TTI 10-K Fiscal year ended Dec. 31, 2010

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON D.C. 20549

FORM 10-K

(MARK ONE)

[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010

OR

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO .

COMMISSION FILE NUMBER 1-13455

TETRA Technologies, Inc.

(EXACT NAME OF THE REGISTRANT AS SPECIFIED IN ITS CHARTER)

DELAWARE	74-2148293
(STATE OR OTHER JURISDICTION OF	(I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION)	IDENTIFICATION NO.)
24955 INTERSTATE 45 NORTH
THE WOODLANDS, TEXAS	77380
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)	(ZIP CODE)
REGISTRANT’S TELEPHONE NUMBER, INCLUDING AREA CODE: (281) 367-1983

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE A CT:
COMMON STOCK, PAR VALUE $.01 PER SHARE	NEW YORK STOCK EXCHANGE
(TITLE OF CLASS)	(NAME OF EXCHANGE ON WHICH REGISTERED)
RIGHTS TO PURCHASE SERIES ONE
JUNIOR PARTICIPATING PREFERRED STOCK	NEW YORK STOCK EXCHANGE
(TITLE OF CLASS)	(NAME OF EXCHANGE ON WHICH REGISTERED)
S ECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE

INDICATE BY CHECK MARK IF THE REGISTRANT IS A WELL-KNOWN SEASONED ISSUER (AS DEFINED IN RULE 405 OF THE SECURITIES ACT). YES [ X ]   NO [   ]

INDICATE BY CHECK MARK IF THE REGISTRANT IS NOT REQUIRED TO FILE REPORTS PURSUANT TO SECTION 13 OR SECTION 15(d) OF THE ACT. YES [   ]   NO [ X ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS) AND (2) HAS BEEN SUBJECT TO SUCH FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES [ X ]   NO [   ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT HAS SUBMITTED ELECTRONICALLY AND POSTED ON ITS CORPORATE WEB SITE, IF ANY, EVERY INTERACTIVE DATA FILE REQUIRED TO BE SUBMITTED AND POSTED PURSUANT TO RULE 405 OF REGULATION S-T DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO SUBMIT AND POST SUCH FILES). YES  [ X ]   NO [   ]

INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT’S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS FORM 10-K. [   ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A LARGE ACCELERATED FILER, AN ACCELERATED FILER, A NON-ACCELERATED FILER, OR A SMALLER REPORTING COMPANY. SEE THE DEFINITIONS OF “LARGE ACCELERATED FILER,” “ACCELERATED FILER,” AND “SMALLER REPORTING COMPANY”  IN RULE  12b-2 OF THE EXCHANGE ACT. (CHECK ONE):

LARGE ACCELERATED FILER [ X ]

ACCELERATED FILER [   ]

NON-ACCELERATED FILER [   ]

SMALLER REPORTING COMPANY [   ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A SHELL COMPANY (AS DEFINED IN RULE 12b-2 OF THE EXCHANGE ACT). YES [   ]  NO [ X ]

THE AGGREGATE MARKET VALUE OF COMMON STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT WAS $668,609,042 AS OF JUNE 30, 2010, THE LAST BUSINESS DAY OF THE REGISTRANT’S MOST RECENTLY COMPLETED SECOND FISCAL QUARTER.

N UMBER OF SHARES OUTSTANDING OF THE ISSUER’S COMMON STOCK AS OF FEBRUARY 25, 2011 WAS 76,598,911 SHARES.

DOCUMENTS INCORPORATED BY REFERENCE

P ART III INFORMATION IS INCORPORATED BY REFERENCE TO THE REGISTRANT’S PROXY STATEMENT FOR ITS ANNUAL MEETING OF STOCKHOLDERS TO BE HELD MAY 3, 2011 TO BE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION WITHIN 120 DAYS OF THE END OF THE REGISTRANT’S FISCAL YEAR.

