LAYNE CHRISTENSEN CO - FORM 10-Q

Attached files

file	filename
EX-32.1 - EXHIBIT 32.1 - LAYNE CHRISTENSEN CO	a6533965_ex321.htm
EX-32.2 - EXHIBIT 32.2 - LAYNE CHRISTENSEN CO	a6533965_ex322.htm
EX-31.2 - EXHIBIT 31.2 - LAYNE CHRISTENSEN CO	a6533965_ex312.htm
EX-31.1 - EXHIBIT 31.1 - LAYNE CHRISTENSEN CO	a6533965_ex311.htm

FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

(Mark One)

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

For the quarterly period ended October 31, 2010

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 incorporation or organization)		(I.R.S. Employer Identification No.)

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. Yes x No o

Indicated by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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 filer o	Accelerated filer x	Non-accelerated filer o	Smaller reporting company o
		(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). Yes o No x

There were 19,570,105 shares of common stock, $.01 par value per share, outstanding on December 2, 2010.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED OCTOBER 31, 2010

INDEX

		Page
	PART I
ITEM 1.	Financial Statements	1

ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	21

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	29

ITEM 4.	Controls and Procedures	29

	PART II
ITEM 1.	Legal Proceedings	31

ITEM 1A.	Risk Factors	31

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32

ITEM 3.	Defaults Upon Senior Securities	32

ITEM 4.	Removed and Reserved	32

ITEM 5.	Other Information	32

ITEM 6.	Exhibits	32

	Signatures	33

PART I

ITEM 1. FINANCIAL STATEMENTS

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	October 31,			January 31,
	2010			2010
ASSETS	(unaudited)			(unaudited)

Current assets:
Cash and cash equivalents	$	32,886		$	84,450
Customer receivables, less allowance of $8,924 and $7,425, respectively		143,584			106,056
Costs and estimated earnings in excess of billings on uncompleted contracts		101,615			83,712
Inventories		28,328			25,637
Deferred income taxes		21,814			18,324
Income taxes receivable		1,638			3,761
Restricted deposits-current		3,265			1,415
Other		14,104			6,996
Total current assets		347,234			330,351

Property and equipment:
Land		12,282			12,056
Buildings		37,144			34,539
Machinery and equipment		427,731			378,868
Gas transportation facilities and equipment		40,816			40,748
Oil and gas properties		96,719			95,252
Mineral interests in oil and gas properties		22,213			21,939
		636,905			583,402
Less - Accumulated depreciation and depletion		(382,485	)		(350,630	)
Net property and equipment		254,420			232,772

Other assets:
Investment in affiliates		64,609			44,073
Goodwill		105,891			92,532
Other intangible assets, net		22,871			19,649
Restricted deposits-long term		3,700			3,151
Other		9,557			8,427
Total other assets		206,628			167,832

	$	808,282		$	730,955

See Notes to Consolidated Financial Statements.

- Continued -

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS - (Continued)

(in thousands, except per share data)

	October 31,			January 31,
	2010			2010
LIABILITIES AND STOCKHOLDERS' EQUITY	(unaudited)			(unaudited)

Current liabilities:
Accounts payable	$	98,767		$	87,818
Current maturities of long term debt		6,667			20,000
Accrued compensation		38,502			33,572
Accrued insurance expense		9,157			9,255
Other accrued expenses		36,827			16,779
Acquisition escrow obligation-current		3,265			1,415
Income taxes payable		12,513			4,219
Billings in excess of costs and estimated earnings on uncompleted contracts		56,073			37,644
Total current liabilities		261,771			210,702

Noncurrent and deferred liabilities:
Long-term debt		-			6,667
Accrued insurance expense		12,368			10,759
Deferred income taxes		19,609			17,761
Acquisition escrow obligation-long term		3,700			3,151
Other		17,657			15,042
Total noncurrent and deferred liabilities		53,334			53,380

Common stock, par value $.01 per share, 30,000 shares authorized, 19,504 and 19,435
shares issued and outstanding, respectively		195			194
Capital in excess of par value		345,802			342,952
Retained earnings		150,932			129,718
Accumulated other comprehensive loss		(5,438	)		(6,066	)
Total Layne Christensen Company stockholders' equity		491,491			466,798
Noncontrolling interest		1,686			75
Total equity		493,177			466,873

	$	808,282		$	730,955

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)

	Three Months						Nine Months
	Ended October 31,						Ended October 31,
	(unaudited)						(unaudited)
	2010			2009			2010			2009
Revenues	$	269,797		$	217,800		$	753,812		$	639,219
Cost of revenues (exclusive of depreciation, depletion and
amortization shown below)		(209,669	)		(161,781	)		(579,327	)		(487,234	)
Selling, general and administrative expenses		(37,931	)		(31,504	)		(103,145	)		(93,508	)
Depreciation, depletion and amortization		(12,798	)		(14,233	)		(39,054	)		(42,844	)
Impairment of oil and gas properties		-			-			-			(21,642	)
Litigation settlement gains		-			334			-			3,495
Equity in earning of affiliates		4,310			1,239			7,797			5,525
Interest expense		(337	)		(584	)		(1,380	)		(2,206	)
Other income (expense), net		5			290			81			(348	)
Income before income taxes		13,377			11,561			38,784			457
Income tax expense		(5,183	)		(4,940	)		(17,570	)		(1,480	)
Net income (loss)		8,194			6,621			21,214			(1,023	)

Basic income (loss) per share	$	0.42		$	0.34		$	1.09		$	(0.05	)

Diluted income (loss) per share	$	0.42		$	0.34		$	1.09		$	(0.05	)

Weighted average shares outstanding:
Basic		19,396			19,342			19,384			19,319
Diluted		19,540			19,513			19,532			19,319

See Notes to Consolidated Financial Statements.

