Layne Christensen (LAYN) 8-K Other Events

Exhibit 99.4

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)	January 31, 2013			January 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	27,242		$	41,916
Customer receivables, less allowance of $7,827 and $8,141, respectively		145,890			162,043
Costs and estimated earnings in excess of billings on uncompleted contracts		101,960			107,295
Inventories		49,913			35,392
Deferred income taxes		25,200			21,895
Income taxes receivable		6,809			4,137
Restricted deposits-current		—			3,143
Other		24,809			16,968
Total current assets		381,823			392,789
Property and equipment:
Land		17,505			17,155
Buildings		40,621			41,159
Machinery and equipment		534,849			478,896
Gas transportation facilities and equipment		—			40,995
Oil and gas properties, including unevaluated mineral interests excluded from amortization of $6,185		—			102,251
Mineral interests in oil and gas properties		—			21,374
		592,975			701,830
Less - Accumulated depreciation and depletion		(326,435	)		(424,473	)
Net property and equipment		266,540			277,357
Other assets:
Investment in affiliates		78,290			88,297
Goodwill		23,561			19,536
Other intangible assets, net		8,840			12,266
Restricted deposits-long term		2,861			443
Deferred income taxes		24,530			—
Other		25,781			15,148
Total other assets		163,863			135,690
Total assets	$	812,226		$	805,836

See Notes to Consolidated Financial Statements.

- Continued -

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LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS - (Continued)

(in thousands, except per share data)	January 31, 2013			January 31, 2012
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	86,329		$	104,261
Current maturities of long term debt		12,789			7,450
Accrued compensation		53,651			48,573
Accrued insurance expense		13,645			12,596
Other accrued expenses		47,398			29,120
Acquisition escrow obligation-current		—			3,143
Income taxes payable		8,063			19,328
Billings in excess of costs and estimated earnings on uncompleted contracts		34,869			31,914
Total current liabilities		256,744			256,385
Noncurrent liabilities:
Long-term debt		96,539			52,716
Accrued insurance expense		14,442			14,018
Deferred income taxes		1,553			9,883
Acquisition escrow obligation-long term		2,861			443
Other		25,016			20,510
Total noncurrent liabilities		140,411			97,570
Contingencies (Note 14)
Stockholders’ equity:
Common stock, par value $.01 per share, 30,000 shares authorized, 19,818 and 19,699 shares issued and outstanding, respectively		198			197
Capital in excess of par value		352,048			351,057
Retained earnings		66,983			103,634
Accumulated other comprehensive loss		(6,492	)		(6,223	)
Total Layne Christensen Company stockholders’ equity		412,737			448,665
Noncontrolling interests		2,334			3,216
Total equity		415,071			451,881
Total liabilities and stockholders’ equity	$	812,226		$	805,836

See Notes to Consolidated Financial Statements.

2

LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended January 31,
(in thousands, except per share data)	2013			2012			2011
Revenues	$	1,069,126		$	1,106,018		$	993,758
Cost of revenues (exclusive of depreciation,amortization, and impairment charges shown below)		(873,807	)		(869,074	)		(774,491	)
Selling, general and administrative expenses		(161,507	)		(162,739	)		(138,237	)
Depreciation and amortization		(61,158	)		(55,640	)		(44,604	)
Impairment charges		(8,431	)		(96,579	)		—
Loss on remeasurement of equity method investment		(7,705	)		—			—
Equity in earning of affiliates		20,572			24,647			13,153
Interest expense		(4,309	)		(2,357	)		(1,594	)
Other income, net		5,844			9,685			524
(Loss) income from continuing operations before income taxes		(21,375	)		(46,039	)		48,509
Income tax benefit (expense)		9,115			(8,634	)		(20,629	)
Net (loss) income from continuing operations		(12,260	)		(54,673	)		27,880
Net (loss) income from discontinued operations		(23,763	)		1,491			3,707
Net (loss) income		(36,023	)		(53,182	)		31,587
Net loss attributable to noncontrolling interests		(628	)		(2,893	)		(1,596	)
Net (loss) income attributable to Layne	$	(36,651	)	$	(56,075	)	$	29,991
(Loss) income earnings per share information attributable to Layne Christensen shareholders:
Basic (loss) income per share - continuing operations	$	(0.66	)	$	(2.96	)	$	1.36
Basic (loss) income per share - discontinued operations		(1.22	)		0.08			0.19
Basic (loss) income per share	$	(1.88	)	$	(2.88	)	$	1.55
Diluted (loss) income per share - continuing operations	$	(0.66	)	$	(2.96	)	$	1.34
Diluted (loss) income per share - discontinued operations		(1.22	)		0.08			0.19
Diluted (loss) income per share	$	(1.88	)	$	(2.88	)	$	1.53
Weighted average shares outstanding - basic		19,485			19,455			19,393
Dilutive stock options and unvested shares		—			—			185
Weighted average shares outstanding - dilutive		19,485			19,455			19,578

See Notes to Consolidated Financial Statements.

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LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

	Years Ended January 31,
(in thousands)	2013			2012			2011
Net (loss) income	$	(36,023	)	$	(53,182	)	$	31,587
Other comprehensive (loss) income:
Foreign currency translation adjustments (net of tax expense (benefit) of $479, $(108) and $(27), respectively)		(269	)		(414	)		195
Change in unrealized loss on foreign exchange contracts		—			—			62
Other comprehensive (loss) income		(269	)		(414	)		257
Comprehensive (loss) income		(36,292	)		(53,596	)		31,844
Comprehensive loss attributable to noncontrolling interests (all attributable to net income)		(628	)		(2,893	)		(1,596	)
Comprehensive (loss) income attributable to Layne Christensen Company	$	(36,920	)	$	(56,489	)	$	30,248

See Notes to Consolidated Financial Statements

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LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

	Common Stock					Capital In Excess of Par Value			Retained Earnings			Accumulated Other Comprehensive (Loss)			Total Layne Stockholders’ Equity			Noncontrolling Interests			Total
(in thousands, except share data)	Shares			Amount
Balance February 1, 2010		19,435,209		$	194	$	342,952		$	129,718		$	(6,066	)	$	466,798		$	75		$	466,873
Net income		—			—		—			29,991			—			29,991			1,596			31,587
Other comprehensive income		—			—		—			—			257			257			—			257
Issuance of nonvested shares		58,709			1		(1	)		—			—			—			—			—
Forfeiture of nonvested shares		(1,824	)		—		—			—			—			—			—			—
Treasury stock purchased and subsequently cancelled																						—
		(5,441	)		—		(136	)		—			—			(136	)		—			(136	)
Issuance of stock upon exercise of options		53,380			—		896			—			—			896			—			896
Income tax benefit on exercise of options		—			—		224			—			—			224			—			224
Income tax deficiency upon vesting of restricted shares		—			—		(127	)		—			—			(127	)		—			(127	)
Noncontrolling interests of acquisition		—			—		—			—			—			—			851			851
Share-based compensation		—			—		3,499			—			—			3,499			—			3,499
Balance, January 31, 2011		19,540,033			195		347,307			159,709			(5,809	)		501,402			2,522			503,924
Net (loss) income		—			—		—			(56,075	)		—			(56,075	)		2,893			(53,182	)
Other comprehensive loss		—			—		—			—			(414	)		(414	)		—			(414	)
Issuance of nonvested shares		193,188			2		(2	)		—			—			—			—			—
Forfeiture of nonvested shares		(5,927	)		—		—			—			—			—			—			—
Treasury stock purchased and subsequently cancelled																						—
		(5,382	)		—		(150	)		—			—			(150	)		—			(150	)
Expiration of performance contingent nonvested shares		(33,251	)		—		—			—			—			—			—			—
Issuance of stock upon exercise of options		10,611			—		220			—			—			220			—			220
Income tax benefit on exercise of options		—			—		16			—			—			16			—			16
Income tax deficiency upon vesting of restricted shares		—			—		(130	)		—			—			(130	)		—			(130	)
Distributions to noncontrolling interest		—			—		—			—			—			—			(2,199	)		(2,199	)
Share-based compensation		—			—		3,796			—			—			3,796			—			3,796
Balance January 31, 2012		19,699,272			197		351,057			103,634			(6,223	)		448,665			3,216			451,881
Net (loss) income		—			—		—			(36,651	)		—			(36,651	)		628			(36,023	)
Other comprehensive loss		—			—		—			—			(269	)		(269	)		—			(269	)
Issuance of nonvested shares		110,958			1		(1	)		—			—			—			—			—
Expiration of performance contingent nonvested shares		(46,491	)		—		—			—			—			—			—			—
Issuance of stock upon exercise of options		54,637			—		1,004			—			—			1,004			—			1,004
Income tax deficiency upon forfeiture of options		—			—		(280	)		—			—			(280	)		—			(280	)
Acquisition of noncontrolling interest		—			—		(2,656	)		—			—			(2,656	)		(87	)		(2,743	)
Distributions to noncontrolling interest		—			—		—			—			—			—			(1,423	)		(1,423	)
Share-based compensation		—			—		2,924			—			—			2,924			—			2,924
Balance January 31, 2013		19,818,376		$	198	$	352,048		$	66,983		$	(6,492	)	$	412,737		$	2,334		$	415,071

See Notes to Consolidated Financial Statements.

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LAYNE CHRISTENSEN COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

