Edgar Filing: TETRA TECHNOLOGIES INC

tti10q051109.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2009

[ ] 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 registrant as specified in its charter)

Delaware	74-2148293
(State of incorporation)	(I.R.S. Employer Identification No.)

24955 Interstate 45 North
The Woodlands, Texas	77380
(Address of principal executive offices)	(zip code)

(281) 367-1983

(Registrant’s telephone number, including area code)

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 [ ] No [ ]

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 [ ] (Do not check if a smaller reporting company)	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 ]

As of May 1, 2009, there were 75,255,641 shares outstanding of the Company’s Common Stock, $.01 par value per share.

PART I

FINANCIAL INFORMATION

Item 1. Financial Statements.

TETRA Technologies, Inc. and Subsidiaries

Consolidated Statements of Operations

(In Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended March 31,
	2009			2008

Revenues:
Product sales	$	90,658		$	112,225
Services and rentals		104,593			112,931
Total revenues		195,251			225,156

Cost of revenues:
Cost of product sales		48,688			67,184
Cost of services and rentals		66,934			78,036
Depreciation, depletion, amortization and accretion		36,259			37,889
Total cost of revenues		151,881			183,109
Gross profit		43,370			42,047

General and administrative expense		24,569			25,099
Operating income		18,801			16,948

Interest expense, net		3,177			4,433
Other (income) expense, net		(2,511	)		1,183
Income before taxes and discontinued operations		18,135			11,332
Provision for income taxes		6,765			3,978
Income before discontinued operations		11,370			7,354
Income (loss) from discontinued operations, net of taxes		(208	)		(667	)

Net income	$	11,162		$	6,687

Basic net income per common share:
Income before discontinued operations	$	0.15		$	0.10
Income (loss) from discontinued operations		(0.00	)		(0.01	)
Net income	$	0.15		$	0.09

Average shares outstanding		74,925			74,187

Diluted net income per common share:
Income before discontinued operations	$	0.15		$	0.10
Income (loss) from discontinued operations		(0.00	)		(0.01	)
Net income	$	0.15		$	0.09

Average diluted shares outstanding		74,997			75,463

See Notes to Consolidated Financial Statements

TETRA Technologies, Inc. and Subsidiaries

Consolidated Balance Sheets

(In Thousands)

	March 31, 2009			December 31, 2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	12,105		$	3,882
Restricted cash		1,641			2,150
Trade accounts receivable, net of allowances for doubtful
accounts of $3,854 in 2009 and $3,198 in 2008		209,055			225,491
Inventories		112,497			117,731
Derivative assets		56,247			38,052
Prepaid expenses and other current assets		43,993			47,768
Assets of discontinued operations		165			239
Total current assets		435,703			435,313

Property, plant and equipment
Land and building		56,340			23,730
Machinery and equipment		460,427			463,788
Automobiles and trucks		43,644			43,047
Chemical plants		45,353			46,121
Oil and gas producing assets (successful efforts method)		705,841			697,754
Construction in progress		119,175			118,103
		1,430,780			1,392,543
Less accumulated depreciation and depletion		(606,539	)		(585,077	)
Net property, plant and equipment		824,241			807,466

Other assets:
Goodwill		95,196			82,525
Patents, trademarks and other intangible assets, net of accumulated
amortization of $16,568 in 2009 and $15,611 in 2008		15,513			16,549
Derivative assets		33,343			39,098
Other assets		31,382			31,673
Total other assets		175,434			169,845
	$	1,435,378		$	1,412,624

See Notes to Consolidated Financial Statements

TETRA Technologies, Inc. and Subsidiaries

Consolidated Balance Sheets

(In Thousands)

	March 31, 2009			December 31, 2008
	(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Trade accounts payable	$	85,690		$	84,435
Accrued liabilities		133,772			128,033
Liabilities of discontinued operations		23			13
Total current liabilities		219,485			212,481

Long-term debt, net		426,228			406,840
Deferred income taxes		69,370			64,911
Decommissioning and other asset retirement obligations, net		176,564			202,771
Other liabilities		11,102			9,800
		683,264			684,322
Commitments and contingencies

Stockholders' equity:
Common stock, par value $0.01 per share; 100,000,000 shares
authorized; 76,842,924 shares issued at March 31, 2009
and 76,841,424 shares issued at December 31, 2008		768			768
Additional paid-in capital		188,477			186,318
Treasury stock, at cost; 1,587,283 shares held at March 31, 2009
and 1,582,465 shares held at December 31, 2008		(8,845	)		(8,843	)
Accumulated other comprehensive income		46,377			42,888
Retained earnings		305,852			294,690
Total stockholders' equity		532,629			515,821
	$	1,435,378		$	1,412,624

See Notes to Consolidated Financial Statements

TETRA Technologies, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(In Thousands)

(Unaudited)

	Three Months Ended March 31,
	2009			2008
Operating activities:
Net income	$	11,162		$	6,687
Reconciliation of net income to cash provided by operating activities:
Depreciation, depletion, accretion and amortization		35,855			37,889
Impairments of oil and gas properties		404			-
Provision for deferred income taxes		4,759			716
Stock compensation expense		1,884			1,022
Provision for doubtful accounts		602			272
(Gain) loss on sale of property, plant and equipment		(2,522	)		629
Other non-cash charges and credits		1,859			3,290
Excess tax benefit from exercise of stock options		-			(192	)
Equity in (earnings) loss of unconsolidated subsidiary		(97	)		(176	)
Changes in operating assets and liabilities, net of assets acquired:
Accounts receivable		17,249			18,494
Inventories		4,449			(4,868	)
Prepaid expenses and other current assets		21			2,114
Trade accounts payable and accrued expenses		(27,939	)		(14,641	)
Decommissioning liabilities		(8,296	)		(4,895	)
Operating activities of discontinued operations		84			789
Other		382			(508	)
Net cash provided by operating activities		39,856			46,622

Investing activities:
Purchases of property, plant and equipment		(55,570	)		(67,324	)
Proceeds from sale of property, plant and equipment		168			137
Change in restricted cash		509			(28	)
Other investing activities		880			(1,876	)
Net cash used in investing activities		(54,013	)		(69,091	)

Financing activities:
Proceeds from long-term debt obligations		62,450			1,450
Principal payments on long-term debt obligations		(39,950	)		(1,478	)
Proceeds from exercise of stock options		13			431
Excess tax benefit from exercise of stock options		-			192
Net cash provided by financing activities		22,513			595

Effect of exchange rate changes on cash		(133	)		196
Decrease in cash and cash equivalents		8,223			(21,678	)
Cash and cash equivalents at beginning of period		3,882			21,833
Cash and cash equivalents at end of period	$	12,105		$	155

Supplemental cash flow information:
Interest paid	$	3,035		$	4,786
Income taxes paid		2,266			3,176

Supplemental disclosure of non-cash investing and financing activities:
Oil and gas properties acquired through assumption of
decommissioning liabilities	$	-		$	20,236
Adjustment of fair value of decommissioning liabilities
capitalized (credited) to oil and gas properties		2,950			(255	)

See Notes to Consolidated Financial Statements

TETRA Technologies, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

(Unaudited)

NOTE A – BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

We are an oil and gas services and production company with an integrated calcium chloride and brominated products manufacturing operation that supplies feedstocks to energy markets, as well as to other markets. Unless the context requires otherwise, when we refer to “we,” “us,” and “our,” we are describing TETRA Technologies, Inc. and its consolidated subsidiaries on a consolidated basis.

The consolidated financial statements include the accounts of our wholly owned subsidiaries. Investments in unconsolidated joint ventures in which we participate are accounted for using the equity method. Our interests in oil and gas properties are proportionately consolidated. All significant intercompany accounts and transactions have been eliminated in consolidation.

The accompanying unaudited consolidated financial statements have been prepared in accordance with Rule 10-01 of Regulation S-X for interim financial statements required to be filed with the Securities and Exchange Commission (SEC) and do not include all information and footnotes required by generally accepted accounting principles for complete financial statements. However, the information furnished reflects all normal recurring adjustments, which are, in the opinion of management, necessary to provide a fair statement of the results for the interim periods. The accompanying unaudited consolidated financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2008.

Certain previously reported financial information has been reclassified to conform to the current year period’s presentation. The impact of such reclassifications was not significant to the prior year period’s overall presentation.

Cash Equivalents

We consider all highly liquid cash investments with a maturity of three months or less when purchased to be cash equivalents.

Restricted Cash

Restricted cash reflected on our balance sheets as of March 31, 2009 includes funds held by us for a third party’s proportionate obligation in the plugging and abandonment of a particular oil and gas property operated by our Maritech Resources, Inc. subsidiary (Maritech). This cash will remain restricted until such time as the associated plugging and abandonment project is completed, which we expect to occur during the next twelve months.

Inventories

Inventories are stated at the lower of cost or market value and consist primarily of finished goods. Cost is determined using the weighted average method.

Repair Costs and Insurance Recoveries

During the first quarter of 2009, one of our Fluids Division’s transport barges capsized and sank while docked near our West Memphis manufacturing facility, destroying the vessel and the majority of the inventory cargo. The damages associated with the sunken transport barge consist of the cost of recovery efforts, replacement or repair of the barge, and the lost inventory cargo. Total damages associated with the sunken barge are estimated to cost between $4 to $5 million.

During the third quarter of 2008, primarily as a result of Hurricane Ike, Maritech suffered varying levels of damage to the majority of its offshore oil and gas producing platforms. In addition, three of its offshore platforms and one of its inland water production facilities were toppled and/or destroyed. Maritech is the operator of two of the destroyed offshore platforms and the production facility and owns a 10% working interest in the third offshore platform. In addition, certain of our fluids facilities also suffered damage during the 2008 storm.

