LAYNE CHRISTENSEN CO - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - LAYNE CHRISTENSEN CO	Financial_Report.xls
EX-32.1 - EXHIBIT 32.1 - LAYNE CHRISTENSEN CO	a6848639_ex321.htm
EX-31.2 - EXHIBIT 31.2 - LAYNE CHRISTENSEN CO	a6848639_ex312.htm
EX-31.1 - EXHIBIT 31.1 - LAYNE CHRISTENSEN CO	a6848639_ex311.htm
EX-32.2 - EXHIBIT 32.2 - LAYNE CHRISTENSEN CO	a6848639_ex322.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 July 31, 2011

[ ]	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 [ ]

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 [X] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ] (Do not check if a smaller reporting company) Smaller reporting company [ ]

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]

There were 19,631,937 shares of common stock, $.01 par value per share, outstanding on August 31, 2011.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JULY 31, 2011

INDEX

		Page
PART I
ITEM 1.	Financial Statements	3

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

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	27

ITEM 4.	Controls and Procedures	27

PART II
ITEM 1.	Legal Proceedings	28

ITEM 1A.	Risk Factors	28

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29

ITEM 3.	Defaults Upon Senior Securities	29

ITEM 4.	Removed and Reserved	29

ITEM 5.	Other Information	29

ITEM 6.	Exhibits	30

	Signatures	30

PART I

ITEM 1. Financial Statements

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	July 31,			January 31,
(in thousands)	2011			2011
ASSETS	(unaudited)			(unaudited)

Current assets:
Cash and cash equivalents	$	33,264		$	44,985
Customer receivables, less allowance of $8,544 and $8,628, respectively		155,192			142,816
Costs and estimated earnings in excess of billings on uncompleted contracts		118,132			82,569
Inventories		36,518			29,542
Deferred income taxes		19,949			20,824
Income taxes receivable		6,353			8,633
Restricted deposits-current		13,244			3,966
Other		7,946			10,811
Total current assets		390,598			344,146

Property and equipment:
Land		13,145			12,631
Buildings		37,210			36,466
Machinery and equipment		467,957			441,588
Gas transportation facilities and equipment		40,915			40,886
Oil and gas properties		99,263			97,737
Mineral interests in oil and gas properties		22,356			22,261
		680,846			651,569
Less - Accumulated depreciation and depletion		(413,138	)		(391,713	)
Net property and equipment		267,708			259,856

Other assets:
Investment in affiliates		79,133			69,152
Goodwill		105,696			103,378
Other intangible assets, net		25,287			26,453
Restricted deposits-long term		3,445			3,001
Other		14,895			10,666
Total other assets		228,456			212,650

Total assets	$	886,762		$	816,652

See Notes to Consolidated Financial Statements.

- Continued -

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS - (Continued)

	July 31,			January 31,
(in thousands, except per share data)	2011			2011
LIABILITIES AND STOCKHOLDERS' EQUITY	(unaudited)			(unaudited)

Current liabilities:
Accounts payable	$	105,545		$	98,933
Current maturities of long term debt		6,667			9,667
Accrued compensation		40,735			44,584
Accrued insurance expense		12,047			9,579
Other accrued expenses		17,063			22,422
Acquisition escrow obligation-current		3,969			3,966
Income taxes payable		13,182			12,126
Billings in excess of costs and estimated earnings on uncompleted contracts		40,110			49,560
Total current liabilities		239,318			250,837

Noncurrent and deferred liabilities:
Long-term debt		47,500			-
Accrued insurance expense		12,839			11,609
Deferred income taxes		30,206			26,782
Acquisition escrow obligation-long term		3,445			3,001
Other		20,772			20,499
Total noncurrent and deferred liabilities		114,762			61,891
Contingencies

Stockholders' equity:
Common stock, par value $.01 per share, 30,000 shares authorized, 19,704 and 19,540
shares issued and outstanding, respectively		197			195
Capital in excess of par value		349,510			347,307
Retained earnings		183,385			159,709
Accumulated other comprehensive loss		(4,066	)		(5,809	)
Total Layne Christensen Company stockholders' equity		529,026			501,402
Noncontrolling interests		3,656			2,522
Total equity		532,682			503,924

Total liabilities and stockholders' equity	$	886,762		$	816,652

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Three Months						Six Months
	Ended July 31,						Ended July 31,
	(unaudited)						(unaudited)
(in thousands, except per share data)	2011			2010			2011			2010
Revenues	$	295,052		$	253,300		$	562,423		$	484,015
Cost of revenues (exclusive of depreciation, depletion,
and amortization, shown below)		(231,419	)		(197,746	)		(431,644	)		(369,658	)
Selling, general and administrative expenses		(38,054	)		(31,698	)		(78,055	)		(65,213	)
Depreciation, depletion and amortization		(14,706	)		(12,131	)		(29,788	)		(26,256	)
Equity in earnings of affiliates		7,836			1,614			12,505			3,487
Interest expense		(717	)		(517	)		(1,061	)		(1,043	)
Other income, net		1,261			189			8,176			76
Income before income taxes		19,253			13,011			42,556			25,408
Income tax expense		(8,075	)		(6,561	)		(17,746	)		(12,387	)
Net income		11,178			6,450			24,810			13,021
Net income attributable to noncontrolling interests		(568	)		-			(1,134	)		-
Net income attributable to Layne Christensen Company	$	10,610		$	6,450		$	23,676		$	13,021

Earnings per share information attributable to
Layne Christensen Company shareholders:
Basic income per share	$	0.55		$	0.33		$	1.22		$	0.67

Diluted income per share	$	0.54		$	0.33		$	1.20		$	0.67

Weighted average shares outstanding - basic		19,453			19,386			19,449			19,378
Dilutive stock options and nonvested shares		204			136			223			148
Weighted average shares outstanding - dilutive		19,657			19,522			19,672			19,526

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED)

														Total Layne
											Accumulated			Christensen
						Capital In					Other			Company
	Common Stock					Excess of			Retained		Comprehensive			Stockholders'			Noncontrolling
(in thousands, except per share data)	Shares			Amount		Par Value			Earnings		Income (Loss)			Equity			Interest		Total
Balance January 31, 2010		19,435,209		$	194	$	342,952		$	129,718	$	(6,066	)	$	466,798		$	75	$	466,873
Comprehensive income:
Net income		-			-		-			13,021		-			13,021			-		13,021
Other comprehensive income:
Foreign currency translation adjustments,
net of income tax benefit of $315		-			-		-			-		(1,288	)		(1,288	)		-		(1,288	)
Change in unrealized loss on foreign
exchange contracts, net of income tax
expense of $23		-			-		-			-		36			36			-		36
Comprehensive income															11,769			-		11,769
Issuance of nonvested shares		58,709			1		(1	)		-		-			-			-		-
Treasury stock purchased and subsequently
cancelled		(5,279	)		-		(132	)		-					(132	)		-		(132	)
Issuance of stock upon exercise of options		16,744			-		99			-		-			99			-		99
Income tax benefit on exercise of options		-			-		158			-		-			158			-		158
Income tax deficiency upon vesting of
restricted shares		-			-		(112	)		-					(112	)		-		(112	)
Share-based compensation		-			-		2,190			-		-			2,190			-		2,190
Balance July 31, 2010		19,505,383		$	195	$	345,154		$	142,739	$	(7,318	)	$	480,770		$	75	$	480,845