TABLE OF CONTENTS

	Part I
Item 1.	Business	1
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	27
Item 2.	Properties	27
Item 3.	Legal Proceedings	32
Item 4.	[Removed and Reserved]	33
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and
	Issuer Purchases of Equity Securities	34
Item 6.	Selected Financial Data	36
Item 7.	Management’s Discussion and Analysis of Financial Condition
	and Results of Operation	37
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	64
Item 8.	Financial Statements and Supplementary Data	65
Item 9.	Changes in and Disagreements with Accountants on Accounting
	and Financial Disclosure	65
Item 9A.	Controls and Procedures	65
Item 9B.	Other Information	65
	Part III
Item 10.	Directors, Executive Officers, and Corporate Governance	66
Item 11.	Executive Compensation	66
Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	66
Item 13.	Certain Relationships and Related Transactions, and Director Independence	66
Item 14.	Principal Accounting Fees and Services	66
	Part IV
Item 15.	Exhibits, Financial Statement Schedules	67

TETRA Arapaho	Derrick barge with 800-ton capacity crane
TETRA DB-1	Derrick barge with 615-ton capacity crane
Epic Explorer	210-foot dive support vessel with saturation diving system
Epic Seahorse	210-foot dive support vessel

In addition, the Adams Challenge is under chartered lease arrangement by the Offshore Division through 2011. The Adams Challenge is a 280-foot dynamically positioned dive support vessel with a 1,000-foot saturation diving system.

See below for a discussion of the Offshore Division’s oil and gas property assets.

Production Enhancement Division

The Production Enhancement Division conducts its operations through thirteen production testing service centers (twelve of which are leased) in the U.S. located in Texas, Louisiana, and Pennsylvania. In addition, the Production Testing segment has leased facilities in Brazil, Mexico, Libya, Egypt, Bahrain, India, United Arab Emirates, and Saudi Arabia. Compressco’s facilities include an owned fabrication facility and a leased headquarters facility in Oklahoma, a leased fabrication facility in Alberta, Canada, a leased service and sales facility in New Mexico, three leased service facilities in California, Mexico, and Argentina, and six sales offices in Oklahoma, Texas, Colorado, New Mexico, Louisiana, and Canada.

Corporate

Our headquarters are located in The Woodlands, Texas, in our 153,000 square foot office building, which is located on 2.635 acres of land. In addition, we own a 20,000 square foot technical facility to service our Fluids Division operations.

Oil and Gas Properties

The following tables show, for the periods indicated, reserves and operating information related to our Maritech subsidiary’s oil and gas interests in developed and undeveloped leases, all of which are located in the U.S. Gulf Coast region. Maritech’s oil and gas operations are a separate segment included within our Offshore Division.

See also “Note R – Supplemental Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements for additional information.

Oil and Gas Reserves

Through our Maritech subsidiary, we employ full-time, experienced reservoir engineers and geologists, who are responsible for determining proved oil and gas reserves in conformance with guidelines established by the SEC. These SEC guidelines were revised effective with the December 31, 2009, information. Reserve estimates were prepared by Maritech engineers, based upon their interpretation of production performance data and geologic interpretation of sub-surface information derived from the drilling of wells. In accordance with Maritech’s documented oil and gas reserve policy as prescribed by our Board of Directors, the preparation of these reserve estimates is subject to Maritech’s system of internal control, whereby key inputs in preparing reserve estimates, such as oil and natural gas pricing data, oil and gas property ownership interest percentages, and data regarding levels of operating, development, and abandonment costs, are reviewed by Maritech personnel outside of the reserve engineering department. Reserve estimates are also reviewed by Maritech’s President, who is also a licensed professional engineer and has overall responsibility for overseeing the preparation of the proved reserve estimates. In addition to the complete analysis and review by Maritech’s internal reservoir engineers, independent petroleum engineers and geologists performed reserve audits of approximately 92.2% of our proved reserve volumes as of December 31, 2010. The use of the term “reserve audit” is intended only to refer to the collective application of the engineering and geologic procedures that the independent petroleum engineering firms were engaged to perform and may be defined and used differently by other companies.

