupt the commercial relationship between the Company and such government-owned petroleum companies. There can be no assurances that such problems will not be material in the future.

The Company’s solids control, inspection and coating services routinely involve the handling of waste materials, some of which may be considered to be hazardous wastes. The Company is subject to numerous local, state and federal laws and regulations concerning the containment and disposal of materials, pursuant to which the Company has been required to incur compliance and clean-up costs, which were not substantial in 2004, 2003, and 2002. Compliance with environmental laws and regulations due to currently unknown circumstances or developments, however, could result in substantial costs and have a material adverse effect on the Company’s results of operations and financial condition.

A significant portion of the Company’s recent growth in revenues and profitability has been the result of its acquisition program. The Company’s future operating results will be impacted by the Company’s ability to identify additional attractive acquisition opportunities, consummate such acquisitions on favorable terms and successfully integrate the operations of the acquired businesses with those of the Company.

Many of the Company’s oilfield markets for equipment, products and services are predominately priced in U.S. dollars, although some portion may be in local currencies. The Company conducts manufacturing and service operations through foreign locations, and, as a result, has significant costs denominated in local currencies that often exceed the mix of local currency revenue. Consequently, the recent weakening of the U.S. dollar against the Euro, the British Pound and other currencies has resulted in higher costs of sales and services for some of the Company’s business in England, the EEC and other areas, when these costs are converted to U.S. dollars. This is partially but not completely offset by higher foreign currency revenue, when converted to U.S. dollars. Overall, the weakening of the U.S. dollar reduced the Company’s operating profits and margins. This effect on consolidated operating income is offset somewhat by the Company’s position in Canada, where a portion of its costs are in U.S. dollars, but nearly all of its revenues are in Canadian dollars. As a result, the Company’s Canadian operations have benefited from the weakening U.S. dollar. The Company estimates that the net impact of the weaker U.S. dollar compared to foreign currencies where the Company operates (including the EURO, British Pound, Norwegian Kroner, Canadian dollar and Singapore dollar) adversely impacted operating profit by approximately $5.1 million in 2004 as compared to 2003.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company conducts operations in various countries around the world and is exposed to market risk from changes in interest rates and changes in foreign currency rates. The Company does not believe that it has a material exposure to market risk. We use derivatives only to manage existing underlying exposures. The Company does not enter into interest rate or foreign currency transactions for speculative purposes.

Interest Rates

The Company has historically managed its exposure to interest rate changes by using a combination of fixed rate debt, variable rate debt, and interest swap and collar agreements in its total debt portfolio. At December 31, 2004, the Company had $461.8 million of outstanding debt. Fixed rate debt included $150.0 million of the 2012 Notes at a fixed interest rate of 5.5%, $200.0 million of the 2011 Notes at a fixed interest rate of 7.25% and $100.0 million of the 2008 Notes at a fixed interest rate of 7.5%.

As of December 31, 2004, the Company had three interest rate swap agreements with an aggregate notional amount of $100.0 million associated with the Company’s 2008 Notes. Under this agreement, the Company receives interest at a fixed rate of 7.5% and pays interest at a floating rate of six-month LIBOR plus a weighted average spread of approximately 4.675%. The swap agreements will settle semi-annually and will terminate in February 2008. An increase in outside market interest rates of 1% would result in a $1.0 million increase to the Company’s annual interest expense.

Foreign Currency Exchange Rates

Because the Company operates in virtually every oil and gas exploration and production region in the world, it conducts a portion of its business in currencies other than the U.S. dollar. The functional currency for some of the Company’s international operations is the applicable local currency. Although some of the Company’s international revenues are denominated in the local currency, the effects of foreign currency fluctuations are partly mitigated because local expenses of such foreign operations are also generally denominated in the same currency. During the years ended December 31, 2004, 2003, and 2002, the Company reported foreign currency gains (losses) of $1.3 million, $1.1 million, and ($5.2) million respectively. The gains (losses) were

primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency.

With respect to foreign currency fluctuations, the Company uses natural hedges to minimize the effect of rate fluctuations. When natural hedges are not sufficient, the Company may enter into forward foreign exchange contracts designed as cash flow hedgers to hedge significant transactions for periods consistent with the underlying risk.

To protect against the reduction in value of forecasted foreign currency cash flows resulting from sales or expenses denominated in a nonfunctional currency, the Company has instituted a foreign currency cash flow hedging program. The Company may hedge portions of its forecasted nonfunctional currency revenue and expenses with forward contracts from time to time.

At December 31, 2004 we have six foreign currency forward contracts with a notional amount of $7.5 million to hedge forecasted revenues or expense exposures in Canadian Dollars and Euro. The contracts have been designated as cash flow hedges.

The counter party to the forward contracts is a major financial institution. The credit rating and concentration of risk of this financial institution is monitored on a continuing basis. In the unlikely event the counterparty fails to meet the terms of a foreign currency contract, our exposure is limited to the foreign rate differential.

At December 31, 2004, the Company expects to reclassify $0.2 million of net gains on derivative instruments from accumulated other comprehensive income to earnings during the next twelve months due to the actual occurrence of the forecasted sales or expenses.

The Company has market risk sensitive instruments denominated in foreign currencies totaling $30.5 million as of December 31, 2004, excluding trade receivables and payables, which approximate fair value. These market risk sensitive instruments consisted of cash balances overdraft facilities and foreign currency forward contracts. The Company estimates that a hypothetical 10% movement of all applicable foreign currency exchange rates would affect net income by $2.0 million of which $0.5 million relate to the foreign currency forward contracts.

Assets and liabilities of those foreign subsidiaries are translated using the exchange rates in effect at the balance sheet date, resulting in translation adjustments that are reflected in accumulated other comprehensive loss in the common stockholders’ equity section of the Company’s balance sheet. The Company recorded currency translation gains (losses) of $8.3 million, $12.4 million, and ($0.8) million for the years ended December 31, 2004, 2003 and 2002, respectively.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements of the Company and subsidiaries required to be included in this Item 8 are set forth in Item 15 of this Report.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Our disclosure controls and procedures are designed to provide a reasonable level of assurance of reaching our desired disclosure control objectives. Also, we have investments in certain unconsolidated entities. As we do not control or manage these entities, our disclosure controls and procedures with respect to such entities are necessarily substantially more limited than those we maintain with respect to our consolidated subsidiaries.

As required by SEC Rule13a-15(b), the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and the Company’s Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of the end of the quarter covered by this report. Based on the foregoing, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective at the reasonable assurance level.

There has been no change in the Company’s internal controls over financial reporting during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal controls over financial reporting.

The Company’s management report on internal control over financial reporting is included on page F-2.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The registrant has adopted a code of business conduct and ethics that applies to all officers and employees of the registrant and its subsidiaries. The code of business conduct and ethics can be found on the registrant’s website located at http://www.varco.com. Any amendment to or waiver from the code of business conduct and ethics that applies to executive officers will be disclosed to the public.

The remaining information required by this Item is incorporated by reference to the registrant’s definitive proxy statement for its 2005 Annual Meeting to be filed with the Securities and Exchange Commission (the “Commission”) pursuant to regulation 14A within 120 days after the end of the fiscal year covered by this report (the “Varco Proxy Statement”).

ITEM 11.

EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference to the Varco Proxy Statement.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this Item is incorporated by reference to the Varco Proxy Statement.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this Item is incorporated by reference to the Varco Proxy Statement.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this item is incorporated by reference to the Varco Proxy Statement.

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements of the Company


		Page
Report of Independent Registered Public Accounting Firm		F-1
Management’s Report on Internal Control Over Financial Reporting		F-2
Report of Independent Registered Public Accounting Firm		F-3
Consolidated Balance Sheets at December 31, 2004 and 2003		F-4
Consolidated Statements of Income for the years ended December 31, 2004, 2003, and 2002		F-5
Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income for the years ended December 31, 2004, 2003, and 2002		F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003, and 2002		F-7
Notes to Consolidated Financial Statements		F-8–F-27

(2) Financial Statement Schedules:

The information under the following captions is filed as part of this Report:


Schedule I Parent Company Only Condensed Balance Sheets		S-1
Schedule I Parent Company Only Condensed Statements of Income		S-2
Schedule I Parent Company Only Condensed Statements of Cash Flows		S-3
Schedule I Parent Company Only Notes to Condensed Financial Statements		S-4
Schedule II Valuation and Qualifying Accounts		S-5

All other schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and therefore have been omitted or the information is presented in the consolidated financial statements or related notes.

(3) The list of exhibits contained in the Index to Exhibits are filed as part of this Report—Page 49.

EXHIBIT INDEX


Exhibit No.	Description	Note No.