Balance January 31, 2011		19,540,033		$	195	$	347,307		$	159,709	$	(5,809	)	$	501,402		$	2,522	$	503,924
Comprehensive income:
Net income		-			-		-			23,676		-			23,676			1,134		24,810
Other comprehensive income:
Foreign currency translation adjustments,
net of income tax expense of $369		-			-		-			-		1,743			1,743			-		1,743
Comprehensive income															25,419			1,134		26,553
Issuance of nonvested shares		193,188			2		(2	)		-		-			-			-		-
Treasury stock purchased and subsequently
cancelled		(5,220	)		-		(147	)							(147	)				(147	)
Expiration of performance contingent
nonvested shares		(33,251	)		-		-			-		-			-			-		-
Issuance of stock upon exercise of options		9,000			-		191			-		-			191			-		191
Income tax benefit on exercise of options		-			-		16			-		-			16			-		16
Income tax deficiency upon vesting of
restricted shares		-			-		(83	)							(83	)				(83	)
Share-based compensation		-			-		2,228			-		-			2,228			-		2,228
Balance July 31, 2011		19,703,750		$	197	$	349,510		$	183,385	$	(4,066	)	$	529,026		$	3,656	$	532,682

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

	Six Months
	Ended July 31,
	(unaudited)
(in thousands)	2011			2010
Cash flow from operating activities:
Net income	$	24,810		$	13,021
Adjustments to reconcile net income to cash from operations:
Depreciation, depletion and amortization		29,788			26,256
Deferred income taxes		3,802			(4,671	)
Share-based compensation		2,228			2,190
Share-based compensation excess tax benefit		(16	)		(158	)
Equity in earnings of affiliates		(12,505	)		(3,487	)
Dividends received from affiliates		2,524			1,763
Gain from disposal of property and equipment		(8,080	)		(409	)
Changes in current assets and liabilities, net of effects of acquisitions:
Increase in customer receivables		(11,369	)		(41,327	)
(Increase) decrease in costs and estimated earnings in excess
of billings on uncompleted contracts		(35,563	)		2,261
Increase in inventories		(5,676	)		(1,434	)
Decrease (increase) in other current assets		3,074			(2,036	)
(Decrease) increase in accounts payable and accrued expenses		(916	)		11,124
(Decrease) increase in billings in excess of costs and
estimated earnings on uncompleted contracts		(9,450	)		9,606
Other, net		(2,003	)		(122	)
Cash (used in) provided by operating activities		(19,352	)		12,577
Cash flow from investing activities:
Additions to property and equipment		(30,083	)		(29,036	)
Additions to gas transportation facilities and equipment		(29	)		(46	)
Additions to oil and gas properties		(1,526	)		(839	)
Additions to mineral interests in oil and gas properties		(95	)		(254	)
Acquisition of businesses, net of cash acquired		(8,855	)		(5,500	)
Investment in foreign affiliate		-			(16,150	)
Payment of cash purchase price adjustments on prior year acquisitions		-			(226	)
Proceeds from sale of business		-			4,800
Proceeds from disposal of property and equipment		12,496			970
Deposit of cash into restricted accounts		(9,000	)		-
Release of cash from restricted accounts		-			302
Distribution of restricted cash from prior year acquisitions		-			(302	)
Cash used in investing activities		(37,092	)		(46,281	)
Cash flow from financing activities:
Borrowings under revolving loan facilities		63,284			-
Repayments under revolving loan facilities		(20,500	)		-
Issuance of common stock upon exercise of stock options		191			99
Excess tax benefit on exercise of share-based instruments		16			158
Purchases and retirement of treasury stock		(147	)		(132	)
Cash provided by financing activities		42,844			125
Effects of exchange rate changes on cash		1,879			(1,687	)
Net decrease in cash and cash equivalents		(11,721	)		(35,266	)
Cash and cash equivalents at beginning of period		44,985			84,450
Cash and cash equivalents at end of period	$	33,264		$	49,184

See Notes to Consolidated Financial Statements.

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. Accounting Policies and Basis of Presentation

Principles of Consolidation - The consolidated financial statements include the accounts of Layne Christensen Company and its subsidiaries (together, the "Company"). Intercompany transactions have been eliminated. Investments in affiliates (20% to 50% owned) in which the Company exercises influence over operating and financial policies are accounted for by the equity method. The unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements of the Company for the year ended January 31, 2011, as filed in its Annual Report on Form 10-K.

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

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

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

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

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

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

Oil and Gas Properties and Mineral Interests - The Company follows the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, 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 $2,070,000 and $3,717,000 for the six months ended July 31, 2011 and 2010, respectively.

The Company is required to review the carrying value of its oil and gas properties under the full cost accounting rules of the SEC (the “Ceiling Test”). The ceiling limitation is the estimated after-tax future net revenues from proved oil and gas properties discounted at 10%, plus the cost of properties not subject to amortization. If our net book value of oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense. Application of the Ceiling Test requires pricing future revenues at the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of reporting period, unless prices are defined by contractual arrangements, such as fixed-price physical delivery forward sales contracts, when held. 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 - Goodwill is 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 and results of operations.

Intangible Assets - Other intangible assets primarily consist of trademarks, customer-related intangible assets and patents obtained through business acquisitions. Amortizable intangible assets are being amortized using the straight-line method over their estimated useful lives, which range from one to 40 years.

Other Long-lived Assets - Long-lived assets, including amortizable intangible assets and the Company’s gas transportation facilities and equipment, are reviewed for recoverability whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Factors we consider important which could trigger an impairment review include but are not limited to the following:

·	significant underperformance of our assets;

·	significant changes in the use of the assets; and

·	significant negative industry or economic trends.

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 $9,000,000 from the sale of a facility in Fontana, California that are intended to be used for acquiring and relocating to a new facility and escrow funds of $7,689,000 associated with various acquisitions as described in Note 2. See Note 6 for further discussion of the facility sale.

Allowance for Uncollectible Accounts Receivable - The Company makes ongoing estimates relating to the collectibility of its accounts receivable and maintains an allowance for estimated losses resulting from the inability of its customers to make required payments. In determining the amount of the allowance, the Company makes judgments about the creditworthiness of significant customers based on ongoing credit evaluations, and also considers a review of accounts receivable aging, industry trends, customer financial strength, credit standing and payment history to assess the probability of collection.

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 in part 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 basis 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.

The Company’s estimate of uncertainty in income taxes is based on the framework established in the accounting for income taxes guidance. This guidance addresses the determination of how tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. For tax positions that meet this recognition threshold, the Company applies judgment, taking into account applicable tax laws and experience in managing tax audits and relevant accounting guidance, to determine the amount of tax benefits to recognize in the financial statements. For each position, the difference between the benefit realized on our tax return and the benefit reflected in the financial statements is recorded as a liability in the consolidated balance sheet. This liability is updated at each financial statement date to reflect the impacts of audit settlements and other resolution of audit issues, expiration of statutes of limitation, developments in tax law and ongoing discussions with taxing authorities.

As of July 31 and January 31, 2011, the total amount of unrecognized tax benefits recorded was $13,739,000 and $12,016,000, respectively, of which substantially all would affect the effective tax rate if recognized. The Company does not expect the unrecognized tax benefits to change materially within the next 12 months. The Company classifies uncertain tax positions as non-current income tax liabilities unless expected to be paid in one year. The Company reports income tax-related interest and penalties as a component of income tax expense. As of July 31 and January 31, 2011, the total amount of accrued income tax-related interest and penalties included in the balance sheet was $6,681,000 and $5,251,000, 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.

In addition, as discussed in Note 12, the Audit Committee of the Board of Directors has engaged outside counsel to conduct an internal investigation about, among other things, the legality of certain payments by the Company to agents and other third parties interacting with government officials in certain countries in Africa. At this stage of the internal investigation, the Company is unable to predict any potential remedies or actions the Securities and Exchange Commission or the Department of Justice may pursue.

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. When in place, the Company accounts for unrealized foreign currency exchange 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.

Fair Value of Financial Instruments - The carrying amounts of financial instruments, including cash and cash equivalents, customer receivables and accounts payable approximate fair value at July 31, 2011 and 2010, because of the relatively short maturity of those instruments. See Note 4 for disclosure regarding the fair value of indebtedness of the Company, Note 5 for disclosure regarding the fair value of derivative instruments and Note 8 for other fair value disclosures.