A reserve audit is the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserve quantities. In performing a reserve audit, an independent petroleum engineering firm meets with our technical staff to collect all necessary geologic, geophysical, engineering, and economic data, and performs an independent reserve evaluation. The reserve audit of our oil and gas reserves involves the rigorous examination of our technical evaluation, as well as the interpretation and extrapolation of well information such as flow rates, reservoir pressure declines, and other technical information and measurements. Maritech’s internal reservoir engineers interpret this data to determine the nature of the reservoir and, ultimately, the quantity of proved oil and gas reserves attributable to the specific property. Our proved reserves, as reflected in this Annual Report, include only quantities that Maritech expects to recover commercially using current technology, prices, and costs, within

existing economic conditions, operating methods, and governmental regulation. While Maritech can be reasonably certain that the proved reserves are economically producible, the timing and ultimate recovery can be affected by a number of factors, including completion of development projects, reservoir performance, regulatory approvals, and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir, or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also occur associated with significant changes in development strategy, oil and gas prices, or the related production equipment/facility capacity. Maritech’s independent petroleum engineers also examined the reserve estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a), Staff Accounting Bulletin No. 113, and subsequent SEC staff interpretations and guidance.

Maritech engaged Ryder Scott Company, L.P. and DeGolyer and MacNaughton to perform the reserve audits of a portion of our oil and gas reserves as of December 31, 2010, 2009, and 2008. Both Ryder Scott Company, L.P. and DeGolyer and MacNaughton are established oil and gas reservoir engineering firms providing engineering services worldwide. The staffs of both of these firms, including the personnel assigned to the reserve audits of Maritech’s reserve estimates, include licensed reservoir engineers experienced in performing these services. In the conduct of these reserve audits, these independent petroleum engineering firms did not independently verify the accuracy and completeness of information and data furnished by Maritech with respect to property interests owned, oil and gas production and well tests from examined wells, or historical costs of operation and development; however, they did verify product prices, geological structural and isopach maps, along with reservoir data such as well logs, core analyses, and pressure measurements. If, in the course of the examinations, a matter of question arose regarding the validity or sufficiency of any such information or data, the independent petroleum engineering firms did not accept such information or data until all questions relating thereto were satisfactorily resolved. Furthermore, in instances where decline curve analysis was not adequate in determining proved producing reserves, the independent petroleum engineering firms performed volumetric analysis, which included the analysis of geologic, reservoir, and fluids data. Proved undeveloped reserves were analyzed by volumetric analysis, which takes into consideration recovery factors relative to the geology of the location and similar reservoirs. Where applicable, the independent petroleum engineering firms examined data related to well spacing, including potential drainage from offsetting producing wells, in evaluating proved reserves of undrilled well locations.

The reserve audit performed by Ryder Scott Company, L.P. included certain properties selected by Maritech, including all of our significant properties described above, excluding the Main Pass Area properties, and represented approximately 70.6% of our total proved oil and gas reserve volumes as of December 31, 2010. The reserve audit performed by DeGolyer and MacNaughton included the Main Pass Area properties acquired in December 2007 and represented approximately 21.6% of our total proved oil and gas reserve volumes as of December 31, 2010. Ryder Scott Company, L.P. states in its audit report that they believe that the overall procedures and methodologies utilized by Maritech in preparing their estimates of proved reserves as of December 31, 2010 comply with current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Maritech were, in the aggregate, reasonable within the established audit tolerance guidelines of 10% as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE). DeGolyer and MacNaughton states in its audit report that the information relating to Maritech’s estimated proved reserves of oil, condensate, and natural gas contained in this Annual Report have been prepared in accordance with applicable accounting standards and SEC regulations. There were no limitations imposed or encountered by Maritech or the independent petroleum engineers in the preparation of our estimated reserves or in the performance of the reserve audits by the independent petroleum engineers.