2.1	Amended and Restated Agreement and Plan of Merger, effective as of August 11, 2004, by and between the Company and National-Oilwell, Inc.	(Note 23)

3.1	Third Amended and Restated Certificate of Incorporation of Varco International, Inc., dated May 30, 2000.	(Note 1)

3.2	Third Amended and Restated Bylaws.	(Note 1)

3.3	Certificate of Designations of Series A Junior Participating Preferred Stock of Varco International, Inc., dated November 30, 2000.	(Note 1)

4.1	Rights Agreement, dated as of November 29, 2000, by and between the Company and Chase Mellon Shareholder Services, L.L.C., as Rights Agent, which includes the form of Certificate of Designations of the Series A Junior Participating Preferred Stock of Varco International, Inc. as Exhibit A, the form of Right Certificate as Exhibit B, and the Summary of Rights to Purchase Preferred Shares as Exhibit C.	(Note 1)

4.1.1	Rights Agreement Amendment No. 1, dated as of August 11, 2004, to the Rights Agreement dated as of November 29, 2000, between the Company and Mellon Investor Services LLC, as Rights Agent.	(Note 24)

4.2	Purchase Agreement dated as of October 1, 1991 between the Company and Baker Hughes Incorporated regarding certain registration rights.	(Note 2)

4.3	Registration Rights Agreement dated April 24, 1996 among the Company, SCF III, L.P., D.O.S. Partners L.P., Panmell (Holdings), Ltd. And Zink Industries Limited.	(Note 3)

4.4	Registration Rights Agreement dated March 7, 1997 among the Company and certain stockholders of Fiber Glass Systems, Inc.	(Note 4)

4.5	Indenture, dated as of February 25, 1998, between the Company, the Guarantors named therein and The Bank of New York as trustee, relating to $100,000,000 aggregate principal amount of 7.5% Senior Notes due 2008; Specimen Certificate of 7.5% Senior Notes due 2008 (private notes); and Specimen Certificate at 7.5% Senior Notes due 2008 (public notes).	(Note 5)

4.5.1	Fifth Supplemental Indenture dated September 30, 2004 to Indenture dated February 25, 1998 by and among the Company, the Guarantors named therein and the Bank of New York Trust Company, N.A. as trustee.	(Note 27)

4.6	Indenture, dated as of May 1, 2001, among the Company, the Guarantors named therein and The Bank of New York as trustee, relating to $200,000,000 aggregate principal amount of 7.25% Senior Notes due 2011; Specimen Certificate of 7.25% Senior Notes due 2011 (private notes); and Specimen Certificate of 7.25% Senior Notes due 2011 (public notes).	(Note 6)

4.6.1	Third Supplemental Indenture dated September 30, 2004 to Indenture dated May 1, 2001 by and among the Company, the Guarantors named therein and the Bank of New York Trust Company, N.A. as trustee.	(Note 27)

4.7	Indenture, dated as of November 19, 2002, between the Company, the guarantors named therein and The Bank of New York Trust Company of Florida as trustee, relating to $150,000,000 aggregate principal amount of 5.5% Senior Notes due 2012 (private notes) Specimen Certificate of 5.5% Senior Notes due 2012 (private notes); and Specimen Certificate of 5.5% Senior Notes due 2012 (public notes).	(Note 7)

4.7.1	First Supplemental Indenture dated September 30, 2004 to Indenture dated November 19, 2002 by and among the Company, the Guarantors named therein and the Bank of New York Trust Company, N.A. as trustee.	(Note 27)



4.8	Registration Rights Agreement dated as of November 19, 2002, among the Company and Salomon Smith Barney Inc.	(Note 7)

10.1	Credit Agreement, dated as of June 30, 2004, among the Company, as the Borrower, Wells Fargo Bank Texas, National Association, as Administrative Agent, Bank One, NA, and Comercia Bank as Co-Syndication Agents, Credit Suisse First Boston, as Documentation Agent, and the other Banks a party thereto.	(Note 26)

10.1.1	Release of Guaranty Obligations dated September 30, 2004 related to the Credit Agreement dated June 30, 2004 by Wells Fargo Bank, N.A. as administrative agent.	(Note 27)

10.1.2	Amendment No. 1, Consent, and Agreement, dated as of January 14, 2005, among the Company, the lenders party to the credit agreement, dated June 30, 2004, and Wells Fargo, N.A., as administrative agent.	(Note 28)

10.2*	Varco International, Inc. Deferred Compensation Plan (effective January 1, 2003)	(Note 21)

10.3*	2003 Equity Participation Plan of Varco International, Inc.	(Note 22)

10.3.1*	Form of Non-qualified Stock Option Agreement for Employees and Consultants; Form of Non-qualified Stock Option Agreement for Independent Directors.	(Note 20)

10.3.2*	Form of Signature Page for Executive Officer Stock Option Agreement	(Note 25)

10.4*	Amended and Restated Stock Option Plan for Key Employees of Tuboscope Vetco International Corporation; Form of Revised Incentive Stock Option Agreement; and Form of Revised Non-Qualified Stock Option Agreement.	(Note 8)


Exhibit No.	Description	Note No.

10.5*	Stock Option Plan for Non-Employee Directors; Amendment to Stock Option Plan for Non-Employee Directors; and Form of Stock Option Agreement.	(Note 9)

10.6*	Amendment and Restatement of the Varco International, Inc. Supplemental Executive Retirement Plan (effective as of November 15, 2001)	(Note 21)

10.7	Lease dated March 7, 1975, as amended	(Note 10)

10.7.1	Agreement dated as of January 1, 1982, with respect to Lease included as Exhibit 10.8	(Note 11)

10.7.2	Agreement dated as of January 1, 1984, with respect to Lease included as Exhibit 10.8	(Note 12)

10.7.3	Agreement dated as of February 8, 1985, with respect to Lease included as Exhibit 10.8	(Note 12)

10.7.4	Agreement dated as of April 12, 1985, with respect to Lease included as Exhibit 10.8	(Note 13)

10.7.5	Amendment dated as of January 11, 1996, with respect to Lease included as Exhibit 10.8	(Note 14)

10.8	Standard Industrial Lease-Net dated September 29, 1988 for the premises at 743 N. Eckhoff, Orange, California	(Note 15)

10.8.1	First amendment dated as of January 11, 1996 to Lease included as Exhibit 10 B	(Note 14)

10.9*	The Varco International, Inc. 1990 Stock Option Plan, as amended	(Note 16)

10.9.1*	Amendments to the Varco International, Inc. 1990 Stock Option Plan	(Note 17)

10.10*	Varco International, Inc. 1994 Directors’ Stock Option Plan	(Note 14)

10.10.1*	Amendment to Varco International, Inc. 1994 Directors’ Stock Option Plan	(Note 18)

10.11*	Amendment and Restatement of the Varco International, Inc. Executive Retiree Medical Plan (effective as of November 15, 2001)	(Note 21)

10.11.1*	First Amendment to the Amendment and Restatement of the Varco International, Inc. Executive Retiree Medical Plan	(Note 25)

10.12*	Form of Amendment and Restated Executive Agreement of certain members of senior management	(Note 25)

10.13*	Form of Executive Agreement of certain members of senior management	(Note 19)

10.13.1*	Form of First Amendment to Executive Agreements	(Note 19)

10.14*	Executive Agreement of John F. Lauletta	(Note 19)

10.15*	Executive Agreement of Joseph C. Winkler	(Note 19)

10.16*	Agreement with George Boyadjieff dated November 29, 2002	(Note 21)

10.16.1*	First Amendment to Agreement with George Boyadjieff dated December 19, 2003	(Note 25)

10.17*	Form of Indemnity Agreement	(Note 19)

10.18*	Form of Amended and Restated Indemnification Agreement	(Note 27)

10.19*	Form of Deferred Stock Unit Award	(Note 25)

12	Computation of Ratio of Earnings to Fixed Charges



21		Subsidiaries

23		Consent of Independent Registered Public Accounting Firm

31.1		Rule 13a/15d-14(a) Certification of Chief Executive Officer

31.2		Rule 13a/15d-14(a) Certification of Chief Financial Officer

32.1(+)		Section 1350 Certification of Chief Executive Officer

32.2(+)		Section 1350 Certification of Chief Financial Officer

For purposes of this list of exhibits and the notes below, the term “Company” refers to the registrant, Varco International, Inc., a Delaware corporation formerly known as Tuboscope Inc., and the term “Varco” refers to Varco International, Inc., a California corporation which merged with and into the registrant on May 30, 2000.

(*)	Management contract, compensation plan or arrangement.

(+)	In accordance with SEC Release No. 33-8212, this exhibit is being furnished, and is not being filed as part of this report or as a separate disclosure document, and is not being incorporated by reference into any Securities Act of 1933 registration statement.

Table of Contents


Note 1		Incorporated by reference to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, filed on March 9, 2001.

