Layne Christensen (LAYN) 10-Q 2011 Q2 Quarterly report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended July 31, 2010

OR

o 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 001-34195

Layne Christensen Company

(Exact name of registrant as specified in its charter)

Delaware	48-0920712
(State or other jurisdiction of	(I.R.S. Employer Identification No.)
incorporation or organization)
1900 Shawnee Mission Parkway, Mission Woods, Kansas	66205
(Address of principal executive offices)	(Zip Code)

(Registrant’s telephone number, including area code) (913) 362-0510

Not Applicable

(Former name, former address and former fiscal year, if changed since last report.)

     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. Yesþ Noo

     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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
(Check one):

Large accelerated filero	Accelerated filerþ	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yeso Noþ

     There were 19,505,383 shares of common stock, $.01 par value per share, outstanding on August 31, 2010.

TABLE OF CONTENTS

PART I
	Item 1. Financial Statements
	Item 1A. Risk Factors
	Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition
	ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
	ITEM 4. Controls and Procedures
PART II
SIGNATURES
SECTION 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER OF THE COMPANY
SECTION 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER OF THE COMPANY
SECTION 906 CERTIFICATION OF CHIEF EXECUTIVE OFFICER OF THE COMPANY
SECTION 906 CERTIFICATION OF CHIEF FINANCIAL OFFICER OF THE COMPANY

PART I

Item 1. Financial Statements

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	July 31,			January 31,
	2010			2010
	(unaudited)			(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	49,184		$	84,450
Customer receivables, less allowance of $8,481 and $7,425, respectively		144,241			106,056
Costs and estimated earnings in excess of billings on uncompleted contracts		83,123			83,712
Inventories		25,572			25,637
Deferred income taxes		19,337			18,324
Income taxes receivable		1,638			3,761
Restricted deposits-current		1,113			1,415
Other		9,361			6,996
Total current assets		333,569			330,351
Property and equipment:
Land		11,982			12,056
Buildings		34,924			34,539
Machinery and equipment		400,175			378,868
Gas transportation facilities and equipment		40,795			40,748
Oil and gas properties		96,091			95,252
Mineral interests in oil and gas properties		22,193			21,939
		606,160			583,402
Less — Accumulated depreciation and depletion		(369,969	)		(350,630	)
Net property and equipment		236,191			232,772
Other assets:
Investment in affiliates		61,947			44,073
Goodwill		93,758			92,532
Other intangible assets, net		26,180			19,649
Restricted deposits-long term		3,704			3,151
Other		8,789			8,427
Total other assets		194,378			167,832
	$	764,138		$	730,955

See Notes to Consolidated Financial Statements.

— Continued —

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LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS — (Continued)
(in thousands, except per share data)

	July 31,			January 31,
	2010			2010
	(unaudited)			(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	90,627		$	87,818
Current maturities of long term debt		20,000			20,000
Accrued compensation		31,671			33,572
Accrued insurance expense		9,235			9,255
Other accrued expenses		20,812			16,779
Acquisition escrow obligation-current		1,113			1,415
Income taxes payable		8,380			4,219
Billings in excess of costs and estimated earnings on uncompleted contracts		46,100			37,644
Total current liabilities		227,938			210,702
Noncurrent and deferred liabilities:
Long-term debt		6,667			6,667
Accrued insurance expense		11,638			10,759
Deferred income taxes		14,072			17,761
Acquisition escrow obligation-long term		3,704			3,151
Other		19,274			15,042
Total noncurrent and deferred liabilities		55,355			53,380
Common stock, par value $.01 per share, 30,000 shares authorized, 19,505 and 19,435 shares issued and outstanding, respectively		195			194
Capital in excess of par value		345,154			342,952
Retained earnings		142,739			129,718
Accumulated other comprehensive loss		(7,318	)		(6,066	)
Total Layne Christensen Company stockholders’ equity		480,770			466,798
Noncontrolling interest		75			75
Total equity		480,845			466,873
	$	764,138		$	730,955

See Notes to Consolidated Financial Statements.

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LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per share data)

	Three Months						Six Months
	Ended July 31,						Ended July 31,
	(unaudited)						(unaudited)
	2010			2009			2010			2009
Revenues	$	253,300		$	217,227		$	484,015		$	421,419
Cost of revenues (exclusive of depreciation, depletion and amortization shown below)		(197,746	)		(165,549	)		(369,658	)		(325,453	)
Selling, general and administrative expenses		(31,698	)		(30,304	)		(65,213	)		(62,004	)
Depreciation, depletion and amortization		(12,131	)		(14,278	)		(26,256	)		(28,611	)
Impairment of oil and gas properties		—			(21,642	)		—			(21,642	)
Litigation settlement gains		—			—			—			3,161
Equity in earnings of affiliates		1,614			2,351			3,487			4,286
Interest expense		(517	)		(812	)		(1,043	)		(1,622	)
Other income (expense), net		189			(13	)		76			(638	)
Income (loss) before income taxes		13,011			(13,020	)		25,408			(11,104	)
Income tax benefit (expense)		(6,561	)		4,380			(12,387	)		3,460
Net income (loss) attributable to Layne Christensen Company	$	6,450		$	(8,640	)	$	13,021		$	(7,644	)
Basic income (loss) per share	$	0.33		$	(0.45	)	$	0.67		$	(0.40	)
Diluted income (loss) per share	$	0.33		$	(0.45	)	$	0.67		$	(0.40	)
Weighted average shares outstanding-basic		19,386			19,316			19,378			19,307
Dilutive stock options		136			—			148			—
Weighted average shares outstanding-diluted		19,522			19,316			19,526			19,307

See Notes to Consolidated Financial Statements.

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LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(in thousands, except share data)

															Total Layne
												Accumulated			Christensen
						Capital In						Other			Company
	Common Stock					Excess of			Retained			Comprehensive			Stockholders’			Noncontrolling
	Shares			Amount		Par Value			Earnings			Income (Loss)			Equity			Interest		Total
Balance, January 31, 2009		19,382,976		$	194	$	337,528		$	128,353		$	(10,053	)	$	456,022		$	75	$	456,097
Comprehensive loss:
Net loss		—			—		—			(7,644	)		—			(7,644	)		—		(7,644	)
Other comprehensive income:
Foreign currency translation adjustments, net of income tax expense of $680		—			—		—			—			1,803			1,803			—		1,803
Change in unrealized loss on foreign exchange contracts, net of income tax benefit of $372		—			—		—			—			581			581			—		581
Comprehensive loss																(5,260	)				(5,260	)
Issuance of unvested shares		12,771			—		—			—			—			—			—		—
Treasury stock purchased and subsequently cancelled		(5,217	)		—		(109	)		—			—			(109	)		—		(109	)
Issuance of stock upon exercise of options		7,741			—		32			—			—			32			—		32
Income tax benefit on exercise of options		—			—		46			—			—			46			—		46
Income tax deficiency upon vesting of restricted shares		—			—		(177	)		—			—			(177	)		—		(177	)
Share-based compensation		—			—		3,753			—			—			3,753			—		3,753
Issuance of stock upon acquisition of business		12,677			—		280			—			—			280			—		280
Balance, July 31, 2009		19,410,948		$	194	$	341,353		$	120,709		$	(7,669	)	$	454,587		$	75	$	454,662
Balance, January 31, 2010		19,435,209		$	194	$	342,952		$	129,718		$	(6,066	)	$	466,798		$	75	$	466,873
Comprehensive income:
Net income		—			—		—			13,021			—			13,021			—		13,021
Other comprehensive income (loss):
Foreign currency translation adjustments, net of income tax benefit of $315		—			—		—			—			(1,288	)		(1,288	)		—		(1,288	)
Change in unrealized loss on foreign exchange contracts, net of income tax expense of $23		—			—		—			—			36			36			—		36
Comprehensive income																11,769					11,769
Issuance of unvested shares		58,709			1		(1	)		—			—			—			—		—
Treasury stock purchased and subsequently cancelled		(5,279	)		—		(132	)		—			—			(132	)		—		(132	)
Issuance of stock upon exercise of options		16,744			—		99			—			—			99			—		99
Income tax benefit on exercise of options		—			—		158			—			—			158			—		158
Income tax deficiency upon vesting of restricted shares		—			—		(112	)		—			—			(112	)		—		(112	)
Share-based compensation		—			—		2,190			—			—			2,190			—		2,190
Balance, July 31, 2010		19,505,383		$	195	$	345,154		$	142,739		$	(7,318	)	$	480,770		$	75	$	480,845

See Notes to Consolidated Financial Statements.

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LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW
(in thousands)

		Six Months
		Ended July 31,
		(unaudited)
		2010			2009
Cash flow from operating activities:
Net income (loss)		$	13,021		$	(7,644	)
Adjustments to reconcile net income (loss) to cash from operations:
Depreciation, depletion and amortization			26,256			28,611
Deferred income taxes			(4,671	)		(10,156	)
Share-based compensation			2,190			3,753
Share-based compensation excess tax benefits			(158	)		(46	)
Equity in earnings of affiliates			(3,487	)		(4,286	)
Dividends received from affiliates			1,763			1,556
Gain from disposal of property and equipment			(409	)		(7	)
Impairment of oil and gas properties			—			21,642
Non-cash litigation settlement gain			—			(2,868	)
Changes in current assets and liabilities, net of effects of acquisitions:
(Increase) decrease in customer receivables			(41,327	)		3,176
Decrease (increase) in costs and estimated earnings in excess of billings on uncompleted contracts			2,261			(1,450	)
(Increase) decrease in inventories			(1,434	)		2,148
(Increase) decrease in other current assets			(2,036	)		6,364
Increase (decrease) in accounts payable and accrued expenses			11,124			(16,776	)
Increase in billings in excess of costs and estimated earnings on uncompleted contracts			9,606			12,144
Other, net			(122	)		(386	)
Cash provided by operating activities			12,577			35,775
Cash flow from investing activities:
Additions to property and equipment			(29,036	)		(19,188	)
Additions to gas transportation facilities and equipment			(46	)		(783	)
Additions to oil and gas properties	��		(839	)		(2,375	)
Additions to mineral interests in oil and gas properties			(254	)		(401	)
Acquisition of business, net of cash acquired			(5,500	)		(600	)
Investment in foreign affiliate			(16,150	)		—
Payment of cash purchase price adjustment on prior year acquisition			(226	)		(1,349	)
Proceeds from sale of business			4,800			—
Proceeds from disposal of property and equipment			970			277
Release of cash from restricted accounts			302			515
Distribution of restricted cash for prior year acquisitions			(302	)		(515	)
Cash used in investing activities			(46,281	)		(24,419	)
Cash flow from financing activities:
Repayments of long term debt			—			(13,333	)
Issuance of common stock upon exercise of stock options			99			32
Excess tax benefit on exercise of share-based instruments			158			46
Purchases and retirement of treasury stock			(132	)		(109	)
Cash provided by (used in) financing activities			125			(13,364	)
Effects of exchange rate changes on cash			(1,687	)		(318	)
Net decrease in cash and cash equivalents			(35,266	)		(2,326	)
Cash and cash equivalents at beginning of period			84,450			67,165
Cash and cash equivalents at end of period		$	49,184		$	64,839

See Notes to Consolidated Financial Statements.