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 income:
Net loss		-			-		-			(1,023	)		-			(1,023	)		-		(1,023	)
Other comprehensive income:
Foreign currency translation adjustments,
net of income tax expense of $1,213		-			-		-			-			2,852			2,852			-		2,852
Change in unrealized gain on foreign
exchange contracts, net of income tax
expense of $304		-			-		-			-			475			475			-		475
Comprehensive income:																2,304					2,304
Issuance of unvested shares		12,771			-		-			-			-			-			-		-
Treasury stock purchased and subsequently																					-
cancelled		(5,374	)		-		(113	)		-			-			(113	)		-		(113	)
Issuance of stock upon exercise of options		30,259			-		513			-			-			513			-		513
Income tax benefit on exercise of options		-			-		67			-			-			67			-		67
Income tax deficiency upon vesting of
restricted shares		-			-		(190	)		-			-			(190	)		-		(190	)
Share-based compensation		-			-		4,761			-			-			4,761			-		4,761
Issuance of stock upon acquisition																-					-
of business		12,677			-		280			-			-			280			-		280
Balance October 31, 2009		19,433,309		$	194	$	342,846		$	127,330		$	(6,726	)	$	463,644		$	75	$	463,719

Balance January 31, 2010		19,435,209		$	194	$	342,952		$	129,718		$	(6,066	)	$	466,798		$	75	$	466,873
Comprehensive income:
Net income		-			-		-			21,214			-			21,214			-		21,214
Other comprehensive income (loss):
Foreign currency translation adjustments,
net of income tax expense of $228		-			-		-			-			509			509			-		509
Change in unrealized gain on foreign
exchange contracts, net of income tax
expense of $76		-			-		-			-			119			119			-		119
Comprehensive income																21,842					21,842
Issuance of unvested shares		58,709			1		(1	)		-			-			-			-		-
Cancellation of unvested shares		(1,449	)		-		-			-			-			-			-		-
Treasury stock purchased and subsequently																					-
cancelled		(5,441	)		-		(136	)		-			-			(136	)		-		(136	)
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		-			-		(118	)		-			-			(118	)		-		(118	)
Noncontrolling interest of current year
acquisition		-			-		-			-			-			-			1,611		1,611
Share-based compensation		-			-		2,848			-			-			2,848			-		2,848
Balance October 31, 2010		19,503,772		$	195	$	345,802		$	150,932		$	(5,438	)	$	491,491		$	1,686	$	493,177

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

(in thousands)

	Nine Months
	Ended October 31,
	(unaudited)
	2010			2009
Cash flow from operating activities:
Net income (loss)	$	21,214		$	(1,023	)
Adjustments to reconcile net income (loss) to cash from operations:
Depreciation, depletion and amortization		39,054			42,844
Deferred income taxes		(5,235	)		(9,887	)
Share-based compensation		2,848			4,762
Share-based compensation excess tax benefit		(158	)		(67	)
Equity in earnings of affiliates		(7,797	)		(5,525	)
Dividends received from affiliates		3,429			4,040
(Gain) loss from disposal of property and equipment		(526	)		20
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		(28,488	)		11,525
Increase in costs and estimated earnings in excess
of billings on uncompleted contracts		(15,199	)		(4,608	)
(Increase) decrease in inventories		(2,047	)		3,423
(Increase) decrease in other current assets		(6,985	)		3,822
Increase (decrease) in accounts payable and accrued expenses		28,827			(9,416	)
Increase in billings in excess of costs and
estimated earnings on uncompleted contracts		7,428			12,318
Other, net		2,394			(1,207	)
Cash provided by operating activities		38,759			69,795
Cash flow from investing activities:
Additions to property and equipment		(39,468	)		(25,803	)
Additions to gas transportation facilities and equipment		(68	)		(883	)
Additions to oil and gas properties		(1,467	)		(2,552	)
Additions to mineral interests in oil and gas properties		(274	)		(644	)
Acquisition of businesses, net of cash acquired		(16,867	)		(9,819	)
Investment in foreign affiliate		(16,150	)		-
Payment of cash purchase price adjustments on prior year acquisitions		(226	)		(1,349	)
Proceeds from sale of business		4,800			-
Proceeds from disposal of property and equipment		1,165			338
Release of cash from restricted accounts		1,156			515
Distribution of restricted cash for prior year acquisitions		(1,156	)		(515	)
Cash used in investing activities		(68,555	)		(40,712	)
Cash flow from financing activities:
Repayments of long term debt		(20,000	)		(20,000	)
Issuance of common stock upon exercise of stock options		99			513
Excess tax benefit on exercise of share-based instruments		158			67
Purchases and retirement of treasury stock		(136	)		(113	)
Cash used in financing activities		(19,879	)		(19,533	)
Effects of exchange rate changes on cash		(1,889	)		735
Net (decrease) increase in cash and cash equivalents		(51,564	)		10,285
Cash and cash equivalents at beginning of period		84,450			67,165
Cash and cash equivalents at end of period	$	32,886		$	77,450

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 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 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 $4,675,000 and $10,494,000 for the nine months ended October 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 the 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 of the 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 therefrom 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.

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 October 31 and January 31, 2010, the total amount of unrecognized tax benefits recorded was $9,913,000 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 October 31 and January 31, 2010, the total amount of accrued income tax-related interest and penalties included in the balance sheet was $4,248,000 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 of 518,716 and 570,799 shares have been excluded from weighted average shares in the three and nine months ending October 31, 2010, respectively, as their effect was antidilutive. A total of 98,924 nonvested shares have been excluded from weighted average shares in the three and nine months ending October 31, 2010, respectively, as their effect was antidilutive. Options to purchase 435,792 and 1,028,127 shares have been excluded from weighted average shares in the three and nine months ending October 31, 2009, respectively, as their effect was antidilutive. A total of 72,110 nonvested shares have been excluded from weighted average shares in the three and nine months ending October 31, 2009, respectively, 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 October 31, 2010, the Company had unrecognized compensation expense of $2,327,000 to be recognized over a weighted average period of 1.34 years. The Company determines the fair value of share-based compensation granted in the form of stock options using the Black-Scholes model.

Supplemental Cash Flow Information - The amounts paid for income taxes and interest are as follows:

	Nine Months
	Ended October 31,
(in thousands)	2010		2009
Income taxes	$	11,497	$	9,629
Interest		1,473		2,526

The Company had earnings on restricted deposits of $5,000 and $1,000 for the nine months ended October 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 nine months ended October 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.

New Accounting Pronouncements - In January 2010, the FASB issued guidance requiring 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 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.

Note 2. Acquisitions

Fiscal Year 2011

The Company completed three acquisitions during fiscal 2011 as described below:

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, which will expand our offerings in the industrial water market.