Note 2		Incorporated by reference to the Company’s Registration Statement on Form S-1 (No. 33-43525), filed on October 24, 1991.

Note 3		Incorporated by reference to the Company’s Current Report on Form 8-K, filed on January 16, 1996.

Note 4		Incorporated by reference to the Company’s Current Report on 8-K, filed on March 20, 1997.

Note 5		Incorporated by reference to the Company’s Registration Statement on Form S-4 (No. 333-51115), filed on April 27, 1998.

Note 6		Incorporated by reference to the Company’s Registration Statement on Form S-4 (No. 333-64226), filed on June 29, 2001.

Note 7		Incorporated by reference to the Company’s Registration Statement on Form S-4 (No. 333-102162), filed on December 23, 2002.

Note 8		Incorporated by reference to the Company’s Registration Statement on Form S-8 (No. 33-72150), filed on November 24, 1993.

Note 9		Incorporated by reference to the Company’s Registration Statement on Form S-8 (No. 33-72072), filed on November 23, 1993.

Note 10		Incorporated by reference to Varco’s Annual Report on Form 10-K for the year ended December 31, 1981, filed on March 18, 1982.

Note 11		Incorporated by reference to Varco’s Annual Report on Form 10-K for the fiscal year ended December 31, 1982, filed on March 29, 1983.

Note 12		Incorporated by reference to Varco’s Annual Report on Form 10-K for the fiscal year ended December 31, 1984, filed on March 29, 1985.

Note 13		Incorporated by reference to Varco’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 1985, filed on July 30, 1985.

Note 14		Incorporated by reference to Varco’s Annual Report on Form 10-K for the fiscal year ended December 31, 1995, filed on March 29, 1996.

Note 15		Incorporated by reference to Varco’s Annual Report on Form 10-K for the fiscal year ended December 31, 1988, filed on March 30, 1989.


Note 16		Incorporated by reference to Varco’s Registration Statement on Form S-8, Registration No. 333-21681, filed on February 12, 1997.

Note 17		Incorporated by reference to Varco’s Annual Report on Form 10-K for the year ended December 31, 1999, filed on March 24, 2000.

Note 18		Incorporated by reference to Varco’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, filed on March 26, 1998.

Note 19		Incorporated by reference to the Company’s Registration Statement of Form S-4 (333-34582), filed on April 12, 2000.

Note 20		Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2002, filed on November 8, 2002.

Note 21		Incorporated by reference to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, filed on March 28, 2003.

Note 22		Incorporated by reference to the Company’s Quarterly Report on Form 10Q for the fiscal quarter ended March 31, 2003, filed on May 20, 2003.

Note 23		Incorporated by reference to Annex A to the document forming a part of National Oilwell’s Registration Statement on Form S-4 (File No. 333-119071) filed on September 16, 2004.

Note 24		Incorporated by reference to the Company’s Current Report on Form 8-K, filed on August 12, 2004.

Note 25		Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2004, filed on May 6, 2004.

Note 26		Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2004, filed on August 5, 2004.

Note 27		Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2004, filed on November 9, 2004.

Note 28		Incorporated by reference to the Company’s Current Report on Form 8-K, filed on January 26, 2005.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


Dated: February 15, 2005	VARCO INTERNATIONAL, INC.

	By:	/s/ JOHN F. LAULETTA
		John F. Lauletta
		Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ JOHN F. LAULETTA John F. Lauletta	Director, Chairman of the Board and Chief Executive Officer	February 15, 2005

/s/ JOSEPH C. WINKLER Joseph C. Winkler	President and Chief Operating Officer	February 15, 2005

/s/ CLAY C. WILLIAMS Clay C. Williams	Vice President and Chief Financial Officer	February 15, 2005

/s/ ROBERT W. BLANCHARD Robert W. Blanchard	Vice President, Controller	February 15, 2005

/s/ GREG L. ARMSTRONG Greg L. Armstrong	Director	February 15, 2005

/s/ GEORGE S. DOTSON George S. Dotson	Director	February 15, 2005

/s/ RICHARD A. KERTSON Richard A. Kertson	Director	February 15, 2005

/s/ ERIC L. MATTSON Eric L. Mattson	Director	February 15, 2005

/s/ JEFFERY A. SMISEK Jeffery A. Smisek	Director	February 15, 2005

/s/ DOUGLAS E. SWANSON Douglas E. Swanson	Director	February 15, 2005

/s/ JAMES D. WOODS James D. Woods	Director	February 15, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Varco International, Inc.

We have audited the accompanying consolidated balance sheets of Varco International, Inc. as of December 31, 2004 and 2003 and the related consolidated statements of income, common stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedules listed in the Index at Item 15(a). These financial statements and schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Varco International, Inc. at December 31, 2004 and 2003, and the consolidated results of its income and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with U.S generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Varco International, Inc.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 14, 2005 expressed an unqualified opinion thereon.

/S/ ERNST & YOUNG LLP

Houston, Texas

February 14, 2005

F-1

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Varco’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Varco’s internal control system was designed 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.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

Management has used the framework set forth in the report entitled “Internal Control—Integrated Framework” published by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission to evaluate the effectiveness of the Company’s internal control over financial reporting. Management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2004. Ernst & Young LLP has issued an attestation report on management’s assessment of the Company’s internal control over financial reporting.

John F. Lauletta

Clay C. Williams

Houston, Texas

February 14, 2005

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board Of Directors And Stockholders

Varco International, Inc.

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Varco International, Inc. maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Varco International, Inc.s’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Varco International, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Varco International, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Varco International, Inc. as of December 31, 2004 and 2003, and the related consolidated statements of income, common stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004 of Varco International, Inc. and our report dated February 14, 2005 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, TX

February 14, 2005

F-3

VARCO INTERNATIONAL, INC.

CONSOLIDATED BALANCE SHEETS


	December 31,
	2004			2003
	(in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	118.5		$	85.7
Accounts receivable, net		401.1			331.7
Inventory, net		334.5			339.2
Deferred tax assets		20.7			17.0
Prepaid expenses and other		25.3			23.8

Total current assets		900.1			797.4
Property and equipment, net		490.2			488.9
Identified intangibles, net		39.4			31.5
Goodwill, net		458.2			434.0
Other assets, net		13.8			12.5

Total assets	$	1,901.7		$	1,764.3

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	85.3		$	98.4
Accrued liabilities		132.1			125.7
Income taxes payable		21.2			7.8
Current portion of long-term debt and short-term borrowings		3.7			6.5

Total current liabilities		242.3			238.4
Long-term debt		458.1			450.5
Pension liabilities and post-retirement obligations		32.0			29.5
Deferred taxes payable		45.7			46.2
Other liabilities		5.0			5.5

Total liabilities		783.1			770.1

Commitments and contingencies (Note 11)

Common stockholders’ equity:
Common stock, $.01 par value, 200,000,000 shares authorized, 101,196,587 shares issued and 98,125,207 shares outstanding at December 31, 2004 (99,150,487 shares issued and 96,908,207 shares outstanding at December 31, 2003)		1.0			1.0
Paid in capital		569.2			535.1
Retained earnings		592.4			494.6
Accumulated other comprehensive income (loss)		2.3			(6.2	)
Less: treasury stock at cost ( 3,071,380 shares at December 31, 2004 and 2,242,280 shares at December 31, 2003)		(46.3	)		(30.3	)

Total common stockholders’ equity		1,118.6			994.2

Total liabilities and equity	$	1,901.7		$	1,764.3

See accompanying notes.

F-4

VARCO INTERNATIONAL, INC.

CONSOLIDATED STATEMENTS OF INCOME


	Years Ended December 31,
	2004			2003 (restated)			2002 (restated)
	(in millions, except per share data)
Revenue:
Sales	$	775.7		$	776.6		$	798.1
Services and rentals		792.4			661.0			524.3

Total		1,568.1			1,437.6			1,322.4

Cost and expenses:
Cost of sales		472.6			443.9			488.3
Cost of services and rentals		672.2			588.7			452.1
Selling, general and administrative		166.1			177.8			160.2
Research and engineering costs		53.8			61.2			57.1
Merger and transaction costs		5.0			—			6.5

Total		1,369.7			1,271.6			1,164.2

Operating profit		198.4			166.0			158.2

Other expense (income):
Interest expense		31.1			30.2			25.6
Interest income		(1.3	)		(1.4	)		(0.8	)
Foreign exchange loss (gain)		(1.3	)		(1.1	)		5.2
Other		5.7			4.7			3.3

Income from continuing operations before income taxes		164.2			133.6			124.9
Provision for income taxes		56.8			44.8			43.6

Income from continuing operations		107.4			88.8			81.3
Loss from discontinued operations, net of tax		(9.6	)		(21.6	)		(1.5	)

Net income	$	97.8		$	67.2		$	79.8

Earnings per common share:
Basic:
Continuing operations	$	1.10		$	0.91		$	0.84
Discontinued operations		(0.10	)		(0.22	)		(0.02	)

Net Income	$	1.00		$	0.69		$	0.83

Dilutive:
Continuing operations	$	1.09		$	0.90		$	0.83
Discontinued operations		(0.10	)		(0.22	)		(0.02	)

Net Income	$	0.99		$	0.68		$	0.82

Weighted average number of common shares outstanding:
Basic		97.4			97.3			96.6

Dilutive		98.6			98.2			97.4

See accompanying notes.