Reserve information is prepared in accordance with guidelines established by the SEC. All of Maritech’s reserves are located in U.S. state and federal offshore waters in the Gulf of Mexico region and onshore Texas and Louisiana. The following table sets forth information with respect to our estimated proved reserves as of December 31, 2010:

Summary of Oil and Gas Reserves as of December 31, 2010
Based on Average Fiscal Year Prices
Reserves category		Oil				NGL				Natural Gas				Total
		(MBbls)				(MBbls)				(MMcf)				(MBOE)
Proved reserves
Developed			5,760				415				24,795				10,307
Undeveloped			1,012				74				790				1,218
Total proved reserves			6,772				489				25,585				11,525

Maritech’s proved undeveloped reserves as of December 31, 2010, represent approximately 10.6% of Maritech’s total proved reserves. Proved undeveloped reserves represented approximately 12.4% of Maritech total proved reserves as of December 31, 2009. During 2010, Maritech expended approximately $4.6 million of its development costs to convert approximately 55.9% of its proved undeveloped reserves at the beginning of the year to proved developed reserves. All of Maritech’s proved undeveloped reserves as of December 31, 2010, have been classified as proved undeveloped for less than five years. Maritech has historically developed its proved undeveloped reserves over a reasonable period of time and anticipates it will do so in the future, utilizing our future operating cash flows, available working capital, and, if necessary, long-term borrowings. All of Maritech’s proved undeveloped reserves as of December 31, 2010, are scheduled to be developed prior to December 31, 2015.

For additional information regarding estimates of oil and gas reserves, including estimates of proved and proved developed reserves, the standardized measure of discounted future net cash flows, and the changes in discounted future net cash flows, see “Note R – Supplemental Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements.

Maritech is not required to file, and has not filed on a recurring basis, estimates of its total proved net oil and gas reserves with any U.S. or non-U.S. governmental regulatory authority or agency other than the Department of Energy (DOE) and the SEC. The estimates furnished to the DOE have been consistent with those furnished to the SEC, however, they are not necessarily directly comparable, due to special DOE reporting requirements. In no instance have gross reserve volume information used to prepare the estimates for the DOE differed by more than five percent from the corresponding estimates reflected in total reserves reported to the SEC.

Production Information

The table below sets forth information related to production, average sales price, and average production cost per unit of oil and gas produced during 2010, 2009, and 2008:

		Year Ended December 31,
		2010				2009				2008
Production:
Natural gas (Mcf)			7,065,258				10,449,366				10,988,840
NGL (Bbls)			132,191				105,479				82,520
Oil (Bbls)			1,360,126				1,219,336				1,384,101
Revenues:
Natural Gas		$	60,416,000			$	87,905,000			$	99,901,000
NGL (Bbls)			6,003,000				3,308,000				5,917,000
Oil			131,422,000				82,978,000				101,362,000
Total		$	197,841,000			$	174,191,000			$	207,180,000
Average realized unit prices and production costs:
Natural gas (per Mcf)		$	8.55			$	8.41			$	9.09
NGL (per Bbl)		$	45.41			$	31.37			$	71.70
Oil (per Bbl)		$	96.62			$	68.05			$	73.23
Production cost per equivalent barrel		$	26.62			$	25.80			$	27.18
Depletion cost per equivalent barrel		$	27.60			$	25.96			$	25.14

Realized unit prices include the impact of hedge commodity swap contracts. Production cost per equivalent barrel excludes the impact of storm repair and insurance-related costs and recoveries, which were charged or credited to operations during each of the years presented, with approximately $8.2 million and $8.5 million being charged in 2009 and 2008, respectively. Equivalent barrel (BOE) information is calculated assuming six Mcf of gas is equivalent to one barrel of oil. Insurance recoveries during 2010 and 2009 totaled approximately $2.5 million and $45.4 million, respectively, and are excluded from production cost per equivalent barrel for the year. The 2008 production cost per equivalent barrel was also increased due to the impact of hurricanes, which resulted in significant properties being shut-in during the last four months of 2008 and during much of 2009. Depletion cost per equivalent barrel excludes the impact of dry hole costs and property impairments.