	Years Ended January 31,
(in thousands)	2013			2012			2011
Cash flow from operating activities:
Net (loss) income	$	(36,023	)	$	(53,182	)	$	31,587
Adjustments to reconcile net (loss) income to cash flow from operations:
Depreciation, depletion and amortization		65,883			63,566			53,468
Impairment charges		8,431			97,529			—
Loss on disposal of discontinued operations		32,589			—			—
Loss on remeasurement of equity method investment		7,705			—			—
Deferred income taxes		(37,898	)		(18,009	)		(115	)
Share-based compensation		2,924			3,796			3,499
Share-based compensation excess tax benefit		—			(16	)		(224	)
Losses in earnings of affiliates		(20,572	)		(24,647	)		(13,153	)
Dividends received from affiliates		7,080			5,502			4,225
Gain from disposal of property and equipment		(3,364	)		(8,247	)		(896	)
Changes in current assets and liabilities, (exclusive of effects of acquisitions):
Decrease (increase) in customer receivables		26,658			(19,330	)		(27,214	)
Decrease (increase) in costs and estimated earnings in excess of billings on uncompleted contracts		4,342			(24,726	)		3,164
(Increase) decrease in inventories		(12,394	)		(5,882	)		(4,004	)
Increase (decrease) in other current assets		1,306			(7,180	)		(11,200	)
(Decrease) increase in accounts payable and accrued expenses		(13,947	)		26,418			27,311
(Decrease) increase in billings in excess of costs and estimated earnings on uncompleted contracts		(4,798	)		(17,646	)		1,259
Other, net		(3,171	)		(2,234	)		1,173
Cash provided by operating activities		24,751			15,712			68,880
Cash flow from investing activities:
Additions to property and equipment		(75,831	)		(66,952	)		(64,329	)
Additions to gas transportation facilities and equipment		(58	)		(109	)		(138	)
Additions to oil and gas properties		(1,512	)		(3,434	)		(2,414	)
Additions to mineral interests in oil and gas properties		(102	)		(331	)		(322	)
Acquisition of businesses, net of cash acquired		(18,397	)		(8,855	)		(17,302	)
Proceeds from disposal of property and equipment		6,158			14,055			1,664
Proceeds from sale of business		13,500			—			4,800
Deposit of cash into restricted accounts		—			(9,000	)		—
Release of cash from restricted accounts		3,144			12,830			1,156
Distribution of restricted cash for prior year acquisitions		(3,144	)		(3,830	)		(1,156	)
Investment in foreign affiliate					—			(16,150	)
Cash used in investing activities		(76,242	)		(65,626	)		(94,191	)
Cash flow from financing activities:
Borrowing under revolving facilities		89,000			94,784			3,000
Repayments under revolving loan facilities		(46,500	)		(47,000	)		—
Net increase (decrease) in notes payable		1,110			7,366			—
Repayments of long term debt		(2,590	)		(6,667	)		(20,000	)
Principal payments under capital lease obligation		(93	)		—			—
Acquisition of noncontrolling interest		(2,743	)		—			—
Issuance of common stock upon exercise of stock options		1,004			220			896
Excess tax benefit on exercise of share-based instruments		—			16			224
Purchases and retirement of treasury stock		—			(150	)		(136	)
Distribution to noncontrolling interest		(1,423	)		(2,199	)		—
Cash provided by (used in) financing activities		37,765			46,370			(16,016	)
Effects of exchange rate changes on cash		(948	)		475			1,862
Net decrease in cash and cash equivalents		(14,674	)		(3,069	)		(39,465	)
Cash and cash equivalents at beginning of year		41,916			44,985			84,450
Cash and cash equivalents at end of year	$	27,242		$	41,916		$	44,985

See Notes to Consolidated Financial Statements.

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(1) Summary of Significant Accounting Policies

Description of Business – Layne Christensen Company and subsidiaries (together, the “Company”) is a global water management, construction and drilling company. The Company operates throughout North America as well as in parts of Africa, Australia, Brazil, and Italy. Its customers include government agencies, investor-owned water utilities, industrial companies, global mining companies, consulting and engineering firms, heavy civil construction contractors, oil and gas companies and agribusiness. The Company has ownership interest in certain foreign affiliates operating in South America, with facilities in Chile, Peru, Uruguay and Brazil (see Note 3).

Fiscal Year – The Company’s fiscal year end is January 31. References to fiscal years are to the twelve months then ended.

Investment in Affiliated Companies – Investments in affiliates (20% to 50% owned) in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for by the equity method.

Principles of Consolidation – The Consolidated Financial Statements include the accounts of the Company and its majority-owned subsidiaries. Intercompany transactions have been eliminated. Financial information for the Company’s affiliates and certain foreign subsidiaries is reported in the Company’s Consolidated Financial Statements with a one-month lag in reporting periods and use a December 31 year-end, primarily to match the local countries’ statutory reporting requirements. The effect of this one-month lag on the Company’s financial position and results of operations is not significant. The Company has evaluated subsequent events through the time of the filing of these Consolidated Financial Statements. See Note 19 for a discussion of subsequent events.

Presentation – As discussed further in Note 15, during the second quarter of fiscal year 2013, the Company reclassified its Energy division as a discontinued operation, the sale of which was completed October 1, 2012. Also discussed further in Note 15, the Company completed the sale of its SolmeteX operations on July 31, 2013 after classifying it as held for sale, and determining it qualified for a discontinued operation in the first quarter of fiscal year 2014. The Company has reclassified the operations of the Energy division and SolmeteX as discontinued operations for the three years in the period ended January 31, 2013. Amounts presented on the prior year comparable balance sheet have not been reclassified for both the Energy division and SolmeteX.

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.

Foreign Currency Transactions and Translation – The cash flows and financing activities of the Company’s Mexican and African operations are primarily denominated in the U.S. dollar. Accordingly, these operations use the U.S. dollar as their functional currency and measure monetary assets and liabilities at year-end exchange rates while nonmonetary items are measured at historical rates. Income and expense accounts are measured at exchange rates which approximate the exchange rate at the dates on which those elements are recognized, except for depreciation and certain cost of revenues and selling expenses which are translated at historical rates. Gains or losses from changes in exchange rates are recognized in consolidated results of operations in the year of occurrence.

Other foreign subsidiaries and affiliates use local currencies as their functional currency. Assets and liabilities have been measured to U.S. dollars at year-end exchange rates. Income and expense items have been translated at the weighted average of the rates prevailing during each year which approximates the exchange rate at the dates on which those elements are recognized. Translation adjustments are reported as a separate component of accumulated other comprehensive income (loss).

Net foreign currency transaction losses for 2013, 2012 and 2011 were $1.4 million, $0.3 million and $0.5 million, respectively, and are recorded in other income (expense), net in the accompanying consolidated results of operations.

Revenue Recognition – Revenues are recognized on large, long-term construction contracts meeting the criteria of Accounting Standards Codification (“ASC”) Topic 605-35 “Construction-Type and Production-Type Contracts” (“ASC Topic 605-35”), 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. The nature of accounting for contracts is such that refinements of the estimating process for changing conditions and new developments are continuous and characteristic of the process. Many factors can and do change during a contract performance period which can

7

result in a change to contract profitability from one financial reporting period to another. Some of the factors that can change the estimate of total contract revenue and cost include differing site conditions (to the extent that contract remedies are unavailable), the availability of skilled contract labor, the performance of major material suppliers, the performance of major subcontractors, unusual weather conditions and unexpected changes in material costs. These factors may result in revision to costs and income and are recognized in the period in which the revisions are determined. Provisions for estimated losses on uncompleted construction contracts are made in the period in which such losses are determined. Because the Company has many contracts in process at any given time, these changes in estimates can offset each other minimizing the impact on overall profitability. However, large changes in cost estimates on larger, more complex construction projects can have a material impact on the Company’s financial statements and are reflected in results of operations when they become known.

As allowed by ASC Topic 605-35, 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.

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.

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 discontinued Energy division were 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.

Inventories – The Company values inventories at the lower of cost, determined using first-in, first-out (“FIFO”) basis, or market. Adjustments of value are recorded for inventory considered to be excess or obsolete. Inventories consist primarily of finished goods, parts and supplies. Raw materials of $1.8 million and $2.5 million were included in inventories in the consolidated balance sheet at January 31, 2013 and 2012, respectively.

Property and Equipment and Related Depreciation – Property and equipment (including major renewals and improvements) are recorded at cost. Depreciation is provided using the straight-line method. Depreciation expense was $59.5 million, $55.0 million and $45.5 in 2013, 2012 and 2011, respectively. The lives used for the items within each property classification are as follows:

Classification	Years
Buildings	15 - 35
Machinery and equipment	3 - 10

Oil and Gas Properties and Mineral Interests – The Company sold the assets of the Energy division October 1, 2012. Prior to the sale, the Company followed 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. Capitalized costs are depleted based on units of production. Depletion expense was $2.9 million, $4.0 million and $5.7 million in 2013, 2012 and 2011, respectively.

The Company was required to review the carrying value of its oil and gas properties under the full cost accounting rules of the SEC (the “Ceiling Test”). The ceiling limitation is the estimated after-tax future net revenues from proved oil and gas properties discounted at 10%, plus the cost of properties not subject to amortization. If the net book value of oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense. 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 to the end of the reporting period, unless prices are defined by contractual arrangements such as fixed-price physical delivery forward sales contracts. 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.

8

Reserve Estimates – Prior to the sale of the assets of the Energy division, the Company’s estimates of oil and gas reserves, by necessity, were 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 oil and 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 oil and 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 oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material.

Goodwill – The Company’s impairment evaluation for goodwill is conducted annually as of December 31, or more frequently if events or changes in circumstances indicate that goodwill might be impaired. The evaluation is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference. Based on the results of the fiscal year 2013 evaluation, no goodwill impairment was identified. See Note 5 for a discussion of the impairments recorded in fiscal year 2012.

We consider both a market approach and an income approach in estimating the fair value of each reporting unit in our analysis. The market approach may include use of the guideline transaction method, the guideline company method, or both. The guideline transaction method makes use of available transaction price data of companies engaged in the same or similar lines of business as the respective reporting unit. The guideline company method uses market multiples of publically traded companies with operating characteristics similar to the respective reporting unit. The income approach uses projections of each reporting unit’s estimated cash flows discounted using a weighted average cost of capital that reflects current market conditions. We also compare the aggregate fair value of our reporting units to our market capitalization plus a control premium.

The more significant assumptions used in the income approach, which are subject to change as a result of changing economic and competitive conditions, are as follows:

• Anticipated future cash flows and long-term growth rates for each reporting unit. The income approach to determining fair value relies on the timing and estimates of future cash flows, including an estimate of long-term growth rates. The projections use management’s estimates of economic and market conditions over the projected period including growth rates in sales and estimates of expected changes in operating margins. The Company’s projections of future cash flows are subject to change as actual results are achieved that differ from those anticipated. Actual results could vary significantly from estimates.

• Selection of an appropriate discount rate. The income approach requires the selection of an appropriate discount rate, which is based on a weighted average cost of capital analysis. The discount rate is subject to changes in short-term interest rates and long-term yield as well as variances in the typical capital structure of marketplace participants in our industry. The discount rate is determined based on assumptions that would be used by marketplace participants, and for that reason, the capital structure of selected marketplace participants was used in the weighted average cost of capital analysis. Given the current volatile economic conditions, it is possible that the discount rate could change.

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 35 years.

9

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. See Note 5 for a discussion of the impairments recorded in fiscal year 2013 and 2012. 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.

Based on declines in operating performance during FY2013 and FY2012 in our Heavy Civil division, and in the fourth quarter of FY2013 in our Mineral Exploration division, we reviewed the recoverability of the asset values of our equipment during each of the periods. No impairments were indicated by such analyses.

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

Restricted Deposits – Restricted deposits consist of escrow funds associated primarily with acquisitions.

Allowance for Uncollectible Accounts Receivable – The Company makes ongoing estimates relating to the collectability 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.

The Company does not establish an allowance for credit losses on long-term contract unbilled receivables. Adjustments to unbilled receivables related to credit quality, if they occur, are accounted for as a reduction of revenue.

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 health and welfare benefits, workers’ compensation, property and casualty insurance programs resulting from claims which have been incurred 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.

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 January 31, 2013 and 2012, because of the relatively short maturity of those instruments. See Note 7 for disclosure regarding the fair value of indebtedness of the Company and Note 13 for other fair value disclosures.

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. 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.

Derivatives – The Company has foreign operations that have significant costs denominated in foreign currencies, and thus is exposed to risks associated with changes in foreign currency exchange rates. The Company periodically enters into hedge contracts related to certain forecasted foreign currency costs. These contracts are recorded at fair value and are accounted for as cash flow hedges such that changes in fair value for the effective portion of hedge contracts are recorded in accumulated other comprehensive income (loss) 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. The Company does not enter into derivative financial instruments for speculative or trading purposes.