F-5

VARCO INTERNATIONAL, INC.

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME


	Shares Outstanding		Common Stock $.01 Par Value		Paid in Capital		Retained Earnings		Accumulated Other Comprehensive Income (loss)						Treasury Stock			Total Common Stockholders’ Equity
	Shares Outstanding		Common Stock $.01 Par Value		Paid in Capital		Retained Earnings		Foreign Currency Translation Adjustment			Hedging Derivatives			Treasury Stock			Total Common Stockholders’ Equity
Balance at December 31, 2001	96.0		$	1.0	$	514.0	$	347.6	$	(19.0	)	$	—		$	(15.3	)	$	828.3

2002 Comprehensive income:
Net income	—			—		—		79.8		—			—			—			79.8
Foreign currency translation adjustment	—			—		—		—		(0.8	)		—			—			(0.8	)
Gain on hedging derivatives	—			—		—		—		—			1.3			—			1.3

2002 Comprehensive income	—			—		—		79.8		(0.8	)		1.3			—			80.3
Common stock issued	1.0			—		9.5		—		—			—			—			9.5
Common stock issued in exchange for convertible debt	—			—		0.1		—		—			—			—			0.1
Tax benefit of options exercised	—			—		2.0		—		—			—			—			2.0

Balance at December 31, 2002	97.0			1.0		525.6		427.4		(19.8	)		1.3			(15.3	)		920.2

2003 Comprehensive income:
Net income	—			—		—		67.2		—			—			—			67.2
Foreign currency translation adjustment	—			—		—		—		12.4			—			—			12.4
Loss on hedging derivatives	—			—		—		—		—			(0.1	)		—			(0.1	)

2003 Comprehensive income	—			—		—		67.2		12.4			(0.1	)		—			79.5
Common stock issued	0.7			—		8.4		—		—			—			—			8.4
Tax benefit of options exercised	—			—		1.1		—		—			—			—			1.1
Treasury stock purchased	(0.8	)		—		—		—		—			—			(15.0	)		(15.0	)

Balance at December 31, 2003	96.9			1.0		535.1		494.6		(7.4	)		1.2			(30.3	)		994.2

2004 Comprehensive income:
Net income	—			—		—		97.8		—			—			—			97.8
Foreign currency translation adjustment	—			—		—		—		8.3			—			—			8.3
Gain on hedging derivatives	—			—		—		—		—			0.2			—			0.2

2004 Comprehensive income	—			—		—		97.8		8.3			0.2			—			106.3
Common stock issued	2.0			—		29.2		—		—			—			—			29.2
Tax benefit of options exercised	—			—		4.9		—		—			—			—			4.9
Treasury stock purchased	(0.8	)		—		—		—		—			—			(16.0	)		(16.0	)

Balance at December 31, 2004	98.1		$	1.0	$	569.2	$	592.4	$	0.9		$	1.4		$	(46.3	)	$	1,118.6

See accompanying notes.

F-6

VARCO INTERNATIONAL, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2004			2003			2002
	(in millions)
Cash flows from operating activities:
Net income	$	97.8		$	67.2		$	79.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		75.5			67.2			59.2
Non-cash write-offs		—			11.2			—
Provision for losses on accounts receivable		5.2			3.4			2.9
Provision for losses on inventory		12.8			7.4			7.7
Provision (benefit) for deferred taxes		(4.5	)		9.0			7.2
Other non-cash charges		(0.7	)		(1.0	)		(0.6	)
Changes in current assets and liabilities, net of effects from acquisitions:
Accounts receivable		(71.4	)		(10.8	)		35.4
Inventory		(6.7	)		(64.2	)		(54.0	)
Prepaid expenses and other assets		(1.7	)		0.2			3.2
Accounts payable, accrued liabilities and other		(9.8	)		12.6			(23.0	)
Income taxes payable		17.7			(1.5	)		(16.0	)

Net cash provided by operating activities		114.2			100.7			101.8

Cash flows used for investing activities:
Capital expenditures		(51.9	)		(67.1	)		(49.4	)
Business acquisitions, net of cash acquired		(37.0	)		(39.0	)		(152.3	)
Other		(0.9	)		(0.5	)		(0.6	)

Net cash used for investing activities		(89.8	)		(106.6	)		(202.3	)

Cash flows provided by (used for) financing activities:
Borrowings under financing agreements, net		0.1			2.3			239.4
Principal payments under financing agreements		(6.5	)		(10.8	)		(100.2	)
Debt issue costs		(0.5	)		—			(1.7	)
Proceeds from interest rate contract		—			—			1.3
Proceeds from sale of common stock, net		29.2			8.4			9.5
Purchase of treasury stock		(16.0	)		(15.0	)		—

Net cash provided by (used for) financing activities		6.3			(15.1	)		148.3

Effect of exchange rate changes on cash		2.1			0.7			0.7
Net increase (decrease) in cash and cash equivalents		32.8			(20.3	)		48.5
Cash and cash equivalents:
Beginning of year		85.7			106.0			57.5

End of year	$	118.5		$	85.7		$	106.0

Supplemental disclosure of cash information:
Cash paid during the year for:
Interest	$	30.1		$	31.6		$	24.8

Taxes	$	40.1		$	32.8		$	52.8

See accompanying notes

F-7

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Basis of Presentation

Consolidation

The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated.

Nature of Business and Risk Factors

The Company provides highly engineered drilling and well-servicing equipment, products and services to the world’s oil and gas industry. The Company operates in four principal business segments: Drilling Equipment Group, Tubular Services, Drilling Services and Coiled Tubing and Wireline Products. A more detailed description of products and services is provided in Note 12 Business Segments and Foreign Operations.

The oil and gas industry in which the Company participates has historically experienced significant volatility. Demand for the Company’s services and products depends primarily upon the general level of activity in the oil and gas industry worldwide, including the number of drilling rigs in operation, the number of oil and gas wells being drilled, the depth and drilling conditions of these wells, the volume of production, the number of well completions and the level of well remediation activity. Oil and gas activity is in turn heavily influenced by, among other factors, oil and gas prices worldwide. High levels of drilling and well-remediation activity generally spur demand for the Company’s products and services used to drill and remediate oil and gas wells. Additionally, high levels of oil and gas activity increase cash flows available for drilling contractors, well-remediation service companies, and manufacturers of oil country tubular goods to invest in capital equipment which the Company sells.

Much of the Company’s Drilling Equipment group’s revenues are determined by the capital expenditures of drilling contractors and oil companies on equipment for new drilling rig fabrication or drilling rig refurbishment projects. Capital expenditures are influenced by cash flows these contractors generate from drilling activity, but also by the availability of financing, the outlook for future drilling activity, and other factors. Generally the Company believes the demand for more drilling capital equipment lags increases in the level of drilling activity. A significant portion of the Drilling Equipment group’s revenue is related to the sale of drilling equipment spare parts and consumables, the provision of equipment-repair services, and the rental of drilling equipment, which the Company believes are generally determined directly by the level of drilling activity.

The majority of the Company’s Tubular Service group’s revenues are directly related to the level of demand for oil country tubular goods, which is determined by the level of drilling, completion, and well servicing activity (which use oil country tubular goods). A portion of Tubular Services sales are related to (1) demand for pipeline inspections, which is generally unrelated to drilling or well remediation activity and may be adversely affected by high commodity prices that cause operators to defer inspections; (2) the sale of fiberglass and composite tubing to industrial customers, which is generally unrelated to drilling or well remediation activity but may be tied somewhat to oil and gas prices; and (3) the sale of pipe inspection equipment to the manufacturers of oil country tubular goods, which is indirectly related to drilling activity, in the Company’s view. Since the services provided by this group tend to prolong the useful life of steel tubular products, demand for the services may be impacted by steel costs.

The Company’s Drilling Services group’s revenues are closely tied to drilling activity, although a portion of Drilling Services revenues are related to the sale of capital equipment to drilling contractors, which is indirectly related to the level of drilling activity. The Company’s Drilling Services sales of consumables, such as shaker screens, and spare parts for its equipment, are generally determined directly by the level of drilling activity, in the Company’s view.