Acreage and Productive Wells

At December 31, 2010, our Maritech subsidiary owned interests in the following oil and gas wells and acreage:

	Productive Gross							Productive Net							Developed							Undeveloped
	Wells							Wells							Acreage							Acreage
State/Area	Oil				Gas			Oil				Gas			Gross				Net			Gross				Net
Louisiana Onshore		12				1			1.1				0.1			900				450			5,133				2,133
Louisiana Offshore		46				10			46.0				10.0			15,819				15,474			6,729				6,317
Texas Onshore		7				-			1.4				-			1,331				450			-				-
Texas Offshore		-				-			-				-			1,440				190			-				-
Federal Offshore		37				54			17.4				18.5			231,281				110,451			59,988				46,611
Total		102				65			65.9				28.6			250,771				127,015			71,850				55,061

The majority of Maritech’s oil and gas properties are held by production. Leases covering undeveloped acreage other than acreage held by production have expiration terms ranging from 2011 through 2015. The following table sets forth the expiration amounts of our gross and net undeveloped acreage as of December 31, 2010:

																															Held by
	2011						2012						2013						2014						2015						Production
State/Area	Gross			Net			Gross			Net			Gross			Net			Gross			Net			Gross			Net			Gross			Net
Louisiana Onshore		265			133			1,223			582			689			250			2,643			1,012			313			156			-			-
Louisiana Offshore		4,417			4,417			-			-			1,282			1,282			207			207			-			-			823			411
Texas Offshore		-			-			-			-			-			-			-			-			-			-			-			-
Federal Offshore		-			-			-			-			19,521			16,641			-			-			6,250			6,250			34,217			23,720
Total		4,682			4,550			1,223			582			21,492			18,173			2,850			1,219			6,563			6,406			35,040			24,131

Maritech has no significant delivery commitments with regard to its future oil and gas production.

Drilling Activity

During 2010, Maritech participated in the drilling of 6 gross development wells (4.32 net wells) and two gross exploratory wells (1.5 net wells), 7 of which were productive. During 2009, Maritech participated in the drilling of 2 gross development wells (1.12 net wells) and one gross exploratory well (0.5 net wells), all of which were productive. Maritech participated in the drilling of 10 gross development wells (4.3 net wells) during 2008, two of which were unproductive. As of December 31, 2010, there were no wells in the process of being drilled.

Significant Oil and Gas Properties

The following table provides a brief description as of December 31, 2010, of Maritech’s most significant oil and gas properties which individually represent fields that contain 15% or more of Maritech’s total proved reserves on a barrels-of-oil-equivalent (BOE) basis:

	Net Total
	Proved			Net Proved												Productive
	Reserves			Reserves Mix												Gross			Developed			Undeveloped			Working				Production
	(MBOE)			Oil%				NGL%				Gas%				Wells			Acreage			Acreage			Interest %				Status
Timbalier Bay Area		5,504			62	%			4	%			34	%			52			8,351			5,906			100	%		Producing
Main Pass Area		568			31	%			7	%			62	%			12			66,171			9,989			12%-100	%		Producing
East Cameron 328		1,785			92	%			-				8	%			6			5,000			-			50	%		Producing

Production information for each of these most significant properties during the three years ended December 31, 2010, is as follows:

	Year Ended December 31,
	2010									2009									2008
	Oil			NGL			Natural Gas			Oil			NGL			Natural Gas			Oil			NGL			Natural Gas
	(MBbls)			(MBbls)			(MMcf)			(MBbls)			(MBbls)			(MMcf)			(MBbls)			(MBbls)			(MMcf)
Timbalier Bay Area		555			25			912			526			23			1,289			653			53			3,500
Main Pass Area		87			35			2,362			74			40			5,715			36			2			3,251
East Cameron 328		213			-			132			52			-			48			250			-			149

Average realized unit prices and production costs for each of these fields were approximately equal to Maritech’s overall unit prices and costs, as all of Maritech’s production is located in the Gulf of Mexico region.