Remaining hurricane damage repair efforts consist primarily of the well intervention, abandonment, decommissioning, and debris removal associated with destroyed offshore platforms (including three additional offshore platforms which were destroyed by 2005 hurricanes) and the construction of replacement platforms and redrilling of certain destroyed wells. With regard to the six destroyed offshore platforms and remaining destroyed inland water production facility, we have yet to complete the full assessment of the well intervention, abandonment, decommissioning, and debris removal efforts that will be required. Well intervention and abandonment work has been performed on several of the wells associated with the destroyed platforms at a cost of approximately $49.7 million. Well intervention efforts to date have been performed by our Offshore Services segment. We estimate that future well intervention and abandonment efforts associated with the platforms and production facility destroyed in the 2005 and 2008 storms, including efforts to remove debris, reconstruct certain destroyed structures, and redrill certain associated wells, will cost approximately $130 to $180 million net to our interest, before any insurance recoveries. The estimated amount of these future costs are recorded in the period in which such damage occurred, net of expected insurance recoveries, as part of Maritech’s decommissioning liabilities. In addition, we currently estimate that our share of the remaining repairs to the partially damaged platforms will cost from $3 million to $4 million net to our interest and before insurance recoveries, and will be incurred over the next several months.

One of the offshore platforms destroyed in 2008 by Hurricane Ike served a key producing field. We are currently planning to construct a new platform from which we will be able to redrill certain of the wells associated with the destroyed platform in order to restore a portion of the production from this field. The cost to construct the platform and redrill these wells, net of insurance recoveries, will be capitalized as oil and gas properties.

We maintain customary insurance protection which we believe will cover a majority of the damages incurred as well as the expected cost to replace the sunken barge and lost inventory, reconstruct the destroyed platforms, and redrill the associated wells. Such insurance coverage is subject to certain coverage limits, however, and it is possible we could exceed these coverage limits. In addition, with regard to the 2008 hurricanes, the relevant insurance policies provide for deductibles up to $5 million per hurricane. Damages related to Hurricane Gustav were not significant and we do not expect that the Maritech repair costs associated with Hurricane Gustav will exceed this deductible. Damage assessment costs and repair expenses up to the amount of insurance deductibles or not covered by insurance are charged to earnings as they are incurred. For the three month periods ended March 31, 2009 and 2008, we recognized damage related repair expenses of $1.9 million and $0.1 million, respectively.

With regard to repair costs incurred which we believe will qualify for coverage under our various insurance policies, we recognize anticipated insurance recoveries when collection is deemed probable. Any recognition of anticipated insurance recoveries is used to offset the original charge to which the insurance relates. The amount of anticipated insurance recoveries is included either in accounts receivable or as a reduction of Maritech’s decommissioning liabilities in the accompanying consolidated balance sheets.

As discussed further in Note G – Commitments and Contingencies, Insurance Litigation, Maritech incurred well intervention costs related to hurricane damage suffered in 2005, and certain of those costs have not been reimbursed by its insurers. We have reviewed the types of estimated well intervention costs expected to be incurred related to the 2008 hurricanes. Despite our belief that substantially all of these costs in excess of deductibles will qualify for coverage under our current insurance policies, any costs that are similar to the costs that have not been reimbursed following the 2005 storms have been excluded from anticipated insurance recoveries. The changes in anticipated insurance recoveries, including recoveries associated with the sunken barge and other non-hurricane related claims, during the three months ended March 31, 2009 are as follows:

	Three Months Ended
	March 31, 2009
	(In Thousands)

Beginning balance	$	33,591

Activity in the period:
Claim related expenditures		16,766
Insurance reimbursements		(943	)
Contested insurance recoveries		(198	)
Ending balance at March 31, 2009	$	49,216

Anticipated insurance recoveries that have been reflected as a reduction of our decommissioning liabilities were $19.5 million at March 31, 2009 and December 31, 2008. Anticipated insurance recoveries that have been reflected as insurance receivables were $29.7 million and $14.1 million at March 31, 2009 and December 31, 2008, respectively. Uninsured assets that were destroyed during the period are charged to earnings. Repair costs incurred, and the net book value of any destroyed assets which are covered under our insurance policies, are anticipated insurance recoveries which are included in accounts receivable. Repair costs not considered probable of collection are charged to earnings. Insurance recoveries in excess of destroyed asset carrying values and repair costs incurred are credited to earnings when received. During the three months ended March 31, 2009, we received $5.4 million of insurance recoveries associated with the 2005 hurricanes and such amount was credited to earnings during the period. Intercompany profit on repair work performed by our Offshore Services segment is not recognized until such time as insurance claim proceeds are received.

Net Income per Share

The following is a reconciliation of the weighted average number of common shares outstanding with the number of shares used in the computations of net income per common and common equivalent share:

	Three Months Ended March 31,
	2009		2008

Number of weighted average common shares outstanding		74,924,810		74,186,642
Assumed exercise of stock options		71,974		1,276,186
Average diluted shares outstanding		74,996,784		75,462,828

In applying the treasury stock method to determine the dilutive effect of the stock options outstanding during the first three months of 2009, we used the average market price of our common stock of $4.07. For the three months ended March 31, 2009 and 2008, the calculations of the average diluted shares outstanding excludes the impact of 4,204,086 and 869,249 outstanding stock options, respectively, that have exercise prices in excess of the average market price, as the inclusion of these shares would have been antidilutive.

Environmental Liabilities

Environmental expenditures which result in additions to property and equipment are capitalized, while other environmental expenditures are expensed. Environmental remediation liabilities are recorded on an undiscounted basis when environmental assessments or cleanups are probable, and the costs can be reasonably estimated. Estimates of future environmental remediation expenditures often consist of a range of possible expenditure amounts, a portion of which may be in excess of amounts of liabilities recorded. In this instance, we disclose the full range of amounts reasonably possible of being incurred. Any changes or developments in environmental remediation efforts are accounted for and disclosed each quarter as they occur. Any recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.

Complexities involving environmental remediation efforts can cause the estimates of the associated liability to be imprecise. Factors which cause uncertainties regarding the estimation of future expenditures include, but are not limited to, the effectiveness of the anticipated work plans in achieving targeted results and changes in the desired remediation methods and outcomes as prescribed by regulatory agencies. Uncertainties associated with environmental remediation contingencies are pervasive and often result in wide ranges of reasonably possible outcomes. Estimates developed in the early stages of remediation can vary significantly. Normally, a finite estimate of cost does not become fixed and determinable at a specific point in time. Rather, the costs associated with environmental remediation become estimable as the work is performed and the range of ultimate cost becomes more defined. It is possible that cash flows and results of operations could be materially affected by the impact of the ultimate resolution of these contingencies.

Fair Value Measurements

Effective January 1, 2008, we adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 establishes a fair value hierarchy and requires disclosure of fair value measurements within that hierarchy.

Under SFAS No. 157, fair value is defined as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date” within an entity’s principal market, if any. The principal market is the market in which the reporting entity would sell the asset or transfer the liability with the greatest volume and level of activity, regardless of whether it is the market in which the entity will ultimately transact for a particular asset or liability, or if a different market is potentially more advantageous. Accordingly, this exit price concept may result in a fair value that may differ from the transaction price or market price of the asset or liability.

The fair value hierarchy prioritizes inputs to valuation techniques used to measure fair value. Fair value measurements should maximize the use of observable inputs and minimize the use of unobservable inputs, where possible. Observable inputs are developed based on market data obtained from sources independent of the reporting entity. Unobservable inputs may be needed to measure fair value in situations where there is little or no market activity for the asset or liability at the measurement date and are developed based on the best information available in the circumstances, which could include the reporting entity’s own judgments about the assumptions market participants would utilize in pricing the asset or liability.

We utilize fair value measurements to account for certain items and account balances within our consolidated financial statements. Fair value measurements are utilized in the allocation of purchase consideration for acquisition transactions to the assets and liabilities acquired, including intangible assets and goodwill. In addition, we utilize fair value measurements in the initial recording of our decommissioning and other asset retirement obligations. Fair value measurements may also be utilized on a nonrecurring basis, such as for the impairment of long-lived assets, including goodwill.

We also utilize fair value measurements on a recurring basis in the accounting for our derivative contracts used to hedge a portion of our oil and gas production cash flows. For these fair value measurements, we compare forward pricing data from published sources over the remaining derivative contract term to the contract swap price and calculate a fair value using market discount rates. A summary of these fair value measurements as of March 31, 2009, using the fair value hierarchy as prescribed by SFAS No. 157, is as follows:

Fair Value Measurements as of March 31, 2009 Using

Quoted Prices in

Active Markets for

Significant Other

Significant

Identical Assets

Observable

Unobservable

Total as of

or Liabilities

Inputs

Description

March 31, 2009

(Level 1)

(Level 2)

(Level 3)

(In Thousands)

Asset for natural gas

swap contracts

49,057

Asset for oil swap contracts

40,533

Total

89,590

During the three months ended March 31, 2009, the full carrying value of a certain Maritech oil and gas property was charged to earnings as an impairment of $0.4 million. The change in the fair value of this property was due to decreased expected future cash flows based on forward pricing data from published sources. Because such published forward pricing data was applied to estimated oil and gas reserve volumes based on our internally prepared reserve estimates, such fair value calculation is based on significant unobservable inputs (Level 3) in accordance with the fair value hierarchy as prescribed by SFAS No. 157.

New Accounting Pronouncements

In March 2008, the Financial Accounting Standards Board (FASB) published SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133,” which requires entities to provide greater transparency about (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, results of operations, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2008. Accordingly, we adopted SFAS No. 161 as of January 1, 2009 (see Note E – Hedge Contracts).