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 nonvested shares are included based on the treasury stock method for dilutive earnings per share, except when their effect is antidilutive. Options to purchase 370,433 and 290,433 shares have been excluded from weighted average shares in the three and six months ending July 31, 2011, respectively, as their effect was antidilutive. A total of 193,688 nonvested shares have been excluded from weighted average shares in the three and six months ended July 31, 2011, as their effect was antidilutive. Options to purchase 586,063 and 588,784 shares have been excluded from weighted average shares in the three and six months ending July 31, 2010, respectively, as their effect was antidilutive. A total of 100,873 and 110,109 nonvested shares have been excluded from weighted average shares in the three and six months ended July 31, 2010, 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. As of July 31, 2011, the Company had unrecognized compensation expense of $5,411,000 to be recognized over a weighted average period of 2.7 years. The Company determines the fair value of share-based compensation granted in the form of stock options using the Black-Scholes model.

Unearned compensation expense associated with the issuance of nonvested shares is amortized on a straight-line basis as the restrictions on the stock expire.

Supplemental Cash Flow Information - The amounts paid for income taxes, interest and noncash financing activities were as follows:

	Six Months
	Ended July 31,
(in thousands)	2011		2010
Income taxes	$	11,695	$	8,722
Interest		772		978
Noncash financing activities:
Deferred debt issuance costs		1,700		-

During the six months ended July 31, 2011, the Company funded $1,700,000 of debt issuance costs through borrowings under its New Credit Agreement. These costs will be amortized over the life of the credit agreement. See Note 4 for further discussion of the Company’s credit facility agreement.

New Accounting Pronouncements – In May 2011, the FASB issued ASU 2011-04, "Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs" ("ASU 2011-04"), which is effective for annual reporting periods beginning after December 15, 2011. This guidance amends certain accounting and disclosure requirements related to fair value measurements. The Company is currently evaluating ASU 2011-04 and has not yet determined the impact the adoption will have on the Company's Consolidated Financial Statements.

In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income” (“ASU 2011-05”), which is effective for annual reporting periods, and interim periods within those years, beginning after December 15, 2011. The provisions of ASU 2011-05 require companies to display adjustments for items that are reclassified from other comprehensive income ("OCI") to net income in both net income and OCI in either a single continuous statement of comprehensive income or in two separate but consecutive statements. The Company does not believe ASU 2011-05 will have a significant impact on the Company's Consolidated Financial Statements.

2. Acquisitions

Fiscal Year 2012

On February 28, 2011, the Company acquired the Kansas and Colorado cured-in-place pipe (“CIPP”) operations of Wildcat Civil Services (“Wildcat”), a sewer rehabilitation contractor. The acquisition will further the Company’s expansion and geographic reach of its Inliner group westward. The aggregate purchase price for Wildcat of $8,855,000 was comprised of cash ($442,000 of which was placed in escrow to secure certain representations, warranties and indemnifications).

The purchase price allocation was based on an assessment of the fair value of the assets and liabilities acquired, using the Company’s internal operational assessments and other analyses, which are Level 3 measurements.

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

(in thousands)	Wildcat
Working capital	$	293
Property and equipment		6,244
Goodwill		2,318
Total purchase price	$	8,855

The $2,318,000 of goodwill was assigned to the Water Infrastructure Division. The purchase price in excess of the value of Wildcat’s net assets reflects the strategic value the Company placed on the business. The Company believes it will benefit from synergies as these acquired operations are integrated with the Company’s existing operations. Goodwill associated with the acquisition is expected to be deductible for tax purposes.

The results of operations for the acquired entity have been included in the Company’s consolidated statements of income commencing on the closing date. Revenue and income before income taxes for Wildcat since its closing date were not significant. Pro forma amounts related to Wildcat 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.

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 expanded 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 complements and expands 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 $381,000 for Bencor and $65,000 for Intevras 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 an assessment of the fair value of the assets and liabilities acquired, based on the Company’s internal operational assessments and other analyses which are Level 3 measurements. The Bencor purchase price allocation for the estimated fair value of identifiable intangible assets, goodwill and noncontrolling interests is provisional pending completion of further valuation analyses. Any revisions will be recorded by the Company as further adjustments to the purchase price allocation.

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	$	8,683		$	8,796
Property and equipment		556		18,451			19,007
Goodwill		1,891		8,529	*		10,420
Other intangible assets		4,040		5,040	*		9,080
Other assets		-		39			39
Deferred taxes		-		(7,023	)		(7,023	)
Other noncurrent liabilities		-		(795	)		(795	)
Noncontrolling interests
in subsidiary of Bencor		-		(851	) *		(851	)
Total purchase price	$	6,600	$	32,073		$	38,673

* = Provisional amounts

The intangible assets of Intevras consist of patents valued at $3,840,000 with a weighted-average useful life of 9 years and a tradename valued at $200,000 with a useful life of 10 years. The intangible assets of Bencor consist of customer backlog valued at $3,220,000 with a weighted average useful life of 18 months, a tradename valued at $1,140,000 with a useful life of 10 years and non-compete agreements valued at $680,000 with a useful life of 6 years. The $10,420,000 of aggregate goodwill was assigned to the Water Infrastructure Division. The purchase prices in excess of the value of Intevras’ and Bencor’s net assets reflect the strategic value the Company placed on the businesses. The Company believes it will benefit from synergies as these acquired businesses are integrated with the Company’s existing operations. 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. Bencor contributed revenues and income before income taxes to the Company for the three and six months ended July 31, 2011 as follows:

	Three Months		Six Months
	Ended July 31,		Ended July 31,
(in thousands)	2011		2011
Revenues	$	10,007	$	20,036

Income before income taxes		4,025		6,099

Revenue and income before income taxes for Intevras since its closing date, were not significant. 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 fiscal year ended January 31, 2011, the unaudited pro forma consolidated revenues, net income, and net income per share of the Company would be as follows:

	Three Months		Six Months
	Ended July 31,		Ended July 31,
(in thousands, except per share data)	2010		2010
Revenues	$	263,947	$	505,308

Net income attributable to Layne Christensen Company		7,605		15,331

Basic income per share	$	0.39	$	0.79
Diluted income per share	$	0.39	$	0.78

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.

On November 30, 2007, the Company acquired certain assets and liabilities of SolmeteX Inc. (“SolmeteX”), a water and wastewater research and development business and supplier of wastewater filtration products to the dental market. In addition to the initial purchase price, there was contingent consideration up to a maximum of $1,000,000 (the “SolmeteX Earnout Amount”), which was based on a percentage of the amount of SolmeteX’s revenues during the 36 months following the acquisition. Amounts paid pursuant to the SolmeteX Earnout Amount were accounted for as additional purchase consideration. The contingent earnout consideration earned by SolmeteX was $689,000, of which $33,000 was paid in fiscal 2009, $229,000 was paid in fiscal 2010 and $426,000 was paid in fiscal 2011 of which $226,000 was paid in the six months ended July 31, 2010.

3. Goodwill and Other Intangible Assets

Goodwill and other intangible assets consist of the following:

	July 31, 2011							January 31, 2011
(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	$	20,302	$	(4,407	)		28	$	20,302	$	(3,896	)		28
Customer/contract-related		3,220		(1,789	)		1		3,220		(488	)		1
Patents		6,992		(1,460	)		12		6,992		(1,155	)		12
Non-competition agreements		1,144		(543	)		6		1,144		(454	)		6
Other		4,043		(2,215	)		13		2,754		(1,966	)		13
Total intangible assets	$	35,701	$	(10,414	)			$	34,412	$	(7,959	)

Amortizable intangible assets are being amortized over their estimated useful lives of one to 40 years with a weighted average amortization period of 21 years. Total amortization expense for other intangible assets was $874,000 and $394,000 for the three months ended July 31, 2011 and 2010, respectively and $2,456,000 and $794,000 for the six months ended July 31, 2011 and 2010, respectively.