Item 3. Legal Proceedings.

We are named defendants in several lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not reasonably expect these matters to have a material adverse impact on the financial statements.

Class Action Lawsuit

Between March 27, 2008, and April 30, 2008, two putative class action complaints were filed in the United States District Court for the Southern District of Texas (Houston Division) against us and certain former officers by certain stockholders on behalf of themselves and other stockholders who purchased our common stock between January 3, 2007, and October 16, 2007. The complaints assert claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated thereunder. On May 8, 2008, the Court consolidated these complaints as In re TETRA Technologies, Inc. Securities Litigation, No. 4:08-cv-0965 (S.D. Tex.). On June 16, 2010, defendants and plaintiff’s counsel reached a settlement agreement whereby all claims against defendants will be released in exchange for a payment of $8.25 million, which was subsequently paid by our insurers. On September 29, 2010, the Court approved the settlement and entered the Order and Final Judgment terminating the class action lawsuit.

Derivative Lawsuit

Between May 28, 2008 and June 27, 2008, two petitions were filed by alleged stockholders in the District Courts of Harris County, Texas, 133 rd and 113 th Judicial Districts, purportedly on our behalf. The suits name our directors and certain officers as defendants. The factual allegations in these lawsuits mirror those in the class action lawsuit, and the claims are for breach of fiduciary duty, unjust enrichment, abuse of control, gross mismanagement, and waste of corporate assets. The petitions seek disgorgement, costs, expenses, and unspecified equitable relief. On September 22, 2008, the 133 rd District Court consolidated these complaints as In re TETRA Technologies, Inc. Derivative Litigation, Cause No. 2008-23432 (133 rd Dist. Ct., Harris County, Tex.), and appointed Thomas Prow and Mark Patricola as Co-Lead Plaintiffs. This lawsuit was

stayed by agreement of the parties pending the Court’s ruling on our motion to dismiss the federal class action. On September 8, 2009, the plaintiffs in this state court action filed a consolidated petition which makes factual allegations similar to the surviving allegations in the federal lawsuit. On April 19, 2010, the Court granted our motion to abate the suit, based on plaintiff’s inability to demonstrate derivative standing. On June 8, 2010, we received a letter from plaintiff’s counsel demanding that our board of directors take action against the defendants named in the previously filed derivative lawsuit. Our board is currently evaluating the best course of action to take in response to the demand letter.

At this stage, it is impossible to predict the outcome of the derivative lawsuit or its impact upon us. We continue to believe that the allegations made in the derivative lawsuit are without merit, and we intend to continue to seek dismissal of and vigorously defend against this lawsuit. While a successful outcome cannot be guaranteed, we do not reasonably expect this lawsuit to have a material adverse effect.

Environmental Proceedings

One of our subsidiaries, TETRA Micronutrients, Inc. (TMI), previously owned and operated a production facility located in Fairbury, Nebraska. TMI is subject to an Administrative Order on Consent issued to American Microtrace, Inc. (n/k/a/ TETRA Micronutrients, Inc.) in the proceeding styled In the Matter of American Microtrace Corporation , EPA I.D. No. NED00610550, Respondent, Docket No. VII-98-H-0016, dated September 25, 1998 (the Consent Order), with regard to the Fairbury facility. TMI is liable for future remediation costs and ongoing environmental monitoring at the Fairbury facility under the Consent Order; however, the current owner of the Fairbury facility is responsible for costs associated with the closure of that facility.