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LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. Accounting Policies and Basis of Presentation

Principles of Consolidation— The consolidated financial statements include the accounts of Layne Christensen Company and its subsidiaries (together, the “Company”). Intercompany transactions have been eliminated. Investments in affiliates (20% to 50% owned) in which the Company exercises influence over operating and financial policies are accounted for by the equity method. The unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements of the Company for the year ended January 31, 2010, as filed in its Annual Report on Form 10-K.

The accompanying unaudited consolidated financial statements include all adjustments (consisting only of normal recurring accruals) which, in the opinion of management, are necessary for a fair presentation of financial position, results of operations and cash flows. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year. The Company has evaluated subsequent events through the time of the filing of these Consolidated Financial Statements.

Use of Estimates in Preparing Financial Statements —The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenue Recognition —Revenues are recognized on large, long-term construction contracts using the percentage-of-completion method based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions, change orders and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined. Contracts for the Company’s mineral exploration drilling services are billable based on the quantity of drilling performed and revenues for these drilling contracts are recognized on the basis of actual footage or meterage drilled. Revenue is recognized on smaller, short-term construction contracts using the completed contract method. Provisions for estimated losses on uncompleted construction contracts are made in the period in which such losses are determined.

Revenues for direct sales of equipment and other ancillary products not provided in conjunction with the performance of construction contracts are recognized at the date of delivery to, and acceptance by, the customer. Provisions for estimated warranty obligations are made in the period in which the sales occur.

Revenues for the sale of oil and gas by the Company’s energy division are recognized on the basis of volumes sold at the time of delivery to an end user or an interstate pipeline, net of amounts attributable to royalty or working interest holders.

The Company’s revenues are presented net of taxes imposed on revenue-producing transactions with its customers, such as, but not limited to, sales, use, value-added, and some excise taxes.

Oil and Gas Properties and Mineral Interests— The Company follows the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, and salaries, benefits and other internal salary-related costs directly attributable to these activities. Costs associated with production and general corporate activities are expensed in the period incurred. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized. Depletion expense was $3,717,000 and $7,148,000 for the six months ended July 31, 2010 and 2009, respectively.

The Company is required to review the carrying value of its oil and gas properties under the full cost accounting rules of the SEC (the “Ceiling Test”). The ceiling limitation is the estimated after-tax future net revenues from proved oil and gas properties discounted at 10%, plus the cost of properties not subject to amortization. If our net book value of oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense. Beginning with our fiscal 2010 year end, application of the Ceiling Test requires pricing future revenues at the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end

7

of reporting period, unless prices are defined by contractual arrangements, such as fixed-price physical delivery forward sales contracts, when held. Application of the Ceiling Test requires a write-down for accounting purposes if the ceiling is exceeded. Considerations of the Ceiling Test prior to fiscal 2010 year end used the period end prices as adjusted for contractual arrangements. Unproved oil and gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows.

Reserve Estimates— The Company’s estimates of natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material.

Goodwill and Other Intangibles— Goodwill and other intangible assets with indefinite useful lives are not amortized, and instead are periodically tested for impairment. The Company performs its annual impairment as of December 31, or more frequently if events or changes in circumstances indicate that an asset might be impaired. The process of evaluating goodwill for impairment involves the determination of the fair value of the Company’s reporting units. Inherent in such fair value determinations are certain judgments and estimates, including the interpretation of current economic indicators and market valuations, and assumptions about the Company’s strategic plans with regard to its operations. The Company believes at this time that the carrying value of the remaining goodwill is appropriate, although to the extent additional information arises or the Company’s strategies change, it is possible that the Company’s conclusions regarding impairment of the remaining goodwill could change and result in a material effect on its financial position or results of operations.

Other Long-lived Assets— In the event of an indication of possible impairment, the Company evaluates the fair value and future benefits of long-lived assets, including the Company’s gas transportation facilities and equipment, by performing an analysis of the anticipated, undiscounted future net cash flows to the carrying value of the related long-lived assets. If the carrying value of the long-lived assets exceeds the anticipated undiscounted cash flows the carrying value is written down to the fair value. The Company believes at this time that the carrying values and useful lives of its long-lived assets continue to be appropriate.

Cash and Cash Equivalents— The Company considers investments with an original maturity of three months or less when purchased to be cash equivalents. The Company’s cash equivalents are subject to potential credit risk. The Company’s cash management and investment policies restrict investments to investment grade, highly liquid securities. The carrying value of cash and cash equivalents approximates fair value.

Restricted Deposits— Restricted deposits consist of escrow funds associated with various acquisitions as described in Note 2 of the Notes to Consolidated Financial Statements.

Accrued Insurance Expense —The Company maintains insurance programs where it is responsible for a certain amount of each claim up to a self-insured limit. Estimates are recorded for health and welfare, property and casualty insurance costs that are associated with these programs. These costs are estimated based on actuarially determined projections of future payments under these programs. Should a greater amount of claims occur compared to what was estimated or costs of the medical profession increase beyond what was anticipated, reserves recorded may not be sufficient and additional costs to the consolidated financial statements could be required.

Costs estimated to be incurred in the future for employee medical benefits, property, workers’ compensation and casualty insurance programs resulting from claims which have occurred are accrued currently. Under the terms of the Company’s agreement with the various insurance carriers administering these claims, the Company is not required to remit the total premium until the claims are actually paid by the insurance companies. These costs are not expected to significantly impact liquidity in future periods.

8

Income Taxes— Income taxes are provided using the asset/liability method, in which deferred taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and tax bases of existing assets and liabilities. Deferred tax assets are reviewed for recoverability and valuation allowances are provided as necessary. Provision for U.S. income taxes on undistributed earnings of foreign subsidiaries and affiliates is made only on those amounts in excess of funds considered to be invested indefinitely. In general, the Company records income tax expense during interim periods based on its best estimate of the full year’s effective tax rate. However, income tax expense relating to adjustments to the Company’s liabilities for uncertainty in income tax positions is accounted for discretely in the interim period in which it occurs.

As of July 31 and January 31, 2010, the total amount of unrecognized tax benefits recorded was $10,007,000 and $9,312,000, respectively, of which substantially all would affect the effective tax rate if recognized. The Company does not expect the unrecognized tax benefits to change materially within the next 12 months. The Company classifies uncertain tax positions as non-current income tax liabilities unless expected to be paid in one year. The Company reports income tax-related interest and penalties as a component of income tax expense. As of July 31 and January 31, 2010, the total amount of accrued income tax-related interest and penalties included in the balance sheet was $4,334,000 and $3,686,000, respectively.

Litigation and Other Contingencies— The Company is involved in litigation incidental to its business, the disposition of which is not expected to have a material effect on the Company’s business, financial position, results of operations or cash flows. It is possible, however, that future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions related to these proceedings. The Company accrues its best estimate of the probable cost for the resolution of legal claims. Such estimates are developed in consultation with outside counsel handling these matters and are based upon a combination of litigation and settlement strategies. To the extent additional information arises or the Company’s strategies change, it is possible that the Company’s estimate of its probable liability in these matters may change.

Derivatives —The Company follows current accounting guidance which requires derivative financial instruments to be recorded on the balance sheet at fair value and establishes criteria for designation and effectiveness of hedging relationships. The Company accounts for its unrealized hedges of forecasted costs as cash flow hedges, such that changes in fair value for the effective portion of hedge contracts, are recorded in accumulated other comprehensive income in stockholders’ equity. Changes in the fair value of the effective portion of hedge contracts are recognized in accumulated other comprehensive income until the hedged item is recognized in operations. The ineffective portion of the derivatives’ change in fair value, if any, is immediately recognized in operations. In addition, the Company periodically enters into natural gas contracts to manage fluctuations in the price of natural gas. These contracts result in the Company physically delivering gas, and as a result, are exempt from fair value accounting under the normal purchases and sales exception. When in place, the contracts are not reflected in the balance sheet at fair value and revenues from the contracts are recognized as the natural gas is delivered under the terms of the contracts. The Company does not enter into derivative financial instruments for speculative or trading purposes.

Earnings per share— Earnings per share are based upon the weighted average number of common and dilutive equivalent shares outstanding. Options to purchase common stock and unvested restricted shares are included based on the treasury stock method for dilutive earnings per share, except when their effect is antidilutive. Options to purchase 586,063 and 588,784 shares have been excluded from weighted average shares in the three and six months ending July 31, 2010, respectively, as their effect was antidilutive. A total of 100,873 and 110,109 nonvested shares have been excluded from weighted average shares in the three and six month ending July 31, 2010, respectively, as their effect was antidilutive. Options to purchase 1,050,645 shares and 79,836 nonvested shares were excluded from weighted average shares in both the three and six months ending July 31, 2009 as their effect was antidilutive.

Share-based compensation— The Company recognizes all share-based instruments in the financial statements and utilizes a fair-value measurement of the associated costs. The Company elected to adopt the original accounting standard using the Modified Prospective Method which required recognition of all unvested share-based instruments as of the effective date over the remaining term of the instrument. As of July 31, 2010, the Company had unrecognized compensation expense of $3,082,000 to be recognized over a weighted average period of 1.48 years. The Company determines the fair value of share-based compensation granted in the form of stock options using the Black-Scholes model.