The Company’s Coiled Tubing & Wireline Products group’s revenues are generally driven by the capital expenditures of well service contractors. These capital expenditures are influenced by the cash flows these contractors generate from well completion and remediation activity, but also by the availability of financing, the outlook for future well remediation activity, and other factors. A portion of the Coiled Tubing & Wireline Products revenue is determined by the demand for spare parts and consumables, the provision of equipment repair services, and the rental of well servicing equipment, which the Company believes are generally determined directly by the level of well completion and remediation activity.

Drilling and well servicing activity can fluctuate significantly in a short period of time. The willingness of oil and gas operators to make capital investments to explore for and produce oil and natural gas will continue to be influenced by numerous factors over which the Company has no control, including: the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) to maintain oil price stability through voluntary production limits of oil; the level of oil production by non-OPEC

F-8

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

countries; supply and demand for oil and natural gas; general economic and political conditions; costs of exploration and production; and the availability of new leases and concessions; and governmental regulations regarding, among other things, environmental protection, taxation, price controls and product allocations. The willingness of drilling contractors and well remediation contractors to make capital expenditures for the type of specialized equipment the Company provides is also influenced by numerous factors over which the Company has no control, including: the general level of oil and gas well drilling and well remediation; access to external financing; outlook for future increases in well drilling and well remediation activity; and government regulations regarding, among other things, environmental protection, taxation, and price controls.

The Company operates in over 40 countries around the world. Its revenues are geographically located in North America (53%), Latin America (10%), Europe, Africa, and the Middle East (27%), and the Far East (10%). As a result of its international presence, the Company’s operations are subject to the risks normally associated with conducting businesses in foreign countries, including foreign exchange fluctuations and uncertain political and economic environments, which may limit or disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or the taking of property without compensation. In addition, the Company has significant customer concentrations in the Middle East, Latin America and the Far East whose spending can be volatile based on oil price changes, the political environment and delays in the government budget. Adverse changes in individual circumstances can have a significant negative impact on the financial performance of the Company.

On August 11, 2004, the Company entered into an Agreement and Plan of Merger with National-Oilwell, Inc. (National Oilwell) whereby the Company will merge with and into National Oilwell. Under the terms of the agreement, each outstanding share of the Company’s common stock will be converted into the right to receive 0.8363 of a share of National Oilwell common stock. National Oilwell will assume all options outstanding under the Company’s stock option plans and each outstanding option to purchase the Company’s common stock will be converted into an option to purchase National Oilwell common stock, subject to certain adjustments to the exercise price and the number of shares issuable upon exercise of those options to reflect the exchange ratio. In the event of a termination of the agreement under certain circumstances, Varco may be required to pay National Oilwell a termination fee of $75 million.

The completion of the merger is subject to several conditions, including the approval of the merger agreement by the stockholders of the Company and National Oilwell and the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. National Oilwell and Varco have responded to the Antitrust Division of the U.S. Department of Justice’s request for additional information issued under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and continue to work with the Justice Department regarding the proposed merger between the companies. Closing of the proposed merger is expected to occur as quickly as possible after regulatory clearance and stockholder approvals are received. A special meeting of the stockholders of the Company to approve the merger has been scheduled for March 11, 2005.

2.	Summary of Significant Accounting Policies

Revenue Recognition

The Company’s products and services are sold based upon purchase orders or contracts with the customer that include fixed or determinable prices and that do not include right of return or other similar provisions or other significant post delivery obligations. The Company records revenue at the time its manufacturing process is complete, the customer has been provided with all proper inspection and other required documentation, title and risk of loss has passed to the customer, collectibility is reasonably assured and the product has been delivered. Customer advances or deposits are deferred and recognized as revenue when the Company has completed all of its performance obligations related to the sale. The Company also recognizes revenue as services are performed. The amounts billed for shipping and handling cost are included in revenue and related costs are included in costs of sales.

F-9

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Revenue from rig fabrication turnkey contracts is recognized on the completed contract method. Provisions for future losses on turnkey contracts are recognized when it becomes apparent that expenses to be incurred on a specific contract will exceed the revenue from that contract. The Company discontinued its rig fabrication business during the first quarter of 2004.

Cash and Cash Equivalents

The Company considers all highly liquid investments with a maturity of three months or less to be cash equivalents.

Financial Instruments and Concentrations of Credit Risk

The carrying amounts of financial instruments including cash and cash equivalents, short-term investments, accounts receivable and accounts payable approximated fair value because of the relatively short maturity of these instruments. The carrying value of debt approximated fair values as of December 31, 2004 and 2003 except for the Company’s $100 million 7.5% Senior Notes due 2008, $200 million 7.25% Senior Notes due 2011, and $150 million 5.5% Senior Notes due 2012. Based on information provided by a national brokerage company, the $100 million Senior Notes were valued at $107.2 million and $107.4 million at December 31, 2004 and 2003. The $200 million Senior Notes were valued at $227.7 million both at December 31, 2004 and 2003. The fair value of the $150 million 5.5% Senior Notes due 2012 were valued at $153.1 million at December 31, 2004 and $152.5 million at December 31, 2003. The fair value of other financial instruments approximate their carrying value at December 31, 2004 and 2003.

Substantially all of the Company’s accounts receivable are due from customers in the oil and gas industry, both in the United States and internationally. The Company performs periodic credit evaluations of its customers and does not require collateral. In certain circumstances, the Company requires letters of credit to further insure credit worthiness.

Allowance for doubtful accounts are determined on a specific identification basis when we believe that the required payment of specific amounts owed to us is not probable. Accounts receivable are net of allowances for doubtful accounts of approximately $12.8 million and $11.2 million at December 31, 2004 and 2003, respectively.

Inventory

Inventories are stated at the lower of cost or market, and the Company primarily costs inventory at first-in, first-out (“FIFO”). The Company also determines the cost of inventories using the last-in, first-out (“LIFO”) method for certain of its Drilling Equipment Group inventory (representing 7% of total consolidated inventory). Reserves for inventory obsolescence are determined based on our historical usage of inventory on-hand as well as our future expectations related to our substantial installed base and the development of new products. Inventory is net of our reserve of excess and obsolete inventory of approximately $33.8 million and $31.5 million at December 31, 2004 and 2003, respectively.

Property and equipment

Property and equipment is stated at cost, net of accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives for financial reporting purposes and generally by the accelerated or modified accelerated costs recovery systems for income tax reporting purposes. Estimated useful lives are 30 years for buildings and 5-12 years for machinery and equipment. The cost of repairs and maintenance is charged to income as incurred. Major repairs and improvements are capitalized and depreciated over the remaining useful life of the asset. Property and equipment depreciation expense was $69.5 million, $62.5 million, and $54.9 million for the years ended December 31, 2004, 2003, and 2002, respectively.

Goodwill and Identified intangibles

All business combinations are accounted for under the purchase method of accounting. Intangible assets deemed to have indefinite lives (including goodwill) are not amortized but are subject to annual impairment tests. Other intangible assets are amortized over their useful lives. Identified intangibles with determinable lives are being amortized on a straight-line basis, over estimated useful lives between 5 and 40 years, and are presented net of accumulated amortization of approximately $38.9 million and $34.1 million at December 31, 2004 and 2003, respectively. Identified intangibles consist primarily of technology, patents, trademarks, license agreements, existing service contracts and covenants not to compete. Aggregate amortization expense of identified intangibles for each of the next five years is estimated to be approximately $3.0 million.

F-10

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On at least an annual basis, the Company assesses whether goodwill is impaired. The annual impairment tests are performed during the fourth quarter of each year. If it is determined that goodwill is impaired, that impairment is measured based on the amount by which the book value of goodwill exceeds its implied fair value. The implied fair value of goodwill is determined by deducting the fair value of a reporting unit’s identifiable assets and liabilities from the fair value of that reporting unit as a whole. Additional impairment assessments may be performed on an interim basis if the Company encounters events or changes in circumstances that would indicate that, more likely than not, the carrying amount of goodwill has been impaired. Fair value of the reporting units is determined based on internal management estimates, using the average of three methods: discounted cash flow, comparable companies, and representative transactions.

During the fourth quarter of 2003, the Company recognized a charge of $10.1 million related to goodwill impairment as a result of its decision to exit the rig fabrication business. This charge is included in discontinued operations.

Impairment of Long-Lived Assets

Impairment losses are recorded on long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. The net carrying value of assets not recoverable is reduced to fair value if lower than carrying value. In determining the fair market value of the assets, the Company considers market trends and recent transactions involving sales of similar assets, or when not available, discounted cash flow analysis. Long- lived assets expected to be disposed of, including excess equipment and production facilities held for sale, are stated at their estimated fair value less costs to sell.

