tti10q051109

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