9

Supplemental Cash Flow Information— The amounts paid for income taxes and interest are as follows (in thousands):

	Six Months
	Ended July 31,
	2010		2009
Income taxes	$	8,722	$	6,075
Interest		978		1,948

The Company had earnings on restricted deposits of $3,000 and $1,000 for the six months ended July 31, 2010 and 2009, respectively, which were treated as non-cash items as the earnings were restricted for the account of the escrow beneficiaries. For the six months ended July 31, 2009, the Company received land and buildings valued at $2,828,000 in a non-cash settlement of a legal dispute in Australia, and made a non-cash distribution of $280,000 of common stock for a prior year acquisition. See Note 2 for a discussion of acquisition activity.

During fiscal year 2009, the Company entered into financing obligations for software licenses amounting to $1,298,000, payable over three years. The associated assets are recorded as Other Intangible Assets in the balance sheet.

New Accounting Pronouncements— In January 2010, the FASB issued guidance amending Accounting Standards Codification (“ASC”) Topic 820 to require new disclosures concerning transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and activity in Level 3 measurements. In addition, the guidance clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The Company adopted this guidance as of February 1, 2010, which did not have a material impact on its financial position, results of operations or cash flows.

In December 2009, the FASB issued guidance amending the consolidation guidance applicable to variable interest entities. The amendments affect the overall consolidation analysis under ASC Topic 810, “Consolidation.” The Company adopted this guidance as of February 1, 2010, which did not have a material impact on its financial position, results of operations or cash flows.

2. Acquisitions

Fiscal Year 2011

On July 27, 2010, the Company acquired certain assets of Intevras Technologies, LLC (“Intevras”), a Texas based company focused on the treatment, filtration, handling and evaporative crystallization and disposal of industrial wastewaters.

The purchase price of $8,824,000 was comprised of cash of $5,500,000, $550,000 of which was placed in escrow to secure certain representations, warranties and idemnifications, and contingent consideration of $3,324,000.

In accordance with accounting guidance, acquisition related costs were recorded as an expense in the periods in which the costs were incurred. The purchase price has been allocated based on a preliminary assessment of the fair value of the assets acquired and the fair value of contingent consideration to be paid, determined based on the Company’s internal operational assessments and other analyses. Such amounts may be subject to revision as valuations of intangible assets are finalized. Revisions will be recorded by the Company as further adjustments to the purchase price allocation.

In addition to the cash purchase price, there is contingent consideration up to a maximum of $10,000,000 (the “Intevras Earnout Amount”), which is based on a percentage of revenues earned on Intevras products and fixed amounts per barrel of water treated by Intevras products during the 60 months following the acquisition. In accordance with accounting guidance the Company treated the Intevras Earnout Amount as contigent consideration and estimated the liability at fair value as of the acquistion date and included such consideration as a component of total purchase price as noted above. The potential undiscounted amount of all future payments that the Company could be required to make under the agreement is between $0 and $10,000,000. The fair value of the contingent consideration arrangement of $3,324,000 was estimated by applying a market approach. That measure is based on significant inputs that are not observable in the market, also referred to as Level 3 inputs. Key assumptions include a discount rate range of 0.3% to 1.82% and an estimated level of annual revenues of Intevras ranging from $8,000,000 to $27,000,000.

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Based on the Company’s preliminary allocations of the purchase price, the acquisition had the following effect on the Company’s consolidated financial position as of the closing date:

(in thousands)
Property and equipment	$	500
Goodwill		1,000
Other intangible assets		7,324
Total purchase price	$	8,824

The intangible assets consist of patents valued on a preliminary basis at $7,324,000, and have a weighted-average life of 15 years. The $1,000,000 of aggregate goodwill was assigned to the water infrastructure segment and is expected to be deductible for tax purposes.

The results of operations of Intevras have been included in the Company’s consolidated statements of income commencing on the closing date. Pro forma amounts for prior periods have not been presented since the acquisition would not have had a significant effect on the Company’s consolidated revenues or net income.

On July 15, 2010, the Company acquired 50% interest in Diberil Sociedad Anónima (“Diberil”), a Uruguayan company and parent company to Costa Fortuna (Brazil and Uruguay). Diberil, with operations in Sao Paulo, Brazil, and Montevideo, Uruguay, is one of the largest providers of specialty foundation and specialized marine geotechnical services in South America. The Company will account for Diberil as an equity method investment (see Note 13).

In addition to the above acquisitions, the Company paid $226,000 as contingent earnout consideration on prior year acquisitions.

Fiscal Year 2010

The Company completed three acquisitions during fiscal 2010 as described below:

• On December 9, 2009, the Company acquired certain assets of MCL Technology Corporation (“MCL”), an Arizona-based provider of commercial and industrial reverse osmosis, deionization and filtration services.

• On October 30, 2009, the Company acquired 100% of the stock of W.L. Hailey & Company, Inc. (“Hailey”), a water and wastewater solutions firm in Tennessee. The operation was combined with similar service lines and serves to foster the Company’s further expansion of these product lines into the southeast.

• On May 1, 2009, the Company acquired equipment and other assets of Meadow Equipment Sales & Service, Inc. (“Meadow”), a construction company operating primarily in the Midwestern United States.

The aggregate cash purchase price of $16,961,000, comprised of cash ($3,150,000 of which was placed in escrow to secure certain representations, warranties and idemnifications), was as follows:

(in thousands)	MCL		Hailey		Meadow		Total
Cash purchase price	$	1,500	$	14,861	$	600	$	16,961
Escrow deposits		150		3,000		—		3,150

In accordance with new accounting guidance, beginning in fiscal 2010 acquisition related costs were recorded as an expense in the periods in which the costs were incurred. The purchase price for each acquisition has been allocated based on the fair value of the assets and liabilities acquired, determined based on the Company’s internal operational assessments and other analyses. Based on the Company’s allocations of the purchase price, the acquisitions had the following effect on the Company’s consolidated financial position as of their respective closing dates:

(in thousands)	MCL		Hailey			Meadow		Total
Working capital	$	80	$	4,861		$	—	$	4,941
Property and equipment		983		9,515			575		11,073
Goodwill		273		585			—		858
Other intangible assets		164		—			25		189
Deferred taxes		—		(100	)		—		(100	)
Total purchase price	$	1,500	$	14,861		$	600	$	16,961

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The identifiable intangible assets associated with Meadow consist of non-compete agreements valued at $25,000 and have a weighted-average life of three years. The identifiable intangible assets associated with MCL consist of design efficiencies that provide a margin advantage over competitors valued at $164,000 and have a weighted-average life of five years. The $858,000 of aggregate goodwill was assigned to the water infrastructure segment and is expected to be deductible for tax purposes. The results of operations of the acquired entities have been included in the Company’s consolidated statements of income commencing with the respective closing dates. Pro forma amounts related to Meadow and MCL for prior periods have not been presented since the acquisitions would not have had a significant effect on the Company’s consolidated revenues or net income. Assuming Hailey had been acquired as of the beginning of fiscal 2010, the unaudited pro forma consolidated revenues, net income and net income per share of the Company would be as follows:

	Three Months Ended			Six Months Ended
(in thousands, except per share data)	July 31, 2009			July 31, 2009
Revenues	$	242,379		$	467,575
Net income attributable to Layne Christensen Company		(7,863	)		(6,258	)
Basic income per share	$	(0.41	)	$	(0.32	)
Diluted income per share	$	(0.41	)	$	(0.32	)

The pro forma information provided above is not necessarily indicative of the results of operations that would actually have resulted if the acquisition was made as of those dates or of results that may occur in the future.

In addition to the above acquisitions, the company paid $1,349,000 in cash and issued 12,677 shares of Layne common stock (valued at $280,000) as contingent earnout consideration on prior year acquisitions.

3. Goodwill and Other Intangible Assets

Goodwill and other intangible assets consist of the following (in thousands):

	July 31, 2010							January 31, 2010
						Weighted							Weighted
						Average							Average
	Gross					Amortization		Gross					Amortization
	Carrying		Accumulated			Period in		Carrying		Accumulated			Period in
	Amount		Amortization			years		Amount		Amortization			years
Goodwill	$	93,758	$	—				$	92,532	$	—
Amortizable intangible assets:
Tradenames	$	18,962	$	(3,491	)		29	$	18,962	$	(3,086	)		29
Customer-related		332		(332	)		—		332		(332	)		—
Patents		10,476		(849	)		15		3,152		(755	)		15
Non-competition agreements		464		(442	)		2		464		(423	)		2
Other		2,754		(1,694	)		12		2,754		(1,419	)		12
Total amortizable intangible assets	$	32,988	$	(6,808	)			$	25,664	$	(6,015	)

Amortizable intangible assets are being amortized over their estimated useful lives of two to 40 years with a weighted average amortization period of 23 years. Total amortization expense for other intangible assets was $394,000 and $386,000 for the three months ended July 31, 2010 and 2009, respectively, and $794,000 and $770,000 for the six months ended July 31, 2010 and 2009, respectively.

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The carrying amount of goodwill attributed to each operating segment was as follows (in thousands):

			Water
	Energy		Infrastructure		Total
Balance February 1, 2010	$	950	$	91,582	$	92,532
Additions		—		1,226		1,226
Balance, July 31, 2010	$	950	$	92,808	$	93,758

4. Indebtedness

The Company maintains an agreement (“Master Shelf Agreement”) whereby it can issue an additional $50,000,000 in unsecured notes before September 15, 2012. On July 31, 2003, the Company issued $40,000,000 of notes (“Series A Senior Notes”) under the Master Shelf Agreement. The Series A Senior Notes bear a fixed interest rate of 6.05%, with annual principal payments of $13,333,000. Final payment on the Series A Senior Notes was made on August 2, 2010. The Company issued an additional $20,000,000 of notes under the Master Shelf Agreement in October 2004 (“Series B Senior Notes”). The Series B Senior Notes bear a fixed interest rate of 5.40% and are due on September 29, 2011, with annual principal payments of $6,667,000.

The Company also maintains a revolving credit facility under an Amended and Restated Loan Agreement (the “Credit Agreement”) with Bank of America, N.A., as Administrative Agent and as Lender (the “Administrative Agent”), and the other Lenders listed therein (the “Lenders”), which contains a revolving loan commitment of $200,000,000, less any outstanding letter of credit commitments (which are subject to a $30,000,000 sublimit).

The Credit Agreement provides for interest at variable rates equal to, at the Company’s option, a LIBOR rate plus 0.75% to 2.00%, or a base rate, as defined in the Credit Agreement, plus up to 0.50%, depending upon the Company’s leverage ratio. The Credit Agreement is unsecured and is due and payable November 15, 2011. On July 31, 2010, there were letters of credit of $23,851,000 and no borrowings outstanding on the Credit Agreement resulting in available capacity of $176,149,000.