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

(in thousands)	Energy		Water Infrastructure		Total
Balance January 31, 2011	$	950	$	102,428	$	103,378
Additions		-		2,318		2,318
Balance July 31, 2011	$	950	$	104,746	$	105,696

4. Indebtedness

On July 31, 2003, the Company issued $40,000,000 of notes (“Series A Senior Notes”) under its 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 prior 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 of $6,667,000 is due on September 29, 2011.

On July 8, 2011, the Company entered into a new private shelf agreement (the “Shelf Agreement”) whereby it can issue $150,000,000 in unsecured notes. The $150,000,000 private shelf agreement extends to July 8, 2021 and replaced the prior Master Shelf Agreement. The $6,667,000 outstanding under the prior Master Shelf Agreement reduces the borrowing capacity of the new Shelf Agreement to $143,333,000 as of July 31, 2011.

On March 25, 2011, the Company entered into a new revolving credit facility (the “New Credit Agreement”) which contains a revolving loan commitment of $300,000,000, less any outstanding letter of credit commitments (which are subject to a $100,000,000 sublimit). The unsecured $300,000,000 facility extends to March 25, 2016, and replaces the Company’s prior Credit Agreement, which was terminated. The New Credit Agreement was entered into to extend the expiration period of the Company’s debt facilities and increase borrowing capacity. The Company funded $1,700,000 of debt issuance costs through borrowings under its New Credit Agreement. These costs will be amortized over the life of the credit agreement.

The New Credit Agreement provides for interest at variable rates equal to, at the Company’s option, a LIBOR rate plus 1.25% to 2.25%, or a base rate as defined in the New Credit Agreement, plus up to 1.25%, each depending on the Company’s leverage ratio. On July 31, 2011, there were letters of credit of $19,389,000 and borrowings of $47,500,000 outstanding on the New Credit Agreement resulting in available capacity of $233,111,000.

The Master Shelf Agreement and the New 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 and leverage ratio. Additionally, the Company must maintain a minimum tangible net worth under the Master Shelf Agreement. The Company was in compliance with its covenants as of July 31, 2011.

Debt outstanding as of July 31, 2011, and January 31, 2011, whose carrying value approximates fair value, was as follows:

	July 31,			January 31,
(in thousands)	2011			2011
Long-term debt:
Credit agreement	$	47,500		$	3,000
Senior notes		6,667			6,667
Total debt		54,167			9,667
Less current maturities		(6,667	)		(9,667	)
Total long-term debt	$	47,500		$	-

5. Derivatives

The Company’s Energy Division is exposed to fluctuations in the price of natural gas and periodically enters into fixed-price physical delivery contracts to manage natural gas price risk for a portion of its production, if available at attractive prices. As of July 31, 2011 and January 31, 2011 the Company held no such contracts.

The Company has entered into physical delivery contracts in order to facilitate normal recurring sales with our natural gas purchasing counterparty. As of July 31, 2011, the Company had committed to deliver a total of 1,104,000 million British Thermal Units (“MMBtu”) of natural gas through October 2011. The contract price resets daily based on a weighted average price of the reported trades for deliveries on the following day.

Additionally, the Company has foreign operations that have significant costs denominated in foreign currencies, and thus is exposed to risks associated with changes in foreign currency exchange rates. At any point in time, the Company might use various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated with forecasted expatriate labor costs and purchases of operating supplies. As of July 31, 2011 and January 31, 2011 the Company held no such contracts.

6. Other Income, Net

Other income, net consisted of the following for the three and six months ended July 31, 2011 and 2010:

	Three Months						Six Months
	Ended July 31,						Ended July 31,
(in thousands)	2011			2010			2011			2010
Gain from disposal of property and equipment	$	2,438		$	345		$	8,080		$	409
Gain on sale of investment securities		-			-			996			-
Interest income		36			51			58			124
Currency exchange loss		(793	)		(59	)		(593	)		(192	)
Other		(420	)		(148	)		(365	)		(265	)
Total	$	1,261		$	189		$	8,176		$	76

On March 21, 2011, the Company sold its operating facility in Fontana, California, with the intent of acquiring and relocating to a new facility. In the interim until a new facility can be purchased, the Company entered into a leasehold agreement of the existing facility. The total gain on the sale of the facility was $6,354,000, of which $1,379,000 was deferred to match the expected lease payments under the leasehold agreement. The deferred gain will be recognized over the 36 month term of the lease. The Company recognized $115,000 and $192,000 of the deferred gain during the three and six months ended July 31, 2011, respectively. The proceeds of the sale of $9,000,000 were placed in a restricted escrow fund for purposes of purchasing the new facility. Funds not spent will revert to the Company as of September 17, 2011.

7. Employee Benefit Plans

The Company provides supplemental retirement benefits to its chief executive officer. Benefits are computed based on the compensation earned during the highest five consecutive years of employment reduced for a portion of Social Security benefits and an annuity equivalent of the chief executive’s defined contribution plan balance. The Company does not contribute to the plan or maintain any investment assets related to the expected benefit obligation. The Company has recognized the full amount of its actuarially determined pension liability. Net periodic pension cost of the supplemental retirement benefits for the three and six months ended July 31, 2011 and 2010 include the following components:

	Three Months				Six Months
	Ended July 31,				Ended July 31,
(in thousands)	2011		2010		2011		2010
Service cost	$	138	$	87	$	276	$	174
Interest cost		47		43		94		86
Net periodic pension cost	$	185	$	130	$	370	$	260

8. Fair Value Measurements

The Company follows current accounting 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 our 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 are presented below as of July 31, 2011 and January 31, 2011:

			Fair Value Measurements
(in thousands)	Carrying Value		Level 1		Level 2		Level 3
July 31, 2011
Financial Assets:
Restricted deposits held at fair value	$	16,689	$	16,689	$	-	$	-

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

January 31, 2011
Financial Assets:
Restricted deposits held at fair value	$	6,967	$	6,967	$	-	$	-

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

(1)

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.

9. Stock and Stock Option Plans

In October 2008, the Company amended the Rights Agreement signed October 1998 whereby the Company 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 Rights Agreement will expire in October 2011.

The Company has stock option and employee incentive plans that provide for the granting of options to purchase or the issuance of shares of common stock at a price fixed by the Board of Directors or a committee. As of July 31, 2011, there was an aggregate of 2,850,000 shares registered under the plans, 1,074,011 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 824,011 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 always issued new shares and expects to continue to issue new shares in the future. For the six months ended July 31, 2011, the Company granted 193,188 restricted shares which, in general, ratably vest over periods of one to five years from the grant date.

The Company recognized $2,228,000 and $2,190,000 of compensation cost for these share-based plans during the six months ended July 31, 2011 and 2010, respectively. Of these amounts, $685,000 and $559,000, respectively, related to nonvested stock. The total income tax benefit recognized for share-based compensation arrangements was $869,000 and $854,000 for the six months ended July 31, 2011 and 2010, respectively.