In December 2007, the FASB published SFAS No. 141R, “Business Combinations,” which established principles and requirements for how an acquirer of a business (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R changes many aspects of the accounting for business combinations. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted SFAS No. 141R as of January 1, 2009 with no significant impact, as there have been no acquisitions in the current year. However, SFAS No. 141R is expected to significantly impact how we account for and disclose future acquisition transactions.

In April 2009, the FASB issued FASB Staff Position (FSP) SFAS No. 141R-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies.” This FSP amends and clarifies SFAS No. 141R, “Business Combinations,” to require that an acquirer recognize at fair value, as of the acquisition date, an asset acquired or a liability assumed in a business combination that arises from a contingency if the acquisition date fair value of that asset or liability can be determined during the measurement period. If the acquisition date fair value of such an asset acquired or liability assumed cannot be determined, the acquirer is required to apply the provisions of SFAS No. 5, “Accounting for Contingencies,” to determine whether the contingency should be recognized at the acquisition date or after it. FSP SFAS No. 141R-1 is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is after the beginning of the first annual reporting period beginning after December 15, 2008. Accordingly, we adopted FSP SFAS No. 141R-1 as of January 1, 2009 with no significant impact, as there have been no acquisitions in the current year.

In December 2007, the FASB published SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51,” which establishes accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We adopted SFAS No. 160 as of January 1, 2009, however, the impact was not material.

In December 2008, the SEC released its “Modernization of Oil and Gas Reporting” rules, which revise the disclosure of oil and gas reserve information. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves in certain circumstances. The new requirements also will allow companies to disclose their probable and possible reserves and require companies to (1) report on the independence and qualifications of a reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserve estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon the prior twelve month period, rather than year-end prices. These new reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. We are currently assessing the impact that adoption of the new disclosure requirements will have on our disclosures of oil and gas reserves.

NOTE B – ACQUISITIONS

In March 2006, we acquired Beacon Resources, LLC (Beacon), a production testing operation, for approximately $15.6 million paid at closing. In addition, the acquisition agreement provided for additional contingent consideration of up to $19.1 million, depending on the average of Beacon’s annual pretax results of operations over the three year period following the closing date through March 2009. Based on Beacon’s annual pretax results of operations during this three year period, we have accrued as of March 31, 2009 $12.7 million to be paid to the sellers pursuant to this contingent consideration provision, as the amount to be paid is now fixed and determinable and was paid in April 2009. This amount was charged to goodwill associated with the acquisition of Beacon.

NOTE C – LONG-TERM DEBT AND OTHER BORROWINGS

Long-term debt consists of the following:

		March 31, 2009		December 31, 2009
		(In Thousands)
	Scheduled Maturity
Bank revolving line of credit facility	June 26, 2011	$	119,246	$	97,368
5.07% Senior Notes, Series 2004-A	September 30, 2011		55,000		55,000
4.79% Senior Notes, Series 2004-B	September 30, 2011		36,982		39,472
5.90% Senior Notes, Series 2006-A	April 30, 2016		90,000		90,000
6.30% Senior Notes, Series 2008-A	April 30, 2013		35,000		35,000
6.56% Senior Notes, Series 2008-B	April 30, 2015		90,000		90,000
European bank credit facility			-		-
			426,228		406,840
Less current portion			-		-
Total long-term debt		$	426,228	$	406,840

NOTE D – DECOMMISSIONING AND OTHER ASSET RETIREMENT OBLIGATIONS

We account for asset retirement obligations in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations.” The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The large majority of these asset retirement costs consists of the future well abandonment and decommissioning costs for offshore oil and gas properties and platforms owned by our Maritech subsidiary. The amount of decommissioning liabilities recorded by Maritech is reduced by amounts allocable to joint interest owners, anticipated insurance recoveries, and any contractual amount to be paid by the previous owner of the oil and gas property when the liabilities are satisfied. We also operate facilities in various U.S. and foreign locations that are used in the manufacture, storage, and/or sale of our products, inventories, and equipment, including offshore oil and gas production facilities and equipment. These facilities are a combination of owned and leased assets. We are required to take certain actions in connection with the retirement of these assets. We have reviewed our obligations in this regard in detail and estimated the cost of these actions. These estimates are the fair values that have been recorded for retiring these long-lived assets. The costs are depreciated on a straight-line basis over the life of the asset for non-oil and gas assets and on a unit of production basis for oil and gas properties. The market risk premium for a significant majority of asset retirement obligations is considered small, relative to the related estimated cash flows, and has not been used in the calculation of asset retirement obligations.

The changes in total asset retirement obligations during the three months ended March 31, 2009 and 2008 are as follows:

	Three Months Ended March 31,
	2009			2008
	(In Thousands)

Beginning balance for the period, as reported	$	248,725		$	199,506
Activity in the period:
Accretion of liability		2,281			2,015
Retirement obligations incurred		-			20,274
Revisions in estimated cash flows		3,562			2,401
Settlement of retirement obligations		(10,872	)		(4,736	)
Ending balance as of March 31	$	243,696		$	219,460

As of March 31, 2009, approximately $67.1 million of the decommissioning and asset retirement obligation is related to well abandonment and decommissioning costs to be incurred over the next twelve month period and is included in current liabilities in the accompanying consolidated balance sheet.

NOTE E – HEDGE CONTRACTS

We are exposed to financial and market risks that affect our businesses. We have market risk exposure in the sales prices we receive for our oil and gas production. We have currency exchange rate risk exposure related to specific transactions denominated in a foreign currency as well as to investments in certain of our international operations. As a result of the outstanding balance under a variable rate bank credit facility, we face market risk exposure related to changes in applicable interest rates. We have concentrations of credit risk as a result of trade receivables from companies in the energy industry. Our financial risk management activities involve, among other measures, the use of derivative financial instruments, such as swap and collar agreements, to hedge the impact of market price risk exposures for a significant portion of our oil and gas production and for certain foreign currency transactions. We are exposed to the volatility of oil and gas prices for the portion of our oil and gas production that is not hedged.

Derivative Hedge Contracts

As of March 31, 2009, we had the following cash flow hedging swap contracts outstanding relating to a portion of our Maritech subsidiary’s oil and gas production:

Derivative Contracts	Aggregate Daily Volume	Weighted Average Contract Price	Contract Year
March 31, 2009

Oil swap contracts	2,500 barrels/day	$68.864/barrel	2009
Oil swap contracts	2,000 barrels/day	$104.125/barrel	2010

Natural gas swap contracts	25,000 MMBtu/day	$8.967/MMBtu	2009
Natural gas swap contracts	10,000 MMBtu/day	$10.265/MMBtu	2010

We believe that our swap agreements are “highly effective cash flow hedges,” as defined by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” in managing the volatility of future cash flows associated with our oil and gas production. The effective portion of the change in the derivative’s fair value (i.e., that portion of the change in the derivative’s fair value that offsets the corresponding change in the cash flows of the hedged transaction) is initially reported as a component of accumulated other comprehensive income and will be subsequently reclassified into product sales revenues utilizing the specific identification method when the hedged exposure affects earnings (i.e., when hedged oil and gas production volumes are reflected in revenues). Any “ineffective” portion of the change in the derivative’s fair value is recognized in earnings immediately.

The fair value of our oil and natural gas swap contracts as of March 31, 2009 is as follows:

Derivatives designated as hedging instruments	Balance Sheet	Fair Value at
under SFAS No. 133	Location	March 31, 2009
		(In Thousands)

Natural gas swap contracts	Current assets	$	37,788
Oil swap contracts	Current assets		18,459
			56,247

Natural gas swap contracts	Long-term assets		11,269
Oil swap contracts	Long-term assets		22,074
			33,343
Total derivatives designated as hedging instruments
under SFAS No. 133		$	89,590

Oil and natural gas swap assets which are classified as current assets relate to the portion of the derivative contracts associated with hedged oil and gas production to occur over the next twelve month period. None of the oil and natural gas swap contracts contain credit risk related contingent features that would require us to post assets as collateral for contracts that are classified as liabilities.

As the hedge contracts were highly effective, the entire gain from changes in contract fair value, net of taxes, as of March 31, 2009, is included in other comprehensive income within stockholders’ equity.

	March 31, 2009
Derivative Swap Contracts	Oil			Natural Gas			Total
	(In Thousands)
Amount of gain recognized in other comprehensive income
on derivative, net of taxes (effective portion)	$	24,442		$	27,941		$	52,383

	Three Months Ended March 31, 2009
Derivative Swap Contracts	Oil			Natural Gas			Total
	(In Thousands)
Amount of pretax gain reclassified from accumulated other comprehensive
income into product sales revenue (effective portion)	$	4,521		$	7,391		$	11,912

Amount of pretax gain (loss) recognized in other income (expense)
(ineffective portion)		(241	)		(638	)		(879	)

Other Hedge Contracts

Our long-term debt includes borrowings which are designated as a hedge of our net investment in our European calcium chloride operations. The hedge is considered to be effective, since the debt balance designated as the hedge is less than or equal to the net investment in the foreign operation. At March 31, 2009, we had 35 million Euros (approximately $46.2 million) designated as a hedge of a net investment in this foreign operation. Changes in the foreign currency exchange rate have resulted in a cumulative change to the cumulative translation adjustment account of $2.2 million, net of taxes, at March 31, 2009.