In August of 2009, the Environmental Protection Agency (EPA), pursuant to Sections 308 and 311 of the Clean Water Act (CWA), served a request for information with regard to a release of zinc bromide that occurred from one of our transport barges on the Mississippi River on March 11, 2009. We timely filed a response to that request for information in August 2009. In January 2010, the EPA issued a Notice of Violation and Opportunity to Show Cause related to the spill. We met with the EPA in April 2010 to discuss potential violations and penalties. It has been agreed that no injunctive relief will be required. We have finalized a joint stipulation of settlement with the EPA whereby we are responsible for a penalty of $487,000, which has been submitted to the Department of Justice for approval. We expect to pay this penalty amount during the second quarter of 2011 and expect the full amount to be covered by insurance.

Item 4. [Removed and Reserved.]

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Repurchases of Equity Securities.

Price Range of Common Stock

Our common stock is traded on the New York Stock Exchange under the symbol “TTI.” As of February 25, 2011, there were approximately 11,558 holders of record of the common stock. The following table sets forth the high and low sale prices of the common stock for each calendar quarter in the two years ended December 31, 2010, as reported by the New York Stock Exchange.

		High				Low
2010
First Quarter		$	13.49			$	8.95
Second Quarter			14.64				8.20
Third Quarter			11.10				8.00
Fourth Quarter			12.14				9.41
2009
First Quarter		$	6.28			$	1.94
Second Quarter			10.44				3.01
Third Quarter			10.74				6.79
Fourth Quarter			11.62				8.70

Market Price of Common Stock

The following graph compares the five-year cumulative total returns of our common stock, the Standard & Poor’s 500 Composite Stock Price Index (S&P 500) and the Philadelphia Oil Service Sector Index (PHLX Oil Service Sector), assuming $100 invested in each stock or index on December 31, 2005, all dividends reinvested, and a fiscal year ending December 31. This information shall be deemed furnished, and not filed, in this Form 10-K and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934 as a result of this furnishing, except to the extent we specifically incorporate it by reference.

Dividend Policy

We have never paid cash dividends on our common stock. We currently intend to retain earnings to finance the growth and development of our business. Any payment of cash dividends in the future will depend upon our financial condition, capital requirements, and earnings, as well as other factors the Board of Directors may deem relevant. We declared a dividend of one Preferred Stock Purchase Right per share of

common stock to holders of record at the close of business on November 6, 1998. See “Note T – Stockholders’ Rights Plan” in the Notes to Consolidated Financial Statements attached hereto for a description of such Rights. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Liquidity and Capital Resources” for a discussion of potential restrictions on our ability to pay dividends.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases may be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit. During 2004 through 2005, we repurchased 340,950 shares of our common stock pursuant to the repurchase program at a cost of approximately $5.7 million. There were no repurchases made during 2006, 2007, 2008, 2009, or 2010 pursuant to the repurchase program. Shares repurchased during the fourth quarter of 2010 other than pursuant to our repurchase program are as follows:

Period		Total Number of Shares Purchased				Average Price Paid per Share				Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)				Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Publicly Announced Plans or Programs (1)
Oct 1 - Oct 31, 2010			2,265	(2)		$	10.40				-			$	14,327,000
Nov 1 - Nov 30, 2010			-				-				-			$	14,327,000
Dec 1 - Dec 31, 2010			118	(2)		$	11.18				-			$	14,327,000
Total			2,383								-			$	14,327,000

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(1)	In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases may be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit.
(2)	Shares we received in connection with the vesting of certain employee restricted stock. These shares were not acquired pursuant to the stock repurchase program.

Item 6. Selected Financial Data.