A summary of nonvested share activity for the six months ended July 31, 2011, is as follows:

	Number of Shares			Average Grant Date Fair Value		Intrinsic Value (in thousands)
Nonvested stock at January 31, 2011		107,785		$	32.24
Granted		193,188			30.67
Vested		(24,561	)		36.02
Canceled		(33,251	)		35.71
Nonvested stock at July 31, 2011		243,161			30.14	$ 7,127

Significant option groups outstanding at July 31, 2011, 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		35
6/04		60,076		60,076		16.65		35
6/05		10,000		10,000		17.54		47
9/05		104,707		104,707		23.05		50
1/06		173,981		173,981		27.87		54
6/06		80,000		80,000		29.29		59
6/07		65,625		65,625		42.26		71
7/07		25,500		25,500		42.76		72
9/07		3,000		2,250		55.48		74
2/08		73,164		73,164		35.71		78
1/09		6,000		6,000		24.01		89
2/09		198,365		132,240		15.78		90
2/09		4,580		4,580		15.78		90
6/09		106,993		71,325		21.99		94
6/09		2,472		2,472		21.99		94
2/10		85,290		28,426		27.79		102
2/10		2,721		2,721		25.44		102
2/11		101,843		-		33.10		114
3/11		1,312		-		34.50		116
6/11		2,096		-		28.71		118
7/11		17,893		-		29.31		120
		1,145,618		863,067

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 $18.70 and $16.08 for the six months ended July 31, 2011 and 2010, respectively. The fair value was based on an expected life of approximately six years, no dividend yield, an average risk-free rate of 1.84% and 2.43%, respectively, and assumed volatility of 65%. The options have terms of ten years from the date of grant and generally vest ratably over periods of one month to five years. Transactions for stock options for the six months ended July 31, 2011, were as follows:

	Number of Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)		Intrinsic Value (in thousands)
Outstanding at January 31, 2011		1,031,474		$	25.34		6.4	$	7,793
Granted		123,144			32.49
Exercised		(9,000	)		21.27				112
Outstanding at July 31, 2011		1,145,618			26.14		6.4		5,760

Exercisable at January 31, 2011		693,587			26.23		5.6		4,696
Exercisable at July 31, 2011		863,067			26.07		5.6		4,517

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.

10. Investment in Affiliates

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 investments in affiliates are carried at the fair value of the investment considered at the date acquired, plus the Company’s equity in undistributed earnings from that date. These affiliates, which generally are engaged in mineral exploration drilling and the manufacture and supply of drilling equipment, parts and supplies, are as follows at July 31, 2011:

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

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				Six Months
	Ended July 31,				Ended July 31,
(in thousands)	2011		2010		2011		2010
Income statement data:
Revenues	$	137,822	$	70,592	$	246,507	$	135,515
Gross profit		32,982		11,429		57,060		22,717
Operating income		22,735		5,875		38,195		11,962
Net income		17,205		4,176		27,716		8,696

11. 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 oil and 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. Although individual offices within a division may periodically perform services normally provided by another division, the results of those services are recorded in the offices’ own division. For example, if a Mineral Exploration Division office performed water well drilling services, the revenues would be recorded in the Mineral Exploration Division rather than the Water Infrastructure Division. The Company’s 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, well design, drilling and development, pump installation, sewer rehabilitation, pipeline construction 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. 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 the exploration and production of oil and gas properties, primarily concentrating on projects in the mid-continent region of the United States.

Other

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

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

	Three Months						Six Months
	Ended July 31,						Ended July 31,
(in thousands)	2011			2010			2011			2010
Revenues
Water Infrastructure	$	217,718		$	193,990		$	413,783		$	366,895
Mineral Exploration		68,997			50,785			131,764			96,663
Energy		5,742			5,843			11,402			15,392
Other		2,595			2,682			5,474			5,065
Total revenues	$	295,052		$	253,300		$	562,423		$	484,015

Equity in earnings of affiliates
Water Infrastructure	$	799		$	-		$	925		$	-
Mineral Exploration		7,037			1,614			11,580			3,487
Total equity in earnings of affiliates	$	7,836		$	1,614		$	12,505		$	3,487

Income (loss) before income taxes
Water Infrastructure	$	7,658		$	10,285		$	21,833		$	18,925
Mineral Exploration		18,819			8,956			36,065			17,543
Energy		259			480			1,239			2,997
Other		501			544			804			792
Unallocated corporate expenses		(7,267	)		(6,737	)		(16,324	)		(13,806	)
Interest expense		(717	)		(517	)		(1,061	)		(1,043	)
Total income before income taxes	$	19,253		$	13,011		$	42,556		$	25,408

Product Line Revenue Information
Water systems	$	49,046		$	53,145		$	95,687		$	92,760
Water treatment technologies		13,729			5,150			25,751			21,094
Sewer rehabilitation		33,491			27,665			62,914			54,017
Water plant construction		54,922			63,547			107,473			115,086
Pipeline construction		30,113			21,831			55,762			40,869
Soil stabilization		28,567			17,378			53,497			31,531
Environmental and specialty drilling		6,399			3,956			10,826			8,783
Exploration drilling		70,037			50,885			133,071			96,899
Energy		6,195			6,608			12,421			17,014
Other		2,553			3,135			5,021			5,962
Total revenues	$	295,052		$	253,300		$	562,423		$	484,015

Geographic Information
Revenue
United States	$	235,145		$	210,548		$	451,781		$	402,752
Africa/Australia		27,566			19,860			54,284			38,306
Mexico		13,915			12,909			25,377			23,564
Other foreign		18,426			9,983			30,981			19,393
Total revenues	$	295,052		$	253,300		$	562,423		$	484,015

12. Contingencies

The Company’s drilling 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 drill 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.

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 agents and other third parties interacting with government officials in certain countries in Africa. The Audit Committee of the Board of Directors engaged outside counsel to conduct an internal investigation to review these and other payments with assistance from an outside accounting firm. The internal investigation, which is continuing, has found documents and information suggesting that improper payments, which may violate the FCPA and other local laws, were made over a considerable period of time, by or on behalf of, certain foreign subsidiaries of the Company to third parties interacting with government officials in Africa relating to the payment of taxes, the importing of equipment and the employment of expatriates. The Company contacted the Securities and Exchange Commission ("SEC") and the U.S. Department of Justice ("DOJ") to voluntarily inform them of this matter and is fully cooperating with these governmental authorities as the investigation continues and as they review the matter. At this stage of the internal investigation, the Company is unable to predict any potential remedies or actions these agencies may pursue. Additional potential FCPA violations or violations of other laws or regulations may be uncovered through the investigation.

The Company is involved in various other 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 to agents and other third parties interacting with government officials in certain countries in Africa relating to the payment of taxes, the importing of equipment and the employment of expatriates (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, 2011, 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, 2011. MD&A includes the following sections:

·	Our Business — a general description of our business and key fiscal 2012 events.

·	Consolidated Review of Operations — an analysis of our consolidated results of operations for the three and six months ended July 31, 2011.

Operating Segment Review of Operations — an analysis of our results of operations for the three and six months ended July 31, 2011 as presented in our Consolidated Financial Statements for our three primary operating segments: Water Infrastructure Division, Mineral Exploration Division and Energy Division.

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

·	Critical Accounting Policies — a 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

The Company is a multinational company that 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 oil and unconventional natural gas for the energy market. We operate throughout North America, as well as in Africa, Australia, Brazil and Italy. We also operate through our affiliates in South America and Mexico. 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 agribusiness.

Key Fiscal 2012 Events

On August 1, 2011, the Company announced its Chief Executive Officer (“CEO”), Andrew B. Schmitt, will retire at the end of the fiscal year ending January 31, 2012. Rene J. Robichaud a current board member, has assumed the position of President as of September 6, 2011, and will assume the additional role of CEO upon Mr. Schmitt’s retirement. Mr. Schmitt will continue to serve on the Company’s Board of Directors. In connection with Mr. Schmitt’s retirement, the Company estimates that it will recognize additional expenses in the range of $1,800,000 to $2,000,000 in retirement benefit costs over the remainder of the fiscal year.

We experienced continued improvements in the minerals exploration markets served by our wholly owned operations and our Latin America affiliates. For the six months ended July 31, 2011, revenues in our Mineral Exploration Division have increased 36.3% and pre-tax earnings have improved 105.6% compared to the same period last year.

We recognized a gain of $5,167,000 (inclusive of $192,000 amortization of deferred gain) on the sale of a facility in Fontana, California. The facility was sold March 21, 2011, in anticipation of relocating existing operations to a different property.