NOTE F – COMPREHENSIVE INCOME

Comprehensive income (loss) for the three month periods ended March 31, 2009 and 2008 is

as follows:

	Three Months Ended March 31,
	2009			2008
	(In Thousands)

Net income	$	11,162		$	6,687
Net change in derivative fair value, net of taxes of $7,344
and $(13,719), respectively		12,398			(23,160	)
Reclassification of derivative fair value into product sales
revenues, net of taxes of $(4,431) and $2,697, respectively		(7,481	)		4,553
Foreign currency translation adjustment, net of taxes of
$(1,197) and $1,221, respectively		(1,428	)		2,152
Comprehensive income (loss)	$	14,651		$	(9,768	)

NOTE G – COMMITMENTS AND CONTINGENCIES

Litigation

We are named as 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 of our 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. The complaints allege that the defendants violated the federal securities laws during the period by, among other things, disseminating false and misleading statements and/or concealing material facts concerning our current and prospective business and financial results. The complaints also allege that, as a result of these actions, our stock price was artificially inflated during the class period, which enabled our insiders to sell their personally-held shares for a substantial gain. The complaints seek unspecified compensatory damages, costs, and expenses. 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 August 27, 2008, Lead Plaintiff Fulton County Employees’ Retirement System filed its Amended Consolidated Complaint. On October 28, 2008, we filed a motion to dismiss the federal class action that is currently pending before the Court.

Between May 28, 2008 and June 27, 2008, two petitions were filed by alleged stockholders in the District Courts of Harris County, Texas, 133rd and 113th 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 actions, 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 133rd District Court consolidated these complaints as In re TETRA Technologies, Inc. Derivative Litigation, Cause No. 2008-23432 (133rd Dist. Ct., Harris County, Tex.), and appointed Thomas Prow and Mark Patricola as Co-Lead Plaintiffs. This case has been stayed by agreement of the parties pending the Court’s ruling on our motion to dismiss the federal class action.

At this stage, it is impossible to predict the outcome of these proceedings or their impact upon us. We currently believe that the allegations made in the federal complaints and state petitions are without merit, and we intend to seek dismissal of and vigorously defend against these actions. While a successful outcome cannot be guaranteed, we do not reasonably expect these lawsuits to have a material adverse effect.

Insurance Litigation - Through March 31, 2009, we have expended approximately $47.6 million of well intervention work on certain wells associated with the three Maritech offshore platforms which were destroyed as a result of Hurricanes Katrina and Rita in 2005. We estimate that future repair and well intervention efforts related to these destroyed platforms, including platform debris removal and other storm related costs, will result in approximately $50 million to $70 million of additional costs. As a result of submitting claims associated with well intervention costs previously expended and responding to underwriters’ request for additional information, approximately $28.9 million of these well intervention costs have been reimbursed; however, our insurance underwriters maintain that well intervention costs for certain of the damaged wells do not qualify as covered costs and that certain well intervention costs for qualifying wells are not covered under the policy. In addition, the underwriters have also maintained that there is no additional coverage provided under an endorsement we obtained in August 2005 for the cost of removal of these platforms or for other damage repairs on certain properties in excess of the insured values provided by our property damage policy. After continuing to provide requested information to the underwriters regarding the damaged wells and having numerous discussions with the underwriters, brokers, and insurance adjusters, we have not received the requested reimbursement for these contested costs. On November 16, 2007, we filed a lawsuit in Montgomery County, Texas, entitled Maritech Resources, Inc. v. Certain Underwriters and Insurance Companies at Lloyd’s, London subscribing to Policy no. GA011150U and Steege Kingston, in which we are seeking damages for breach of contract and various related claims and a declaration of the extent of coverage of an endorsement to the policy. We cannot predict the outcome of this lawsuit.

We continue to believe that these costs, up to the amount of coverage limits, qualify for coverage pursuant to the policy. However, during the fourth quarter of 2007, we reversed the anticipated insurance recoveries previously included in estimating Maritech’s decommissioning liability, increasing the decommissioning liability to $48.4 million for well intervention and debris removal work to be performed, assuming no insurance reimbursements will be received. In addition, during 2007 we reversed a portion of our anticipated insurance recoveries previously included in accounts receivable related to certain damage repair costs incurred, as the amount and timing of further reimbursements from our insurance providers are now indeterminable.

If we successfully collect our reimbursement from our insurance providers, such reimbursements will be credited to operations in the period collected. In the event that our actual well intervention costs are more or less than the associated decommissioning liabilities, as adjusted, the difference may be reported in income in the period in which the work is performed.

Environmental

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. We have reviewed estimated remediation costs prepared by our independent, third-party environmental engineering consultant, based on a detailed environmental study. Based upon our review and discussions with our third-party consultants, we established a reserve for such remediation costs. As of March 31, 2009, and following the performance of the required remediation activities at the site, the amount of the reserve for these remediation costs, included in current liabilities, is approximately $0.1 million. The reserve will be further adjusted as information develops or conditions change.

We have not been named a potentially responsible party by the EPA or any state environmental agency.

Other Contingencies

In March 2006, we acquired the assets and operations of Epic Divers, Inc. and certain affiliated companies (Epic), a full service commercial diving operation. In June 2006, Epic purchased a dynamically positioned dive support vessel and saturation diving unit. Pursuant to the Epic Asset Purchase Agreement, a portion of the net profits earned by this dive support vessel and saturation diving unit over the initial three year term following its purchase is to be paid to the sellers. We currently anticipate that a payment will be required during 2009 pursuant to this contingent consideration provision of the agreement due to the high utilization of the acquired dive support vessel following the 2008 hurricanes. Any amount payable pursuant to this provision will be reflected as a liability and added to goodwill as it becomes fixed and determinable at the end of the three year period. In addition, approximately $1.6 million of the original purchase consideration is to be paid to the sellers at the end of this three year term. This amount was accrued as part of the original recording of the Epic acquisition during the first quarter of 2006.

NOTE H – INDUSTRY SEGMENTS

We manage our operations through five operating segments: Fluids, Offshore Services, Maritech, Production Testing, and Compressco. Beginning in the fourth quarter of 2008, our Production Enhancement Division consists of two separate reporting segments: the Production Testing segment and the Compressco segment. Segment information for the prior year period has been revised to conform to the 2009 presentation.

Our Fluids Division manufactures and markets clear brine fluids, additives, and other associated products and services to the oil and gas industry for use in well drilling, completion, and workover operations, both domestically and in certain regions of Latin America, Europe, Asia, and Africa. The Division also markets certain fluids and dry calcium chloride manufactured at its production facilities to a variety of markets outside the energy industry.

Our Offshore Division, previously known as our Well Abandonment and Decommissioning (WA&D) Division, consists of two operating segments: Offshore Services and Maritech. The Offshore Services segment provides (1) downhole and sub-sea services such as plugging and abandonment, workover, inland water drilling, and wireline services; (2) construction and decommissioning services, including hurricane damage remediation, utilizing our heavy-lift barges and cutting technologies in the construction or decommissioning of offshore oil and gas production platforms and pipelines; and (3) diving services involving conventional and saturated air diving and the operation of several dive support vessels.

The Maritech segment consists of our Maritech subsidiary, which, with its subsidiaries, is an oil and gas exploration, exploitation, and production company focused in the offshore, inland waters, and onshore regions of the Gulf of Mexico. Maritech acquires oil and gas properties in order to grow its production operations, to provide additional development and exploitation opportunities, and to provide a baseload of business of the Division’s Offshore Services segment.

Our Production Enhancement Division consists of two operating segments: Production Testing and Compressco. The Production Testing segment provides production testing services to markets in Texas, New Mexico, Colorado, Oklahoma, Arkansas, Louisiana, Pennsylvania, offshore Gulf of Mexico, Mexico, Brazil, Northern Africa, and the Middle East.

The Compressco segment provides wellhead compression-based production enhancement services to a broad base of customers throughout 14 states that encompass most of the onshore producing regions of the United States, as well as in Canada, Mexico, and other international locations. These production enhancement services improve the value of natural gas and oil wells by increasing daily production and total recoverable reserves.

We generally evaluate performance and allocate resources based on profit or loss from operations before income taxes and nonrecurring charges, return on investment, and other criteria. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies. Transfers between segments, as well as geographic areas, are priced at the estimated fair value of the products or services as negotiated between the operating units. “Corporate overhead” includes corporate general and administrative expenses, corporate depreciation and amortization, interest income and expense, and other income and expense.

Summarized financial information concerning the business segments from continuing operations is as follows:

	Three Months Ended March 31,
	2009			2008
	(In Thousands)
Revenues from external customers
Product sales
Fluids Division	$	46,982		$	50,990
Offshore Division
Offshore Services		892			1,063
Maritech		40,470			57,211
Intersegment eliminations		-			-
Total Offshore Division		41,362			58,274
Production Enhancement Division
Production Testing		-			-
Compressco		2,314			2,961
Total Production Enhancement Division		2,314			2,961
Consolidated		90,658			112,225

Services and rentals
Fluids Division		16,682			16,096
Offshore Division
Offshore Services		47,120			50,068
Maritech		742			308
Intersegment eliminations		(7,643	)		(3,145	)
Total Offshore Division		40,219			47,231
Production Enhancement Division
Production Testing		24,619			29,512
Compressco		23,073			20,092
Total Production Enhancement Division		47,692			49,604
Consolidated		104,593			112,931

Intersegment revenues
Fluids Division		25			98
Offshore Division
Offshore Services		32			35
Maritech		-			-
Intersegment eliminations		-			-
Total Offshore Division		32			35
Production Enhancement Division
Production Testing		-			12
Compressco		-			-
Total Production Enhancement Division		-			12
Intersegment eliminations		(57	)		(145	)
Consolidated		-			-

	Three Months Ended March 31,
	2009			2008
	(In Thousands)
Revenues from external customers
Total revenues
Fluids Division		63,689			67,184
Offshore Division
Offshore Services		48,044			51,166
Maritech		41,212			57,519
Intersegment eliminations		(7,643	)		(3,145	)
Total Offshore Division		81,613			105,540
Production Enhancement Division
Production Testing		24,619			29,524
Compressco		25,387			23,053
Total Production Enhancement Division		50,006			52,577
Intersegment eliminations		(57	)		(145	)
Consolidated	$	195,251		$	225,156