On October 22, 2010, the Company purchased 100% of the outstanding stock of Bencor Corporation of America – Foundation Specialist (“Bencor”), a leading contractor in foundation and underground engineering, which will complement and expand our geoconstruction capabilities.

The aggregate purchase price for Intevras and Bencor of $38,673,000 was comprised of cash ($3,550,000 of which was placed in escrow to secure certain representations, warranties and indemnifications) and contingent consideration as follows:

(in thousands)	Intevras		Bencor		Total
Cash purchase price	$	5,500	$	32,073	$	37,573
Contingent consideration		1,100		-		1,100
Total purchase price	$	6,600	$	32,073	$	38,673

Escrow deposits	$	550	$	3,000	$	3,550

In addition to the Intevras 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 contingent consideration and estimated the liability at fair value as of the acquisition 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 $1,100,000 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 of 41.2% and an estimated level of annual revenues of Intevras ranging from $1,500,000 to $6,100,000.

Acquisition related costs of $301,000 for Bencor and $64,000 for Intevras were recorded as an expense in the periods in which the costs were incurred. The purchase price for the Bencor acquisition has been allocated based on a preliminary assessment of the fair value of the assets and liabilities acquired, determined based on the Company’s internal operational assessments and other analyses which are Level 3 measurements. Such amounts may be subject to revision as valuations of tangible and intangible assets and the noncontrolling interest of a subsidiary of Bencor are finalized. Other revisions will be recorded by the Company as further adjustments to the purchase price allocation. The purchase price for Intevras has been decreased $2,224,000 during the third quarter ended October 31, 2010 to reflect updates to the estimated fair value of contingent consideration based on the completion of valuation 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)	Intevras		Bencor			Total
Working capital	$	113	$	8,564		$	8,677
Property and equipment		556		17,000	*		17,556
Goodwill		1,891		11,242	*		13,133
Other intangible assets		4,040		600	*		4,640
Deferred taxes		-		(3,722	) *		(3,722	)
Noncontrolling interest
in subsidiary of Bencor		-		(1,611	) *		(1,611	)
Total purchase price	$	6,600	$	32,073		$	38,673

* = Provisional amounts

The intangible assets of Intevras consist of patents valued at $4,040,000 with a weighted-average useful life of 9 years, the intangible assets of Bencor consist of a tradename valued at $500,000 with an indefinite useful life, and software licenses valued at $100,000 with a useful life of 3 years. The $13,133,000 of aggregate goodwill was assigned to the Water Infrastructure segment. Goodwill associated with the Intevras acquisition is expected to be deductible for tax purposes. Goodwill associated with the Bencor acquisition is not deductible for tax purposes.

The results of operations of the acquired entities have been included in the Company’s consolidated statements of income commencing on the closing date and did not have a significant effect on the Company’s consolidated revenues or net income. Pro forma amounts related to Intevras 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.

Assuming Bencor had been acquired at the beginning of each period, the unaudited pro forma consolidated revenues, net income, and net income per share of the Company would be as follows:

	Three Months		Three Months		Nine Months		Nine Months
	Ended October 31,		Ended October 31,		Ended October 31,		Ended October 31,
(in thousands, except per share data)	2010		2009		2010		2009
Revenues	$	280,444	$	223,496	$	789,301	$	656,306

Net income		9,349		6,872		25,065		(269	)

Basic income (loss) per share	$	0.48	$	0.36	$	1.29	$	(0.01	)
Diluted income (loss) per share	$	0.48	$	0.35	$	1.28	$	(0.01	)

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 $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 indemnifications), 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 of $5,000 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

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		Nine Months
	Ended October 31,		Ended October 31,
(in thousands, except per share data)	2009		2009
Revenues	$	237,600	$	705,175

Net income		7,345		1,057

Basic income per share	$	0.38	$	0.05
Diluted income per share	$	0.38	$	0.05

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.

Note 3. Goodwill and Other Intangible Assets

Other intangible assets consist of the following:

	October 31, 2010							January 31, 2010
(in thousands)	Gross Carrying Amount		Accumulated Amortization			Weighted Average Amortization Period in Years		Gross Carrying Amount		Accumulated Amortization			Weighted Average Amortization Period in Years
Amortizable intangible assets:
Tradenames	$	18,962	$	(3,694	)		29	$	18,962	$	(3,086	)		29
Customer-related		332		(332	)		-		332		(332	)		-
Patents		7,192		(961	)		15		3,152		(755	)		15
Non-competition agreements		464		(452	)		3		464		(423	)		2
Other		2,854		(1,994	)		12		2,754		(1,419	)		12
Total amortizable intangible assets		29,804		(7,433	)				25,664		(6,015	)

Indefinite-lived tradenames		500		-					-		-

Total intangible assets	$	30,304	$	(7,433	)			$	25,664	$	(6,015	)

Amortizable intangible assets are being amortized over their estimated useful lives of 3 to 40 years with a weighted average amortization period of 24 years. Total amortization expense for other intangible assets was $624,000 and $386,000 for the three months ended October 31, 2010 and 2009, respectively, and $1,418,000 and $1,156,000 for the nine months ended October 31, 2010 and 2009, respectively.

The carrying amount of goodwill attributed to each operating segment was as follows:

(in thousands)	Energy		Water Infrastructure		Total
Balance February 1, 2010	$	950	$	91,582	$	92,532
Additions		-		13,359		13,359
Balance October 31, 2010	$	950	$	104,941	$	105,891

Note 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 the remaining balance is due on September 29, 2011.

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 October 31, 2010, there were letters of credit of $20,582,000 and no borrowings outstanding on the Credit Agreement resulting in available capacity of $179,418,000.

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 October 31, 2010.

Debt outstanding as of October 31, 2010, and January 31, 2010, whose carrying value approximates fair value, was as follows:

	October 31,			January 31,
(in thousands)	2010			2010
Long-term debt:
Credit agreement	$	-		$	-
Senior notes		6,667			26,667
Total debt		6,667			26,667
Less current maturities		(6,667	)		(20,000	)
Total long-term debt	$	-		$	6,667

Note 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 October 31, 2010, the Company held option contracts with an aggregate U.S. dollar notional value of $1,730,000 which are intended to hedge exposure to Australian dollar fluctuations over a period to January 31, 2011. As of October 31, 2010, and January 31, 2010, the fair values of outstanding derivatives were a gain of $93,000 and a loss of $102,000, respectively, recorded in other current assets and 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.