10

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

	Years Ended January 31,
(in thousands)	2013		2012		2011
Income taxes	$	20,234	$	18,616	$	20,165
Interest		3,972		1,795		1,676
Noncash investing and financing activities:
Accrued capital additions		1,896		3,537		1,479
Deferred debt issuance costs		—		1,716		—
Capital lease obligations		—		300		—

Additionally, during fiscal year 2012, the Company entered into financing obligations for software licenses amounting to $1.3 million, payable over three years. The associated assets are recorded as other intangible assets, net in the balance sheet.

Income Taxes – Income taxes are provided using the asset/liability method, in which deferred taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and tax bases of existing assets and liabilities. The company reviews deferred tax assets for recoverability on a jurisdictional basis. In assessing the need for a valuation allowance, the company considers both positive and negative evidence related to the likelihood of realization of the deferred tax assets. The weight given to the positive and negative evidence is commensurate with the extent to which the evidence may be objectively verified. Accounting guidance states that a cumulative loss in recent years is a significant piece of negative evidence that is difficult to overcome in determining that a valuation allowance is not needed against deferred tax assets. As such, it is generally difficult for positive evidence regarding projected future taxable income exclusive of reversing taxable temporary differences to outweigh objective negative evidence of recent financial reporting losses. In preparing future taxable income projections, the company considers the periods in which future reversals of existing taxable and deductible temporary differences are likely to occur, future taxable income, taxable income available in prior carry back years, and the availability of tax-planning strategies when determining the realizability of recorded deferred tax assets. Provision for U.S. income taxes on undistributed earnings of foreign subsidiaries and affiliates is made only on those amounts in excess of those funds considered to be invested indefinitely (see Note 9).

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, to determine the amount of tax benefits to recognize in the financial statements. For each uncertain 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.

Income Per Share – Income per common share are based upon the weighted average number of common and dilutive equivalent shares outstanding. Options to purchase common stock are included based on the treasury stock method for dilutive earnings per share except when their effect is antidilutive. Options to purchase 1,285,303, 1,133,211 and 421,270 shares have been excluded from weighted average shares in 2013, 2012 and 2011, respectively, as their effect was antidilutive. A total of 275,666, 226,919 and 49,076 non-vested shares have been excluded from weighted average shares in 2013, 2012 and 2011, respectively, as their effect was antidilutive.

Share-Based Compensation – The Company recognizes the cost of all share-based instruments in the financial statements using a fair-value measurement of compensation expense related to all share-based instruments over the term expected to be benefited by the instrument. As of January 31, 2013, the Company had unrecognized compensation expense of $4.3 million to be recognized over a weighted average period of 2.1 years. The Company determines the fair value of share-based compensation granted in the form of stock options using the lattice valuation model or the Black-Scholes valuation model.

11

Unearned compensation expense associated with the issuance of non-vested shares is amortized on a straight-line basis as the restrictions on the stock expire, subject to achievement of certain contingencies.

Research and Development Costs – Research and development costs charged to expense during 2013, 2012 and 2011 were $0.3 million, $1.6 million and $0.3 million, respectively, and are recorded in selling, general and administrative expenses in the accompanying consolidated results of operations.

(2) Acquisitions

Fiscal Year 2013

On October 4, 2012, the Company acquired 100% of the stock of Fursol Informatica S.r.l., (“Fursol”) an Italian company. Fursol is active in the business of production, marketing, installation and maintenance of software and electronic devices. The Company believes it will benefit from Fursol’s technology to improve the performance and efficiency of its Geoconstruction operations. The aggregate purchase price was $1.0 million, of which $0.8 million was paid at the acquisition date, with the remainder of $0.2 million to be paid on October 4, 2013. The purchase price was allocated to an identifiable intangible asset associated with computer software valued at $1.5 million (with a weighted-average life of three years) and to a noncurrent liability of $0.5 million.

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

On May 30, 2012, the Company acquired the remaining 50% interest of Diberil Sociedad Anónima (“Diberil”), a Uruguayan company and parent company to Costa Fortuna (Brazil and Uruguay). We expect Diberil to expand our geoconstruction capabilities into the Brazil market as well as serve as a platform for further expansion into South America. The aggregate purchase price for the remaining 50% of Diberil of $16.2 million was comprised of cash ($2.4 million of which was placed in escrow to secure certain representations, warranties and indemnifications). The Company acquired the initial 50% interest in Diberil on July 15, 2010. In accordance with accounting guidance in moving Diberil to a fully consolidated basis, the Company remeasured the previously held equity investment to fair value and recognized a loss of $7.7 million during the second quarter. The fair value of the 50% noncontrolling interest was estimated to be $15.8 million at the time of the adjustment. The fair value assessment was determined based on the value of our current year transaction, discounted to reflect that the initial interest was noncontrolling, and that there was no ready public market for our interest. The discounts for lack of control and marketability were 5% and 10%, respectively, determined based on control premiums seen on recent transactions in the construction contractor and engineering services market and an estimate of the value of a put option on restricted stock using the Black-Scholes valuation method.

Acquisition related costs of $0.2 million were recorded as an expense in the periods in which the costs were incurred. The purchase price allocation was based on an assessment of the fair value of the assets required and liabilities assumed using the Company’s internal operational assessments and other analyses which are Level 3 measurements. The preliminary purchase allocation recorded in the second quarter was adjusted as the valuation analysis progressed. As a result of the adjustment, goodwill was decreased $0.5 million from the initial amount. The adjustments made were retrospectively applied to the acquisition date, and did not have a significant effect on the financial statements.

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

(in thousands)	Diberil
Working capital	$	3,592
Property and equipment		33,500
Goodwill		4,025
Other intangible assets		1,000
Other assets		9,131
Other noncurrent liabilities		(16,981	)
Total purchase price	$	34,267

12

The $4.0 million of goodwill was assigned to the Geoconstruction division. The purchase price in excess of the value of Diberil’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 Diberil purchase agreement provided for a purchase price adjustment based on the levels of working capital and debt at closing. The adjustment resulted in an additional purchase price of $2.3 million, which was paid during the third quarter of fiscal year 2013.

The total purchase price above consists of the $16.2 million cash purchase price, the $2.3 million purchase price adjustment, and the $15.8 million adjusted basis of our existing investment in Diberil.

The results of operations of Diberil have been included in the Company’s consolidated statements of operations commencing on the closing date. Including its consolidated and equity basis results, Diberil contributed $8.1 million income before income taxes for fiscal year 2013, compared to $3.3 million in fiscal year 2012.

Assuming the remaining 50% of Diberil had been acquired at the beginning of each period, the unaudited pro forma consolidated revenues, net loss, and net loss per share of the Company would be as follows:

	Year Ended January 31,
(in thousands, except per share data)	2013			2012
Revenues	$	1,099,330			1,152,068
Net loss attributable to Layne Christensen Company		(33,155	)		(52,726	)
Basic loss per share attributable to Layne Christensen Company	$	(1.70	)	$	(2.71	)
Diluted loss per share attributable to Layne Christensen Company	$	(1.70	)	$	(2.71	)

On March 5, 2012, the Company acquired the remaining shares in Layne do Brazil, which were previously held by noncontrolling interests. The shares were acquired for cash payments totaling $2.7 million. In conjunction with the acquisition, the Company eliminated noncontrolling interests of $0.1 million and recorded an adjustment to equity of $2.7 million in accordance with accounting guidance.

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 division westward. The aggregate purchase price for Wildcat of $8.9 million was comprised of cash ($0.4 million 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 acquired and liabilities assumed, 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 $2.3 million of goodwill was assigned to the Inliner 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 believed it would benefit from synergies as these acquired operations were 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. Wildcat contributed revenues and loss before income taxes to the Company for the period from February 28, 2011 to January 31, 2012, of $14.2 million and $0.9 million. Pro forma amounts related to Wildcat for prior periods have not been presented because the acquisition would not have had a significant effect on the Company’s consolidated revenues or net income.

13

Fiscal Year 2011

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

• 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 specialized marine geotechnical services in South America and will expand our geoconstruction capabilities into these geographic markets. The Company accounted for Diberil as an equity method investment (see Note 3) until the Company acquired the remaining 50% on May 30, 2012 (see Note 2).

• 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 the Company’s 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 complemented and expanded the Company’s geoconstruction capabilities.

The aggregate purchase price for Intevras and Bencor of $38.7 million was comprised of cash ($3.6 million 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 $10.0 million (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 $10.0 million. The fair value of the contingent consideration arrangement of $1.1 million 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 $1.5 million to $6.1 million. On July 31, 2012, the Intevras Earnout Amount was reassessed and, based on our estimates of the likelihood of future revenues subject to the earnout provisions, assigned no value.

Acquisition related costs of $0.4 million for Bencor and $0.1 million 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.

14

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 interest in subsidiary of Bencor		—		(851	)		(851	)
Total purchase price	$	6,600	$	32,073		$	38,673

The intangible assets of Intevras consist of patents valued at $3.8 million with a weighted average useful life of nine years and a trade name valued at $0.2 million with a useful life of ten years. The intangible assets of Bencor consist of customer backlog valued at $3.2 million with a weighted average useful life of 18 months, a trade name valued at $1.1 million with a useful life of ten years and non-compete agreements valued at $0.7 million with a useful life of six years. The $10.4 million of aggregate goodwill was assigned to the Geoconstruction 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 believed it would benefit from synergies as these acquired businesses were 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.

In fiscal year 2012, the Company changed the structure of its reporting segments and reallocated goodwill to the new reporting units based on the relative fair value of each reporting unit as of December 31, 2011. See Note 6 for further discussion of the change in reporting segments and the reallocation of goodwill.

The results of operations of the acquired entities have been included in the Company’s consolidated results of operations commencing on the closing date. Bencor contributed revenues and income before income taxes to the Company for the period from October 22, 2010, through January 31, 2011, of $20.8 million and $8.2 million, respectively.

Fiscal year 2011 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 because 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 the period, the unaudited pro forma consolidated revenues, net income and net income per share of the Company would be as follows:

(in thousands, except per share data)	Year Ended January 31, 2011
Revenues	$	1,029,247
Net income attributable to Layne Christensen Company		33,842
Basic income per share attributable to Layne Christensen Company	$	1.75
Diluted income per share attributable to Layne Christensen Company	$	1.73

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

In addition to the above acquisitions, the Company paid $0.4 million as contingent earnout consideration on prior year acquisitions. 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 $1.0 million (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 total contingent earnout consideration earned by SolmeteX was $0.7 million, $0.4 million of which was paid in fiscal year 2011 and the remainder paid in previous years. As discussed in Note 15, the Company sold SolmeteX on July 31, 2013.

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(3) Investments 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 $14.9 million, of which $10.1 million was paid to Diberil shareholders and $4.8 million 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 $4.8 million. Subsequent to the acquisition, the Company invested an additional $1.3 million in Diberil as its proportionate share of a capital contribution. See Note 2 for a further discussion of our acquisition of the remaining 50% interest in Diberil during May 2012.