Income before taxes and discontinued operations
Fluids Division	$	12,153		$	6,841
Offshore Division
Offshore Services		(644	)		(4,103	)
Maritech		9,186			7,374
Intersegment eliminations		(311	)		243
Total Offshore Division		8,231			3,514
Production Enhancement Division
Production Testing		5,699			8,422
Compressco		6,669			6,950
Total Production Enhancement Division		12,368			15,372
Corporate overhead		(14,617	)(1)		(14,395	)(1)
Consolidated	$	18,135		$	11,332

	March 31,
	2009			2008
	(In Thousands)
Total assets
Fluids Division	$	345,216		$	295,919
Offshore Division
Offshore Services		184,431			237,465
Maritech		425,994			431,757
Intersegment eliminations		(3,213	)		(1,877	)
Total Offshore Division		607,212			667,345
Production Enhancement Division
Production Testing		109,922			89,532
Compressco		212,336			191,428
Total Production Enhancement Division		322,258			280,960
Corporate overhead		160,692	(2)		68,640	(2)
Consolidated	$	1,435,378		$	1,312,864

(1) Amounts reflected include the following general corporate expenses:

	Three Months Ended March 31,
	2009		2008
	(In Thousands)

General and administrative expense	$	9,667	$	8,427
Depreciation and amortization		699		611
Interest expense		3,368		4,579
Other general corporate (income) expense, net		883		778
Total	$	14,617	$	14,395

(2) Includes assets of discontinued operations.

NOTE I – SUBSEQUENT EVENT

Our Fluids Division owns a 50% interest in an unconsolidated joint venture whose assets consist primarily of a calcium chloride plant located in Europe. In April 2009, the joint venture partner announced the planned shutdown of its adjacent plant facility which supplies raw material to the calcium chloride plant. While we and our joint venture partner are currently reviewing the operating alternatives available, the suspension of the raw material supply for the joint venture’s plant could ultimately lead to the shutdown and disposal of the joint venture’s main operating asset. The carrying value of our investment in the joint venture, including an associated note receivable, is approximately $6.4 million.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Business Overview

The impact of the global economic downturn continues to adversely affect the oil and gas industry and the demand for many of our products and services. Energy commodity prices during the first quarter of 2009 averaged significantly below the levels from the prior year period, and natural gas prices have continued to drop during the first four months of 2009. This decrease in commodity prices has resulted in decreased cash flows for many of our customers, which, along with continuing tight capital markets, has resulted in decreased spending within the industry. This impact has particularly been reflected in the domestic rig count, which showed a 42.5% decrease in total domestic rigs at the end of March 2009 compared to the same date from the prior year. The current environment has particularly affected our Maritech exploration, exploitation, and production segment, our Production Testing and Compressco segments, and certain of our Offshore Services segment businesses. Most of these affected businesses reported declining revenues during the first quarter of 2009. While the impact on Maritech from decreased commodity prices is currently largely offset by our hedging activity, production volumes remain adversely affected by shut-in properties following the 2008 hurricanes, more than offsetting new production from wells drilled during 2008. In addition, Maritech’s current exploitation and development activities have been slowed by our efforts to conserve capital, and this could reduce our ability to replace depleting reserve volumes. Certain activities within our Offshore Services segment have benefitted, and may continue to benefit, from repair activities resulting from damages caused by Hurricane Ike in September 2008. In addition, deepwater projects in the Gulf of Mexico and certain international markets, generally performed by major oil and gas companies, may have been affected less severely by the current economic conditions.

We have continued to respond to the current market environment by conserving operating cash flows and reducing discretionary capital expenditures. During the first quarter of 2009, we increased our efforts to improve efficiencies and reduce costs, including taking steps to reduce operating and administrative staff, reduce salaries, consolidate operating locations, and temporarily suspend the utilization of certain equipment assets. Despite decreased revenues compared to the first quarter of 2008, overall profitability during the first quarter of 2009 improved compared to the prior year period. Our Fluids and Offshore Services segments reported increased earnings on lower revenues, while Maritech recorded higher earnings primarily due to insurance reimbursements and a gain from the sale of assets during the current year period. Capital expenditure activity during the first quarter of 2009 was significantly reduced compared to the prior year period, despite the ongoing construction of our new Arkansas calcium chloride plant facility and the completion of our new corporate headquarters building. Our efforts to reduce capital expenditures and conserve operating cash flows are expected to allow us to contain additional long-term debt borrowings and, particularly following the completion of the Arkansas plant, allow us to reduce our outstanding debt balance prior to the end of 2009. As of March 31, 2009, our outstanding long-term debt balance increased to $426.2 million and our debt to total capital ratio was 44.5%, a slight increase from 44.1% as of December 31, 2008. Our bank credit facility is scheduled to mature in June 2011, and our Senior Notes are scheduled to mature at various dates from September 2011 through April 2016.

Critical Accounting Policies

There have been no material changes or developments in the evaluation of the accounting estimates and the underlying assumptions or methodologies pertaining to our Critical Accounting Policies and Estimates disclosed in our Form 10-K for the year ended December 31, 2008. In preparing our consolidated financial statements, we make assumptions, estimates, and judgments that affect the amounts reported. We periodically evaluate our estimates and judgments, including those related to potential impairments of long-lived assets (including goodwill), the collectibility of accounts receivable (including insurance receivables), and the current cost of future abandonment and decommissioning obligations. Our judgments and estimates are based on historical

experience and on future expectations that are believed to be reasonable. The combination of these factors forms the basis for judgments made about the carrying values of assets and liabilities that are not readily apparent from other sources. These judgments and estimates may change as new events occur, as new information is acquired, and as our operating environment changes. Actual results are likely to differ from our current estimates, and those differences may be material.

Results of Operations

	Three Months Ended March 31,
	2009			2008
	(In Thousands)
Revenues
Fluids Division	$	63,689		$	67,184
Offshore Division
Offshore Services		48,044			51,166
Maritech		41,212			57,519
Intersegment eliminations		(7,643	)		(3,145	)
Total Offshore Division		81,613			105,540
Production Enhancement Division
Production Testing		24,619			29,524
Compressco		25,387			23,053
Total Production Enhancement Division		50,006			52,577
Intersegment eliminations		(57	)		(145	)
		195,251			225,156
Gross Profit
Fluids Division		17,021			13,257
Offshore Division
Offshore Services		2,901			(7	)
Maritech		7,652			9,045
Intersegment eliminations		(311	)		243
Total Offshore Division		10,242			9,281
Production Enhancement Division
Production Testing		7,687			10,616
Compressco		9,121			9,503
Total Production Enhancement Division		16,808			20,119
Other		(701	)		(610	)
		43,370			42,047
Income before taxes and discontinued operations
Fluids Division		12,153			6,841
Offshore Division
Offshore Services		(644	)		(4,103	)
Maritech		9,186			7,374
Intersegment eliminations		(311	)		243
Total Offshore Division		8,231			3,514
Production Enhancement Division
Production Testing		5,699			8,422
Compressco		6,669			6,950
Total Production Enhancement Division		12,368			15,372
Corporate overhead		(14,617	)		(14,395	)
		18,135			11,332

The above information excludes the results of our Venezuelan and process services businesses, which have been accounted for as discontinued operations.

Three months ended March 31, 2009 compared with three months ended March 31, 2008.

Consolidated Comparisons

Revenues and Gross Profit – Our total consolidated revenues for the quarter ended March 31, 2009 were $195.3 million compared to $225.2 million for the first quarter of the prior year, a decrease of 13.3%. Our consolidated gross profit increased to $43.4 million during the first quarter of 2009 compared to $42.0 million in the prior year quarter, an increase of 3.1%. Consolidated gross profit as a percentage of revenue was 22.2% during the first quarter of 2009 compared to 18.7% during the prior year period.

General and Administrative Expenses – General and administrative expenses were $24.6 million during the first quarter of 2009 compared to $25.1 million during the first quarter of 2008, a decrease of $0.5 million or 2.1%. This decrease was primarily due to approximately $0.9 million of decreased salary, benefits, contract labor costs, and other associated employee expenses, and approximately $0.8 million of decreased professional fees, partially offset by approximately $0.3 million of increased bad debt expenses and approximately $0.9 million of increased insurance, taxes, and other general expenses. General and administrative expenses as a percentage of revenue were 12.6% during the first quarter of 2009 compared to 11.1% during the prior year period.

Other Income and Expense – Other income and expense was $2.5 million of income during the first quarter of 2009 compared to $1.2 million of expense during the first quarter of 2008, primarily due to approximately $3.2 million of increased gains on sales of assets in the current period and approximately $0.5 million of increased other income, primarily from increased foreign currency gains.

Interest Expense and Income Taxes – Net interest expense decreased to $3.2 million during the first quarter of 2009 compared to $4.4 million during the first quarter of 2008, despite increased borrowings of long-term debt which were used to fund our capital expenditure and working capital requirements since the beginning of 2008. The decrease was due to lower interest rates on the outstanding revolving credit facility and due to increased capitalized interest, primarily associated with our Arkansas calcium chloride plant and corporate headquarters construction projects. The corporate headquarters building was completed during the first quarter of 2009 and we anticipate that our new calcium chloride facility in El Dorado, Arkansas will be completed later this year. Our provision for income taxes during the first quarter of 2009 increased to $6.8 million compared to $4.0 million during the prior year period, due to increased earnings.

Net Income – Net income before discontinued operations was $11.4 million during the first quarter of 2009 compared to $7.4 million in the prior year first quarter, an increase of $4.0 million. Net income per diluted share before discontinued operations was $0.15 on 74,996,784 average diluted shares outstanding during the first quarter of 2009 compared to $0.10 on 75,462,828 average diluted shares outstanding in the prior year period.