Warranty Accruals

Accruals for warranty claims are provided based on historical experience at the time of sale. Product warranties generally cover periods from one to three years. Our accruals for warranty claims are affected by the size of our installed base of products currently under warranty, as well as new products delivered to the market.

Environmental Liabilities

When environmental assessments or remediations are probable and the costs can be reasonably estimated, remediation liabilities are recorded on an undiscounted basis and are adjusted as further information develops or circumstances change.

Income taxes

The liability method is used to account for income taxes. Deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to amounts which are more likely than not to be realized. The provision for income taxes is the tax payable or refundable for the period plus or minus the change during the period in deferred tax assets and liabilities.

Our tax filings are subjected to audit by tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe we have adequately provided for any reasonably foreseeable outcome related to these matters. However, our future results may include favorable or unfavorable adjustments to our estimated tax liabilities in the period the assessments are made or resolved.

As described in Note 7 to the Consolidated Financial Statements, our 2004 results do not reflect the impact of the American Jobs Creation Act of 2004 (the “Jobs Act”). We have not completed the process of reevaluating our position with respect to the indefinite reinvestment of foreign earnings to take into account the possible election of the repatriation provisions contained in the Jobs Act.

Derivative financial instruments

The Company records derivative financial instruments at fair value in our consolidated balance sheet. The Company holds derivative instruments which are designated as cash flow or fair value hedges and are highly effective in offsetting movements in the underlying risks. The effective portion of cash flow hedges (which include foreign currency forward contracts) are deferred in other comprehensive income and reclassified to earnings when the instruments mature during the period of actual occurrence of the forecasted sales or expenses. Because the

F-11

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

derivative financial instrument is so closely related to the underlying transaction, hedge ineffectiveness is insignificant. The fair value hedges (which includes interest rate swap agreements) are considered perfectly effective against changes in the fair value of debt due to changes in the benchmark interest rate over its term. The remaining term of these hedges is tied to the underlying hedged items. Substantially all amounts included in other comprehensive income are due to be reclassified into income within 12 months.

Foreign exchange rates

Revenue and expenses for foreign operations have been translated into U.S. dollars using average exchange rates and reflect currency exchange gains and losses resulting from transactions conducted in other than functional currencies.

The assets and liabilities of certain foreign subsidiaries are translated at current exchange rates and the related translation adjustments are recorded directly in stockholders’ equity. For subsidiaries where the U.S. dollar is the functional currency, certain assets are remeasured at historical exchange rates and all remeasurement adjustments are reflected in the statements of income.

Stock based compensation

The Company accounts for its stock-based employee compensation plans using the intrinsic value method. If the Company had accounted for its stock-based employee compensation plans using the alternative fair value method, the Company’s pro forma net income and earnings per common share would have been as follows (in millions, except per share data):


	Years Ended December 31,
	2004			2003			2002
Proforma net income and earnings per common share

Income from continuing operations, as reported	$	107.4		$	88.8		$	81.3
Income (loss) from discontinued operations, net of tax		(9.6	)		(21.6	)		(1.5	)

Net income, as reported		97.8			67.2			79.8
Stock-based employee compensation cost, net of related tax effects		8.6			9.8			7.7

Proforma net income	$	89.2		$	57.4		$	72.1


Earnings per common share:
Basic earnings per common share, as reported
Continuing operations, as reported	$	1.10		$	0.91		$	0.84
Discontinued operations		(0.10	)		(0.22	)		(0.02	)

Net income, as reported	$	1.00		$	0.69		$	0.83

Basic earnings per common share, pro forma
Continuing operations, pro forma	$	1.02		$	0.81		$	0.76
Discontinued operations		(0.10	)		(0.22	)		(0.02	)

Net income, pro forma	$	0.92		$	0.59		$	0.75

Dilutive earnings per common share, as reported
Continuing operations, as reported	$	1.09		$	0.90		$	0.83
Discontinued operations		(0.10	)		(0.22	)		(0.02	)

Net income, as reported	$	0.99		$	0.68		$	0.82

Dilutive earnings per common share, pro forma
Continuing operations, pro forma	$	1.00		$	0.80		$	0.76
Discontinued operations		(0.10	)		(0.22	)		(0.02	)

Net income, pro forma	$	0.90		$	0.58		$	0.74

Weighted average number of common shares outstanding:
Basic		97.4			97.3			96.6
Dilutive		98.6			98.2			97.4

F-12

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Earnings per common share

Basic earnings per common share is computed by dividing net income by the weighted-average number of common shares outstanding for the period. The Company’s diluted earnings per common share is calculated by adjusting net income for after-tax interest expense on convertible debt and dividing that number by the weighted average number of common shares outstanding plus shares which would be assumed outstanding after conversion of convertible debt, vested stock options and outstanding stock warrants under the treasury stock method. The weighted average number of outstanding stock options, which were excluded from the calculation of diluted earnings per share because their impact would have been antidilutive, aggregated 89,811; 197,513; and 331,904 in 2004, 2003, and 2002, respectively.

The following table sets forth the computation of basic and dilutive earnings per share (in millions, except per share data):


	Years Ended December 31,
	2004		2003		2002
Numerator:
Net income	$	97.8	$	67.2	$	79.8

Denominator:
Basic—weighted average common shares outstanding		97.4		97.3		96.6
Dilutive effect of employee stock options		1.2		0.9		0.8

Dilutive outstanding shares		98.6		98.2		97.4

Basic earnings per share	$	1.00	$	0.69	$	0.83

Dilutive earnings per share	$	0.99	$	0.68	$	0.82

Use of estimates in the preparation of financial statements

The consolidated financial statements and related notes, which have been prepared in conformity with generally accepted accounting principles, require the use of management estimates. Actual results could differ from these estimates.

New Accounting Standards

In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151, “Inventory Costs – an amendment of ARB 43, Chapter 4” (“SFAS 151”). SFAS 151 clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. Paragraph 5 of Accounting Research Bulletin (“ARB”) 43, Chapter 4 “Inventory Pricing,” previously stated that “under certain circumstances, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs may be so abnormal as to require treatment as current-period charges” SFAS 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition, SFAS 151 requires that the allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS 151 is effective for fiscal years beginning after June 15, 2005. The Company does not believe the implementation of SFAS 151 will have a material impact on the Company’s financial position, results of operations or cash flows.

F-13

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

begins after June 15, 2005. The Company is currently in the process of evaluating the impact of Revised SFAS 123 on its financial statements, including different option-pricing models. The pro forma table in Note 10 of the Notes to Consolidated Financial Statements illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123.

Drilling Equipment Group Restructuring

Discontinued Operations

In late 2003, the Company decided to discontinue its rig fabrication operation (Morinoak International Limited or “MIL”). The company determined that its integrated packages of drilling equipment and structural rig components bore too much risk, and failed to produce a sufficient economic return, and therefore, the Company decided to exit the rig fabrication business and close the MIL Facility in Great Yarmouth, England. In January 2004, the Company announced plans to close MIL. The Company incurred $11.7 million (net of tax) in charges related to its discontinued rig fabrication business in the first quarter of 2004 and recognized an after tax gain of $2.1 million in the third quarter of 2004 due to the favorable resolution of an outstanding contractual issue. The first quarter 2004 charges included severance costs for MIL personnel, facility closure costs, additional losses from a $31 million land drilling rig in the Middle East, and other operating losses. The 2003 and 2002 results have been restated to reflect the MIL operation as discontinued. Previously, these results were included as part of the Company’s Drilling Equipment Group.

The following summarizes the operations of MIL for the years ended December 31, 2004, 2003 and 2002 (in millions):


	2004			2003			2002
Revenue	$	39.1		$	12.0		$	12.7

Operating loss	$	(13.1	)	$	(26.1	)	$	(2.1	)
Income tax benefit		(3.5	)		(4.5	)		(0.6	)

Loss from discontinued operations, net of tax	$	(9.6	)	$	(21.6	)	$	(1.5	)

3.	Acquisitions

Fiscal 2004

The Company completed eight acquisitions and outside investments for an aggregate purchase price of $43.7 million consisting of cash of $33.2 million and notes payable of $10.5 million. The most significant acquisitions include:

•

Wildcat Services, LP, a Texas-based manufacturer of automatic drilling systems.

•

JB Equipment, Inc., a Louisiana-based provider of horizontal cuttings dryers.

•

Wellsite Gas Detection, Inc., a Canada-based manufacturer of wellsite gas monitors.