The Master Shelf Agreement and the Credit Agreement contain certain covenants including restrictions on the incurrence of additional indebtedness and liens, investments, acquisitions, transfer or sale of assets, transactions with affiliates, payment of dividends and certain financial maintenance covenants, including among others, fixed charge coverage, leverage and minimum tangible net worth. The Company was in compliance with its covenants as of July 31, 2010.

Debt outstanding as of July 31, 2010, and January 31, 2010, whose carrying value approximates fair value, was as follows (in thousands):

	July 31,			January 31,
	2010			2010
Long-term debt:
Credit Agreement	$	—		$	—
Senior Notes		26,667			26,667
Total debt		26,667			26,667
Less current maturities		(20,000	)		(20,000	)
Total long-term debt	$	6,667		$	6,667

5. Derivatives

The Company has foreign operations that have significant costs denominated in foreign currencies, and thus is exposed to risks associated with changes in foreign currency exchange rates. At any point in time, the Company might use various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated with forecasted expatriate labor costs and purchases of operating supplies. As of July 31, 2010, the Company held option contracts with an aggregate U.S. dollar notional value of $3,580,000 which are intended to hedge exposure to Australian dollar fluctuations over a period to January 31, 2011. As of July 31, 2010 and January 31, 2010, the fair values of outstanding derivatives were losses of $42,000 and $102,000, respectively, recorded in other accrued expenses on the consolidated balance sheets. The fair value of foreign currency contracts is estimated based on comparable quotes from brokers. The Company does not enter into foreign currency derivative financial instruments for speculative or trading purposes.

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The Company’s energy division is exposed to fluctuations in the price of natural gas and enters into fixed-price physical delivery contracts to manage natural gas price risk for a portion of its production, if available at attractive prices. As of July 31, 2010 the Company held no such contracts.

Additionally, the Company has entered into physical delivery contracts in order to facilitate normal recurring sales with our natural gas purchasing counterparty. As of July 31, 2010, the Company had committed to deliver a total of 1,426,000 million British Thermal Units (“MMBtu”) of natural gas through October 2010. For 1,104,000 MMBtu the contract price resets monthly, on the first day of the month, based on a weighted average price of the trades reported during the last week of the previous month for gas deliveries in the current month. For 322,000 million MMBtu the contract price resets daily based on a weighted average price of the reported trades for deliveries on the following day.

6. Accumulated Other Comprehensive Income (Loss)

The components of accumulated other comprehensive income (loss) for the six months ended July 31, 2010 and 2009 are as follows (in thousands):

							Unrealized			Accumulated
	Cumulative			Unrecognized			Loss on			Other
	Translation			Pension			Exchange			Comprehensive
	Adjustment			Liability			Contracts			Loss
Balance, February 1, 2010	$	(6,004	)	$	—		$	(62	)	$	(6,066	)
Period change		(1,288	)		—			36			(1,252	)
Balance, July 31, 2010	$	(7,292	)	$	—		$	(26	)	$	(7,318	)
							Unrealized			Accumulated
	Cumulative			Unrecognized			Loss on			Other
	Translation			Pension			Exchange			Comprehensive
	Adjustment			Liability			Contracts			Loss
Balance, February 1, 2009	$	(8,940	)	$	(1,017	)	$	(96	)	$	(10,053	)
Period change		1,803			—			581			2,384
Balance, July 31, 2009	$	(7,137	)	$	(1,017	)	$	485		$	(7,669	)

7. Impairment of Oil and Gas Properties

As of July 31, 2010, the Company evaluated its oil and gas reserves and recoverability of capitalized cost of the energy division. This determination was made according to SEC guidelines and used average gas prices for July 31, 2010, of $3.91 per Mcf, compared to a price of $3.24 per Mcf for the evaluation for January 31, 2010 and $2.89 per Mcf for July 31, 2009. Based on the reserve determination, no Ceiling Test impairment was required for the three or six months ended July 31, 2010. For the three months ended July 31, 2009, the Company recorded a non-cash Ceiling Test impairment charge of $21,642,000, or $13,039,000 after income tax, for the carrying value of the assets in excess of future net cash flows. If gas pricing falls, additional impairments could occur. As of July 31, 2010, the remaining net book value of assets subject to Ceiling Test impairment was $24,074,000.

8. Litigation Settlement Gains

In fiscal 2000, the Company initiated litigation against a former owner of a subsidiary and associated partners. The action stemmed from alleged competition in violation of non-competition agreements, and sought damages for lost profits and recovery of legal expenses. During the six months ended July 31, 2009, the Company entered into an agreement whereby it received certain land and buildings in settlement of these claims. The settlement was valued at $2,828,000, based on management’s estimate of the fair market value of the land and buildings received considering current market conditions and information provided by a third party appraisal.

In fiscal 2008, the Company initiated litigation against former officers of a subsidiary and associated energy production companies. During September 2008, the Company entered into a settlement agreement whereby it received certain payments over a period through September 2009. Payments were received during the six months ended July 31, 2009, of $333,000, net of contingent attorney fees. There were no litigation settlement gains recorded in the six months ended July 31, 2010.

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9. Other Income (Expense)

Other income (expense) consisted of the following for the three and six months ended July 31, 2010 and 2009 (in thousands):

	Three Months Ended						Six Months Ended
	July 31,						July 31,
	2010			2009			2010			2009
Gain (loss) from disposal of property and equipment	$	345		$	(39	)	$	409		$	7
Interest income		51			165			124			221
Currency exchange loss		(59	)		(64	)		(192	)		(569	)
Other		(148	)		(75	)		(265	)		(297	)
Total	$	189		$	(13	)	$	76		$	(638	)

10. Employee Benefit Plans

The Company sponsored a pension plan covering certain hourly employees not covered by union-sponsored, multi-employer plans. Benefits were computed based mainly on years of service. On January 29, 2010, the Company terminated the plan and distributed $10,054,000 to an annuity provider and fulfilled the remaining obligations for approximately $300,000 in cash. These distributions triggered a settlement and resulted in a recognized settlement loss of $4,980,000 in fiscal 2010. Net periodic pension cost for the three and six months ended July 31, 2009 was $100,000 and $200,000, respectively.

The Company provides supplemental retirement benefits to its chief executive officer. Benefits are computed based on the compensation earned during the highest five consecutive years of employment reduced for a portion of Social Security benefits and an annuity equivalent of the chief executive’s defined contribution plan balance. The Company does not contribute to the plan or maintain any investment assets related to the expected benefit obligation. The Company has recognized the full amount of its actuarially determined pension liability. Net periodic pension cost of the supplemental retirement benefits for the three and six months ended July 31, 2010 and 2009 include the following components (in thousands):

	Three Months Ended				Six Months Ended
	July 31,				July 31,
	2010		2009		2010		2009
Service cost	$	87	$	73	$	174	$	146
Interest cost		43		44		86		88
Net periodic pension cost	$	130	$	117	$	260	$	234

11. Fair Value Measurements

The Company follows reporting guidance which defines fair value, establishes a three-level fair value hierarchy based upon the assumptions (inputs) used to price assets or liabilities, and expands disclosures about fair value measurements. The hierarchy requires the Company to maximize the use of observable inputs and minimize the use of unobservable inputs. The three levels of inputs used to measure fair value are listed below:

Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 — Observable inputs other than those included in Level 1, such as quoted market prices for similar assets and liabilities in active markets or quoted prices for identical assets in inactive markets.

Level 3 — Unobservable inputs reflecting the Company’s own assumptions and best estimate of what inputs market participants would use in pricing an asset or liability.

     The Company’s assessment of the significance of a particular input to the fair value in its entirety requires judgment and considers factors specific to the asset or liability. The Company’s financial instruments held at fair value, which include restrictive deposits held in acquisition escrow accounts and foreign currency option contracts, are presented as of the periods ended July 31, 2010 and January 31, 2010 (in thousands):

15

	Carrying			Fair Value Measurements
	Value			Level 1		Level 2			Level 3
July 31, 2010
Financial Assets:
Restricted deposits held at fair value	$	4,817		$	4,817	$	—		$	—
Financial Liabilities:
Forward currency contracts	$	(42	)	$	—	$	(42	)	$	—
January 31, 2010
Financial Assets:
Restricted deposits held at fair value	$	4,566		$	4,566	$	—		$	—
Financial Liabilities:
Forward currency contracts	$	(102	)	$	—	$	(102	)	$	—

The Company had no Level 3 fair value measurements at July 31, 2010 or January 31, 2010.

12. Stock and Stock Option Plans

In October 2008, the Company amended the Rights Agreement signed October 1998 whereby the Company has authorized and declared a dividend of one preferred share purchase right (“Right”) for each outstanding common share of the Company. Subject to limited exceptions, the Rights are exercisable if a person or group acquires or announces a tender offer for 20% or more of the Company’s common stock. Each Right will entitle shareholders to buy one one-hundredth of a share of a newly created Series A Junior Participating Preferred Stock of the Company at an exercise price of $75.00. The Company is entitled to redeem the Right at $0.01 per Right at any time before a person has acquired 20% or more of the Company’s outstanding common stock. The Rights expire three years from the date of grant.

The Company has stock option and employee incentive plans that provide for the granting of options to purchase or the issuance of shares of common stock at a price fixed by the Board of Directors or a committee. As of July 31, 2010, there were an aggregate of 2,850,000 shares registered under the plans, 1,390,343 of which remain available to be granted under the plans. Of this amount, 250,000 shares may only be granted as stock in payment of bonuses, and 1,140,343 may be issued as stock or options. The Company has the ability to issue shares under the plans either from new issuances or from treasury, although it has previously issued only new shares and expects to continue to issue new shares in the future. For the six months ended July 31, 2010, the Company granted approximately 59,000 restricted shares which generally ratably vest over periods of one to four years from the grant date.

The Company recognized $2,190,000 and $3,753,000 of compensation cost for these share-based plans during the six months ended July 31, 2010 and 2009, respectively. Of these amounts, $559,000 and $739,000, respectively, related to nonvested stock. The total income tax benefit recognized for share-based compensation arrangements was $854,000 and $1,464,000 for the six months ended July 31, 2010 and 2009, respectively.