The Company’s investments in affiliates are carried at the fair value of the investment consideration at the date acquired, plus the Company’s equity in undistributed earnings from that date. These affiliates generally are engaged in mineral exploration drilling and the manufacture and supply of drilling equipment, parts and supplies. A summary of directly owned affiliates, as well as their primary operating subsidiaries if applicable, and the percentages directly or indirectly owned by the Company are as follows as of January 31, 2013:

	Percentage Owned Directly			Percentage Owned Indirectly
Boyles Bros Servicios Tecnicos Geologicos S.A. (Panama)		50.00	%
Boytec, S.A. (Panama)					50.00	%
Boytec Sondajes de Mexico, S.A. de C.V. (Mexico)					50.00
Sondajes Colombia, S.A. (Colombia)					50.00
Mining Drilling Fluids (Panama)					25.00
Plantel Industrial S.A. (Chile)					50.00
Christensen Chile, S.A. (Chile)		50.00
Christensen Commercial, S.A. (Chile)		50.00
Geotec Boyles Bros., S.A. (Chile)		50.00
Centro Internacional de Formacion S.A. (Chile)					50.00
Geoestrella S.A. (Chile)					25.00
Diamantina Christensen Trading (Panama)		42.69
Christensen Commercial, S.A. (Peru)		35.38
Geotec, S.A. (Peru)		35.38
Boyles Bros., Diamantina, S.A. (Peru)		29.49

Financial information of the affiliates is reported with a one-month lag in the reporting period. Summarized financial information of the affiliates, including Diberil and its subsidiaries up to the date of acquisition of the remaining 50% equity interest, was as follows:

	As of and Years Ended January 31,
(in thousands)	2013		2012		2011
Balance sheet data:
Current assets	$	168,770	$	212,066	$	148,069
Noncurrent assets		74,572		109,868		84,622
Current liabilities		57,998		131,622		86,051
Noncurrent liabilities		21,203		16,529		14,951
Income statement data:
Revenues		444,871		449,599		329,932
Gross profit		98,418		118,658		67,545
Operating income		57,934		76,520		39,191
Net income		43,990		54,856		29,768

The Company had no significant transactions or balances with its affiliates as of January 31, 2013, 2012 and 2011, and for the years then ended.

The Company’s equity in undistributed earnings of the affiliates totaled $73.7 million, $57.6 million and $38.4 million as of January 31, 2013, 2012 and 2011, respectively.

16

(4) Costs and Estimated Earnings on Uncompleted Contracts

Costs and estimated earnings on uncompleted contracts consisted of the following:

	As of January 31,
(in thousands)	2013			2012
Cost incurred on uncompleted contracts	$	1,410,722		$	1,286,453
Estimated earnings		351,126			291,258
		1,761,848			1,577,711
Less: Billing to date		1,689,082			1,502,330
Total	$	72,766		$	75,381
Included in accompanying balance sheets under the following captions:
Costs and estimated earnings in excess of billing on uncompleted contracts	$	101,960		$	107,295
Other Assets (non-current retainage)		5,675			—
Billings in excess of costs and estimated earnings on uncompleted contracts		(34,869	)		(31,914	)
Total	$	72,766		$	75,381

The Company bills its customers based on specific contract terms. Substantially all billed amounts are collectible within one year. As of January 31, 2013 and 2012, the Company held unbilled contract retainage amounts of $50.5 million and $25.1 million, respectively.

(5) Impairment Charges

During fiscal year 2013, due to the underperformance of certain product lines within the Water Resources division, and our Energy Services business, we assessed the value of certain of our long-lived assets within those businesses. We also assessed the value of certain of our trademarks in light of strategic decisions for those product lines. As a result of our assessments, we concluded that certain impairments of value had occurred, and we recorded impairment charges. The impaired assets included certain patents and trademarks and certain property and equipment. The carrying value of the assets before impairment was $15.8 million and the impairments totaled $8.4 million, of which $4.4 million was associated with the Water Resources division and $4.0 million was associated with the Energy Services business. The charges consisted of $2.9 million associated with intangible assets, with the remainder consisting of adjustments to record tangible assets at an expected sales value. None of these operations had any associated goodwill recorded. Of the total assessed fair value of $7.4 million, the amount determined based on Level 1 inputs was $3.6 million, with the remainder based on Level 3 inputs. (See Note 13 for additional discussion of how Level 1, 2 and 3 inputs are defined.)

During fiscal year 2012, in connection with the annual goodwill impairment test and as a result of the on-going weakness in municipal spending due to the poor economic environment, changes in corporate strategy and the revision of its reporting units and segments and declining natural gas prices, the Company reassessed its estimates of the fair value of its reporting units. These circumstances indicated a potential impairment of our goodwill and, as such, we assessed the fair value of our goodwill to determine if the book value exceeded its fair value. As a result of this assessment, we determined that the carrying value of goodwill of $105.7 million exceeded its fair value and we recorded an impairment charge of $86.2 million. Of this charge, $17.1 million related to the Water Resources division, $23.1 million to the Inliner division, $44.6 million to the Heavy Civil division, $1.0 million to the discontinued Energy division and $0.4 million to our other businesses. The total assessed fair value of $19.5 million was determined based on Level 3 inputs. The write-offs were a result of projected continued weakness in demand for construction projects that was greater and more persistent than originally anticipated, continuing projected weakness in the economy adversely affecting spending by government agencies and the resulting pressures on margins from increased competition from smaller competitors. The goodwill charge in the Water Resources division was also impacted by a shift in the corporate strategy in the fourth quarter to focus more on traditional water treatment services, resulting in the write-off of goodwill associated with acquired companies that had a heavy research and development focus.

Also during fiscal year 2012, due to a change in corporate strategy to emphasize the Layne name for all the Company’s services worldwide, we decided to cease using certain trade names. The Company recorded an impairment charge of $9.4 million related to those trade names, $9.1 million of which was associated with the Heavy Civil division. Additionally, due to significant underperformance of certain water treatment businesses, we assessed the value of certain of our definite-lived intangible assets and recorded an impairment charge of $2.0 million in the Energy Services division. The carrying value of the trademarks and other intangibles before impairment was $12.6 million. The total assessed fair value of $1.2 million was determined based on Level 3 inputs.

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(6) Goodwill and Other Intangible Assets

Goodwill

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

(in thousands)	Water Resources			Inliner			Heavy Civil			Geo- construction		Mineral Exploration			Energy			Energy Services			Other		Total
Balance February 1, 2011	$	17,084		$	29,727		$	44,551		$	10,621	$	—		$	950		$	445		$		$	103,378
Additions		—			2,318			—			—		—			—			—			—		2,318
Impairment of goodwill		(17,084	)		(23,130	)		(44,551	)		—		—			(950	)		(445	)				(86,160	)
Balance January 31, 2012		—			8,915			—			10,621		—			—			—			—		19,536
Additions		—			—			—			4,025		—			—			—			—		4,025
Balance January 31, 2013	$	—		$	8,915		$	—		$	14,646	$	—		$	—		$	—		$	—	$	23,561
Accumulated goodwill impairment losses	$	(17,084	)	$	(23,130	)	$	(44,551	)	$	—	$	(20,225	)	$	(950	)	$	(445	)	$		$	(106,385	)

Goodwill expected to be tax deductible was $1.5 million as of January 31, 2013 and 2012.

Other Intangible Assets

Other intangible assets consisted of the following as of January 31:

	2013							2012
(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	$	8,008	$	(3,798	)		14	$	10,950	$	(4,855	)		14
Customer/contract-related		3,340		(3,215	)		1		2,340		(1,526	)		2
Patents		3,012		(1,634	)		15		4,616		(1,372	)		12
Software and licenses		2,747		(919	)		3		1,289		(286	)		3
Non-competition agreements		680		(255	)		6		705		(165	)		6
Other		1,600		(726	)		21		1,160		(590	)		24
Total intangible assets	$	19,387	$	(10,547	)			$	21,060	$	(8,794	)

Total amortization expense for other intangible assets was $3.4 million, $4.0 million and $2.2 million in the fiscal years 2013, 2012 and 2011, respectively. Amortization expense for the subsequent five fiscal years is estimated as follows:

(in thousands)	Amount
2014	$	1,969
2015		1,598
2016		1,338
2017		932
2018		842

(7) Indebtedness

The Company maintains an unsecured $300.0 million revolving credit facility (the “Credit Agreement”) which extends to March 25, 2016, as well as a private shelf agreement (the “Shelf Agreement”) whereby it can issue $150.0 million in unsecured notes. The Shelf Agreement extends to July 8, 2021. No unsecured notes have been issued under the Shelf Agreement as of January 31, 2013. The Company issued $20.0 million of notes under a previous shelf agreement in October 2004, on which the final payment of $6.7 million was made on September 29, 2011.

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During fiscal year 2012, the Company funded $1.7 million of debt issuance costs through borrowings under its Credit Agreement. These costs will be amortized over the life of the agreement.

The 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 Credit Agreement, plus up to 1.25%, each depending on the Company’s leverage ratio. On January 31, 2013, there were letters of credit of $22.3 million and borrowings of $95.0 million outstanding under the Credit Agreement resulting in available capacity of $182.7 million. The weighted average interest rate on the borrowings outstanding as of January 31, 2013 was 2.3%.

The Company’s Shelf Agreement and Credit Agreement each contain certain covenants including restrictions on the incurrence of additional indebtedness and liens, investments, acquisitions, transfer or sale of assets, transactions with affiliates and payment of dividends. These provisions generally allow such activity to occur, subject to specific limitations and continued compliance with financial maintenance covenants. Significant financial maintenance covenants are a fixed charge coverage ratio and a maximum leverage ratio. Covenant levels and definitions are generally consistent between the two agreements. The Company was in compliance with its covenants as of January 31, 2013.

The financial covenants are based on defined terms included in the agreements, such as adjusted EBITDA and adjusted EBITDAR. 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 discontinued operations, 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. 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, asset retirement obligations and escrow liabilities.

As of January 31, 2013 and 2012, the Company’s actual and required covenant levels under the existing agreements were as follows:

	Actual 2013		Required 2013		Actual 2012		Required 2012
Minimum fixed charge coverage ratio		2.57		1.50		2.98		1.50
Maximum leverage ratio		1.99		3.00		0.78		3.00

Maximum borrowings outstanding under the Company’s credit agreements during the fiscal years 2013 and 2012 were $124.5 million and $71.7 million, respectively, and the average outstanding borrowings were $97.3 million and $49.4 million, respectively. The weighted average interest rates, including amortization of loan costs, were 3.0% and 3.3%, respectively.

Loan costs incurred for securing long-term financing are amortized using a method that approximates the effective interest method over the term of the respective loan agreement. Amortization of these costs for the fiscal years 2013, 2012 and 2011 were $0.4 million, $0.4 million and $0.2 million, respectively. Amortization of loan costs is included in interest expense in the consolidated results of operations.