F-14

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2004 acquisitions (in millions):


Current assets	$	4.6
Property, plant and equipment		8.2
Intangible assets		8.7
Goodwill		24.3
Other assets		0.9

Total assets acquired		46.7

Current liabilities		4.0
Long term debt		9.5

Total liabilities assumed		13.5

Net assets acquired	$	33.2

The following table summarizes goodwill additions for 2004 acquisitions by business segment (in millions):


	2004
Drilling Services	$	19.7
Coiled Tubing & Wireline Products		4.6

Total goodwill	$	24.3

Fiscal 2003

The Company completed thirteen acquisitions and outside investments for an aggregate purchase price of $36.6 million consisting of cash of $35.7 million and notes and accrued payables of $0.9 million. The most significant acquisitions include:

•

Mud Rentals Ltd., a UK-based provider of horizontal dryers.

•

Thermal desorption assets of Maersk Contractors Environmental Division, a UK-based provider of oilfield waste management services.

•

Church Oil Tools, a Texas-based provider of blowout preventers, gate valves, drilling and standpipe manifolds and related accessories.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2003 acquisitions (in millions):


Current assets	$	6.7
Property, plant and equipment		13.5
Intangible assets		1.4
Goodwill		14.4
Other assets		2.3

Total assets acquired		38.3

Current liabilities		1.1
Long term debt		0.6

Total liabilities assumed		1.7

Net assets acquired	$	36.6

The following table summarizes goodwill additions for 2003 acquisitions by business segment (in millions):


	2003
Drilling Equipment Group	$	2.4
Tubular Services		3.7
Drilling Services		7.8
Coiled Tubing & Wireline Products		0.5

Total goodwill	$	14.4

F-15

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Fiscal 2002

On September 6, 2002, the Company acquired substantially all of ICO Inc.’s oilfield services business for approximately $138.6 million including cash of $136.2 million and accrued payables of $2.4 million. The acquisition of ICO’s oilfield services business further solidified the Company’s worldwide leadership position in the oilfield inspection and coating markets. The combination of the Company’s and ICO’s business has created operating efficiencies and reduce costs through operational integration. ICO’s oilfield services business provides inspection, coating and reconditioning of drill pipe, tubing, casing and sucker rods used in oil and gas operations. Additionally, it sells and rents equipment and supplies used in the inspection of tubular goods and sucker rods. Under the purchase agreement, the Company acquired the assets of ICO’s oilfield services business in the U.S., Mexico, Southeast Asia and Europe and the stock of ICO’s Canadian operating subsidiary. The Company incurred transaction costs of approximately $3.7 million related primarily to the write off of duplicate facilities as a result of the ICO acquisition.

The Company also completed six other acquisitions in 2002 for an aggregate purchase price of $15.0 million including cash of $13.7 million and notes payable of $1.3 million. These acquisitions included:

•

A & A Tubular Inspection Inc., a California-based provider of inspection and reclamation of oilfield tubular goods and sucker rods.

•

Environmental Rig Solutions, a Texas-based provider of equipment to enhance waste management on customer well sites.

•

Marr Associates Pipeline Integrity, Ltd, a Canada-based provider of integrity and data management, direct assessment, corrosion control and stress corrosion cracking services to the Pipeline industry.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2002 acquisitions (in millions):


	ICO		All Other Acquisitions		Total
Current assets	$	23.2	$	2.2	$	25.4
Property, plant and equipment		46.9		3.8		50.7
Intangible assets		—		4.4		4.4
Goodwill		86.4		5.9		92.3
Other assets		0.7		2.0		2.7

Total assets acquired		157.2		18.3		175.5

Current liabilities		17.4		2.4		19.8
Long term debt		2.9		0.8		3.7
Other liabilities		0.6		—		0.6

Total liabilities		20.9		3.2		24.1

Net assets acquired	$	136.3	$	15.1	$	151.4

Goodwill allocated to business segments in 2002 was $90.3 million for Tubular Services and $2.0 million for Drilling Services.

Each of the acquisitions were accounted for using the purchase method of accounting and, accordingly, the results of operations of each business is included in the consolidated results of operations from the date of acquisition. A summary of the acquisitions follows (in millions):


	2004			2003			2002
Fair value of assets acquired	$	50.5		$	40.7		$	176.4
Cash paid		(37.0	)		(39.0	)		(152.4	)

Liabilities assumed and debt issued	$	13.5		$	1.7		$	24.0

Excess purchase price over fair value of assets acquired	$	24.3		$	14.4		$	92.3

Other

Cash paid in 2004, 2003, and 2002 includes $3.8 million, $3.3 million and $2.4 million for 2003, 2002, and 2001 acquisitions, respectively.

F-16

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following unaudited pro forma information presents a summary of the consolidated results of operations of the Company as if these acquisitions had occurred at the beginning of 2003 (in millions, except per share data.) The pro forma information includes certain adjustments which give effect to interest expense on acquisition debt and other adjustments, together with related income tax effects. The pro forma financial information is not necessarily indicative of the results of operations as they would have been had the transactions been effected at the beginning of 2003.


	2004		2003
Revenue	$	1,578.8	$	1,481.0

Net income	$	101.1	$	77.4

Dilutive earnings per common share	$	1.03	$	0.79

4.	Inventory

At December 31, inventories consist of the following (in millions):


	2004			2003
Raw materials	$	100.8		$	84.2
Work in progress		71.1			61.3
Finished goods		205.8			191.7
Rig fabrication MIL inventory		—			43.0
Inventory reserves including LIFO reserves		(43.2	)		(41.0	)

	$	334.5		$	339.2

5.	Property, plant and equipment

At December 31, property, plant, and equipment consist of the following (in millions):


	2004			2003
Land and buildings	$	211.4		$	197.4
Operating equipment		434.7			424.0
Rental equipment		294.7			263.6

		940.8			885.0
Less accumulated depreciation		(450.6	)		(396.1	)

	$	490.2		$	488.9

6.	Accrued Liabilities

At December 31, accrued liabilities consist of the following (in millions):


	2004		2003
Compensation	$	46.0	$	40.4
Warranty		11.0		9.1
Interest		6.8		5.9
Taxes (non income)		7.5		7.2
Insurance		15.4		15.2
Other		45.4		47.9

	$	132.1	$	125.7

7.	Income Taxes

The components of income from continuing operations before income taxes consist of the following (in millions):


	2004		2003		2002
U.S.	$	89.1	$	86.0	$	64.5
Foreign		75.1		47.6		60.4

	$	164.2	$	133.6	$	124.9

F-17

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Such income is inclusive of various intercorporate eliminations of income or expense items, such as royalties, interest and similar items that are taxable or deductible in the respective locations. Such income is also inclusive of export sales by U.S. locations. Therefore, the relationship of domestic and foreign taxes to reported U.S. and foreign income is not representative of actual effective tax rates.

The provision (benefit) for income taxes from continuing operations consists of the following at December 31 (in millions):


	2004			2003			2002
Current provision:
U.S.	$	32.7		$	14.8		$	18.3
Foreign		28.6			21.0			18.1

Total current provision		61.3			35.8			36.4

Deferred provision (benefit):
U.S.		(6.0	)		11.0			3.0
Foreign		1.5			(2.0	)		4.2

Total deferred provision (benefit)		(4.5	)		9.0			7.2

Total provision	$	56.8		$	44.8		$	43.6

The reconciliation of the expected to the computed tax provision (benefit) is as follows at December 31 (in millions):


	2004			2003			2002
Tax expense at federal statutory rate	$	57.4		$	46.8		$	43.7
Incremental effect of foreign operations		1.4			0.3			3.0
Nondeductible merger related costs		1.8			—			—
FSC/ETI benefit		(2.1	)		(2.7	)		(3.7	)
Other, net		(1.7	)		0.4			0.6

	$	56.8		$	44.8		$	43.6

Significant components of the Company’s deferred tax liabilities and assets as of December 31, are as follows (in millions):


	2004			2003
Gross deferred tax assets:
Receivables	$	2.8		$	2.2
Foreign net operating losses		0.5			2.1
Accrued liabilities and other reserves		2.9			1.5
Inventory reserves and intercompany profit elimination		14.5			13.1
Post retirement benefit obligation		3.0			2.7

Subtotal gross deferred tax assets		23.7			21.6
Valuation allowance		(2.3	)		(2.5	)

Net deferred tax assets		21.4			19.1

Gross deferred tax liabilities:
Property and equipment		33.6			38.0
Intangible assets		6.3			3.8
Reserve for unremitted foreign earnings		6.5			6.5

Gross deferred tax liabilities		46.4			48.3

Total net deferred tax liability	$	25.0		$	29.2

The total net deferred tax liability at December 31, 2004 is comprised of $20.7 million of net current tax assets and $45.7 million net noncurrent deferred tax liabilities.