During the fourth quarter of 2007, we sold our process services operation for approximately $58.7 million, net of certain adjustments. During the fourth quarter of 2006, we made the decision to discontinue our Venezuelan fluids and production testing businesses due to several factors, including the changing political climate in that country. Net loss from discontinued operations was $0.2 million during the first quarter of 2009 compared to $0.7 million of net income from discontinued operations during the first quarter of 2008.

Net income was $11.2 million during the first quarter of 2009 compared to $6.7 million in the prior year first quarter, an increase of $4.5 million. Net income per diluted share was $0.15 on 74,996,784 average diluted shares outstanding during the first quarter of 2009 compared to $0.09 on 75,462,828 average diluted shares outstanding in the prior year quarter.

Divisional Comparisons

Fluids Division – Our Fluids Division revenues decreased $3.5 million to $63.7 million during the first quarter of 2009 compared to $67.2 million during the first quarter of 2008, a 5.2% decrease. This decrease was primarily due to reduced sales volumes for brine products and domestic chemicals. These decreases were partially offset by approximately $2.4 million from increased international product sales. In addition, the Division also reflected $0.6 million of increased service revenues.

Our Fluids Division gross profit increased to $17.0 million during the first quarter of 2009, compared to $13.3 million during the prior year period, an increase of $3.8 million or 28.4%. Gross profit as a percentage of

revenue increased to 26.7% during the current year period compared to 19.7% during the prior year period. This increase was primarily due to a more favorable product mix for our manufactured products, increased international brine sales activity, and increased services margins. During March 2009, a major contractual supplier of feedstock raw materials for our Fluids Division, Chemtura Corporation (Chemtura), announced that it had filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy code. Although it is impossible to predict the outcome of our contractual arrangements as a result of the bankruptcy filings, we do not believe that Chemtura’s filing will have a material impact on our operations. However, we have contingency plans for the procurement of alternative feedstock supplies.

Fluids Division income before taxes during the first quarter of 2009 totaled $12.2 million compared to $6.8 million in the corresponding prior year period, an increase of $5.3 million or 77.6%. This increase was generated by the $3.8 million increase in gross profit discussed above, plus approximately $0.8 million of decreased administrative expenses and approximately $0.7 million of increased other income, primarily from foreign currency gains.

Offshore Division – Revenues from our Offshore Division, which was previously known as the Well Abandonment and Decommissioning (WA&D) Division, decreased from $105.5 million during the first quarter of 2008 to $81.6 million during the first quarter of 2009, a decrease of $23.9 million or 22.7%. Offshore Division gross profit during the first quarter of 2009 totaled $10.2 million compared to $9.3 million during the prior year first quarter, an increase of $1.0 million or 10.4%. Offshore Division income before taxes was $8.2 million during the first quarter of 2009 compared to $3.5 million during the prior year period, an increase of $4.7 million or 134.2%.

The Division’s Offshore Services operations revenues decreased to $48.0 million during the first quarter of 2009 compared to $51.2 million in the prior year quarter, a decrease of $3.1 million or 6.1%. This decrease was due to the reduced offshore activity and vessel utilization during the current year quarter. Partially offsetting these decreases was the increased activity for the segment’s contract diving and cutting services businesses, which continue to enjoy increased demand following the 2008 hurricanes. The Division aims to capitalize on the current demand for well abandonment and decommissioning services in the Gulf of Mexico, including the demand for work to be performed over the next several years on offshore properties which were damaged or destroyed by hurricanes during 2005 and 2008. In addition, the segment is planning to perform significant work for Maritech during the next eighteen months.

The Offshore Services segment of the Division reported gross profit of $2.9 million during the first quarter of 2009, compared to negligible negative gross profit during the first quarter of 2008, a $2.9 million increase. The Offshore Services segment’s gross profit as a percentage of revenues was 6.0% during the first quarter of 2009. This increase was primarily due to the increased gross profit of the segment’s contract diving and cutting services businesses, which generated significant efficiencies from increased utilization during the current year period. It is anticipated that the segment’s gross profit margin will increase during the seasonally strong second and third quarters of the year, as the segment has historically incurred the greatest weather risks associated with offshore operations during the first and fourth quarters. In addition, the segment has consolidated certain office and administrative functions, reduced crews, and temporarily idled selected equipment in order to increase efficiencies for certain of its operations.

Offshore Services segment loss before taxes decreased from $4.1 million during the first quarter of 2008 to $0.6 million during the current year quarter, an increase in earnings of $3.5 million or 84.3%. This increase was due to the $2.9 million increase in gross profit described above, plus approximately $0.3 million of decreased administrative expenses and $0.3 million of decreased other expense.

The Division’s Maritech operations reported revenues of $41.2 million during the first quarter of 2009 compared to $57.5 million during the prior year period, a decrease of $16.3 million, or 28.4%. Decreased production volumes resulted in decreased revenues of approximately $11.7 million, primarily due to certain properties which continue to be shut-in following Hurricane Ike. The decreased production from the shut-in properties more than offset newly added production during the quarter from wells drilled in 2008. In particular, one of Maritech’s key oil producing fields, East Cameron 328, will continue to have a portion of its production shut-in until a new platform can be constructed to replace a platform which was toppled during the storm. However, operations are underway to install production equipment on the remaining platform in the field to restore approximately half of the field’s production prior to the end of 2009. Much of Maritech’s daily production is processed through neighboring platforms, pipelines, and processing facilities of other operators and third parties, many of which were also damaged during the storm. As a result, a portion of Maritech’s production remains shut-

in. During 2008, Maritech expended cash of approximately $85.0 million on acquisition and development activities, and the level of such activity is expected to significantly decrease during 2009, as this activity is now subject to constraints as a result of our efforts to conserve capital. In addition to the decreased production, revenues decreased by approximately $5.0 million as a result of decreased realized commodity prices. Maritech has hedged a portion of its expected future production levels by entering into derivative hedge contracts, with certain contracts extending through 2010. Including the impact of these hedge contracts, Maritech reflected average realized oil and natural gas prices during the first quarter of 2009 of $63.41/barrel and $8.19/MMBtu, respectively, each of which were decreased from 2008 levels. In addition, Maritech reported $0.4 million of increased processing revenue during the current year quarter.

Maritech reported gross profit of $7.7 million during the first quarter of 2009 compared to $9.0 million of gross profit during the first quarter of 2008, a decrease of $1.4 million or 15.4%. Maritech’s gross profit as a percentage of revenues increased during the quarter to 18.6% from 15.7% during the prior year period. Largely offsetting the impact of decreased revenues was the impact of decreased lease operating and depreciation expenses, primarily associated with the decreased production. In addition, Maritech credited operating expenses during 2009 upon the receipt of $5.4 million of insurance proceeds from 2005 hurricane damages. The decreased operating expenses were despite approximately $1.6 million of increased repair expenses recorded during the current year period, primarily related to the 2008 hurricanes.

The Division’s Maritech operations reported income before taxes of $9.2 million during the first quarter of 2009 compared to $7.4 million during the prior year period, an increase of $1.8 million or 24.6%. This increase was despite the $1.4 million decrease in gross profit discussed above, due to approximately $0.6 million of decreased administrative costs and approximately $2.6 million of increased gains on sales of properties recorded compared to the prior year period.

Production Enhancement Division – Beginning in the fourth quarter of 2008, our Production Enhancement Division consists of two separate reporting segments: the Production Testing segment and the Compressco segment. Production Enhancement Division revenues decreased from $52.6 million during the first quarter of 2008 to $50.0 million during the current year quarter, a decrease of $2.6 million or 4.9%. Production Enhancement Division gross profit decreased from $20.1 million during the first quarter of 2008 to $16.8 million during the current year period, a decrease of 16.5%. Production Enhancement Division gross profit as a percentage of revenue also decreased from 38.3% during the first quarter of 2008 to 33.6% during the first quarter of 2009. Production Enhancement Division income before taxes decreased during the first quarter of 2009 to $12.4 million, compared to $15.4 million during the first quarter of 2008, a decrease of $3.0 million.

Production Testing revenues decreased during the first quarter of 2009 to $24.6 million, a $4.9 million decrease compared to $29.5 million during the first quarter of 2008. This 16.6% decrease was primarily due to a $5.0 million decrease in domestic operations, primarily due to the decreased drilling activity, as reflected in the domestic rig count. This decrease was partially offset by slightly increased international revenues, primarily from Mexico and Brazil.

Production Testing gross profit also decreased during the first quarter of 2009 from $10.6 million during the prior year period to $7.7 million during the current year period. Gross profit as a percentage of revenues also decreased from 36.0% during the first quarter of 2008 to 31.2% during the first quarter of 2009. This decrease was due to the weaker demand and decreased activity domestically.

Production Testing income before taxes decreased from $8.4 million during the first quarter of 2008 to $5.7 million during the first quarter of 2009, a decrease of $2.7 million or 32.3%. This decrease was due to the $2.9 million decrease in gross profit discussed above and approximately $0.1 million of increased administrative costs, which were partially offset by approximately $0.3 million of increased other income, primarily due to increased foreign currency gains.

Compressco revenues increased by approximately $2.3 million during the first quarter of 2009 compared to the prior year period, increasing from $23.1 million during the first quarter of 2008 to $25.4 million during the current year period. This increase was due to Compressco’s overall growth domestically, as well as in Mexico, reflecting the growth of its compressor fleet during 2008. Compressco has significantly decreased the fabrication of new compressor units during early 2009 to rationalize its fleet to the expected demand of the current environment.

Compressco gross profit decreased from $9.5 million during the first quarter of 2008 to $9.1 million during the first quarter of 2009, a decrease of $0.4 million or 4.0%. Gross profit as a percentage of revenues also decreased from 41.2% during the first quarter of 2008 to 35.9% during the current year period. This decrease was primarily due to unabsorbed fabrication overhead as a result of the decreased production of new compressor units, along with other increased operating expenses for Compressco’s domestic operations.