As of January 31, 2013 and 2012, the Company had outstanding notes payable of $11.7 million and $7.4 million, respectively. These notes were issued under short-term unsecured borrowing arrangements at wholly owned foreign subsidiaries. The notes bear interest at an average rate of 5.6% and have stated maturities of less than one year, but are repayable on demand at the option of either the Company or the lender. Average outstanding borrowings for 2013 and 2012 were $7.7 million and $6.8 million, respectively.

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Debt outstanding as of January 31, 2013 and 2012, whose carrying value approximates fair market value, was as follows:

(in thousands)	January 31, 2013			January 31, 2012
Credit agreement	$	95,000		$	52,500
Capitalized lease obligations		3,645			315
Less amounts representing interest		(993	)		(15	)
Notes payable		11,676			7,366
Total debt		109,328			60,166
Less current maturities of long-term debt		(12,789	)		(7,450	)
Total long-term debt	$	96,539		$	52,716

As of January 31, 2013, debt outstanding will mature by fiscal year as follows:

(in thousands)	Notes Payable		Credit Agreement		Capitalized Lease Obligations		Total
2014	$	11,586	$	—	$	1,203	$	12,789
2015		71		—		913		984
2016		19		—		536		555
2017		—		95,000		—		95,000
2018		—		—		—		—

(8) Other Income

Other income consisted of the following:

	Years Ended January 31,
(in thousands)	2013			2012			2011
Gain from disposal of property and equipment		3,364		$	8,247		$	896
Gain on sale of investment securities		—			996			—
Interest income		143			196			201
Currency exchange loss		(1,379	)		(310	)		(458	)
Other		3,716			556			(115	)
Total	$	5,844		$	9,685		$	524

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 could be purchased, the Company entered into a leasehold agreement of the existing facility. The total gain on the sale of the facility was $6.4 million, of which $1.4 million was deferred to match the expected lease payments under the leasehold agreement. The Company recognized $0.4 million of the deferred gain during the fiscal year ended January 31, 2012. The deferred gain was being recognized over the 36 month term of the lease. In September 2012, the Company terminated the leasehold agreement and recognized the remaining $0.7 million deferred gain on the sale of the facility.

During fiscal year 2012, the Company recognized a gain of $1.0 million on the sale of certain investment securities in Australia. The securities were received in settlement of previously written off accounts receivable.

(9) Income Taxes

(Loss) income from continuing operations before income taxes consisted of the following:

	Years Ended January 31,
(in thousands)	2013			2012			2011
Domestic	$	(60,745	)	$	(98,480	)	$	9,309
Foreign		39,370			52,441			39,200
Total	$	(21,375	)	$	(46,039	)	$	48,509

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Components of income tax (benefit) expense from continuing operations were as follows:

	Years Ended January 31,
(in thousands)	2013			2012			2011
Currently due:
U.S. federal	$	(1,049	)	$	5,624		$	7,070
State and local		(278	)		1,729			2,452
Foreign		13,847			20,349			13,279
		12,520			27,702			22,801
Deferred:
U.S. federal		(19,582	)		(16,556	)		(1,858	)
State and local		(1,430	)		(3,773	)		(748	)
Foreign		(623	)		1,261			434
		(21,635	)		(19,068	)		(2,172	)
Total	$	(9,115	)	$	8,634		$	20,629

The Company’s provision for income taxes has been allocated between continuing operations and discontinued operations. The net (loss) income from discontinued operations for fiscal years 2013, 2012 and 2011 was ($23.8 million), $1.5 million and $3.7 million, respectively. These amounts are net of income tax benefits (expense) of $15.3 million, ($0.6 million) and ($2.0 million), respectively. The effective tax rate for discontinued operations was 39.2%, 28.4% and 34.5% for fiscal years 2013, 2012 and 2011, respectively.

Deferred income taxes result from temporary differences between the financial statement and tax bases of the Company’s assets and liabilities. The sources of these differences and their cumulative tax effects were as follows as of January 31:

	2013									2012
(in thousands)	Assets			Liabilities			Total			Assets			Liabilities			Total
Contract income	$	2,563		$	—		$	2,563		$	2,002		$	—		$	2,002
Inventories		1,316			(392	)		924			1,132			(338	)		794
Accrued insurance		4,212			—			4,212			3,502			—			3,502
Other accrued liabilities		5,849			—			5,849			4,967			—			4,967
Prepaid expenses		—			(1,116	)		(1,116	)		—			(950	)		(950	)
Bad debts		2,814			—			2,814			3,137			—			3,137
Employee compensation		9,575			—			9,575			8,149			—			8,149
Tax loss carry forward		2,735						2,735			—			—			—
Other		527			(48	)		479			465			(171	)		294
Total current		29,591			(1,556	)		28,035			23,354			(1,459	)		21,895
Valuation allowance		(2,835	)		—			(2,835	)		—			—			—
Cumulative translation adjustment		4,528			—			4,528			4,049			—			4,049
Buildings, machinery and equipment		798			(18,059	)		(17,261	)		307			(21,939	)		(21,632	)
Gas transportation facilities and equipment		—			—			—			—			(7,992	)		(7,992	)
Mineral interests and oil and gas properties		—			—			—			—			(1,428	)		(1,428	)
Intangible assets		2,410			(1,955	)		455			1,448			(2,067	)		(619	)
Tax deductible goodwill		4,916			—			4,916			6,163			—			6,163
Accrued insurance		5,026			—			5,026			5,148			—			5,148
Retirement benefits		2,201			—			2,201			1,776			—			1,776
Share-based compensation		5,988			—			5,988			5,367			—			5,367
Tax loss carry forward		4,791						4,791			1,584			—			1,584
Foreign tax credit carry forward		20,954			—			20,954			9,500			—			9,500
Unremitted foreign earnings		—			(3,636	)		(3,636	)		—			(3,087	)		(3,087	)
Other		1,534			—			1,534			2,372			—			2,372
Total noncurrent		53,146			(23,650	)		29,496			37,714			(36,513	)		1,201
Valuation allowance		(6,519	)		—			(6,519	)		(11,084	)		—			(11,084	)
Total	$	73,383		$	(25,206	)	$	48,177		$	49,984		$	(37,972	)	$	12,012

In assessing the need for a valuation allowance, the Company considered both positive and negative evidence related to the likelihood of realization of the deferred tax assets. The weight given to the positive and negative evidence was commensurate with the extent to which the evidence could be objectively verified. Management determined that the Company was not in a cumulative loss position as of January 31, 2013, 2012 and 2011, respectively, based on an analysis of income over the current and prior two fiscal years, after adjusting for significant non-recurring charges. The Company considered the periods in which future reversals of existing taxable and deductible temporary differences are likely to occur, future taxable income, taxable income available in prior carry back years, and the availability of tax-planning strategies when determining the realizability of

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recorded deferred tax assets. The Company determined that it is more-likely-than-not the deferred tax asset was realizable at January 31, 2013, 2012 and 2011, respectively, and no valuation allowance was needed at this time, other than for a portion of the foreign tax credit carry forwards, for which the Company has in the past and continues to conclude that such carry forward benefits may not be used before they expire.

The Company has U.S. federal loss carry forwards that will expire if not used prior to January 31, 2033, and Canadian loss carry forwards that will expire if not used between January 31, 2030 and January 31, 2032. The Company also has foreign tax credit carry forwards that will expire if not used between January 31, 2018 and 2023.

As of January 31, 2013, undistributed earnings of foreign subsidiaries and certain foreign affiliates included $80.8 million for which no federal income or foreign withholding taxes have been provided. These earnings, which are considered to be invested indefinitely, become subject to income tax if they were remitted as dividends or if the Company were to sell its stock in the affiliates or subsidiaries. It is not practicable to determine the amount of income or withholding tax that would be payable upon remittance of these earnings.

Deferred income taxes were provided on undistributed earnings of certain foreign subsidiaries and foreign affiliates where the earnings are not considered to be invested indefinitely.

A reconciliation of the total income tax (benefit) expense from continuing operations to the statutory federal rate is as follows for the years ended January 31:

	2013						2012						2011
(in thousands)	Amount			Effective Rate			Amount			Effective Rate			Amount			Effective Rate
Income tax at statutory rate	$	(7,482	)		35.0	%	$	(16,114	)		35.0	%	$	16,977			35.0	%
State income tax, net		(1,156	)		5.4			(1,383	)		3.0			1,057			2.2
Difference in tax expense resulting from:
Nondeductible goodwill impairment		—			—			22,500			(48.9	)		—			—
Nondeductible expenses		960			(4.5	)		1,257			(2.7	)		1,078			2.2
Loss on remeasurement of equity method investment					—						—						—
		2,697			(12.6	)		—			—			—			—
Taxes on foreign affiliates		(4,707	)		22.0			(7,141	)		15.5			(4,106	)		(8.5	)
Taxes on foreign operations		1,965			(9.2	)		10,192			(22.1	)		7,833			16.2
Cash surrender value of life insurance		(567	)		2.7			87			(0.2	)		(260	)		(0.5	)
Qualified production activity deduction		—			—			(662	)		1.4			(980	)		(2.0	)
Other		(825	)		3.8			(102	)		0.2			(970	)		(1.9	)
Total	$	(9,115	)		42.6	%	$	8,634			(18.8	)%	$	20,629			42.5	%

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

(in thousands)	2013			2012			2011
Balance, beginning of year	$	13,322		$	12,016		$	9,312
Additions based on tax positions related to current year		2,501			2,534			1,734
Additions for tax positions of prior years		34			637			1,051
Additions related to acquired subsidiaries		1,387			—			982
Impact of changes in exchange rate		—			130			265
Settlement with tax authorities		(1,087	)		(1,070	)		(46	)
Reductions for tax positions of prior years		—			(214	)		(13	)
Reductions due to the lapse of statutes of limitation		(2,774	)		(711	)		(1,269	)
Balance, end of year	$	13,383		$	13,322		$	12,016

Substantially all of the unrecognized tax benefits recorded at January 31, 2013, 2012 and 2011 would affect the effective rate if recognized. It is reasonably possible that the amount of unrecognized tax benefits will decrease during the next year by approximately $2.0 million due to settlements of audit issues and expiration of statutes of limitation.

The Company classifies interest and penalties related to income taxes as a component of income tax expense. As of January 31, 2013, 2012 and 2011, the Company had $8.8 million, $6.8 million and $5.3 million, respectively, of interest and penalties accrued associated with unrecognized tax benefits. The liability for interest and penalties increased $2.0 million, $1.6 million and $1.6 million during fiscal years 2013, 2012 and 2011, respectively.

The Company files income tax returns in the U.S. federal jurisdiction, various state jurisdictions and certain foreign jurisdictions. During the tax year ended January 31, 2013, the U.S. federal statute of limitations expired for the tax year ended

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January 31, 2009. The statute of limitations remains open for tax years ended January 31, 2010 through 2013. The tax years ended January 31, 2011 and 2012 are currently under examination. The Company has two state examinations currently in progress.

The Company files income tax returns in the foreign jurisdictions where it operates. The returns are subject to examination which may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which will be due upon settlement of those examinations. The tax years subject to examination by foreign tax authorities vary by jurisdiction, but generally the tax years 2008 through 2013 remain open to examination.