The following tables set forth our selected consolidated financial data for the years ended December 31, 2010, 2009, 2008, 2007, and 2006. The selected consolidated financial data does not purport to be complete and should be read in conjunction with, and is qualified by, the more detailed information, including the Consolidated Financial Statements and related Notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operation” appearing elsewhere in this report. Please read “Item 1A. Risk Factors” beginning on page 13 for a discussion of the material uncertainties which might cause the selected consolidated financial data not to be indicative of our future financial condition or results of operations. In December 2007, we sold our process services operations. In 2006, we made the decision to discontinue our Venezuelan fluids and production testing operations. In 2003, we made the decision to discontinue the operations of our Norwegian process services operations. During 2000, we commenced our exit from the micronutrients business. Accordingly, we have reflected each of the above operations as discontinued operations. During 2008, Maritech acquired certain oil and gas properties. During 2007, we completed the acquisition of two service companies and Maritech acquired certain oil and gas properties. During 2006, we completed the acquisitions of the operations of Epic Divers, Inc., Beacon Resources, LLC, and a heavy lift barge. During 2010, we recorded significant impairments of our oil and gas properties, a dive support vessel, and a calcium chloride manufacturing plant as well as significant charges to earnings associated with adjustments to Maritech’s decommissioning liabilities. During 2008, we recorded significant impairments of oil and gas properties, goodwill, and other long-lived assets. During 2007, we recorded significant impairments of our oil and gas properties. These acquisitions, dispositions, and impairments significantly impact the comparison of our financial statements for 2010 to earlier years.

		Year Ended December 31,
		2010				2009				2008				2007				2006
		(In Thousands, Except Per Share Amounts)
Income Statement Data
Revenues		$	872,678			$	878,877			$	1,009,065			$	982,483			$	767,795
Gross profit			43,707				213,097				152,001				116,383				252,804
Operating income (loss)			(56,425	)			112,265				(21	)			16,512				160,800
Interest expense			(17,528	)			(13,207	)			(17,557	)			(17,886	)			(13,637	)
Interest income			224				417				779				731				348
Other income (expense), net			(64	)			5,895				12,884				2,805				4,858
Income (loss) before discontinued
operations			(43,325	)			68,807				(9,655	)			1,221				99,880
Net income (loss)		$	(43,718	)		$	68,804			$	(12,136	)		$	28,771			$	101,878
Income (loss) per share, before
discontinued operations (1)		$	(0.57	)		$	0.92			$	(0.13	)		$	0.02			$	1.39
Average shares (1)			75,539				75,045				74,519				73,573				71,631
Income (loss) per diluted share,
before discontinued operations (1)		$	(0.57	)		$	0.91			$	(0.13	)		$	0.02			$	1.33
Average diluted shares (1)			75,539	(2)			75,722	(3)			74,519	(2)			75,921	(4)			74,824

(1)	Net income (loss) per share and average share outstanding information reflects the retroactive impact of a 2-for-1 stock split as of May 15, 2006. The stock split was effected in the form of a stock dividend as of the record date.
(2)	For the years ended December 31, 2008 and 2010, the calculation of average diluted shares outstanding excludes the impact of all of our outstanding stock options, since all were antidilutive due to the net loss for the periods.
(3)	For the year ended December 31, 2009, the calculation of average diluted shares outstanding excludes the impact of 3,185,388 average outstanding stock options that would have been antidilutive.
(4)	For the year ended December 31, 2007, the calculation of average diluted shares outstanding excludes the impact of 716,354 average outstanding stock options that would have been antidilutive.

		December 31,
		2010				2009				2008				2007				2006
		(In Thousands)
Balance Sheet Data
Working capital		$	198,106			$	148,343			$	222,832			$	181,441			$	262,572
Total assets			1,299,628				1,347,599				1,412,624				1,295,536				1,086,190
Long-term debt			305,035				310,132				406,840				358,024				336,381
Decommissioning and other
long-term liabilities			261,438				218,498				277,482				247,543				167,671
Stockholders' equity			516,323				576,494				515,821				447,919				420,380