A summary of nonvested share activity for the six months ended July 31, 2010, is as follows:

				Weighted		Aggregate
				Average		Intrinsic
	Number of			Grant Date		Value (in
	Shares			Fair Value		thousands)
Nonvested stock at January 31, 2010		79,336		$	36.23
Granted		58,709			27.42
Vested		(27,936	)		32.51
Nonvested stock at July 31, 2010		110,109		$	32.48	$	2,776

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Significant option groups outstanding at July 31, 2010, related exercise price and remaining contractual term follows:

							Remaining
							Contractual
Grant	Options		Options		Exercise		Term
Date	Outstanding		Exercisable		Price		(Months)
6/04		20,000		20,000	$	16.600		47
6/04		68,576		68,576		16.650		47
6/05		10,000		10,000		17.540		59
9/05		140,332		140,332		23.050		62
1/06		191,481		191,481		27.870		66
6/06		10,000		10,000		29.290		71
6/06		70,000		70,000		29.290		71
6/07		65,625		48,125		42.260		83
7/07		33,000		24,750		42.760		84
9/07		3,000		1,500		55.480		86
2/08		74,524		49,675		35.710		90
1/09		6,000		6,000		24.100		101
2/09		201,311		67,102		15.780		102
2/09		4,580		4,580		15.780		102
6/09		108,582		36,190		21.990		106
6/09		2,472		2,472		21.990		106
2/10		85,290		—		27.790		114
2/10		2,721		2,721		25.440		114
		1,097,494		753,504

All options were granted at an exercise price equal to the fair market value of the Company’s common stock at the date of grant. The weighted average fair value at the date of grant for the options granted was $16.08 and $9.92 for the six months ended July 31, 2010 and 2009, respectively. The options have terms of ten years from the date of grant and generally vest ratably over periods of one month to five years. Transactions for stock options for the six months ended July 31, 2010, were as follows:

	Stock Options
						Weighted
						Average
				Weighted		Remaining		Intrinsic
	Number of			Average		Contractual Term		Value
	Shares			Exercise Price		(years)		(in thousands)
Stock Option Activity Summary:
Outstanding at February 1, 2010		1,026,227		$	24.856		7.02	$	3,840
Granted		88,011			27.717				—
Exercised		(16,744	)		5.813				373
Canceled		—							—
Forfeited		—							—
Expired		—							—
Outstanding at July 31, 2010		1,097,494		$	25.376		6.86		3,445
Shares Exercisable		753,504		$	26.154		6.04	$	1,947

The aggregate intrinsic value was calculated using the difference between the current market price and the exercise price for only those options that have an exercise price less than the current market price.

13. Investment in Affiliates

The Company’s investments in affiliates are carried at the fair value of the investment consideration paid, adjusted for the Company’s equity in undistributed earnings or losses from the investment date and dividends declared by the investee.

On July 15, 2010, the Company acquired a 50% interest in Diberil Sociedad Anónima (“Diberil”), a Uruguayan company and parent company to Costa Fortuna (Brazil and Uruguay). Diberil, with operations in Sao Paulo, Brazil, and Montevideo, Uruguay, is one of the largest providers of specialty foundation and marine geotechnical services in South America. The interest was acquired for a total cash consideration of $14,900,000, of which $10,100,000 was paid to Diberil shareholders and $4,800,000

17

was paid to Diberil to purchase newly issued Diberil stock. Concurrent with the investment, Diberil purchased Layne GeoBrazil, an equipment leasing company in Brazil wholly owned by the Company, for a cash payment of $4,800,000. Subsequent to the acquisition, the Company invested an additional $1,250,000 in Diberil as its proportionate share of a capital contribution.

The Company’s other affiliates are generally engaged in mineral exploration drilling and the manufacture and supply of drilling equipment, parts and supplies.

A summary of affiliates and percentages owned are as follows as of July 31, 2010:

	Percentage
	Owned
Christensen Chile, S.A. (Chile)		50.00	%
Christensen Commercial, S.A. (Chile)		50.00
Geotec Boyles Bros., S.A. (Chile)		50.00
Boyles Bros. Diamantina, S.A. (Peru)		29.49
Christensen Commercial, S.A. (Peru)		35.38
Geotec, S.A. (Peru)		35.38
Boytec, S.A. (Panama)		50.00
Plantel Industrial S.A. (Chile)		50.00
Boytec Sondajes de Mexico, S.A. de C.V. (Mexico)		50.00
Geoductos Chile, S.A. (Chile)		50.00
Mining Drilling Fluids (Panama)		25.00
Diamantina Christensen Trading (Panama)		42.69
Boyles Bros. do Brasil Ltd. (Brazil)		40.00
Boytec, S.A. (Columbia)		50.00
Centro Internacional de Formacion S.A. (Chile)		50.00
Geoestrella S.A.(Chile)		25.00
Diberil Sociedad Anónima (Uruguay)		50.00

Financial information of the affiliates is reported with a one-month lag in the reporting period. Summarized financial information of the affiliates was as follows (in thousands):

	Three Months Ended				Six Months Ended
	July 31,				July 31,
	2010		2009		2010		2009
Revenues	$	70,592	$	54,105	$	135,515	$	105,540
Income before income taxes		11,429		10,472		22,717		20,499
Operating income		5,875		6,407		11,962		12,391
Net income		4,176		4,838		8,696		8,574

14. Operating Segments

The Company is a multinational company that provides sophisticated services and related products to a variety of markets, as well as being a producer of unconventional natural gas for the energy market. Management defines the Company’s operational organizational structure into discrete divisions based on its primary product lines. Each division comprises a combination of individual district offices, which primarily offer similar types of services and serve similar types of markets. The Company’s reportable segments are defined as follows:

Water Infrastructure Division

This division provides a full line of water-related services and products including soil stabilization, hydrological studies, site selection, well design, drilling and development, pump installation, and well rehabilitation. The division’s offerings include the design and construction of water and wastewater treatment facilities, the provision of filter media and membranes to treat volatile organics and other contaminants such as nitrates, iron, manganese, arsenic, radium and radon in groundwater, Ranney collector wells, sewer rehabilitation and water and wastewater transmission lines. The division also offers environmental services to assess and monitor groundwater contaminants.

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Mineral Exploration Division

This division provides a complete range of drilling services for the mineral exploration industry. Its aboveground and underground drilling activities include all phases of core drilling, diamond, reverse circulation, dual tube, hammer and rotary air-blast methods.

Energy Division

This division focuses on exploration and production of unconventional gas properties, primarily concentrating on projects in the mid-continent region of the United States.

Other

Other includes two small specialty energy service companies and any other specialty operations not included in one of the other divisions.

Financial information (in thousands) for the Company’s operating segments is presented below. Unallocated corporate expenses primarily consist of general and administrative functions performed on a company-wide basis and benefiting all operating segments. These costs include accounting, financial reporting, internal audit, treasury, corporate and securities law, tax compliance, certain executive management (chief executive officer, chief financial officer and general counsel) and board of directors.

	Three Months Ended						Six Months Ended
	July 31,						July 31,
	2010			2009			2010			2009
Revenues
Water infrastructure	$	193,990		$	174,141		$	366,895		$	342,228
Mineral exploration		50,785			30,257			96,663			55,051
Energy		5,843			11,988			15,392			22,309
Other		2,682			841			5,065			1,831
Total revenues	$	253,300		$	217,227		$	484,015		$	421,419
Equity in earnings of affiliates Mineral exploration	$	1,614		$	2,351		$	3,487		$	4,286
Income (loss) before income taxes
Water infrastructure	$	10,285		$	8,253		$	18,925		$	12,780
Mineral exploration		8,956			3,543			17,543			5,310
Energy		480			(17,473	)		2,997			(14,885	)
Other		544			(11	)		792			137
Unallocated corporate expenses		(6,737	)		(6,520	)		(13,806	)		(12,824	)
Interest expense		(517	)		(812	)		(1,043	)		(1,622	)
Total income (loss) before income taxes	$	13,011		$	(13,020	)	$	25,408		$	(11,104	)
Geographic Information
Revenue
United States	$	210,548		$	190,863		$	402,752		$	373,269
Africa/Australia		19,860			14,141			38,306			24,516
Mexico		12,909			5,988			23,564			10,996
Other foreign		9,983			6,235			19,393			12,638
Total revenues	$	253,300		$	217,227		$	484,015		$	421,419

15. Contingencies

The Company’s service activities involve certain operating hazards that can result in personal injury or loss of life, damage and destruction of property and equipment, damage to the surrounding areas, release of hazardous substances or wastes and other damage to the environment, interruption or suspension of site operations and loss of revenues and future business. The magnitude of these operating risks is amplified when the Company, as is frequently the case, conducts a project on a fixed-price, “turnkey” basis where the Company delegates certain functions to subcontractors but remains responsible to the customer for the subcontracted work. In addition, the Company is exposed to potential liability under foreign, federal, state and local laws and regulations, contractual indemnification agreements or otherwise in connection with its services and products. Litigation arising from any such occurrences may result in the Company being named as a defendant in lawsuits asserting large claims. Although

19

the Company maintains insurance protection that it considers economically prudent, there can be no assurance that any such insurance will be sufficient or effective under all circumstances or against all claims or hazards to which the Company may be subject or that the Company will be able to continue to obtain such insurance protection. A successful claim or damage resulting from a hazard for which the Company is not fully insured could have a material adverse effect on the Company. In addition, the Company does not maintain political risk insurance with respect to its foreign operations.

The Company is involved in various matters of litigation, claims and disputes which have arisen in the ordinary course of the Company’s business. The Company believes that the ultimate disposition of these matters will not, individually and in the aggregate, have a material adverse effect upon its business or consolidated financial position, results of operations or cash flows.

Item 1A. Risk Factors

There have been no significant changes to the risk factors disclosed under Item 1A in our Annual Report on form 10-K for the year ended January 31, 2010.