(10) Operating Lease and Asset Retirement Obligations

Future minimum lease payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year from January 31, 2013, are as follows:

(in thousands)	Operating Leases
2014	$	6,127
2015		3,878
2016		2,589
2017		2,001
2018		1,611
Minimum lease payments	$	16,206

The Company’s operating leases are primarily for light and medium duty trucks and other equipment. Rent expense under operating leases (including insignificant amounts of contingent rental payments) was $23.7 million, $28.7 million and $28.9 million in 2013, 2012 and 2011, respectively.

Asset retirement obligations consist of the estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. An asset retirement obligation and the related asset retirement cost are recorded when a well is drilled and completed. The asset retirement cost is determined based on the expected costs to complete the reclamation at the end of the well’s economic life, discounted to its present value using a credit adjusted risk-free-rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected in the consolidated results of operations as depreciation, depletion and amortization. Asset retirement costs are capitalized as part of oil and gas properties and depleted accordingly. During fiscal year 2013, the Company sold the assets of its Energy division. These obligations were included as part of the sale.

Asset retirement obligations recorded in other long-term liabilities as of January 31, 2013, 2012 and 2011 were as follows:

(in thousands)	January 31, 2013			January 31, 2012		January 31, 2011
Beginning asset retirement obligation	$	1,835		$	1,667	$	1,498
Liabilities incurred during year		—			63		71
Liabilities settled during year		—			—		—
Accretion expense		75			105		98
Liability transferred upon sale of business		(1,910	)		—		—
Ending asset retirement obligation	$	—		$	1,835	$	1,667

(11) Employee Benefit Plans

The Company’s salaried and certain hourly employees participate in Company sponsored, defined contribution plans. Total expense for the Company’s portion of these plans was $4.0 million, $4.1 million and $4.3 million in the fiscal years 2013, 2012 and 2011, respectively.

The Company has a deferred compensation plan for certain management employees. Participants may elect to defer up to 25% of their salaries and up to 50% of their bonuses to the plan. Company matching contributions, and the vesting period of those contributions, are established at the discretion of the Company. Employee deferrals are vested at all times. The total amount deferred, including Company matching, for the fiscal years 2013, 2012 and 2011 was $1.3 million, $2.0 million and $1.5 million, respectively. The total liability for deferred compensation was $12.4 million and $11.2 million as of January 31, 2013 and 2012, respectively. These liabilities are included in other long-term liabilities.

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The Company contributes to 33 multiemployer defined benefit pension plans under the terms of collective-bargaining agreements that cover its union-represented employees. The risks of participating in these multiemployer plans are different from single-employer plans in the following aspects:

• assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers;

• if a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers; and

• if the Company chooses to stop participating in some of its multiemployer plans, the Company may be required to pay those plans an amount based on the underfunded status of the plan, referred to as a withdrawal liability.

In accordance with accounting guidance, the Company evaluated each of its multiemployer plans to determine if any were individually significant to the Company. The evaluation was based on the following criteria:

• the Company’s total employees participating in the multiemployer plan compared to the total employees covered by the plan;

• the Company’s total contributions to the multiemployer plan as a percentage of the total contributions to the plan by all participating employers; and

• the amount of potential liability that could be incurred due to the Company’s withdrawal from the multiemployer plan, underfunded status of the plan or other participating employers’ withdrawal from the plan.

As of January 31, 2013 and 2012 the Company did not participate in multiemployer plans that would be considered individually significant.

The Company makes contributions to these multiemployer plans equal to the amounts accrued for pension expense. Total contributions and union pension expense for these plans was $3.2 million, $3.1 million and $3.6 million in the fiscal years 2013, 2012 and 2011, respectively. Information regarding assets and accumulated benefits of these plans has not been made available to the Company.

The Company also provides supplemental retirement benefits to its former 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 his 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. The amount recognized in the Company’s consolidated balance sheets at January 31, 2013 and 2012 were $5.6 million and $4.6 million, respectively, and are included in other long-term liabilities. Net periodic pension cost of the supplemental retirement benefits for the fiscal years 2013, 2012 and 2011 was $1.4 million, $1.1 million and $0.5 million, respectively.

(12) Stock and Stock Option Plans

The Company had previously adopted a Rights Agreement whereby the Company authorized and declared a dividend of one preferred share purchase right (“Right”) for each outstanding common share of the Company. The Rights Agreement expired in October 2011 and was not renewed.

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 January 31, 2013, there were 558,714 shares which remain available to be granted under the plan as stock 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. In fiscal years 2012 and 2011, the Company purchased and subsequently cancelled 5,382 and 5,441, respectively, shares of stock related to settlement of withholding obligations. There were no such treasury stock transactions in fiscal year 2013.

The Company recognized $2.9 million, $3.8 million and $3.5 million of compensation cost for share-based plans for fiscal years 2013, 2012 and 2011, respectively. Of these amounts, $0.9 million, $1.7 million and $1.1 million, respectively, related to non-vested stock. The total income tax benefit recognized for share-based compensation arrangements was $1.1 million, $1.5 million and $1.4 million for fiscal years 2013, 2012 and 2011, respectively.

24

Options outstanding as of January 31, 2013, as well as the 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		17
6/04		53,076		53,076		16.65		17
6/05		10,000		10,000		17.54		29
9/05		94,707		94,707		23.05		32
1/06		173,981		173,981		27.87		36
6/06		80,000		80,000		29.29		41
6/07		65,625		65,625		42.26		53
7/07		25,500		25,500		42.76		54
2/08		72,439		72,439		35.71		60
1/09		6,000		6,000		24.01		71
2/09		162,752		162,749		15.78		72
2/09		4,580		4,580		15.78		72
6/09		92,551		92,551		21.99		76
6/09		2,472		2,472		21.99		76
2/10		76,590		51,057		27.79		84
2/10		2,721		2,721		25.44		84
2/11		93,193		31,054		33.10		96
3/11		1,312		437		34.50		98
6/11		2,096		698		28.71		100
7/11		17,893		5,963		29.31		102
2/12		174,649		10,140		24.32		108
4/12		27,135		—		21.77		110
7/12		16,477		—		20.89		113
8/12		9,554		—		20.56		114
		1,285,303		965,750

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 options have contractual terms of 10 years from the date of grant and generally vest ratably over periods of one month to five years. All options outstanding are expected to vest. Certain option awards provide for accelerated vesting if there is a change of control (as defined in the plans) and for equitable adjustments in the event of changes in the Company’s equity structure.

The Company determines the fair value of share-based compensation granted in the form of stock options using the lattice valuation model or the Black-Scholes valuation model. The valuations in each respective year were made using the assumptions noted in the following table. Expected volatilities are based on historical volatility of the Company’s stock price. The Company uses historical data to estimate expected term and employee termination within the valuation model. The risk-free interest rate for the periods within the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The weighted-average fair value at the date of grant for options granted during the fiscal years 2013, 2012 and 2011 was $10.93, $18.70 and $16.08, respectively.

	Years Ended January 31,
Assumptions:	2013			2012			2011
Weighted-average expected volatility		55.1	%		65.0	%		65.0	%
Expected dividend yield		0	%		0	%		0	%
Risk-free interest rate		1.32	%		1.94	%		2.43	%
Expected term (in years)		6.0			5.4			5.4

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Stock option transactions for the fiscal years 2013, 2012 and 2011 were as follows:

	Number of Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)		Intrinsic Value (in thousands)
Outstanding at February 1, 2010		1,026,227		$	24.86
Granted		88,011			27.72
Exercised		(53,380	)		16.78			$	757
Forfeited		(29,384	)		31.01
Outstanding at January 31, 2011		1,031,474			25.34
Granted		123,144			32.49
Exercised		(10,611	)		20.77				122
Forfeited		(10,796	)		29.57
Outstanding at January 31, 2012		1,133,211			26.12
Granted		280,547			23.32
Exercised		(54,637	)		17.44				13
Forfeited		(73,818	)		24.50
Outstanding at January 31, 2013		1,285,303			25.97		5.5		1,784
Exercisable at January 31, 2011		693,587			26.23
Exercisable at January 31, 2012		860,756			26.11
Exercisable at January 31, 2013		965,750			25.95		4.5		1,710

Non-vested share transactions for the fiscal years 2013, 2012 and 2011 were as follows:

	Number of Shares			Average Grant Date Fair Value		Intrinsic Value (in thousands)
Nonvested stock at February 1, 2010		79,336		$	36.23
Granted		58,709			27.42
Vested		(28,436	)		32.91
Forfeited		(1,824	)		40.54
Nonvested stock at January 31, 2011		107,785			32.24
Granted		193,188			30.67
Vested		(34,876	)		35.48
Canceled		(33,251	)		35.71
Forfeited		(5,927	)		30.43
Nonvested stock at January 31, 2012		226,919			29.94
Granted		110,958			22.29
Vested		(15,720	)		26.70
Canceled		(46,491	)		27.79
Nonvested stock at January 31, 2013		275,666			27.41	$	5,905

All nonvested stock awards are valued as of the grant date closing stock price and generally vest ratably over service periods of one to five years. Certain nonvested stock awards vest based upon the Company meeting various performance goals. Certain nonvested stock awards provide for accelerated vesting if there is a change of control (as defined in the plans) and for equitable adjustment in the event of changes in the Company’s equity structure.

(13) Fair Value Measurements

The Company’s estimates of fair value for financial assets and financial liabilities are based on the framework established in the fair value accounting guidance. The framework is based on the inputs used in the valuation, gives the highest priority to quoted prices in active markets and requires that observable inputs be used in the valuations when available. The three levels of the hierarchy are as follows:

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

26

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

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

The Company’s assessment of the significance of a particular input to the fair value in its entirety requires judgment and considers factors specific to the asset or liability. The Company’s financial instruments held at fair value, which include restricted deposits held in acquisition escrow accounts and contingent earnout of acquired businesses, are presented below as of January 31, 2013 and 2012:

			Fair Value Measurements
(in thousands)	Carrying Value		Level 1		Level 2		Level 3
January 31, 2013
Financial Assets:
Restricted deposits held at fair value	$	2,861	$	2,861	$	—	$	—
Financial Liabilities:
Contingent earnout of acquired businesses(1)	$	—	$	—	$	—	$	—
January 31, 2012
Financial Assets:
Restricted deposits held at fair value	$	3,586	$	3,586	$	—	$	—
Financial Liabilities:
Contingent earnout of acquired businesses(1)	$	541	$	—	$	—	$	541

(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 $1.5 million to $6.1 million over the life of the earnout. On July 31, 2012, the contingent earnout was reassessed and, based on our estimates of the likelihood of future revenues subject to the earnout provisions, assigned no value. Our conclusions have not changed as of January 31, 2013.

(14) 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 payments with assistance from outside accounting firms. The internal investigation 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. We have made a voluntary disclosure to the United States Department of Justice (“DOJ”) and the Securities and Exchange Commission (“SEC”) regarding the results of our investigation and we are cooperating with the DOJ and the SEC in connection with their review of the matter.