The majority of the Company’s forward sales contracts in the Energy Division expired in March 2010, and as a result of the unfavorable natural gas pricing have not been renewed. For the six months ended July 31, 2011, revenues in this division have accordingly dropped 25.9% and pre-tax earnings have decreased 58.7% compared to the same period last year.

On February 28, 2011, the Company acquired the Kansas and Colorado cured-in-place pipe operations of Wildcat Civil Services, a sewer rehabilitation contractor. The acquisition will further the Company’s expansion and geographic reach of its Inliner group westward.

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						Six Months						Period-to-Period
	Ended July 31,						Ended July 31,						Change
	2011			2010			2011			2010			Three			Six
Revenues:													Months			Months
Water Infrastructure		73.8	%		76.6	%		73.6	%		75.8	%		12.2	%		12.8	%
Mineral Exploration		23.4			20.0			23.4			20.0			35.9			36.3
Energy		1.9			2.3			2.0			3.2			(1.7	)		(25.9	)
Other		0.9			1.1			1.0			1.0			(3.2	)		8.1
Total net revenues		100.0			100.0			100.0			100.0			16.5			16.2
Cost of revenues		(78.4	)		(78.1	)		(76.7	)		(76.4	)		17.0			16.8
Selling, general and administrative expenses		(12.9	)		(12.5	)		(13.9	)		(13.5	)		20.1			19.7
Depreciation, depletion and amortization		(5.0	)		(4.8	)		(5.3	)		(5.4	)		21.2			13.5
Equity in earning of affiliates		2.7			0.6			2.2			0.7			385.5			258.6
Interest expense		(0.2	)		(0.2	)		(0.2	)		(0.2	)		38.7			1.7
Other income, net		0.4			0.1			1.5			-			567.2			10,657.9
Income before income taxes		6.6			5.1			7.6			5.2			48.0			67.5
Income tax expense		(2.7	)		(2.6	)		(3.2	)		(2.6	)		23.1			43.3
Net income		3.9			2.5			4.4			2.6			73.3			90.5
Net income attributable to noncontrolling interests		(0.2	)		-			(0.2	)		-			*			*
Net income attributable to Layne Christensen Company		3.7	%		2.5	%		4.2	%		2.6	%		64.5			81.8
* = 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, safety, treasury, corporate and securities law, tax compliance, certain executive management (chief executive officer, chief operating officer, chief financial officer and general counsel) and board of directors.

	Three Months						Six Months
	Ended July 31,						Ended July 31,
(in thousands)	2011			2010			2011			2010
Revenues
Water Infrastructure	$	217,718		$	193,990		$	413,783		$	366,895
Mineral Exploration		68,997			50,785			131,764			96,663
Energy		5,742			5,843			11,402			15,392
Other		2,595			2,682			5,474			5,065
Total revenues	$	295,052		$	253,300		$	562,423		$	484,015
Equity in earnings of affiliates
Water Infrastructure	$	799		$	-		$	925		$	-
Mineral Exploration		7,037			1,614			11,580			3,487
Total equity in earnings of affiliates	$	7,836		$	1,614		$	12,505		$	3,487
Income (loss) before income taxes
Water Infrastructure	$	7,658		$	10,285		$	21,833		$	18,925
Mineral Exploration		18,819			8,956			36,065			17,543
Energy		259			480			1,239			2,997
Other		501			544			804			792
Unallocated corporate expenses		(7,267	)		(6,737	)		(16,324	)		(13,806	)
Interest expense		(717	)		(517	)		(1,061	)		(1,043	)
Total income before income taxes	$	19,253		$	13,011		$	42,556		$	25,408

Revenues increased $41,752,000, or 16.5%, to $295,052,000, for the three months ended July 31, 2011, and $78,408,000, or 16.2%, to $562,423,000 for the six months ended July 31, 2011, as compared to the same periods last year. A further discussion of results of operations by division is presented below.

Cost of revenues increased $33,673,000, or 17.0%, to $231,419,000 (78.4% of revenues) and $61,986,000, or 16.8% to $431,644,000 (76.7% of revenues) for the three and six months ended July 31, 2011, compared to $197,746,000 (78.1% of revenues) and $369,658,000 (76.4% of revenues) for the same periods last year. The increases as a percentage of revenues are primarily due to margin pressures in the Water Infrastructure Division as discussed below.

Selling, general and administrative expenses increased 20.1% to $38,054,000 and 19.7% to $78,055,000 for the three and six months ended July 31, 2011, compared to $31,698,000 and $65,213,000 for the same periods last year. The increases were primarily due to additional expenses of $2,814,000 and $4,235,000 from acquired operations, $2,815,000 and $4,883,000 of increased compensation costs, $1,948,000 and $2,574,000 of increased legal and professional fees and $750,000 and $1,262,000 of increased travel costs for the three and six months, respectively, partially offset by reduction in various other expense categories.

Depreciation, depletion and amortization increased 21.2% to $14,706,000 and 13.5% to $29,788,000 for the three and six months ended July 31, 2011, compared to $12,131,000 and $26,256,000 for the same periods last year. The increases were primarily the result of acquisitions and property additions, partially offset by lower depletion in the Energy Division as a result of higher estimates of economically recoverable gas reserves.

Equity in earnings of affiliates increased 385.5% to $7,836,000 and 258.6% to $12,505,000 for the three and six months ended July 31, 2011, compared to $1,614,000 and $3,487,000 for the same periods last year. The increase reflects the impact of an improved minerals exploration market in Latin America, primarily for gold and copper in Chile and Peru.

Interest expense increased to $717,000 and $1,061,000 for the three and six months ended July 31, 2011, compared to $517,000 and $1,043,000 for the same periods last year, the result of increased borrowings on our credit facilities to fund working capital.

Other income, net for the three months ended July 31, 2011, consisted primarily of gains of $2,323,000 on the sale of equipment, partially offset by foreign exchange losses of $793,000. Other income, net for the six months ended July 31, 2011, consisted primarily of a gain of $5,167,000 (inclusive of $192,000 amortization of deferred gain) on the sale of a facility in California, a gain of $996,000 on the sale of certain investment securities in Australia and gains of $2,913,000 on the sale of other equipment, partially offset by foreign exchange losses of $593,000. The facility in California was sold in anticipation of relocating existing operations to a different property.

Income tax expense of $8,075,000 (an effective rate of 41.9%) and $17,746,000 (an effective rate of 41.7%) was recorded for the three and six months ended July 31, 2011, respectively, compared to $6,561,000 (an effective rate of 50.4%) and $12,387,000 (an effective rate of 48.7%) for the same periods last year. The decrease in the effective rate was primarily attributable to a lesser tax impact of certain foreign operations and foreign affiliates. The effective rate in excess of the statutory federal rate for the periods was due primarily to the impact of nondeductible expenses and the tax treatment of certain foreign operations.

Operating Segment Review of Operations

Water Infrastructure Division	Three Months				Six Months
	Ended July 31,				Ended July 31,
(in thousands)	2011		2010		2011		2010
Revenues	$	217,718	$	193,990	$	413,783	$	366,895
Income before income taxes		7,658		10,285		21,833		18,925

Water Infrastructure Division revenues increased 12.2% to $217,718,000 and 12.8% to $413,783,000 for the three and six months ended July 31, 2011, respectively, compared to $193,990,000 and $366,895,000 for the same periods last year. The increase for the three months was primarily attributable to additional revenues of $16,456,000 from acquired and start-up operations, $9,308,000 in water resources and technologies, $3,216,000 from our specialty and injection well drilling operations and $1,717,000 in our Inliner businesses. The increases were partially offset by a decline of $4,101,000 in our heavy construction operations that were impacted by weather related project delays. The increase for the six months was primarily attributable to additional revenues of $31,361,000 from acquired and start-up operations, $8,220,000 in water resources and technologies and $3,228,000 in our Inliner businesses. The increases were partially offset by a decline of $669,000 in our heavy construction operations that were impacted by weather related project delays and $2,770,000 in our non-acquisition related geoconstruction projects, the result of lower activity compared to last year.