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 October 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 October 31, 2010, the Company had committed to deliver a total of 360,000 million British Thermal Units (“MMBtu”) of natural gas through November 2010. The contract price resets daily based on a weighted average price of the reported trades for deliveries on the following day.

Note 6. Impairment of Oil and Gas Properties

As of October 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 October 31, 2010, of $4.14 per Mcf, compared to a price of $3.24 per Mcf for the evaluation for January 31, 2010 and $4.01 per Mcf for October 31, 2009. Based on the reserve determination, no Ceiling Test impairment was required for the three or nine months ended October 31, 2010. In the nine months ended October 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 October 31, 2010, the remaining net book value of assets subject to Ceiling Test impairment was $23,764,000.

Note 7. 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 nine months ended October 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 nine months ended October 31, 2009, of $667,000, net of contingent attorney fees. There were no litigation settlement gains recorded in the nine months ended October 31, 2010.

Note 8. Other Income (Expense)

Other income (expense) consisted of the following for the three and nine months ended October 31, 2010 and 2009:

	Three Months						Nine Months
	Ended October 31,						Ended October 31,
(in thousands)	2010			2009			2010			2009
Gain (loss) from disposal of property and equipment	$	108		$	(27	)	$	526		$	(20	)
Interest income		31			110			155			330
Currency exchange loss		(246	)		(83	)		(438	)		(652	)
Other		112			290			(162	)		(6	)
Total	$	5		$	290		$	81		$	(348	)

Note 9. 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 nine months ended October 31, 2009 was $100,000 and $300,000, 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 nine months ended October 31, 2010 and 2009 include the following components:

	Three Months				Nine Months
	Ended October 31,				Ended October 31,
(in thousands)	2010		2009		2010		2009
Service cost	$	87	$	73	$	261	$	219
Interest cost		43		44		129		132
Net periodic pension cost	$	130	$	117	$	390	$	351

Note 10. 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 restricted deposits held in acquisition escrow accounts, foreign currency option contracts, and contingent earnout of acquired businesses, are presented as of the periods ended October 31, 2010 and January 31, 2010:

			Fair Value Measurements
(in thousands)	Carrying Value		Level 1		Level 2		Level 3
October 31, 2010
Financial Assets:
Restricted deposits held at fair value	$	6,965	$	6,965	$	-	$	-
Forward currency contracts(1)	$	93	$	-	$	93	$	-

Financial Liabilities:
Contingent earnout of acquired businesses(2)	$	1,100	$	-	$	-	$	1,100

January 31, 2010
Financial Assets:
Restricted deposits held at fair value	$	4,566	$	4,566	$	-	$	-

Financial Liabilities:
Forward currency contracts(1)	$	102	$	-	$	102	$	-

(1)

The fair value of the foreign currency contracts are determined using a mark-to-market technique based on observable foreign currency exchange rates.

(2)

The fair value of the contingent earnout of acquired businesses is determined using a mark-to-market modeling technique based on significant unobservable inputs calculated using a discounted future cash flows approach. Key assumptions include a discount rate of 41.2% and annual revenues of acquired businesses ranging from $1,500,000 to $6,100,000 over the life of the earnout.

Note 11. 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 October 31, 2010, there were an aggregate of 2,850,000 shares registered under the plans, 1,390,000 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 1,140,000 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 nine months ended October 31, 2010, the Company granted approximately 59,000 restricted shares which generally vest ratably over periods of one to four years from the grant date.

The Company recognized $2,848,000 and $4,762,000 of compensation cost for these share-based plans during the nine months ended October 31, 2010 and 2009, respectively. Of these amounts, $792,000 and $1,074,000, respectively, related to nonvested stock. The total income tax benefit recognized for share-based compensation arrangements was $1,111,000 and $1,857,000 for the nine months ended October 31, 2010 and 2009, respectively.

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

	Number of Shares			Average Grant Date Fair Value			Intrinsic Value (in thousands)
Nonvested stock at January 31, 2010		79,336		$	36.23
Granted		58,709			27.42
Vested		(28,436	)		32.91
Forfeited		(1,449	)		39.97
Nonvested stock at October 31, 2010		108,160			32.27	$	3,022

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

Grant Date	Options Outstanding	Options Exercisable	Exercise Price	Remaining Contractual Term (Months)
6/04	20,000	20,000	$ 16.60	44
6/04	68,576	68,576	16.65	44
6/05	10,000	10,000	17.54	56
9/05	140,332	140,332	23.05	59
1/06	178,981	178,981	27.87	63
6/06	80,000	80,000	29.29	68
6/07	65,625	48,125	42.26	80
7/07	31,750	24,750	42.76	81
9/07	3,000	2,250	55.48	83
2/08	74,070	49,675	35.71	87
1/09	6,000	6,000	24.01	98
2/09	199,347	67,102	15.78	99
2/09	4,580	4,580	15.78	99
6/09	107,522	36,190	21.99	103
6/09	2,472	2,472	21.99	103
2/10	85,290	-	27.79	111
2/10	2,721	2,721	25.44	111
	1,080,266	741,754

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 nine months ended October 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 nine months ended October 31, 2010, were as follows:

	Number of Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)		Intrinsic Value (in thousands)
Stock Option Activity Summary:
Outstanding at February 1, 2010		1,026,227		$	24.86		7.02	$	3,840
Granted		88,011			27.72				-
Exercised		(16,744	)		5.81				373
Forfeited		(17,228	)		27.42				-
Outstanding at October 31, 2010		1,080,266			25.34		6.61		4,981
Shares Exercisable		741,754			26.16		5.80		2,936

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.

Note 12. 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 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 October 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:

	Three Months				Nine Months
	Ended October 31,				Ended October 31,
(in thousands)	2010		2009		2010		2009
Revenues	$	92,385	$	53,977	$	227,900	$	159,517
Gross profit		20,608		8,076		43,325		28,575
Operating income		13,187		3,657		25,149		16,048
Net income		9,761		2,685		18,457		11,259

Note 13. 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.