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

Cautionary Language Regarding Forward-Looking Statements

This Form 10-Q may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act of 1934. Such statements may include, but are not limited to, statements of plans and objectives, statements of future economic performance and statements of assumptions underlying such statements, and statements of management’s intentions, hopes, beliefs, expectations or predictions of the future. Forward-looking statements can often be identified by the use of forward-looking terminology, such as “should,” “intended,” “continue,” “believe,” “may,” “hope,” “anticipate,” “goal,” “forecast,” “plan,” “estimate” and similar words or phrases. Such statements are based on current expectations and are subject to certain risks, uncertainties and assumptions, including but not limited to prevailing prices for various commodities, unanticipated slowdowns in the Company’s major markets, the availability of credit, the risks and uncertainties normally incident to the construction industry and exploration for and development and production of oil and gas, the impact of competition, the effectiveness of operational changes expected to increase efficiency and productivity, worldwide economic and political conditions and foreign currency fluctuations that may affect worldwide results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially and adversely from those anticipated, estimated or projected. These forward-looking statements are made as of the date of this filing, and the Company assumes no obligation to update such forward-looking statements or to update the reasons why actual results could differ materially from those anticipated in such forward-looking statements.

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Results of Operations

The following table presents, for the periods indicated, the percentage relationship which certain items reflected in the Company’s consolidated statements of income bear to revenues and the percentage increase or decrease in the dollar amount of such items period to period.

													Period-to-Period
	Three Months						Six Months						Change
	Ended July 31,						Ended July 31,						Three			Six
	2010			2009			2010			2009			Months			Months
Revenues:
Water infrastructure		76.6	%		80.2	%		75.8	%		81.2	%		11.4	%		7.2	%
Mineral exploration		20.0			13.9			20.0			13.1			67.8			75.6
Energy		2.3			5.5			3.2			5.3			(51.3	)		(31.0	)
Other		1.1			0.4			1.0			0.4			218.9			176.6
Total net revenues		100.0	%		100.0	%		100.0	%		100.0	%		16.6			14.9
Cost of revenues		(78.1)	%		(76.2	)%		(76.4)	%		(77.2	)%		19.4			13.6
Selling, general and administrative expenses		(12.5	)		(13.9	)		(13.5	)		(14.7	)		4.6			5.2
Depreciation, depletion and amortization		(4.8	)		(6.6	)		(5.4	)		(6.8	)		(15.0	)		(8.2	)
Impairment of oil and gas properties		—			(10.0	)		—			(5.1	)		(100.0	)		(100.0	)
Litigation settlement gains		—			—			—			0.8			—			(100.0	)
Equity in earnings of affiliates		0.6			1.1			0.7			1.0			(31.3	)		(18.6	)
Interest expense		(0.2	)		(0.4	)		(0.2	)		(0.4	)		(36.3	)		(35.7	)
Other, net		0.1			—			—			(0.2	)		*			*
Income (loss) before income taxes		5.1			(6.0	)		5.2			(2.6	)		(199.9	)		(328.8	)
Income tax benefit (expense)		(2.6	)		2.0			(2.6	)		0.8			(249.8	)		(458.0	)
Net income (loss)		2.5	%		(4.0	)%		2.6	%		(1.8	)%		(174.7	)		(270.3	)

* not meaningful

Revenues, equity in earnings of affiliates and income (loss) before income taxes pertaining to the Company’s operating segments are presented below. Unallocated corporate expenses primarily consist of general and administrative functions performed on a company-wide basis and benefiting all operating segments. These costs include accounting, financial reporting, internal audit, treasury, corporate and securities law, tax compliance, certain executive management (chief executive officer, chief financial officer and general counsel), and board of directors. Operating segment revenues and income (loss) before income taxes are summarized as follows (in thousands):

	Three Months Ended						Six Months Ended
	July 31,						July 31,
	2010			2009			2010			2009
Revenues
Water infrastructure	$	193,990		$	174,141		$	366,895		$	342,228
Mineral exploration		50,785			30,257			96,663			55,051
Energy		5,843			11,988			15,392			22,309
Other		2,682			841			5,065			1,831
Total revenues	$	253,300		$	217,227		$	484,015		$	421,419
Equity in earnings of affiliates
Mineral exploration	$	1,614		$	2,351		$	3,487		$	4,286
Income (loss) before income taxes
Water infrastructure	$	10,285		$	8,253		$	18,925		$	12,780
Mineral exploration		8,956			3,543			17,543			5,310
Energy		480			(17,473	)		2,997			(14,885	)
Other		544			(11	)		792			137
Unallocated corporate expenses		(6,737	)		(6,520	)		(13,806	)		(12,824	)
Interest expense		(517	)		(812	)		(1,043	)		(1,622	)
Total income (loss) before income taxes	$	13,011		$	(13,020	)	$	25,408		$	(11,104	)

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Revenues increased $36,073,000, or 16.6% to $253,300,000, for the three months ended July 31, 2010, and $62,596,000, or 14.9%, to $484,015,000 for the six months ended July 31, 2010, as compared to the same periods last year. A further discussion of results of operations by division is presented below.

Cost of revenues increased $32,197,000, or 19.4% to $197,746,000 (78.1% of revenues) and $44,205,000, or 13.6% to $369,658,000 (76.4% of revenues) for the three and six months ended July 31, 2010, compared to $165,549,000 (76.2% of revenues) and $325,453,000 (77.2% of revenues) for the same periods last year. The increase as a percentage of revenues for the three months was primarily focused in the energy division as a result of nearly flat production costs combined with lower revenues due to the expiration of favorably priced forward sales contracts in the first quarter of fiscal 2011. The decrease as a percentage of revenues for the six months was focused in both the mineral exploration division as a result of increasing activity as well as the water infrastructure division as the result of higher profit margins during the first three months of the fiscal year on geoconstruction and specialty drilling work.

Selling, general and administrative expenses were $31,698,000 and $65,213,000 for the three and six months ended July 31, 2010, compared to $30,304,000 and $62,004,000 for the same periods last year. The increases were primarily the result of increased compensation expenses of $1,874,000 and $4,182,000 due to higher earnings and $1,108,000 and $2,530,000 in added expenses from acquired operations for the three and six months, respectively, offset by reduction in various other expense categories.

Depreciation, depletion and amortization were $12,131,000 and $26,256,000 for the three and six months ended July 31, 2010, compared to $14,278,000 and $28,611,000 for the same periods last year. The decreases were primarily due to lower depletion in the energy division as a result of updated estimates of economically recoverable gas reserves.

The Company recorded a non-cash Ceiling Test impairment of oil and gas properties of $21,642,000 for the three months ended July 31, 2009, primarily as a result of a significant continued decline in natural gas prices and the expiration of higher priced forward sales contracts. There were no impairments recorded for the six months ending July 31, 2010.

During the six months ended July 31, 2009, the Company received litigation settlements valued at $3,161,000. The settlements included receipt of land and buildings valued at $2,828,000, and cash receipts of $333,000, net of contingent attorney fees. There were no litigation settlement gains in the six months ended July 31, 2010.

Equity in earnings of affiliates was $1,614,000 and $3,487,000 for the three and six months ended July 31, 2010, compared to $2,351,000 and $4,286,000 for the same periods last year. The decreased earnings are primarily a result of a customer-driven project delay at a large South American mine site.

Interest expense decreased to $517,000 and $1,043,000 for the three and six months ended July 31, 2010, compared to $812,000 and $1,622,000 for the same periods last year. The decreases were a result of scheduled debt reductions.

Income tax expenses of $6,561,000 (an effective rate of 50.4%) and $12,387,000 (an effective rate of 48.8%) were recorded for the three and six months ended July 31, 2010, respectively, compared to income tax benefits of $4,380,000 (an effective rate of 33.6%) and $3,460,000 (an effective rate of 31.2%) for the same periods last year, including an $8,603,000 benefit related to the non-cash impairment charge of proved oil and gas properties recorded as a discrete item in the three months ended July 31, 2009. Excluding the impairment and related tax benefit, the Company would have recorded income tax expense of $4,223,000 (an effective rate of 49.0%) and $5,143,000 (an effective rate of 48.8%) for the three and six months ended July 31, 2009. The effective rate in excess of the statutory federal rate for the periods was due primarily to the impact of nondeductible expenses and the tax treatment of certain foreign operations.

Water Infrastructure Division
(in thousands)

	Three months ended				Six months ended
	July 31,				July 31,
	2010		2009		2010		2009
Revenues	$	193,990	$	174,141	$	366,895	$	342,228
Income before income taxes		10,285		8,253		18,925		12,780

Water infrastructure revenues increased 11.4% to $193,990,000 and 7.2% to $366,895,000 for the three and six months ended July 31, 2010, respectively, compared to $174,141,000 and $342,228,000 for the same periods last year. The increases were primarily attributable to additional revenues from acquired operations and specialty drilling projects including work in Afghanistan. The increases were partially offset by a reduction in revenue from a large utility contract in Colorado

22

that was substantially completed last year.

Income before income taxes for the water infrastructure division increased 24.6% to $10,285,000 and 48.1% to $18,925,000 for the three and six months ended July 31, 2010, respectively, compared to $8,253,000 and $12,780,000 for the same periods last year. The increases in income before income taxes were primarily from the New Orleans geoconstruction and Afghanistan projects.

The backlog in the water infrastructure division was $526,972,000 as of July 31, 2010, compared to $553,034,000 as of April 30, 2010, and $453,384,000 as of July 31, 2009.

Mineral Exploration Division

(in thousands)

	Three months ended				Six months ended
	July 31,				July 31,
	2010		2009		2010		2009
Revenues	$	50,785	$	30,257	$	96,663	$	55,051
Income before income taxes		8,956		3,543		17,543		5,310

Mineral exploration revenues increased 67.8% to $50,785,000 and 75.6% to $96,663,000 for the three and six months ended July 31, 2010, respectively, compared to $30,257,000 and $55,051,000 for the same periods last year. The increased activity levels which began in the fourth quarter of last year continued across most locations with the largest increases in Africa and Mexico.

Income before income taxes for the mineral exploration division increased 152.8% to $8,956,000 and 230.4% to $17,543,000 for the three and six months ended July 31, 2010, respectively, compared to $3,543,000 and $5,310,000 for the same periods last year. The increases were primarily attributable to stronger earnings in Africa, Mexico and the western U.S. During the six month period in the prior year, the Company had two unusual items, receipt of a litigation settlement in Australia of $2,828,000 and increased non-income tax expense of $2,244,000 due to a reassessment of the recoverability of value added taxes and accruals for certain other non-income tax expenses in certain foreign jurisdictions.