Included in revenues for the three and six months ended July 31, 2011, were $3,218,000 and $6,950,000, respectively, from our project in Afghanistan compared to $3,604,000 and $9,081,000 for the same periods last year. This project contributed $2,692,000 and $5,873,000, respectively, to income before income taxes for the three and six months ended July 31, 2011, compared to $2,166,000 and $5,399,000 for the same periods last year. Drilling operations on this project have ceased and we are nearing the completion of demobilizing our equipment.

Income before income taxes for the Water Infrastructure Division decreased 25.5% to $7,658,000 for the three months ended July 31, 2011, compared to $10,285,000 for the same period last year. The decrease was primarily attributable to a decline of $5,436,000 from our heavy construction operations, partially offset by an increase of $3,064,000 from acquired and start-up operations. The heavy construction decline was due to continued downward pressure on margins for municipal bid projects and inefficiencies and cost overruns due to weather and other project delays. We expect profit margins for projects in the municipal sector to remain under pressure for some time.

Included in the results of the Water Infrastructure Division for the six months ended July 31, 2011, was a gain of $5,167,000 (inclusive of $192,000 amortization of deferred gain) on the sale of a facility in Fontana, California. Exclusive of this gain, income before income taxes for the Water Infrastructure Division decreased 11.9% to $16,666,000 for the six months ended July 31, 2011, compared to $18,925,000 for the same period last year. The decrease was primarily attributable to a decline of $6,123,000 from our heavy construction operations that were impacted by continued downward pressure on margins for municipal bid projects and weather related project delays, partially offset by an increase of $4,626,000 from acquired and start-up operations.

The backlog in the Water Infrastructure Division was $478,087,000 as of July 31, 2011, compared to $526,972,000 as of July 31, 2010.

Mineral Exploration Division	Three Months				Six Months
	Ended July 31,				Ended July 31,
(in thousands)	2011		2010		2011		2010
Revenues	$	68,997	$	50,785	$	131,764	$	96,663
Income before income taxes		18,819		8,956		36,065		17,543

Mineral Exploration Division revenues increased 35.9% to $68,997,000 and 36.3% to $131,764,000 for the three and six months ended July 31, 2011, respectively, compared to $50,785,000 and $96,663,000 for the same periods last year. The increases were driven by increased activity levels across all locations, particularly the southeast U.S., Brazil and southern Africa.

Income before income taxes for the Mineral Exploration Division increased 110.1% to $18,819,000 and 105.6% to $36,065,000 for the three and six months ended July 31, 2011, respectively, compared to $8,956,000 and $17,543,000 for the same periods last year. The increase resulted primarily from the equity earnings from our affiliates, and the higher revenues in our wholly-owned businesses, combined with slightly higher margins. Equity earnings from our affiliates increased $5,423,000 to $7,037,000 and $8,093,000 to $11,580,000 for the three and six months ended July 31, 2011, respectively, compared to $1,614,000 and $3,487,000 for the same periods last year. Our affiliates had significant increases in activity at copper and gold mine sites in Chile and Peru.

Energy Division	Three Months				Six Months
	Ended July 31,				Ended July 31,
(in thousands)	2011		2010		2011		2010
Revenues	$	5,742	$	5,843	$	11,402	$	15,392
Income before income taxes		259		480		1,239		2,997

Energy Division revenues decreased 1.7% to $5,742,000 and 25.9% to $11,402,000 for the three and six months ended July 31, 2011, respectively, compared to revenues of $5,843,000 and $15,392,000 for the same periods last year. The decreases were primarily attributable to lower natural gas prices compared to last year and, for the six months, the expiration of the forward sales contracts existing in the first three months of last year.

Income before income taxes for the Energy Division decreased 46.0% to $259,000 and 58.7% to $1,239,000 for the three and six months ended July 31, 2011, respectively, compared to $480,000 and $2,997,000 for the same periods last year. The decreases were due to the impact of lower natural gas prices and, for the six months, the expiration of the forward sales contracts existing in the first three months of last year.

Net gas production by the Energy Division for the three and six months ended July 31, 2011, was 1,135 MMcf and 2,227 MMcf, compared to 1,143 MMcf and 2,285 MMcf for the same periods last year. The average net sales price on production for the three and six months ended July 31, 2011, was $3.67 and $3.37 per Mcf, respectively, compared to $4.12 and $5.67 per Mcf for the same periods last year. The net sales price excludes revenues generated from third party gas.

Other	Three Months				Six Months
	Ended July 31,				Ended July 31,
(in thousands)	2011		2010		2011		2010
Revenues	$	2,595	$	2,682	$	5,474	$	5,065
Income before income taxes		501		544		804		792

Other revenues and income before income taxes were primarily the 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 $7,267,000 and $16,324,000 for the three and six months ended July 31, 2011, respectively, compared to $6,737,000 and $13,806,000 for the same periods last year. The increases were primarily attributable to legal and professional fees.

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.

On July 8, 2011, the Company entered into a new private shelf agreement (the “Shelf Agreement”) whereby it can issue $150,000,000 in unsecured notes. The $150,000,000 private shelf agreement extends to July 8, 2021, and replaced the Company’s prior Master Shelf Agreement. At July 31, 2011, the Company had $6,667,000 in notes outstanding under the prior Master Shelf Agreement which will be paid in September 2011. The notes outstanding under the prior Master Shelf Agreement reduce the borrowing capacity of the new Shelf Agreement to $143,333,000.

The Company also maintains an unsecured $300,000,000 revolving credit facility (the “New Credit Agreement”) which extends to March 25, 2016. At July 31, 2011, the Company had letters of credit of $19,389,000 and borrowings of $47,500,000 outstanding under the New Credit Agreement resulting in available capacity of $233,111,000.

The Company’s Shelf Agreement and New 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 a fixed charge coverage ratio, a maximum leverage ratio and a minimum tangible net worth. Covenant levels and definitions are consistent between the two agreements with the exception of the tangible net worth covenant not being a requirement of the New Credit Agreement. The Company was in compliance with its covenants as of July 31, 2011, 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. 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 EDITDA, 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 July 31, 2011 and 2010, the Company’s actual and required covenant levels under the existing agreements were as follows:

	Actual		Required		Actual		Required
(in thousands, except for ratio data)	July 31, 2011		July 31, 2011		July 31, 2010		July 31, 2010
Minimum fixed charge coverage ratio		2.59		1.50		3.71		1.50
Maximum leverage ratio		0.65		3.00		0.37		3.00
Minimum tangible net worth	$	384,301	$	324,187	$	350,020	$	302,875

The Company’s working capital as of July 31, 2011 and 2010 was $151,280,000 and $105,631,000, respectively. The Company’s cash and cash equivalents as of July 31, 2011, were $33,264,000, compared to $44,985,000 as of January 31, 2011 and $49,184,000 as of July 31, 2010. The decreased amount of cash and cash equivalents as of July 31, 2011 compared to the same period last year was primarily due to cash payments for acquisitions, capital expenditures, working capital changes and scheduled debt repayments. The Company believes it will have sufficient cash from operations and access to credit facilities to meet the Company’s operating cash requirements and to fund its budgeted capital expenditures for fiscal 2012.

Operating Activities

Cash used in operating activities was $19,352,000 for the six months ended July 31, 2011 compared to cash provided by operating activities of $12,577,000 for the same period last year. The decrease is primarily attributable to increased working capital needs as a result of increased revenues, and delays in the timing of billings as contract terms on a number of our larger current projects have extended milestones before billings may be submitted. We expect our working capital needs to decrease over the balance of the fiscal year.

Investing Activities

During the six months ended July 31, 2011, the Company sold a facility in California for $9,000,000. The proceeds from the sale were deposited into a restricted cash account in anticipation of purchasing a different property to relocate existing operations. The funds will be released to us in September 2011.