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 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						Nine Months
	Ended October 31,						Ended October 31,
(in thousands)	2010			2009			2010			2009
Revenues
Water infrastructure	$	209,870		$	174,345		$	576,765		$	516,573
Mineral exploration		51,662			30,713			148,325			85,764
Energy		4,944			11,743			20,336			34,052
Other		3,321			999			8,386			2,830
Total revenues	$	269,797		$	217,800		$	753,812		$	639,219

Equity in earnings of affiliates
Water infrastructure	$	80		$	-		$	80		$	-
Mineral exploration		4,230			1,239			7,717			5,525
Total equity in earnings of affiliates	$	4,310		$	1,239		$	7,797		$	5,525

Income (loss) before income taxes
Water infrastructure	$	13,072		$	11,675		$	31,997		$	24,455
Mineral exploration		9,000			1,984			26,543			7,294
Energy		(106	)		4,659			2,891			(10,226	)
Other		404			112			1,195			249
Unallocated corporate expenses		(8,656	)		(6,285	)		(22,462	)		(19,109	)
Interest expense		(337	)		(584	)		(1,380	)		(2,206	)
Total income before income taxes	$	13,377		$	11,561		$	38,784		$	457

Geographic Information
Revenue
United States	$	226,513		$	190,234		$	629,265		$	563,503
Africa/Australia		18,821			11,631			57,127			36,147
Mexico		11,309			6,881			34,873			17,877
Other foreign		13,154			9,054			32,547			21,692
Total revenues	$	269,797		$	217,800		$	753,812		$	639,219

Note 14. 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, bundled 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 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 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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: the outcome of the ongoing internal investigation into, among other things, the legality, under the FCPA and local laws, of certain payments made by the Company to customs clearing and other agents in the Democratic Republic of Congo and other countries in Africa (including any government enforcement action which could arise out of the matters under review or that the matters under review may have resulted in a higher dollar amount of payments or may have a greater financial or business impact than management currently anticipates), 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.

Overview

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to help the reader understand Layne Christensen Company, our operations and our present business environment. MD&A is provided as a supplement to, and should be read in connection with, our Consolidated Financial Statements and the accompanying notes thereto included under Part I Item 1 of this report. MD&A should also be read in conjunction with our Consolidated Financial Statements as of January 31, 2010, and for the year then ended, and the related MD&A, both of which are contained in our Form 10-K for the year ended January 31, 2010. MD&A includes the following sections:

•

Our Business — a brief description of our business, key 2011 events, the impact of new federal legislation, and details of an internal investigation.

•

Consolidated Review of Operations — an analysis of our consolidated results of operations for the three and nine months ended October 31, 2010 and October 31, 2009.

•

Operating Segment Review of Operations — an analysis of our results of operations for the three and nine months ended October 31, 2010 and October 31, 2009 as presented in our Consolidated Financial Statements for our three operating segments: Water Infrastructure, Mineral Exploration, and Energy.

•

Liquidity and Capital Resources — an analysis of cash flows, aggregate financial commitments and certain financial condition ratios.

•

Critical Accounting Policies — an update since January 31, 2010 of our discussion of our critical accounting policies that involve a higher degree of judgment or complexity. This section also includes the impact of new accounting standards.

OUR BUSINESS

Layne Christensen Company provides drilling and construction services and related products in two principal markets: water infrastructure and mineral exploration, as well as operates as a producer of unconventional natural gas for the energy market. We operate throughout North America, as well as Africa, Australia, Europe and Brazil. We also operate through our affiliates in South America. Layne Christensen’s customers include municipalities, investor-owned water utilities, industrial companies, global mining companies, consulting engineering firms, heavy civil construction contractors, oil and gas companies and, to a lesser extent, agribusiness.

Key 2011 Events

We have completed three acquisitions during fiscal 2011, Bencor Corporation of America – Foundation Specialist (“Bencor”) in the third quarter, Diberil Sociedad Anonima (“Diberil”) and Intevras Technologies, LLC (“Intevras”) in the second quarter. All of these acquisitions have occurred in our Water Infrastructure division. Bencor is a foundation construction and underground engineering company operating in the U.S., and was purchased to complement and expand our geoconstruction capabilities. We acquired a 50% interest in Diberil, a specialty foundation and marine geotechnical provider operating in Brazil and Uruguay. This investment was made to expand our geoconstruction service capabilities into these geographic markets. Intevras is a Texas based treatment operation focusing on the treatment and handling of industrial wastewater which will expand our offerings in the industrial water markets.

In a joint drilling operation with our affiliates in Chile, our personnel and equipment succeeded in reaching 33 trapped miners at the San Jose mine in Chile. The rescue efforts were completed two months ahead of original estimates.

We experienced continued improvements in the minerals exploration markets served by our wholly owned operations and our affiliates. Revenues have increased 72.9% for the year and pre-tax earnings have improved 263.9%.

The Company’s water supply contract in Afghanistan continued during the year. For the first three quarters we have recognized revenue of $14.9 million. We have recently been informed that the drilling program will be curtailed, and expect our involvement to wind down over the next two quarters.

The Company’s forward sales contracts in its Energy division expired in March 2010, and as a result of unfavorable natural gas pricing have not been renewed. Revenues in this division have accordingly dropped 40.3% for the year.

Impact of New Federal Legislation

In the first quarter of fiscal 2011, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act were signed into law. Because the Company generally does not offer post-employment healthcare benefits, the Company was not required to recognize a significant charge associated with the change in tax treatment of Medicare Part D benefits.

Internal Investigation

In connection with the Company updating its Foreign Corrupt Practices Act ("FCPA") policy, questions were raised internally in late September 2010 about, among other things, the legality of certain payments by the Company to customs clearing agents in connection with importing equipment into the Democratic Republic of Congo ("DRC") and other countries in Africa. The Audit Committee of the Board of Directors has engaged outside counsel to conduct an internal investigation to review these and other payments with assistance from an outside accounting firm. Although the internal investigation is ongoing, based on the results to date, the Company currently believes the amount of such questionable payments is not material with respect to the Company's results of operations or its financial statements.

If violations of the FCPA or other local laws occurred, the Company could be subject to fines, civil and criminal penalties, equitable remedies, including profit disgorgement, and injunctive relief. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly a monitor being appointed to review future business and practices with the goal of ensuring compliance with the FCPA. In addition, disclosure of the subject matter of the investigation could adversely affect the Company's reputation and its ability to obtain new business or retain existing business from its current clients and potential clients, to attract and retain employees and to access the capital markets. If it is determined that a violation of the FCPA has occurred, such violation may give rise to an event of default under the agreements governing our debt instruments. See Part II, Items 1 (Legal Proceedings) and 1A (Risk Factors) in this Form 10-Q for additional information.