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In February 2012, we began having discussions with the DOJ and SEC regarding the potential resolution of this matter and have held follow-up discussions with both the DOJ and SEC since that time. The discussions with the government are ongoing and the Company is currently unable to assess whether the government will accept voluntary settlement terms that would be acceptable to the Company. As of January 31, 2012, the Company accrued a $3.7 million liability representing the Company’s initial estimate, based on, among other things, the results of its own internal investigation and an analysis of recent and similar FCPA settlements, of the amount that it may be required to disgorge to the SEC in estimated benefits, plus interest thereon. At the request of the SEC and DOJ, the Company has performed and provided the government additional analysis regarding the estimated benefits that the Company may have received, or intended to receive and interest from the payments in question. Accordingly, no assurance is made or can be given that the government will accept this estimated disgorgement and interest amount. The estimated disgorgement amount recorded at January 31, 2013, remains $3.7 million. Investors are cautioned to not rely upon the presently accrued liability as accurately reflecting the ultimate amount that the Company may be required to pay as disgorgement and interest thereon.

In addition to the ultimate liability for disgorgement and related interest, the Company believes that it could be further liable for fines and penalties as part of any settlement. At this time, the Company is not able to reasonably estimate the amount of any fine or penalty that it may have to pay as a part of any possible settlement. Furthermore, the Company cannot currently assess the potential liability that might be incurred if a settlement is not reached and the government were to litigate the matter. As such, based on the information available at this time any additional liability related to this matter is not reasonably estimable. The Company will continue to evaluate the amount of its liability pending final resolution of the investigation and any related settlement discussions with the government. The amount of the actual liability for any fines, penalties, disgorgement or interest that may be recorded in connection with a final settlement could be significantly higher than the liability accrued to date.

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.

(15) Discontinued Operations

After weighing alternatives, during the second quarter of fiscal year 2013, the Company authorized the sale of the Energy division and entered into negotiations for the sale of substantially all of the Energy division assets to a third party. As of July 31, 2012, the Company considered the Energy division as a discontinued operation and reflected it as such retrospectively in the consolidated financial statements. We recorded a loss of $32.6 million as of July 31, 2012, based on the difference between its carrying value as a continuing operation and the expected selling price, less costs to sell. The tax benefit related to this loss was $12.5 million.

On October 1, 2012, the Company completed the sale of all of the exploration and production assets of its Energy division for $15.0 million. No additional loss on disposal of the net assets was recognized. Pursuant to the sale agreement, the Company received $13.5 million and received an additional $1.5 million in October 2013 when certain conditions were met. The sale agreement provides for additional proceeds of $2.0 million contingent on natural gas futures prices exceeding $5.25 per MMBTU for five months out of any given six consecutive months occurring during the 36 months following closing. The amount will be recorded as additional proceeds if the conditions are met.

The financial results of discontinued operations include an accrual of $3.9 million recorded in the fourth quarter of fiscal 2013 associated with certain litigation claims, related to the Energy division, which were retained by the Company.

On July 31, 2013, the Company completed the sale of its SolmeteX operations to a third party. The Company had previously announced its plans to sell substantially all of the assets of SolmeteX as part of its One Layne strategy during the first quarter of fiscal year 2014 and reclassified it as a discontinued operation. SolmeteX was previously reported as part of the Water Resources division. Pursuant to the sale agreement, the Company received $0.8 million in preferred units of SolmeteX, LLC and received $10.6 million of cash on August 1, 2013. The preferred units have a 4% yield accruing daily, compounded quarterly on the unreturned capital and unpaid preferred yield. During the second quarter of fiscal 2014, the Company valued the units at $0.4 million on the balance sheet as part of Other Assets, and recorded a gain on the sale of the assets of $8.3 million which was included on the income statement as income from discontinued operations.

The financial results of the two discontinued operations were as follows:

	Years Ended January 31,
(in thousands)	2013			2012			2011
Revenues	$	15,018		$	27,128		$	31,901
(Loss) income before income taxes		(39,102	)		2,083			5,659
Income tax benefit (expense)		15,339			(592	)		(1,952	)
Net (loss) income from discontinued operations		(23,763	)		1,491			3,707

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(16) Segments and Foreign Operations

The Company is a global solutions provider to the world of essential natural resources – water, minerals and energy. Management defines the Company’s operational and 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 Resources division.

Effective with the start of fiscal 2014, operating responsibility for certain of our operations has changed which resulted in a change in reportable segments. Our Specialty Drilling group and operations in Ethiopia have been shifted from the Water Resources Division to the Mineral Exploration Division. We believe the shift more closely aligns our international operating expertise in the markets in which those groups operate. We have also shifted certain of our purchasing groups out of the Water Resources Division as they are now focusing on worldwide purchasing for all divisions. These purchasing groups, which also have some third party sales, are now grouped in our Other section. Information for prior periods has been reclassified to conform to our new presentation. We have also separated the Energy Services division from Other and are presenting it as a separate segment due to the expected growth within the Energy Services division.

In addition to the change in reportable segments, in the first quarter of fiscal 2014, the Company has classified the operations of Solmetex as a discontinued operation, as discussed in Note 15.

The Company’s segments are defined as follows:

Water Resources Division

Our Water Resources division provides our customers with every aspect of water supply system development and technology, including hydrologic design and construction, source of supply exploration, well and intake construction and well and pump rehabilitation. The division also brings new technologies to the water and wastewater markets and offers water treatment equipment engineering services, providing systems for the treatment of regulated and “nuisance” contaminants, specifically, iron, manganese, hydrogen sulfide, arsenic, radium, nitrate, perchlorate, and volatile organic compounds. The Water Resources division provides water systems and services in most regions of the U.S.

Inliner Division

Our Inliner division provides a wide range of process, sanitary and storm water rehabilitation solutions to municipalities and industrial customers dealing with aging infrastructure needs. We focus on our proprietary Inliner® cured-in-place pipe (“CIPP”) which allows us to rehabilitate aging sanitary sewer, storm water and process water infrastructure to provide structural rebuilding as well as infiltration and inflow reduction. Our trenchless technology minimizes environmental impact and reduces or eliminates surface and social disruption. We are somewhat unique in that the technology itself, the liner tube manufacturer and the largest installer of the Inliner CIPP technology are all housed within our family of companies. While we focus on our proprietary Inliner CIPP, we are committed to full system renewal. We also provide a wide variety of other rehabilitative methods including Janssen structural renewal for service lateral connections and mainlines, slip lining, traditional excavation and replacement, U-Liner high-density polyethylene fold and form and manhole renewal with cementitious and epoxy products. The Inliner division provides services in most regions of the U.S.

Heavy Civil Division

Our Heavy Civil division delivers sustainable solutions to government agencies and industrial clients by overseeing the design and construction of water and wastewater treatment plants and pipeline installation. In addition, Heavy Civil builds radial collector wells (Ranney Method), surface water intakes, pumping stations, hard rock tunnels and marine construction services – all in support of the world’s water infrastructure. Beyond water solutions, our Heavy Civil division also designs and constructs biogas facilities (anaerobic digesters) for the purpose of generating and capturing methane gas, an emerging renewable energy resource. The Heavy Civil division provides services in most regions of the U.S.

Geoconstruction Division

We provide specialized geotechnical foundation construction services to the heavy civil, industrial, commercial and private construction markets around the globe. We have the expertise and equipment to provide the most appropriate deep foundation system, ground improvement and earth support solution to be applied given highly variable geological and site conditions. In addition, we offer extensive experience in successful completion of complex and schedule-driven major underground construction projects. We provide services that are focused primarily on the foundation systems for dams/levees, tunnel shafts, utility systems, subways or transportation systems, commercial building and port facilities. Services offered include jet grouting, structural diaphragm and slurry cutoff walls, cement and chemical grouting, drilled piles, ground improvement and earth retention systems. The Geoconstruction division provides services in most regions of the U.S., as well as Brazil and Uruguay.

29

Mineral Exploration Division

Our Mineral Exploration division conducts primarily aboveground drilling activities, including all phases of core drilling, reverse circulation, dual tube, hammer and rotary air-blast methods. Our service offerings include both exploratory (‘greenfield’) and definition (‘brownfield’) drilling. Global mining companies hire us to extract samples from their sites that they analyze for mineral content before investing heavily in development to extract the minerals. We help our clients determine if a minable mineral deposit exists on the site, the economic viability of mining the site and the geological properties of the ground, which helps in the determination of mine planning. Our primary markets are in the western U.S., Mexico, Australia, Brazil and Africa. We also have ownership interests in foreign affiliates operating in Latin America that form our primary presence in this market.

Energy Services Division

The Energy Services division focuses on bringing responsible water management solutions to the exploration and productions (E & P) industry’s growing water related challenges. In fiscal year 2014, we began to offer total water management solutions to our E & P clients that encompass water sourcing, transfer, treatment and recycling. The Energy Services division will provide services in most regions of the U.S.

Other

Other includes specialty and purchasing 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, executive management and board of directors. Corporate assets are all assets of the Company not directly associated with a segment, and consist primarily of cash and deferred income taxes.

30

	Years Ended January 31,
(in thousands)	2013			2012			2011
Revenues
Water Resources	$	214,091		$	214,625		$	193,001
Inliner		133,256			132,108			116,566
Heavy Civil		278,131			343,760			353,304
Geoconstruction		133,247			89,210			77,969
Mineral Exploration		302,119			322,100			249,705
Energy Services		5,885			4,214			3,209
Other		11,509			8,992			8,272
Intersegment Eliminations		(9,112	)		(8,991	)		(8,268	)
Total revenues	$	1,069,126		$	1,106,018		$	993,758
Equity in earnings of affiliates
Geoconstruction	$	3,872		$	3,345		$	517
Mineral Exploration		16,700			21,302			12,636
Total equity in earnings of affiliates	$	20,572		$	24,647		$	13,153
Income (loss) from continuing operations before income taxes
Water Resources	$	(1,290	)	$	(18,095	)	$	4,376
Inliner		9,936			(13,236	)		9,426
Heavy Civil		(32,308	)		(61,649	)		9,637
Geoconstruction		517			12,828			11,708
Mineral Exploration		49,406			71,552			45,457
Energy Services		(7,444	)		(4,887	)		(92	)
Other		126			671			(185	)
Unallocated corporate expenses		(36,009	)		(30,866	)		(30,224	)
Interest expense		(4,309	)		(2,357	)		(1,594	)
Total (loss) income from continuing operations before income taxes	$	(21,375	)	$	(46,039	)	$	48,509
Investment in affiliates
Geoconstruction	$	384		$	20,011		$	16,666
Mineral Exploration		77,906			68,286			52,486
Total investment in affiliates	$	78,290		$	88,297		$	69,152