Energy Division

(in thousands)

	Three months ended					Six months ended
	July 31,					July 31,
	2010		2009			2010		2009
Revenues	$	5,843	$	11,988		$	15,392	$	22,309
Income (loss) before income taxes		480		(17,473	)		2,997		(14,885	)

Energy revenues decreased 51.3% to $5,843,000 and 31.0% to $15,392,000 for the three and six months ended July 31, 2010, respectively, compared to revenues of $11,988,000 and $22,309,000 for the same periods last year. The decreases were primarily attributable to the expiration of favorably priced forward sales contracts.

For the three months ended July 31, 2009, the Company recorded a non-cash Ceiling Test impairment charge of $21,642,000, or $13,039,000 after income tax, for the carrying value of the assets in excess of future net cash flows.

Excluding the non-cash impairment charge, income before income taxes for the energy division decreased to $480,000 and $2,997,000 for the three and six months ended July 31, 2010, respectively, compared to $4,169,000 and $6,757,000 for the same periods last year. The decreases in income before income taxes were due to the impact on revenues from the expiration of forward sales contracts as noted above, partially offset by lower depletion.

For the three and six months ended July 31, 2010, net gas production was 1,143 Mmcf and 2,285 Mmcf, compared to 1,151 Mmcf and 2,359 Mmcf for the same periods last year. The average net sales price on production for the three and six months ended July 31, 2010, was $4.12 and $5.67 per Mcf, respectively, compared to $8.85 and $8.08 per Mcf for the same periods last year. The net sales price excludes revenues generated from third party gas.

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Other

	Three Months Ended					Six Months Ended
	July 31,					July 31,
	2010		2009			2010		2009
Revenue	$	2,682	$	841		$	5,065	$	1,831
Income (loss) before income tax		544		(11	)		792		137

Other revenues increased primarily as a result of machining and fabrication operations.

Unallocated Corporate Expenses

Corporate expenses not allocated to individual divisions, primarily included in selling, general and administrative expenses, were $6,737,000 and $13,806,000 for the three and six months ended July 31, 2010, compared to $6,520,000 and $12,824,000 for the same periods last year. The increases were primarily due to increased incentive compensation based on increased earnings and increased professional fees, partially offset by decreased compensation costs on share-based plans.

Liquidity and Capital Resources

Management exercises discretion regarding the liquidity and capital resource needs of its business segments. This includes the ability to prioritize the use of capital and debt capacity, to determine cash management policies and to make decisions regarding capital expenditures. The Company’s primary sources of liquidity have historically been cash from operations, supplemented by borrowings under its credit facilities.

The Company maintains an agreement (the “Master Shelf Agreement”) under which it may issue unsecured notes. Under the Master Shelf Agreement, the Company has an additional $50,000,000 of unsecured notes available to be issued before September 15, 2012. At July 31, 2010, the Company has $26,667,000 in notes outstanding under the Master Shelf Agreement.

The Company maintains an unsecured $200,000,000 revolving credit facility (the “Credit Agreement”) which extends to November 15, 2011. At July 31, 2010, the Company had letters of credit of $23,851,000 and no borrowings outstanding under the Credit Agreement resulting in available capacity of $176,149,000.

The Company’s Master Shelf Agreement and Credit Agreement each contain certain covenants including restrictions on the incurrence of additional indebtedness and liens, investments, acquisitions, transfer or sale of assets, transactions with affiliates and payment of dividends. These provisions generally allow such activity to occur, subject to specific limitations and continued compliance with financial maintenance covenants. Significant financial maintenance covenants are fixed charge coverage ratio, maximum leverage ratio and minimum tangible net worth. Covenant levels and definitions are consistent between the two agreements. The Company was in compliance with its covenants as of July 31, 2010, and expects to be in compliance in fiscal 2011.

Compliance with the financial covenants is required on a quarterly basis, using the most recent four fiscal quarters. The Company’s fixed charge coverage ratio and leverage ratio covenants are based on ratios utilizing adjusted EBITDA and adjusted EBITDAR, as defined in the agreements. Adjusted EBITDA is generally defined as consolidated net income excluding net interest expense, provision for income taxes, gains or losses from extraordinary items, gains or losses from the sale of capital assets, non-cash items including depreciation and amortization, and share-based compensation. Equity in earnings of affiliates is included only to the extent of dividends or distributions received. Adjusted EBITDAR is defined as adjusted EBITDA, plus rent expense. The Company’s tangible net worth covenant is based on stockholders’ equity less intangible assets. All of these measures are considered non-GAAP financial measures and are not intended to be in accordance with accounting principles generally accepted in the United States.

The Company’s minimum fixed charge coverage ratio covenant is the ratio of adjusted EBITDAR to the sum of fixed charges. Fixed charges consist of rent expense, interest expense, and principal payments of long-term debt. The Company’s leverage ratio covenant is the ratio of total funded indebtedness to adjusted EBITDA. Total funded indebtedness generally consists of outstanding debt, capital leases, unfunded pension liabilities, asset retirement obligations and escrow liabilities. The Company’s tangible net worth covenant is measured based on stockholders’ equity, less intangible assets, as compared to a threshold amount defined in the agreements. The threshold is adjusted over time based on a percentage of net income and the proceeds from the issuance of equity securities.

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As of July 31, 2010 and 2009, the Company’s actual and required covenant levels were as follows:

	Actual		Required		Actual		Required
(in thousands, except for ratio data)	July 31,2010		July 31,2010		July 31,2009		July 31,2009
Minimum fixed charge coverage ratio		3.71		1.50		2.57		1.50
Maximum leverage ratio		0.37		3.00		0.42		3.00
Minimum tangible net worth	$	350,020	$	302,875	$	337,303	$	291,269

The Company’s working capital as of July 31, 2010, and July 31, 2009, was $105,631,000 and $122,012,000, respectively. The Company’s cash and cash equivalents as of July 31, 2010, were $49,184,000, compared to $84,450,000 as of January 31, 2010 and $64,839,000 as of July 31, 2009. The decreased amount of cash and cash equivalents as of July 31, 2010 is primarily due to cash spent on acquisitions and other investing activities as described below. During the upcoming quarter ending October 31, 2010, the Company will make payments on existing Senior Notes totaling $20,000,000. The Company also intends to continue to evaluate acquisition opportunities to enhance our existing service offerings and to expand our geographic market. The Company believes it will have sufficient cash from operations to access to credit facilities to meet its operating cash requirements, make required debt payments and fund its capital expenditures. Funding for potential acquisitions will be evaluated based on the particular facts and circumstances of the opportunity.

Operating Activities

Cash provided by operating activities was $12,577,000 for the six months ended July 31, 2010 as compared to $35,775,000 for the same period last year. The change was primarily attributed to additional working capital needs due to increased business volume.

Investing Activities

The Company’s capital expenditures, net of disposals, of $29,205,000 for the six months ended July 31, 2010, were split between $28,066,000 to maintain and upgrade its equipment and facilities and $1,139,000 toward the Company’s expansion into unconventional gas exploration and production, including the construction of gas pipeline infrastructure near the Company’s development projects. This compares to equipment spending of $18,911,000 and gas exploration and production spending of $3,559,000 in the same period last year. Over the course of fiscal 2011, we expect equipment and facilities spending to be at or near last year’s level, however unless gas pricing improves, we expect to hold gas exploration and production spending below last year’s level.

For the six months ended July 31, 2010, the Company invested $21,650,000 for acquired businesses, $16,150,000 of which was to acquire a 50% interest in Diberil Sociedad Anónima (see Note 13), $5,500,000 for Intevras Technologies, LLC, and $226,000 for prior acquisitions (see Note 2). These investments were offset in part by the sale of Layne GeoBrazil, a wholly owned subsidiary, for a cash payment of $4,800,000 (see Note 13). This compares to acquisition related spending of $1,949,000 in the same period last year.

Financing Activities

For the six months ended July 31, 2010, the Company had no incremental borrowings under its credit facilities. The Company will make scheduled principal payments on the Senior Notes of $13,333,000 in August 2010, and $6,667,000 in September 2010.

25

The Company’s contractual obligations and commercial commitments as of July 31, 2010, are summarized as follows (in thousands):

			Payments/Expiration by Period
			Less than						More than
	Total		1 year		1-3 years		4-5 years		5 years
Contractual obligations and other commercial commitments
Senior Notes	$	26,667	$	20,000	$	6,667	$	—	$	—
Credit Agreement		—		—		—		—		—
Interest payments		1,261		1,081		180		—		—
Software financing obligations		403		403		—		—		—
Operating leases		27,297		11,732		12,782		2,764		19
Mineral interest obligations		352		44		174		89		45
Income tax uncertainties		2,494		2,494		—		—		—
Total contractual obligations		58,474		35,754		19,803		2,853		64
Standby letters of credit		23,851		23,851		—		—		—
Asset retirement obligations		1,545		—		—		—		1,545
Total contractual obligations and commercial commitments	$	83,870	$	59,605	$	19,803	$	2,853	$	1,609

The Company expects to meet its contractual cash obligations in the ordinary course of operations, and that the standby letters of credit will be renewed in connection with its annual insurance renewal process. Interest is payable on the Senior Notes at fixed interest rates of 6.05% and 5.40%. Interest is payable on the Credit Agreement at variable interest rates equal to, at the Company’s option, a LIBOR rate plus 0.75% to 2.00%, or a base rate, as defined in the Credit Agreement plus up to 0.50%, depending on the Company’s leverage ratio (See Note 4 of the Notes to Consolidated Financial Statements). Interest payments have been included in the table above based only on outstanding balances and interest rates as of July 31, 2010.

The Company has income tax uncertainties of $11,085,000 at July 31, 2010, that are classified as non-current on the Company’s balance sheet as resolution of these matters is expected to take more than a year. The ultimate timing of resolutions of these items is uncertain, and accordingly the amounts have not been included in the table above.

The Company incurs additional obligations in the ordinary course of operations. These obligations, including but not limited to income tax payments and pension fundings, are expected to be met in the normal course of operations.

Critical Accounting Policies and Estimates

Management’s Discussion and Analysis of Financial Condition and Results of Operations discuss the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an on-going basis, management evaluates its estimates and judgments, which are based on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

Our accounting policies are more fully described in Note 1 of the Notes to Consolidated Financial Statements, located in Item 1 of this Form 10-Q. We believe that the following represent our more critical estimates and assumptions used in the preparation of our consolidated financial statements, although not all inclusive.