CONSOLIDATED REVIEW 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.

	Three Months						Nine Months						Period-to-Period
	Ended October 31,						Ended October 31,						Change
	2010			2009			2010			2009			Three			Nine
Revenues:													Months			Months
Water infrastructure		77.8	%		80.0	%		76.5	%		80.8	%		20.4	%		11.7	%
Mineral exploration		19.1			14.1			19.7			13.4			68.2			72.9
Energy		1.8			5.4			2.7			5.3			(57.9	)		(40.3	)
Other		1.3			0.5			1.1			0.5			232.4			196.3
Total net revenues		100.0	%		100.0	%		100.0	%		100.0	%		23.9			17.9
Cost of revenues		(77.7	) %		(74.3	) %		(76.9	) %		(76.2	) %		29.6			18.9
Selling, general and administrative expenses		(14.1	)		(14.5	)		(13.7	)		(14.6	)		20.4			10.3
Depreciation, depletion and amortization		(4.7	)		(6.5	)		(5.2	)		(6.7	)		(10.1	)		(8.8	)
Impairment of oil and gas properties		-			-			-			(3.4	)		*			(100.0	)
Litigation settlement gains		-			0.2			-			0.5			(100.0	)		(100.0	)
Equity in earning of affiliates		1.6			0.6			1.0			0.8			247.9			41.1
Interest expense		(0.1	)		(0.3	)		(0.2	)		(0.4	)		(42.3	)		(37.4	)
Other (expense) income, net		-			0.1			-			-			(98.3	)		(123.3	)
Income before income taxes		4.9			5.3			5.1			-			15.7			8,386.7
Income tax expense		(1.9	)		(2.3	)		(2.3	)		(0.2	)		4.9			1,087.2
Net income (loss)		3.0	%		3.0	%		2.8	%		(0.2	) %		23.8			*

* = not meaningful

Revenues, equity in earnings of affiliates and income 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 before income taxes are summarized as follows:

	Three Months						Nine Months
	Ended October 31,						Ended October 31,
(in thousands)	2010			2009			2010			2009
Revenues
Water infrastructure	$	209,870		$	174,345		$	576,765		$	516,573
Mineral exploration		51,662			30,713			148,325			85,764
Energy		4,944			11,743			20,336			34,052
Other		3,321			999			8,386			2,830
Total revenues	$	269,797		$	217,800		$	753,812		$	639,219
Equity in earnings of affiliates
Water infrastructure	$	80		$	-		$	80		$	-
Mineral exploration		4,230			1,239			7,717			5,525
Total equity in earnings of affiliates	$	4,310		$	1,239		$	7,797		$	5,525
Income (loss) before income taxes
Water infrastructure	$	13,072		$	11,675		$	31,997		$	24,455
Mineral exploration		9,000			1,984			26,543			7,294
Energy		(106	)		4,659			2,891			(10,226	)
Other		404			112			1,195			249
Unallocated corporate expenses		(8,656	)		(6,285	)		(22,462	)		(19,109	)
Interest expense		(337	)		(584	)		(1,380	)		(2,206	)
Total income before income taxes	$	13,377		$	11,561		$	38,784		$	457

Revenues increased $51,997,000, or 23.9% to $269,797,000, for the three months ended October 31, 2010, and $114,593,000, or 17.9%, to $753,812,000 for the nine months ended October 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 $47,888,000, or 29.6% to $209,669,000 (77.7% of revenues) and $92,093,000, or 18.9% to $579,327,000 (76.9% of revenues) for the three and nine months ended October 31, 2010, compared to $161,781,000 (74.3% of revenues) and $487,234,000 (76.2% of revenues) for the same periods last year. The increase as a percentage of revenues for the three and nine months was primarily focused in the water infrastructure and energy divisions. Comparative costs in the water infrastructure division were affected by the unusually low cost structure of the geoconstruction projects performed in the prior year. The increase in the energy division was a result of nearly flat production costs measured against lower revenues that resulted from lower natural gas prices and the expiration of favorably priced forward sales contracts in the first quarter of fiscal 2011.

Selling, general and administrative expenses were $37,931,000 and $103,145,000 for the three and nine months ended October 31, 2010, compared to $31,504,000 and $93,508,000 for the same periods last year. The increases were primarily the result of increased incentive compensation expenses of $2,328,000 and $7,598,000 due to higher earnings and $1,355,000 and $3,885,000 in added expenses from acquired operations for the three and nine months, respectively.

Depreciation, depletion and amortization expenses were $12,798,000 and $39,054,000 for the three and nine months ended October 31, 2010, compared to $14,233,000 and $42,844,000 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 nine months ended October 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 nine months ending October 31, 2010.

During the nine months ended October 31, 2009, the Company received litigation settlements valued at $3,495,000. The settlements included receipt of land and buildings valued at $2,828,000, and cash receipts of $667,000, net of contingent attorney fees. There were no litigation settlement gains in the nine months ended October 31, 2010.

Equity in earnings of affiliates was $4,310,000 and $7,797,000 for the three and nine months ended October 31, 2010, compared to $1,239,000 and $5,525,000 for the same periods last year. The increases reflect the impact of an improved minerals exploration market in Latin America, primarily for gold and copper in Chile and Peru.

Interest expense decreased to $337,000 and $1,380,000 for the three and nine months ended October 31, 2010, compared to $584,000 and $2,206,000 for the same periods last year. The decreases were a result of scheduled debt reductions.

Income tax expenses of $5,183,000 (an effective rate of 38.7%) and $17,570,000 (an effective rate of 45.3%) were recorded for the three and nine months ended October 31, 2010, respectively, compared to income tax expenses of $4,940,000 (an effective rate of 42.7%) and $1,480,000 (an effective rate of 323.9%) 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 $4,940,000 (an effective rate of 42.7%) and $10,083,000 (an effective rate of 45.6%) for the three and nine months ended October 31, 2009. The effective rate for the three months ended October 31, 2010, was lower than last year due to higher estimated annual earnings through the third quarter that reduced the impact of non-deductible expenses and the tax treatment of certain foreign operations on the effective rate for the year. The effective rate in excess of the statutory federal rate for the nine months was due primarily to the impact of nondeductible expenses and the tax treatment of certain foreign operations.