Income before taxes for Compressco decreased 4.0%, from $7.0 million during the prior year first quarter to $6.7 million during the first quarter of 2009, a decrease of $0.3 million. This decrease was primarily due to the $0.4 million of decreased gross profit discussed above, partially offset by approximately $0.1 million of decreased administrative costs.

Corporate Overhead – Corporate Overhead includes corporate general and administrative expense, interest income and expense, and other income and expense. Such expenses and income are not allocated to our operating divisions, as they relate to our general corporate activities. Corporate overhead increased from $14.4 million during the first quarter of 2008 to $14.6 million during the first quarter of 2009, primarily due to increased administrative and depreciation expense. Corporate administrative costs increased approximately $1.2 million due to approximately $1.3 million of increased salaries and other general employee expenses, primarily due to increased equity compensation expense. Approximately $0.4 million of increased office and other general expenses was largely offset by approximately $0.4 million of decreased professional fee expense. Corporate interest expense decreased by approximately $1.2 million during the first quarter of 2009 due to lower interest rates on the outstanding balance of our bank credit facility, as well as from an increase in the amount of interest capitalized on construction projects during the period.

Liquidity and Capital Resources

Given the current economic environment, we are balancing our long-term growth objectives with an attention to conserving cash and reducing long-term debt. Our management’s focus includes maximizing operating cash flows by reducing operating and administrative expenses, while preserving liquidity through reduced capital expenditures. This focus has not interrupted two of our most significant capital projects: the construction of our new headquarters building, which was completed during the first quarter of 2009, and our new El Dorado, Arkansas calcium chloride plant facility, which is scheduled to be completed later this year. Particularly following the completion of the Arkansas plant, we intend to apply discretionary cash flows to the reduction of our outstanding long-term debt balances.

Operating Activities – Cash flows generated by operating activities totaled approximately $39.9 million during the first quarter of 2009 compared to approximately $46.6 million during the prior year quarter. Despite increased earnings during the current year period, changes in working capital items contributed to much of this decrease in operating cash flows from the prior year period. Future operating cash flows for many of our businesses are largely dependent upon the level of oil and gas industry activity, particularly in the Gulf of Mexico region of the U.S. Such demand has decreased due to current economic conditions, and we expect that this current decreased demand for many of our products and services may continue indefinitely. In addition, the currently shut-in production following Hurricane Ike has significantly affected Maritech’s operating cash flows. Decreased Maritech cash flows as a result of currently decreasing oil and natural gas prices are largely offset by the impact of commodity derivative contracts, some of which extend through the end of 2010. We also expect the reduced operating cash flows from the currently decreased demand to be partially offset by our efforts to decrease our operating and administrative costs and by the current demand for hurricane repair activities that benefits certain of our Offshore Services businesses.

Following the 2005 and 2008 hurricanes, Maritech has six offshore platforms and one remaining inland water production facility which have been toppled and destroyed. The estimated cost to perform well intervention, decommissioning, and debris removal efforts on these platforms is particularly imprecise due to the unique nature of the work to be performed. Maritech estimates that future well intervention and abandonment efforts, including costs to remove debris, reconstruct certain destroyed structures, and redrill certain wells associated with these destroyed platforms and production facility, will cost from $130 to $180 million, net to our interest before any insurance recoveries. Actual costs could greatly exceed these estimates. Maritech incurred well intervention costs in prior years related to hurricane damage suffered in 2005, and certain of those costs have not been reimbursed by insurers. We have reviewed the types of remaining estimated well intervention costs to be incurred related to the six toppled platforms, including those costs related to the 2008 storms. Despite our belief that substantially all of these costs qualify for coverage under our insurance policies, any costs that are similar to the costs that have

not yet been reimbursed following the 2005 storms are required to be excluded from anticipated insurance recoveries.

Future operating cash flows will be significantly affected by the timing and amount of expenditures required for the plugging, abandonment, and decommissioning of Maritech’s oil and gas properties, including the cost associated with the six destroyed offshore platforms discussed above. The third party discounted fair value, including an estimated profit, of Maritech’s total decommissioning liability as of March 31, 2009 was $239.5 million ($257.8 million undiscounted), net of anticipated future insurance recoveries. The cash outflow necessary to extinguish this liability is expected to occur over several years, shortly after the end of each property’s productive life. The amount and timing of these cash outflows are estimated based on expected costs, as well as the timing of future oil and gas production and the resulting depletion of Maritech’s oil and gas reserves. Such estimates are imprecise and subject to change due to changing cost estimates, Minerals Management Service (MMS) requirements, commodity prices, revisions of reserve estimates, and other factors.

Maritech’s estimated decommissioning liabilities are also net of amounts allocable to joint interest owners and any contractual amounts to be paid by the previous owners of the properties. In some cases, the previous owners are contractually obligated to pay Maritech a fixed amount for the future well abandonment and decommissioning work on these properties as the work is performed, partially offsetting Maritech’s future obligation expenditures. As of March 31, 2009, Maritech’s total undiscounted decommissioning obligation is approximately $310.2 million and consists of Maritech’s total liability of $257.8 million plus approximately $52.4 million, which is contractually required to be reimbursed to Maritech pursuant to such contractual arrangements with the previous owners.

Investing Activities – During 2009, we plan to expend less than $200 million of capital expenditures and other investing activities, and approximately $54.0 million of this amount was expended during the first quarter of 2009. This planned level of capital expenditures is significantly reduced compared to the past two years, despite the completion during 2009 of two major construction projects: the El Dorado, Arkansas calcium chloride plant facility and the completion of our new headquarters building in The Woodlands, Texas. These two construction projects accounted for 58.5% of our first quarter capital expenditures. Due to current capital market constraints, our capital expenditure plans have been reviewed carefully and a significant amount of such capital expenditures have been deferred until after the completion of the Arkansas plant. A large portion of our other planned capital expenditures is related to identified opportunities to grow and expand our existing businesses, and certain of these expenditures may be further postponed or cancelled as conditions change. We expect to fund our 2009 capital expenditure activity through cash flows from operations and from our bank credit facility. This restraint on capital expenditure activity may result in a moderation of the aggressive growth strategy we have experienced over the past several years, and in the case of Maritech, may result in negative growth as a result of postponing the replacement of depleting oil and gas reserves and production cash flows. However, despite the current economic environment, our long-term growth strategy continues to include the pursuit of suitable acquisitions or opportunities to establish operations in additional niche oil and gas service markets. To the extent we consummate a significant transaction, our liquidity position will be affected.

Cash capital expenditures of approximately $55.6 million during the first quarter of 2009 included approximately $32.7 million by the Fluids Division, approximately $25.5 million of which related to our Arkansas calcium chloride facility. Our Offshore Division incurred approximately $12.6 million of capital expenditures during the period, approximately $9.1 million of which was expended by the Division’s Maritech subsidiary primarily related to exploitation and development expenditures on its offshore oil and gas properties. In addition, the Offshore Division expended approximately $3.6 million on its Offshore Services operations, primarily for costs on its various heavy lift and dive support vessels. The Production Enhancement Division spent approximately $3.5 million, consisting of approximately $3.3 million by the Production Testing segment for production testing equipment fleet expansion and approximately $0.2 million by the Compressco segment for additional wellhead compression equipment. Corporate capital expenditures were approximately $6.8 million, primarily related to the cost to complete our new corporate headquarters building during the quarter. In addition to its continuing capital expenditure program, Maritech continues to pursue the purchase of additional producing oil and gas properties.

Financing Activities

To fund our capital and working capital requirements, we may supplement our existing cash balances and cash flows from operating activities as needed from long-term borrowings, short-term borrowings, equity issuances, and other sources of capital.

Bank Credit Facilities - We have a revolving credit facility with a syndicate of banks, pursuant to a credit facility agreement which was amended in June 2006 and December 2006 (the Credit Agreement). As of May 11, 2009, we had an outstanding balance of $129.3 million and $26.2 million in letters of credit and guarantees against the $300 million revolving credit facility, leaving a net availability of $144.5 million. Although this outstanding balance has increased from the amounts outstanding as of December 31, 2008 and March 31, 2009, once our Arkansas calcium chloride facility is completed later this year, we expect that operating and investing cash flows will be sufficient to enable us to begin to reduce the outstanding balance prior to the end of 2009.

Pursuant to the Credit Agreement, the revolving credit facility is scheduled to mature in June 2011, is unsecured, and is guaranteed by certain of our material domestic subsidiaries. Borrowings generally bear interest at the British Bankers Association LIBOR rate plus 0.50% to 1.25%, depending on one of our financial ratios. As of March 31, 2009, the weighted average interest rate on the outstanding balance under the credit facility was 1.82%. We pay a commitment fee ranging from 0.15% to 0.30% on unused portions of the facility. The Credit Agreement contains customary covenants and other restrictions, including certain financial ratio covenants involving our levels of debt and interest cost compared to a defined measure of our operating cash flows over a twelve month period. In addition, the Credit Agreement includes limitations on aggregate asset sales, individual acquisitions, and aggregate annual acquisitions and capital expenditures. Access to our revolving credit line is dependent upon our ability to comply with the certain financial ratio covenants set forth in the Credit Agreement, as discussed above. Significant deterioration of the financial ratios could result in a default under the Credit Agreement and, if not remedied, could result in termination of the agreement and acceleration of any outstanding balances under the facility prior to 2011. The Credit Agreement also includes cross-default provisions relating to any other indebtedness greater than a defined amount. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the Credit Agreement. We were in compliance with all covenants and conditions of our Credit Agreement as of March 31, 2009. Our continuing ability to comply with these financial covenants centers largely upon our ability to generate adequate cash flows. Historically, our financial performance has been more than adequate to meet these covenants, and subject to the duration of the current economic environment, we expect this trend to continue.