The Company has undistributed earnings of foreign subsidiaries, as calculated under the laws of the jurisdiction in which the foreign subsidiary is located, of approximately $121.8 million at December 31, 2004. If such earnings were repatriated, foreign withholding taxes of approximately $4.8 million would result. The Company has made provision for additional taxes on the anticipated repatriation of certain earnings from its foreign subsidiaries. Undistributed earnings of its foreign subsidiaries in excess of the amount already provided are considered permanently reinvested. It is not practical to determine the amount of federal income taxes, if any, that might become due in the event that the balance of such earnings were to be distributed. The

F-18

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Company has not reevaluated its position with respect to the indefinite reinvestment of foreign earnings to take into account the possible election of the repatriation provisions contained in the American Jobs Creation Act of 2004.

At December 31, 2004 the Company has approximately $3.2 million of foreign net operating loss carryforwards, the majority of which have a seven year life. The Company has a valuation allowance of $0.5 million against these net operating losses as the Company believes that the corresponding deferred tax asset may not be fully realizable.

As of December 31, 2004, the Internal Revenue Service was in the process of examining the Company’s income tax return for the year 2002. In addition, the Company believes it has adequately provided for any reasonably foreseeable outcome related to these matters. The Company is currently engaged in tax audits in various foreign tax jurisdictions. The years covered by each audit vary considerably among legal entities. Assessments, if any, are not expected to have a material adverse effect on the financial statements.

Because of the number of tax jurisdictions in which the Company operates, its effective tax rate can fluctuate as operations and the local country tax rates fluctuate. The Company is also subject to audits by federal, state and foreign jurisdictions which may result in proposed assessments. The Company’s future tax provision will reflect any favorable or unfavorable adjustments to its estimated tax liabilities when resolved. The Company is unable to predict the outcome of these matters, however, management believes that none of these matters will have a material adverse effect on the results of operations or financial condition of the Company.

In October 2004, the American Jobs Creation Act of 2004 (the “Jobs Act”) was signed into law which introduced a special one-time dividends received deduction on the repatriation of foreign earnings to a U.S. taxpayer (repatriation provision), provided certain criteria are met. The Act provides for a special one-time deduction of 85 percent of certain foreign earnings that are repatriated in either the Company’s last tax year that began before the enactment date, or the first tax year that begins during the one-year period beginning on the date of enactment. The maximum amount of the Company’s foreign earnings that qualify for temporary deduction is $121.8 million.

The Company is in the process of evaluating whether it will repatriate foreign earnings under the repatriation provisions of the Jobs Act, and if so, the amount that will be repatriated. The range of reasonably possible amounts that the Company is considering for repatriation, which would be eligible for the temporary deduction, is zero to $121.8 million. The Company is awaiting the issuance of further regulatory guidance and passage of statutory technical corrections with respect to certain provisions in the Jobs Act prior to determining the amounts it will repatriate. The Company expects to determine the amounts and sources of foreign earnings to be repatriated, if any, in 2005.

The Company is not yet in a position to determine the impact of a qualifying repatriation, should it choose to make one, on its income tax expense for 2005, the amount of its indefinitely reinvested foreign earnings, the range of income tax effects or the amount of its deferred tax liability with respect to foreign earnings.

8.	Long-term Debt

At December 31, long-term debt consists of the following (in millions):


	2004			2003
$200.0 million Senior Notes, interest at 7.25% payable semiannually, principal due on May 1, 2011	$	201.0		$	201.2
$100.0 million Senior Notes, interest at 7.5% payable semiannually, principal due on February 15, 2008		96.1			95.3
$150.0 million Senior Notes, interest at 5.5% payable semiannually, principal due on November 19, 2012		149.4			149.3
Other		15.3			11.2

Total debt		461.8			457.0
Less: Current maturities		(3.7	)		(6.5	)

Long-term debt	$	458.1		$	450.5

Principal payments of long-term debt for years subsequent to 2005 are as follows (in millions):


2006	$	4.2
2007		1.7
2008		97.2
2009		1.2
Thereafter		353.8

	$	458.1

F-19

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Senior Notes

On September 30, 2004, the Company entered into supplemental indentures with The Bank of New York Trust Company, N.A., as trustee, relating to its 7.5% Senior Notes due 2008, its 7.25% Senior Notes due 2011, and its 5.5% Senior Notes due 2012 which released the guarantee on these notes by each of the material subsidiaries of the Company.

Revolver Facility

Other

Other debt includes $12.7 million in promissory notes due to former owners of businesses acquired who remain employed by the Company.

9.	Retirement and Other Benefit Plans

During the periods reported, substantially all the Company’s U.S. employees were covered by defined contribution retirement plans. The Company also has a deferred compensation plan for its highly compensated employees to permit retirement contributions in excess of the statutory limits. Employees may voluntarily contribute up to 25% of compensation, as defined, to these plans. The participants’ contributions were matched by the Company up to a maximum of 4% of compensation. Under these plans, Company cash contributions were approximately $6.0 million, $6.0 million, and $5.1 million, in 2004, 2003, and 2002, respectively.

The Company has four major unfunded post-retirement benefit plans. These plans include the Supplemental Executive Retirement Plan (“SERP”), the Retiree Medical Plan, and two German Pension Plans. The following is information regarding each plan:

Supplemental Executive Retirement Plan

For certain executives, the Company has a supplemental defined benefits plan providing retirement and death benefits. All participants become fully vested with full service credit upon a change in control or become fully vested with 10 years of service. The discount rate for this plan was 6.0% at December 31, 2004 and 6.5% at December 31, 2003.

Net periodic post-retirement benefit costs related to the SERP includes the following components (in millions):


	2004		2003		2002
Service costs	$	0.3	$	0.3	$	0.2
Interest costs		0.6		0.5		0.6
Amortization of prior service costs		0.2		0.2		0.2

	$	1.1	$	1.0	$	1.0

F-20

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table sets forth the change in benefit obligation of the Company’s SERP (in millions):


	2004			2003
Benefit obligation at beginning of year	$	9.4		$	9.8
Service costs		0.3			0.3
Interest costs		0.6			0.5
Actuarial loss (gains)		0.4			(0.9	)
Benefit paid		(0.2	)		(0.3	)

Benefits obligation at end of year	$	10.5		$	9.4

Benefit obligation at end of year	$	10.5		$	9.4
Unrecognized actuarial loss		(0.1	)		0.3
Unrecognized prior service cost		(1.8	)		(2.0	)

Accrued post-retirement benefit obligation	$	8.6		$	7.7

Retiree Medical Plan

For certain former employees who retired prior to December 31, 1993 and current executive officers of the Company upon their retirement, healthcare and life insurance benefits are provided through insurance companies. The assumed weighted-average annual rate of increase in the per capita cost of covered benefits is 10.0% for 2005 and is assumed to decrease gradually to 5.0% for 2010 and remain at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. For example, increasing the assumed health care cost trend rates by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 2004, by $753,752 and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 2004 by $50,878. The weighted-average discount rate used in determining the accumulated postretirement benefit obligation was 6.0% at December 31, 2004 and 6.75% at December 31, 2003.

Net periodic postretirement benefit cost related to the retiree medical plan includes the following components (in millions):


	2004			2003			2002
Interest cost	$	0.6		$	0.8		$	0.8
Amortization of transition obligation		0.8			0.8			0.8
Amortization of unrecognized gain		(0.6	)		(0.3	)		(0.4	)

	$	0.8		$	1.3		$	1.2

The following table sets forth the change in benefit obligation of the Company’s unfunded postretirement benefit plan (in millions):


	2004			2003
Benefit obligation at beginning of year	$	8.6		$	11.9
Interest cost		0.6			0.8
Benefits paid		(1.0	)		(1.0	)
Actuarial loss (gain)		0.8			(3.1	)

Benefit obligation at end of year	$	9.0		$	8.6

Benefit obligation at end of year	$	9.0		$	8.6
Unrecognized actuarial loss		5.1			6.5
Unrecognized transition obligation		(6.1	)		(6.9	)

Accrued post-retirement benefit obligation	$	8.0		$	8.2

German Pension Plans

The Company has two defined benefit pension plans covering substantially all full-time employees in Germany. Plan benefits are based on years of service and employee compensation for the last three years of service. The plans are unfunded and benefit payments are made directly by the Company. Pension expense includes the following components for the fiscal years ending December 31 (in millions):


	2004		2003		2002
Service cost	$	0.4	$	0.4	$	0.3
Interest cost		1.1		0.9		0.7
Net amortization		—		—		(0.2	)

Pension expense	$	1.5	$	1.3	$	0.8

F-21

VARCO INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table sets forth the amounts recognized in the Company’s consolidated balance sheets and reconciles the projected benefit obligation from the beginning of the year to the end of the year (in millions):


	2004			2003
Projected benefit obligation at beginning of year	$	13.5		$	10.2
Service cost		0.4			0.4
Interest cost		1.1			0.9
Benefits paid		(0.4	)		(0.4	)
Change in discount rates		1.8			—
Exchange rate change

Filing Compare · VARCO INTERNATIONAL INC /DE/