OPERATING SEGMENT REVIEW OF OPERATIONS

Water Infrastructure Division	Three Months				Nine Months
	Ended October 31,				Ended October 31,
(in thousands)	2010		2009		2010		2009
Revenues	$	209,870	$	174,345	$	576,765	$	516,573
Income before income taxes		13,072		11,675		31,997		24,455

Water infrastructure revenues increased 20.4% to $209,870,000 and 11.7% to $576,765,000 for the three and nine months ended October 31, 2010, respectively, compared to $174,345,000 and $516,573,000 for the same periods last year.

The increases were primarily attributable to additional revenues from operations acquired in the prior year and specialty drilling projects including work in Afghanistan. The acquired operations contributed revenue of $27,495,000 and $62,673,000 for the three and nine months ended October 31, 2010. The increases were partially offset by a reduction in revenues from a large utility contract in Colorado that was substantially completed last year. We have recently been informed that the drilling program in Afghanistan will be curtailed, and expect our involvement to wind down over the next two quarters.

Income before income taxes for the water infrastructure division increased 12.0% to $13,072,000 and 30.8% to $31,997,000 for the three and nine months ended October 31, 2010, respectively, compared to $11,675,000 and $24,455,000 for the same periods last year. The increases in income before income taxes were primarily from the Afghanistan project, partially offset by lower results in the western U.S.

The backlog in the water infrastructure division was $625,795,000 as of October 31, 2010, including $69,236,000 related to Bencor, compared to $526,972,000 as of July 31, 2010, and $540,535,000 as of October 31, 2009.

Mineral Exploration Division	Three Months				Nine Months
	Ended October 31,				Ended October 31,
(in thousands)	2010		2009		2010		2009
Revenues	$	51,662	$	30,713	$	148,325	$	85,764
Income before income taxes		9,000		1,984		26,543		7,294

Mineral exploration revenues increased 68.2% to $51,662,000 and 72.9% to $148,325,000 for the three and nine months ended October 31, 2010, respectively, compared to $30,713,000 and $85,764,000 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, the U.S. and Mexico.

Income before income taxes for the mineral exploration division increased 353.6% to $9,000,000 and 263.9% to $26,543,000 for the three and nine months ended October 31, 2010, respectively, compared to $1,984,000 and $7,294,000 for the same periods last year. The increases were primarily attributable to stronger earnings in Africa, Mexico and the western U.S. Equity earnings from our affiliates, reduced earlier in the year by a customer driven project delay, improved in the quarter as the projects were caught up. During the nine 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 $2,569,000 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	Three Months					Nine Months
	Ended October 31,					Ended October 31,
(in thousands)	2010			2009		2010		2009
Revenues	$	4,944		$	11,743	$	20,336	$	34,052
(Loss) income before income taxes		(106	)		4,659		2,891		(10,226	)

Energy revenues decreased 57.9% to $4,944,000 and 40.3% to $20,336,000 for the three and nine months ended October 31, 2010, respectively, compared to revenues of $11,743,000 and $34,052,000 for the same periods last year. The decreases were primarily attributable to lower natural gas prices and the expiration of favorably priced forward sales contracts in the first quarter of this year.

For the nine months ended October 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. During the nine months ended October 31, 2009 we recorded settlement gains, net of attorney fees, of $667,000 related to litigation against former officers of a subsidiary and associated energy production companies.

Excluding the non-cash impairment charge and litigation gains, income before income taxes for the energy division decreased to a loss of ($106,000) and income of $2,891,000 for the three and nine months ended October 31, 2010, compared to income of $4,325,000 and $10,514,000 for the same periods last year. The decreases in income before income taxes were due to the impact on revenues from lower natural gas prices and the expiration of forward sales contracts as noted above, partially offset by lower depletion.

For the three and nine months ended October 31, 2010, net gas production was 1,101 Mmcf and 3,386 Mmcf, compared to 1,121 Mmcf and 3,480 Mmcf for the same periods last year. The average net sales price on production for the three and nine months ended October 31, 2010, was $3.80 and $5.07 per Mcf, respectively, compared to $8.97 and $8.36 per Mcf for the same periods last year. The net sales price excludes revenues generated from third party gas.

Other	Three Months				Nine Months
	Ended October 31,				Ended October 31,
(in thousands)	2010		2009		2010		2009
Revenues	$	3,321	$	999	$	8,386	$	2,830
Income before income taxes		404		112		1,195		249

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 $8,656,000 and $22,462,000 for the three and nine months ended October 31, 2010, compared to $6,285,000 and $19,109,000 for the same periods last year. The increases were primarily due to increased incentive compensation based on increased earnings and increased consulting 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’s working capital as of October 31, 2010, and October 31, 2009, was $85,463,000 and $120,975,000, respectively. The Company’s cash and cash equivalents as of October 31, 2010, were $32,886,000, compared to $84,450,000 as of January 31, 2010 and $77,450,000 as of October 31, 2009. The decreased amount of cash and cash equivalents as of October 31, 2010 is primarily due to cash payments of $33,017,000 for acquisitions, net of cash acquired, and $20,000,000 for scheduled debt payments. The Company believes it will have sufficient cash from operations and 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.

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 October 31, 2010, the Company has $6,667,000 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 October 31, 2010, the Company had letters of credit of $20,582,000 and no borrowings outstanding under the Credit Agreement resulting in available capacity of $179,418,000.

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 October 31, 2010, and expects to remain in compliance through the term of the agreements.

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.

As of October 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)	October 31, 2010		October 31, 2010		October 31, 2009		October 31, 2009
Minimum fixed charge coverage ratio		2.61		1.50		2.21		1.50
Maximum leverage ratio		0.23		3.00		0.40		3.00
Minimum tangible net worth	$	349,786	$	302,875	$	342,699	$	291,750

Operating Activities

Cash provided by operating activities was $38,759,000 for the nine months ended October 31, 2010, as compared to $69,795,000 for the same period last year. The decrease was primarily due to working capital changes, including changes in customer receivables and costs and estimated earnings in excess of billings on uncompleted contracts. These working capital items typically turnover on average within a 90-day period, therefore, the 17.9% increase in revenues for the nine months ended October 31, 2010, required higher levels of working capital to support. Additionally, the mix of contract terms and billing arrangements in the water infrastructure divisions’ contracts resulted in slower billing and, thus, higher costs and estimated earnings in excess of billings on uncompleted contracts. The mix of contract terms will shift from period to period depending on many factors, including types of work, customer and location. The negative impact of these working capital items was partially offset by increased levels of accounts payable and accrued expenses.