Senior Notes - In September 2004, we issued, and sold through a private placement, $55 million in aggregate principal amount of Series 2004-A Senior Notes and 28 million Euros (approximately $37.0 million equivalent at March 31, 2009) in aggregate principal amount of Series 2004-B Senior Notes pursuant to the Master Note Purchase Agreement. The Series 2004-A Senior Notes bear interest at a fixed rate of 5.07% and mature on September 30, 2011. The Series 2004-B Notes bear interest at a fixed rate of 4.79% and also mature on September 30, 2011. Interest on the 2004-A and 2004-B Senior Notes is due semiannually on March 30 and September 30 of each year.

In April 2006, we issued, and sold through a private placement, $90.0 million in aggregate principal amount of Series 2006-A Senior Notes pursuant to our existing Master Note Purchase Agreement dated September 2004, as supplemented. The Series 2006-A Senior Notes bear interest at the fixed rate of 5.90% and mature on April 30, 2016. Interest on the 2006-A Senior Notes is due semiannually on April 30 and October 30 of each year.

In April 2008, we issued, and sold through a private placement, $35.0 million in aggregate principal amount of Series 2008-A Senior Notes and $90.0 million in aggregate principal amount of Series 2008-B Senior Notes (collectively the Series 2008 Senior Notes) pursuant to a Note Purchase Agreement dated April 30, 2008. The Series 2008-A Senior Notes bear interest at the fixed rate of 6.30% and mature on April 30, 2013. The Series 2008-B Senior Notes bear interest at the fixed rate of 6.56% and mature on April 30, 2015. Interest on the 2008 Senior Notes is due semiannually on April 30 and October 31 of each year.

The Series 2008 Senior Notes, together with the Series 2004-A Senior Notes, Series 2004-B Senior Notes, and Series 2006-A Senior Notes are collectively referred to as the Senior Notes. We may prepay the Senior Notes, in whole or in part, at any time at a price equal to 100% of the principal amount outstanding, plus accrued and unpaid interest and a “make-whole” prepayment premium. The Senior Notes are unsecured and guaranteed by substantially all of our wholly owned domestic subsidiaries. The Note Purchase Agreement and the Master Note Purchase Agreement, as supplemented, contain customary covenants and restrictions, and require us to maintain certain financial ratios, including a minimum level of net worth and a ratio between our long-term debt balance and a defined measure of operating cash flows over a twelve month period. The Note Purchase Agreement and Master Note Purchase Agreement also contain customary default provisions as well as cross-

default provisions relating to any other indebtedness of $20 million or more. We were in compliance with all covenants and conditions of the Note Purchase Agreement and Master Note Purchase Agreement as of March 31, 2009. Upon the occurrence and during the continuation of an event of default under the Note Purchase Agreement and Master Note Purchase Agreement, the Senior Notes may become immediately due and payable, either automatically or by declaration of holders of more than 50% in principal amount of the Senior Notes outstanding at the time.

Other Sources – In addition to our revolving credit facility, we fund our short-term liquidity requirements from cash generated by operations, from short-term vendor financing, and, to a lesser extent, from leasing with institutional leasing companies. Should additional capital be required, we believe that we have the ability to raise such capital through the issuance of additional debt or equity. Current market conditions, however, have made it increasingly difficult to access capital, either debt or equity, on acceptable terms. Continued instability in the capital markets, as a result of recession or otherwise, may continue to affect the cost of capital and the ability to raise capital for an indeterminable length of time. As discussed above, our bank revolving credit facility matures in June 2011 and our Senior Notes mature at various dates between September 2011 and April 2016. Unless current market conditions improve prior to the dates of these maturities, the replacement of these capital sources at similar or more favorable terms is unlikely. Given the current environment, it may be necessary to utilize our equity to fund our capital needs or issue as consideration in an acquisition transaction, either of which could result in dilution to our common stockholders.

In May 2004, we filed a universal acquisition shelf registration statement on Form S-4 that permits us to issue up to $400 million of common stock, preferred stock, senior and subordinated debt securities, and warrants in one or more acquisition transactions that we may undertake from time to time. As part of our strategic plan, we evaluate opportunities to acquire businesses and assets and intend to consider attractive acquisition opportunities, which may involve the payment of cash or the issuance of debt or equity securities. Such acquisitions may be funded with existing cash balances, funds under our credit facility, or securities issued under our acquisition shelf registration on Form S-4.

During the fourth quarter of 2008, we liquidated the swap derivative contracts related to the remainder of Maritech’s 2008 production in exchange for net cash received of approximately $6.5 million. As of March 31, 2009, the market value of our remaining oil and natural gas swap contracts was approximately $89.6 million. All or a portion of these contracts are currently marketable to the corresponding counterparty and could be liquidated in order to generate additional cash. However, there can be no assurances that such counterparties, the majority of which are banks and financial institutions, would agree to repurchase these swap derivative contracts, particularly if the market values increase significantly, or if the counterparty’s financial condition deteriorated. The liquidation of any of these swap contracts, if not replaced with similar derivative contracts, would expose an additional portion of Maritech’s expected future oil and gas production to market price volatility in future periods.

Off Balance Sheet Arrangements – As of March 31, 2009, we had no “off balance sheet arrangements” that may have a current or future material effect on our consolidated financial condition or results of operations.

Commitments and Contingencies

Litigation

No. 4:08-cv-0965 (S.D. Tex.). On August 27, 2008, Lead Plaintiff Fulton County Employees’ Retirement System filed its Amended Consolidated Complaint. On October 28, 2008, we filed a motion to dismiss the federal class action that is currently pending before the Court.

Environmental

We have not been named a potentially responsible party by the EPA or any state environmental agency.

Other Contingencies

Cautionary Statement for Purposes of Forward-Looking Statements

Certain statements contained herein and elsewhere may be deemed to be forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995 and are subject to the “safe harbor” provisions of that act, including, without limitation, statements concerning future or expected sales, earnings, costs, expenses, acquisitions or corporate combinations, asset recoveries, expected costs associated with damage from hurricanes and the ability to recover such costs under our insurance policies, the ability to resume operations and production from our damaged or destroyed platforms, the ability to obtain alternate sources of raw materials for certain of our calcium chloride facilities, working capital, capital expenditures, financial condition, other results of operations, the expected impact of current economic and capital market conditions on the oil and gas industry and our operations, other statements regarding our beliefs, plans, goals, future events and performance, and other statements that are not purely historical. Such statements involve risks and uncertainties, many of which are beyond our control. Actual results could differ materially from the expectations expressed in such forward-looking statements. Some of the risk factors that could affect our actual results and cause actual results to differ materially from any such results that might be projected, forecast, estimated or budgeted by us in such forward-looking statements are described in our Annual Report on Form 10-K for the year ended December 31, 2008, and set forth from time to time in our filings with the Securities and Exchange Commission.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

There have been no material changes in the information pertaining to our Market Risk exposures as disclosed in our Form 10-K for the year ended December 31, 2008.

Item 4. Controls and Procedures.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on

this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2009, the end of the period covered by this quarterly report.

There were no changes in our internal control over financial reporting that occurred during the fiscal quarter ended March 31, 2009, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II

OTHER INFORMATION

Item 1. 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.

The information regarding litigation matters described in the Notes to Consolidated Financial Statements, Note G – Commitments and Contingencies, Litigation, and included elsewhere in this Quarterly Report on Form 10-Q is incorporated herein by reference.

Item 1A. Risk Factors.

There have been no material changes in the information pertaining to our Risk Factors as disclosed in our Form 10-K for the year ended December 31, 2008.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

(a) None.

(b) None.

								Maximum Number (or
				Average		Total Number of Shares		Approximate Dollar Value) of
	Total Number			Price		Purchased as Part of		Shares that May Yet be
	of Shares			Paid per		Publicly Announced		Purchased Under the Publicly
Period	Purchased			Share		Plans or Programs(1)		Announced Plans or Programs(1)

Jan 1 - Jan 31, 2009		16	(2)	$	5.25		-	$	14,327,000
Feb 1 - Feb 28, 2009		357	(2)		5.19		-		14,327,000
Mar 1 - Mar 31, 2009		-			-		-		14,327,000
Total		373					-	$	14,327,000

(1)

In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases will 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 3. Defaults Upon Senior Securities.

None.

Item 4. Submission of Matters to a Vote of Security Holders.

No matters were submitted to a vote of our security holders, through the solicitation of proxies or otherwise, during the first quarter of 2009.

Item 5. Other Information.

None.

Item 6. Exhibits.

Exhibits:

31.1*	Certification Pursuant to Rule 13a-14(a) or 15d-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification Pursuant to Rule 13a-14(a) or 15d-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed with this report.

** Furnished with this report.

A statement of computation of per share earnings is included in Note A of the Notes to Consolidated Financial Statements included in this report and is incorporated by reference into Part II of this report.

SIGNATURES

Pursuant to the requirements 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.

TETRA Technologies, Inc.

Date: May 11, 2009	By:	/s/Stuart M. Brightman
		Stuart M. Brightman
		President
		Chief Executive Officer


Date: May 11, 2009	By:	/s/Joseph M. Abell
		Joseph M. Abell
		Senior Vice President
		Chief Financial Officer


Date: May 11, 2009	By:	/s/Ben C. Chambers
		Ben C. Chambers
		Vice President – Accounting
		Principal Accounting Officer

EXHIBIT INDEX

31.1*	Certification Pursuant to Rule 13a-14(a) or 15d-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification Pursuant to Rule 13a-14(a) or 15d-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed with this report.

** Furnished with this report.