Excluding the proceeds from the facility sale, the Company’s capital expenditures, net of disposals, of $28,237,000 for the six months ended July 31, 2011, were split between $26,587,000 to maintain and upgrade its equipment and facilities and $1,650,000 toward the Company’s unconventional oil and gas exploration and production, including the construction of gas pipeline infrastructure near the Company’s development projects. This compares to equipment spending of $28,066,000 and gas exploration and production spending of $1,139,000 in the same period last year. The Company expects to spend approximately $30 million over the remainder of the fiscal year.

For the six months ended July 31, 2011, the Company invested $8,855,000 for the Kansas and Colorado cured-in-place pipe operations of Wildcat Civil Services, a sewer rehabilitation contractor.

Financing Activities

For the six months ended July 31, 2011, the Company had net borrowings of $42,784,000 under its credit facilities. The borrowings were primarily used to fund the Wildcat acquisition and the Company’s working capital needs. The Company will make scheduled principal payments on the Senior Notes of $6,667,000 in September 2011.

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, 2011. There have been no changes to our critical accounting policies since January 31, 2011.

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.

Interest Rate Risk

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, 2011 Form 10-K and Note 4 of this Form 10-Q. As of July 31, 2011, an instantaneous change in interest rates of one percentage point would impact the Company’s annual interest expense by approximately $475,000.

Foreign Currency Risk

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, Canada, Brazil 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, 2011, Form 10-K and Notes 10 and 11 of this Form 10-Q. The majority of the Company’s contracts in Africa and Mexico are U.S. dollar based, providing a natural reduction in exposure to currency fluctuations. The Company also may utilize various hedge instruments, primarily foreign currency option contracts, to manage the exposures associated with fluctuating currency exchange rates. As of July 31, 2011, the Company did have any outstanding foreign currency option contracts.

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. The Company estimates that a ten percent change in foreign exchange rates would have impacted income before income taxes by approximately $165,000 for the six months ended July 31, 2011. 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.

Commodity Price Risk

The Company is also exposed to fluctuations in the prices of oil and natural gas, which result from the sale of the Energy Division’s oil and unconventional gas production. The prices of oil and natural gas are volatile and the Company enters into fixed-price physical delivery contracts, if available at attractive prices, to cover a portion of its production to manage price fluctuations and to achieve a more predictable cash flow. The Company generally intends to maintain contracts in place to cover 50% to 75% of its production, although at July 31, 2011, did not have any contracts in place.

The Company estimates that a ten percent change in the price of natural gas would have impacted income before income taxes by approximately $226,000 for the six months ended July 31, 2011.

ITEM 4. Controls and Procedures

Disclosure Controls and Procedures

Based on an evaluation of disclosure controls and procedures for the period ended July 31, 2011, 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 six months ended July 31, 2011, 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

As previously reported, 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 agents and other third parties interacting with government officials in certain countries in Africa. The Audit Committee of the Board of Directors engaged outside counsel to conduct an internal investigation to review these and other payments with assistance from an outside accounting firm. The internal investigation, which is continuing, has found documents and information suggesting that improper payments, which may violate the FCPA and other local laws, were made over a considerable period of time, by or on behalf of, certain foreign subsidiaries of the Company to agents and other third parties interacting with government officials in certain countries in Africa relating to the payment of taxes, the importing of equipment and the employment of expatriates. The Company has terminated the employment of three overseas members of the Mineral Exploration Division management for failing to follow the Company’s policies and procedures. In addition, as previously reported, the Company has appointed Gernot Penzhorn to replace Eric Despain as the President of the Minerals Exploration Division. The Company believes that its continuing efforts to enhance compliance with the FCPA, by the employees of the Mineral Exploration Division, will benefit from this change in leadership.

The Company contacted the Securities and Exchange Commission ("SEC") and the U.S. Department of Justice ("DOJ") to voluntarily inform them of this matter and is fully cooperating with these governmental authorities as the investigation continues and as they review the matter. At this stage of the internal investigation, the Company is unable to predict any potential remedies or actions these agencies may pursue.

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 and other applicable laws. 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. Additional potential FCPA violations or violations of other laws or regulations may be uncovered through the investigation. See Part I, Items 1A (Risk Factors) in the Company’s Annual Report on Form 10-K for the fiscal year ended January 31, 2011 filed with the SEC for additional information.

The Company is involved in litigation incidental to its business, the disposition of which is not expected to have a material effect on the Company’s financial position or results of operations. It is possible, however, that future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions related to these proceedings. In accordance with U.S. GAAP, we record a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. 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.

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, 2011.

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

The table below sets forth information regarding repurchases of our common stock during the three months ended July 31, 2011. The shares repurchased represent shares of our common stock that employees and directors elected to surrender to the Company to satisfy certain minimum tax withholding and other tax obligations upon the vesting of shares of nonvested stock. The Company does not consider this to be a share buyback program.

Period	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
May 1, 2011 to
May 31, 2011		-		-		-		-
June 1, 2011 to
June 30, 2011		3,940	$	27.46		-		-
July 1, 2011 to
July 31, 2011		1,280	$	30.62		-		-

ITEM 3. Defaults Upon Senior Securities

NOT APPLICABLE

ITEM 4. Removed and Reserved

NONE

ITEM 5. Other Information

NONE

ITEM 6. Exhibits

(a)	Exhibits

	31.1	-	Section 302 Certification of Chief Executive Officer of the Company
	31.2	-	Section 302 Certification of Chief Financial Officer of the Company
	32.1	-	Section 906 Certification of Chief Executive Officer of the Company
	32.2	-	Section 906 Certification of Chief Financial Officer of the Company
	10.1	-	Rene J. Robichaud Offer Letter (filed as Exhibit 10.1 to the Company's Form 8-K filed on August 1, 2011, and incorporated by reference herein)
	10.2	-	Rene J. Robichaud Severance Agreement Letter (filed as Exhibit 10.2 to the Company's Form 8-K filed on August 1, 2011, and incorporated by reference herein)
	10.3	-	Rene J. Robichaud Restricted Stock Agreement Letter (filed as Exhibit 10.3 to the Company's Form 8-K filed on August 1, 2011, and incorporated by reference herein)
	10.4	-	Rene J. Robichaud Executive Incentive Compensation Plan Letter (filed as Exhibit 10.4 to the Company's Form 8-K filed on August 1, 2011, and incorporated by reference herein)
	10.5	-	Andrew B. Schmitt Retirement Agreement Letter (filed as Exhibit 10.5 to the Company's Form 8-K filed on August 1, 2011, and incorporated by reference herein)
	10.6	-	Private Shelf Agreement Letter (filed as Exhibit 10.1 to the Company's Form 8-K filed on July 13, 2011, and incorporated by reference herein)
	101	-	The following financial information from the Quarterly Report on Form 10-Q for the fiscal quarter ended July 31, 2011, formatted in XBRL (eXtensible Business Reporting Language) and furnished electronically herewith: (i) the Consolidated Statements of Earnings (Unaudited) for the Three and Six Months Ended July 31, 2011 and 2010; (ii) the Consolidated Balance Sheets (Unaudited) as of July 31, 2011 and January 31, 2011; (iii) the Consolidated Statements of Equity and Comprehensive Income (Unaudited) for the Six Months Ended July 31, 2011 and 2010; (iv) the Consolidated Statements of Cash Flows (Unaudited) for the Six Months Ended July 31, 2011 and 2010; and (v) the Notes to the Consolidated Financial Statements (Unaudited), tagged as blocks of text.**

**	Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

* * * * * * * * * *

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Layne Christensen Company
		(Registrant)




DATE:	September 7, 2011	/s/ A.B. Schmitt
		A.B. Schmitt, Chief Executive Officer




DATE:	September 7, 2011	/s/ Jerry W. Fanska
		Jerry W. Fanska, Sr. Vice President
		Finance and Treasurer

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