Revenue Recognition— Revenues are recognized on large, long-term construction contracts using the percentage-of-completion method based upon the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments proportionate to the percentage of completion are reflected in contract revenues in the reporting period when such estimates are revised. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions, change orders and final contract settlements may result in revisions to costs and income and are recognized in the period in which the revisions are determined. Contracts for the Company’s mineral exploration drilling services are billable based on the quantity of drilling performed and

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revenues for these drilling contracts are recognized on the basis of actual footage or meterage drilled. Revenue is recognized on smaller, short-term construction contracts using the completed contract method. Provisions for estimated losses on uncompleted construction contracts are made in the period in which such losses are determined.

Revenues for direct sales of equipment and other ancillary products not provided in conjunction with the performance of construction contracts are recognized at the date of delivery to, and acceptance by, the customer. Provisions for estimated warranty obligations are made in the period in which the sales occur.

Revenues for the sale of oil and gas by the Company’s energy division are recognized on the basis of volumes sold at the time of delivery to an end user or an interstate pipeline, net of amounts attributable to royalty or working interest holders.

The Company’s revenues are presented net of taxes imposed on revenue-producing transactions with its customers, such as, but not limited to, sales, use, value-added, and some excise taxes.

Oil and Gas Properties and Mineral Interests— The Company follows the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, and salaries, benefits and other internal salary-related costs directly attributable to these activities. Costs associated with production and general corporate activities are expensed in the period incurred. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized.

The Company is required to review the carrying value of its oil and gas properties under the full cost accounting rules of the SEC (the “Ceiling Test”). The ceiling limitation is the estimated after-tax future net revenues from proved oil and gas properties discounted at 10%, plus the cost of properties not subject to amortization. If our net book value of oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off. Beginning with our fiscal 2010, application of the Ceiling Test requires pricing future revenues at the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of reporting period, unless prices are defined by contractual arrangements such as fixed-price physical delivery forward sales contracts, when held. Application of the ceiling test requires a write-down for accounting purposes if the ceiling is exceeded. Considerations of the Ceiling Test prior to fiscal 2010 year end used the period end prices, as adjusted for contractual arrangements. Unproved oil and gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows.

No Ceiling Test impairment was required in the period ended July 31, 2010, but we did record a Ceiling Test impairment in the second quarter of fiscal 2010. If gas pricing falls, additional impairments could occur. As of July 31, 2010, the net book value of assets subject to the Ceiling Test limitation was $24,074,000.

Reserve Estimates— The Company’s estimates of natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material.

Goodwill and Other Intangibles— The Company accounts for goodwill and other intangible assets in accordance with current accounting guidance. Other intangible assets primarily consist of trademarks, customer-related intangible assets and patents obtained through business acquisitions. Amortizable intangible assets are being amortized over their estimated useful lives, which range from two to 40 years.

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The impairment evaluation for goodwill is conducted annually, or more frequently, if events or changes in circumstances indicate that an asset might be impaired. The evaluation is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

The impairment evaluation of the carrying amount of intangible assets with indefinite lives is conducted annually or more frequently if events or changes in circumstances indicate that an asset might be impaired. The evaluation is performed by comparing the carrying amount of these assets to their estimated fair value. If the estimated fair value is less than the carrying amount of the intangible assets with indefinite lives, then an impairment charge is recorded to reduce the asset to its estimated fair value. The estimated fair value is generally determined on the basis of discounted future cash flows.

The assumptions used in the estimate of fair value are generally consistent with the past performance of each reporting unit and are also consistent with the projections and assumptions that are used in current operating plans. Such assumptions are subject to change as a result of changing economic and competitive conditions.

Other Long-lived Assets— In the event of an indication of possible impairment, the Company evaluates the fair value and future benefits of long-lived assets, including the Company’s gas transportation facilities and equipment, by performing an analysis of the anticipated, undiscounted future net cash flows to the carrying value of the related long-lived assets. If the carrying value of the long-lived assets exceeds the anticipated undiscounted cash flows the carrying value is written down to the fair value. The Company believes at this time that the carrying values and useful lives of its long-lived assets continue to be appropriate.

Accrued Insurance Expense— The Company maintains insurance programs where it is responsible for a certain amount of each claim up to a self-insured limit. Estimates are recorded for health and welfare, property and casualty insurance costs that are associated with these programs. These costs are estimated based on actuarially determined projections of future payments under these programs. Should a greater amount of claims occur compared to what was estimated or medical costs increase beyond what was anticipated, reserves recorded may not be sufficient and additional costs to the consolidated financial statements could be required.

Costs estimated to be incurred in the future for employee medical benefits, property, workers’ compensation and casualty insurance programs resulting from claims which have occurred are accrued currently. Under the terms of the Company’s agreement with the various insurance carriers administering these claims, the Company is not required to remit the total premium until the claims are actually paid by the insurance companies. These costs are not expected to significantly impact liquidity in future periods.

Income Taxes— Income taxes are provided using the asset/liability method, in which deferred taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and tax bases of existing assets and liabilities. Deferred tax assets are reviewed for recoverability and valuation allowances are provided as necessary. Provision for U.S. income taxes on undistributed earnings of foreign subsidiaries and affiliates is made only on those amounts in excess of funds considered to be invested indefinitely. In general, the Company records income tax expense during interim periods based on its best estimate of the full year’s effective tax rate. However, income tax expense relating to adjustments to the Company’s liabilities for uncertainty in income tax positions is accounted for discretely in the interim period in which it occurs.

Litigation and Other Contingencies— The Company is involved in litigation incidental to its business, the disposition of which is not expected to have a material effect on the Company’s financial position or results of operations. It is possible, however, that future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions related to these proceedings. The Company accrues its best estimate of the probable cost for the resolution of legal claims. Such estimates are developed in consultation with outside counsel handling these matters and are based upon a combination of litigation and settlement strategies. To the extent additional information arises or the Company’s strategies change, it is possible that the Company’s estimate of its probable liability in these matters may change.

New Accounting Pronouncements— See Note 1 of the Notes to Consolidated Financial Statements for a discussion of new accounting pronouncements and their impact on the Company.

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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

The principal market risks to which the Company is exposed are interest rates on variable rate debt, foreign exchange rates giving rise to translation and transaction gains and losses and fluctuations in the price of natural gas.

The Company centrally manages its debt portfolio considering overall financing strategies and tax consequences. A description of the Company’s debt is in Note 12 of the Notes to Consolidated Financial Statements appearing in the Company’s January 31, 2010 Form 10-K and Note 4 of this Form 10-Q. As of July 31, 2010, an instantaneous change in interest rates of one percentage point would not change the Company’s annual interest expense, as we have no variable rate debt outstanding.

Operating in international markets involves exposure to possible volatile movements in currency exchange rates. Currently, the Company’s primary international operations are in Australia, Africa, Mexico and Italy. The Company’s affiliates also operate in South America and Mexico. The operations are described in Notes l and 3 of the Notes to Consolidated Financial Statements appearing in the Company’s January 31, 2010, Form 10-K and Notes 13 and 14 of this Form 10-Q. The majority of the Company’s contracts in Africa and Mexico are U.S. dollar based, providing a natural reduction in exposure to currency fluctuations. The Company also may utilize various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated with fluctuating currency exchange rates. As of July 31, 2010, the Company held option contracts with an aggregate U.S. dollar notional value of $3,580,000 which are intended to hedge exposure to Australian dollar fluctuations over a period to January 31, 2011.

As currency exchange rates change, translation of the income statements of the Company’s international operations into U.S. dollars may affect year-to-year comparability of operating results. We estimate that a ten percent change in foreign exchange rates would not have significantly impacted income before income taxes for the six months ended July 31, 2010. This quantitative measure has inherent limitations, as it does not take into account any governmental actions, changes in customer purchasing patterns or changes in the Company’s financing and operating strategies.

The Company is also exposed to fluctuations in the price of natural gas, which result from the sale of the energy division’s unconventional gas production. The price of natural gas is volatile and the Company enters into fixed-price physical contracts, if available at attractive prices, to cover a portion of its production to manage price fluctuations and to achieve a more predictable cash flow. The Company generally intends to maintain contracts in place to cover 50% to 75% of its production, although at July 31, 2010, did not have any contracts in place. We estimate that a ten percent change in the price of natural gas would have impacted income before income taxes by approximately $146,000 for the six months ended July 31, 2010.

ITEM 4. Controls and Procedures

Based on an evaluation of disclosure controls and procedures for the period ended July 31, 2010, conducted under the supervision and with the participation of the Company’s management, including the Principal Executive Officer and the Principal Financial Officer, the Company concluded that its disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the Company’s management (including the Principal Executive Officer and the Principal Financial Officer) to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

Based on an evaluation of internal controls over financial reporting conducted under the supervision and the participation of the Company’s management, including the Principal Executive Officer and the Principal Financial Officer, for the period ended July 31, 2010, the Company concluded that its internal control over financial reporting is effective as of July 31, 2010. The Company has not made any significant changes in internal controls or in other factors that could significantly affect internal controls since such evaluation.

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PART II

ITEM 1 — Legal Proceedings

     NONE

ITEM 2 — Changes in Securities

     NOT APPLICABLE

ITEM 3 — Defaults Upon Senior Securities

     NOT APPLICABLE

ITEM 4 — Removed and Reserved

ITEM 5 — Other Information

     NONE

ITEM 6 — Exhibits and Reports on Form 8-K

a) Exhibits

31	(1)	-	Section 302 Certification of Chief Executive Officer of the Company.
31	(2)	-	Section 302 Certification of Chief Financial Officer of the Company.
32	(1)	-	Section 906 Certification of Chief Executive Officer of the Company.
32	(2)	-	Section 906 Certification of Chief Financial Officer of the Company.

** Management contracts or compensatory plans or arrangements required to be identified by Item 14 (a) (3).

b) Reports on Form 8-K

Form 8-K filed on June 2, 2010, related to the Company’s earnings press release for the three months ended April 30, 2010.

Form 8-K filed on June 7, 2010, reporting the results of the proposals voted on by the Company’s stockholders at its annual meeting of stockholders held on June 3, 2010.

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* * * * * * * * * *

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.

	Layne Christensen Company
	(Registrant)
DATE: September 2, 2010	/s/ A.B. Schmitt
	A.B. Schmitt, President
	and Chief Executive Officer
DATE: September 2, 2010	/s/ Jerry W. Fanska
	Jerry W. Fanska, Sr. Vice President
	Finance and Treasurer

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