Investing Activities

The Company’s capital expenditures, net of disposals, of $40,112,000 for the nine months ended October 31, 2010, were split between $38,303,000 to maintain and upgrade its equipment and facilities and $1,809,000 toward the Company’s unconventional natural gas exploration and production. This compares to equipment spending of $25,465,000 and natural gas exploration and production spending of $4,079,000 in the same period last year. The increase in equipment and facilities spending was due to equipment purchased to support the Company’s expansion into the injection well market in Florida and facilities expansion in the southwest U.S. to support our water treatment product capabilities. Unless gas pricing improves, we expect to continue to hold gas exploration and production spending below last year’s level.

For the nine months ended October 31, 2010, the Company invested $33,017,000 for acquired businesses, net of cash acquired, including $16,150,000 for a 50% interest in Diberil, $11,367,000 for Bencor, and $5,500,000 for Intevras. 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 12). This compares to acquisition related spending of $9,819,000 in the same period last year. The Company intends to continue to evaluate acquisition opportunities to enhance its existing service offerings and to expand our geographic market.

Financing Activities

For the nine months ended October 31, 2010, the Company had no incremental borrowings under its credit facilities. The Company made $20,000,000 in scheduled debt payments on its Senior Notes.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

For more information regarding our critical accounting policies, estimates and judgments, see the discussion under Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K for the year ended January 31, 2010. There have been no changes to our critical accounting policies since January 31, 2010.

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.

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 October 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 12 and 13 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 October 31, 2010, the Company held option contracts with an aggregate U.S. dollar notional value of $1,730,000 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 nine months ended October 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 October 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 $155,000 for the nine months ended October 31, 2010.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Based on an evaluation of disclosure controls and procedures for the period ended October 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.

Changes in Internal Control Over Financial Reporting

During the quarter ended October 31, 2010, the Company upgraded certain of its financial systems used in North America. Some controls and procedures were modified as a result of the new system. These modifications are not deemed to have materially affected, nor are they reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II

ITEM 1 - Legal Proceedings

The Company has contacted the Securities and Exchange Commission ("SEC") and the U.S. Department of Justice ("DOJ") to inform them of this matter and intends to cooperate fully with these governmental authorities. At this stage of the internal investigation, the Company is unable to predict whether the SEC and DOJ will open separate investigations of this matter, or any potential remedies or actions these agencies may pursue. Although the Company has had a long-standing published policy requiring compliance with the FCPA and broadly prohibiting any improper payments by the Company to foreign or U.S. officials, the Company has adopted additional policies and procedures to enhance compliance with the FCPA and related books and records requirements. Further measures may be required once the investigation is concluded.

Although the internal investigation is ongoing and no conclusions have yet been reached, based on the results to date, the Company currently believes the amount of such questionable payments is not material with respect to the Company's results of operations or its financial statements. The Company has concluded that it is premature for it to make any financial reserve for any potential liabilities that may result from these activities given the status of the internal investigation. Additional potential FCPA violations or violations of other laws or regulations may be uncovered through the investigation. Please see Part II, Item 1A (Risk Factors) for additional information.

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, except for the following additional factor.

We may be exposed to liabilities under the Foreign Corrupt Practices Act and any determination that the Company or any of its subsidiaries has violated the Foreign Corrupt Practices Act could have a material adverse effect on our business.

We operate in a number of countries throughout the world, including countries known to have a reputation for corruption. We are committed to doing business in accordance with applicable anti-corruption laws and our code of business conduct and ethics. We are subject, however, to the risk that we, our affiliated entities or their respective officers, directors, employees and agents may take action determined to be in violation of such anti-corruption laws, including the U.S. Foreign Corrupt Practices Act of 1977 (“FCPA”). As discussed under Part II, Item 1--Legal Proceedings in this Form 10-Q, we are conducting an internal investigation of certain transactions and payments in the Democratic Republic of Congo and other countries in Africa that potentially implicate the FCPA, including the books and records provisions of the FCPA. In addition, we have informed the Securities and Exchange Commission and the Department of Justice of these matters and intend to fully cooperate with these agencies in their review.

If violations of the FCPA occurred, the Company could be subject to fines, civil and criminal penalties, equitable remedies, including profit disgorgement, and injunctive relief. Civil penalties under the antibribery provisions of the FCPA could range up to $10,000 per violation, with a criminal fine up to the greater of $2 million per violation or twice the gross pecuniary gain to the Company or twice the gross pecuniary loss to others, if larger. Civil penalties under the accounting provisions of the FCPA can range up to $500,000 and a company that knowingly commits a violation can be fined up to $25 million. In addition, both the Securities and Exchange Commission and the Department of Justice could assert that conduct extending over a period of time may constitute multiple violations for purposes of assessing the penalty amounts. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly a monitor being appointed to review future business and practices with the goal of ensuring compliance with the FCPA.

Further detecting, investigating, and resolving these matters is expensive and consumes significant time and attention of the Company's senior management. The Company could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of the Company participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. The Company's customers in those jurisdictions could seek to impose penalties or take other actions adverse to its interests. The Company could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of the Company. In addition, disclosure of the subject matter of the investigation could adversely affect the Company's reputation and its ability to obtain new business or retain existing business from its current clients and potential clients, to attract and retain employees and to access the capital markets. If it is determined that a violation of the FCPA has occurred, such violation may give rise to an event of default under the agreements governing our debt instruments.

ITEM 2 - Unregistered Sales of Equity Securities and Use of Proceeds

NOT APPLICABLE

ITEM 3 - Defaults Upon Senior Securities

NOT APPLICABLE

ITEM 4 - Removed and Reserved

ITEM 5 - Other Information

NONE

ITEM 6 - 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.

* * * * * * * * * *

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
DATE: December 7, 2010	(Registrant) /s/ A.B. Schmitt
	A.B. Schmitt, President and Chief Executive Officer

DATE: December 7, 2010	/s/ Jerry W. Fanska
	Jerry W. Fanska, Sr. Vice President Finance and Treasurer

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