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	As of and Years Ended January 31,
(in thousands)	2013		2012		2011
Revenues by product line
Water systems	$	219,693	$	208,558	$	181,281
Water treatment technologies		47,778		44,670		42,962
Sewer rehabilitation		133,256		132,108		116,757
Water and wastewater plant construction		129,446		200,513		237,360
Pipeline construction		108,408		112,446		85,486
Soil stabilization		167,711		115,402		100,685
Environmental and specialty drilling		7,246		17,902		14,312
Exploration drilling		249,247		271,442		201,479
Energy Services and other		6,341		2,977		13,436
Total revenues by product line	$	1,069,126	$	1,106,018	$	993,758
Capital expenditures
Water Resources	$	22,446	$	23,733	$	17,107
Inliner		4,309		3,218		2,938
Heavy Civil		1,199		5,413		4,302
Geoconstruction		13,391		8,240		3,242
Mineral Exploration		25,661		20,958		30,733
Energy Services		5,169		1,030		515
Other		—		1,499		2,197
Discontinued operations		1,729		4,172		3,298
Corporate		3,599		2,563		2,871
Total capital expenditures	$	77,503	$	70,826	$	67,203
Depreciation and amortization
Water Resources	$	8,126	$	7,740	$	8,182
Inliner		2,647		2,880		2,332
Heavy Civil		7,096		7,389		7,095
Geoconstruction		11,413		8,819		3,619
Mineral Exploration		25,950		21,227		17,059
Energy Services		550		3,418		331
Other		—		1,963		4,382
Corporate		5,376		2,204		1,604
Total depreciation and amortization	$	61,158	$	55,640	$	44,604
Assets
Water Resources	$	119,281	$	147,279	$	127,243
Inliner		67,027		61,601		46,262
Heavy Civil		114,361		123,475		187,333
Geoconstruction		170,064		113,612		118,805
Mineral Exploration		243,383		245,601		204,119
Energy Services		6,470		5,561		7,281
Other		2,193		9,488		9,247
Discontinued operations		3,592		56,728		68,731
Corporate		85,855		42,491		47,631
Total assets	$	812,226	$	805,836	$	816,652

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	As of and Years Ended January 31,
(in thousands)	2013		2012		2011
Geographic Information:
Revenues
United States	$	832,839	$	871,017	$	826,318
Africa/Australia		88,888		110,012		79,546
Mexico		69,970		58,166		43,734
Other foreign		77,429		66,823		44,160
Total revenues	$	1,069,126	$	1,106,018	$	993,758
Property and equipment, net
United States	$	177,198	$	231,838	$	215,966
Africa/Australia		29,875		24,900		24,749
Mexico		10,582		9,559		9,311
Other foreign		48,885		11,060		9,830
Total property and equipment, net	$	266,540	$	277,357	$	259,856

In connection with the revision of the Company’s reportable segments, the Company determined it had made an immaterial error in the summary of the capital expenditures by reporting segment for the year ended January 31, 2013. The error did not have an impact on the capital expenditure total, nor did it impact the consolidated balance sheet, statement of operations, statement of comprehensive (loss) income or cash flows. The table below illustrates the restatement amounts as well as the reclassifications due to our change in segments and discontinued operations as previously discussed.

(in thousands)	As Reported 2013		Restatement Adjustments			Adjusted for restatement 2013		Reclassifications			As restated and reclassified 2013
Water Resources	$	36,077	$	7,379		$	28,698		(6,252	)	$	22,446
Inliner		2,579		(1,730	)		4,309		—			4,309
Heavy Civil		1,088		(111	)		1,199		—			1,199
Geoconstruction		6,760		(6,631	)		13,391		—			13,391
Mineral Exploration		24,682		5,258			19,424		6,237			25,661
Energy Services		—		—			—		5,169			5,169
Other		1,650		(3,561	)		5,211		(5,211	)		—
Discontinued operations		1,672		—			1,672		57			1,729
Corporate		2,995		(604	)		3,599		—			3,599
Total capital expenditures	$	77,503	$	—		$	77,503		—		$	77,503

(17) New Accounting Pronouncements

The FASB has recently issued two Accounting Standards Updates. The first, ASU 2013-01, “Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities”, is effective for fiscal years beginning on or after January 1, 2013. This limits the scope of offsetting disclosures to recognized derivative instruments accounted for in accordance with ASC 815. The Company does not expect this to have an impact on their consolidated financial statements.

On February 5, 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”, which is effective for fiscal years (and interim periods within those years) beginning after December 15, 2012. This requires the Company to present information about significant items reclassified out of Accumulated Other Comprehensive Income (AOCI) either on the face of the income statement or as a separate disclosure in the notes to the financial statements. This is not expected to have a material impact on the Company’s consolidated financial statements.

In July, 2012, the FASB issued ASU 2012-02, “Testing Indefinite-Lived Intangible Assets for Impairment” (“ASU 2012-02”), which is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. This guidance permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test in accordance with Subtopic 350-30, Intangibles-Goodwill and Other-General Intangibles Other than Goodwill. The more-likely than-not threshold is defined as having a likelihood of more than 50 percent. If the Company determines that it

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is not more likely than not that the asset is impaired, the Company will have an option not to calculate annually the fair value of an indefinite-lived intangible asset. The adoption of ASU 2012-02 is not expected to have a significant impact on the Company’s consolidated financial statements.

In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment” (“ASU 2011-08”), which is effective for annual reporting periods, and interim periods within those years, beginning after December 15, 2011. The provisions of ASU 2011-08 gives entities testing goodwill for impairment the option of performing a qualitative assessment before calculating the fair value of a reporting unit in step 1 of the goodwill impairment test. If entities determine, on the basis of qualitative factors, that the fair value of a reporting unit is more likely than not less than the carrying amount, the two-step impairment test would be required. Otherwise, further testing would not be needed. Since the Company chose not to perform the optional qualitative assessment, the adoption of ASU 2011-08 did not have a significant impact on the Company’s consolidated financial statements.

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 IFRS” (“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 adoption of ASU 2011-04 did not have a significant impact on the Company’s consolidated financial statements.

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(18) Quarterly Results (Unaudited)

Unaudited quarterly results were as follows:

	2013
(in thousands, except per share data)	First			Second			Third			Fourth
Revenues	$	271,765		$	287,972		$	281,281		$	228,108
Net income (loss) from continuing operations		4,636			(2,969	)		8,657			(22,584	)
Net income (loss)		3,991			(23,866	)		8,665			(24,813	)
Net (loss) attributable to noncontrolling interests		(241	)		(159	)		(189	)		(39	)
Net income (loss) attributable to Layne		3,750			(24,025	)		8,476			(24,852	)
Basic income (loss) per share - continuing operations		0.23			(0.16	)		0.43			(1.16	)
Diluted income (loss) per share - continuing operations		0.22			(0.16	)		0.43			(1.15	)
Basic income (loss) per share		0.19			(1.23	)		0.43			(1.28	)
Diluted income (loss) per share		0.19			(1.23	)		0.43			(1.27	)

During the fourth quarter of fiscal year 2013, the Company recorded non-cash impairment charges of $7.3 million, or $4.4 million after income tax. See Note 5 for a further discussion of the impairments recorded.

	2012
(in thousands, except per share data)	First			Second			Third			Fourth
Revenues	$	259,942		$	287,734		$	288,075		$	270,267
Net income (loss) from continuing operations		12,588			10,481			9,121			(86,863	)
Net income (loss)		13,632			11,178			9,581			(87,573	)
Net (loss) attributable to noncontrolling interests		(566	)		(568	)		(828	)		(931	)
Net income (loss) attributable to Layne		13,066			10,610			8,753			(88,504	)
Basic income (loss) per share - continuing operations		0.62			0.51			0.43			(4.51	)
Diluted income (loss) per share - continuing operations		0.62			0.50			0.42			(4.49	)
Basic income (loss) per share		0.67			0.55			0.45			(4.55	)
Diluted income (loss) per share		0.67			0.54			0.45			(4.55	)

During the fourth quarter of fiscal year 2012, the Company recorded non-cash goodwill and definite-lived intangible asset impairment charges of $97.6 million, or $84.6 million after income tax. See Note 5 for a further discussion of the impairments recorded.

(19) Subsequent Events

As of January 31, 2013, the Company maintained a bank account in the country of Mauritania with a recorded balance of approximately $2.6 million. Subsequently, the Company has received information of a dispute between the bank and the central regulatory body in Mauritania and that the bank may be ceasing operations. The Company’s balance in the bank account when the dispute arose was $2.9 million. The Company is in the process of engaging local counsel to protect its interests and assist in recovering the funds. At this time, the Company is not able to estimate the amount of funds, if any, which it will be unable to recover.

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Supplemental Information on Oil and Gas Producing Activities (Unaudited)

As further discussed in Note 15 to the Consolidated Financial Statements, during fiscal year 2013, we completed the sale of substantially all of the assets of our Energy Division. At January 31, 2013, we have no oil and gas producing activities. Accordingly, the information presented below only includes information of our operations through the completion of the sale on October 1, 2012. The Company’s oil and gas activities were primarily conducted in the United States.

Capitalized Costs Related to Oil and Gas Producing Activities

Capitalized costs and associated depletion relating to oil and gas producing activities as of January 31, 2012, were as follows:

(in thousands)
Oil and gas properties	$	102,251
Mineral interest in oil and gas properties		21,374
		123,625
Accumulated depletion		(100,170	)
Net capitalized costs	$	23,455

Accumulated depletion includes non-cash ceiling test impairments recorded in 2010 and earlier. There were no such impairments during the year ended January 31, 2012.

Unproved oil and gas properties at January 31, 2012, totaled $153,000. Unevaluated mineral interest costs excluded from depletion at January 31, 2012, totaled $6,185,000.

Capitalized costs and associated depreciation relating to gas transportation facilities and equipment at January 31, 2012, were as follows:

(in thousands)
Gas transportation facilities and equipment	$	40,995
Accumulated depreciation		(15,009	)
Net capitalized costs	$	25,986

Capitalized costs incurred in gas transportation facilities and equipment during the fiscal years 2013 and 2012 totaled $58,000 and $109,000, respectively.

Cost Incurred in Oil and Gas Producing Activities

Capitalized costs incurred in oil and gas producing activities were as follows during the fiscal years 2013 and 2012:

	Years Ended January 31,
(in thousands)	2013		2012
Acquisition
Proved	$	102	$	331
Unproved		—		—
Exploration		—		431
Development		1,512		3,003
Provision for future asset retirement costs		—		63
Total	$	1,614	$	3,828

Results of Operations for Oil and Gas Producing Activities

Results of operations relating to oil and gas producing activities are set forth in the following tables for the years ended January 31, 2013, 2012 and 2011, on a dollar and per Mcf basis and include only revenues and operating costs directly attributable to oil and gas producing activities. General corporate overhead, interest costs, transportation of third party

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gas and other non-oil and gas producing activities are excluded. The income tax expense is calculated by applying statutory tax rates to the revenues after deducting costs, which include depletion allowances.

	Years Ended January 31,
(in thousands)	2013			2012			2011
Revenues	$	7,420		$	17,702		$	23,955
Production taxes		(118	)		(505	)		(592	)
Lease operating expenses		(4,282	)		(5,987	)		(8,628	)
Depletion		(2,946	)		(4,131	)		(5,652	)
Depreciation and amortization		(1,522	)		(2,955	)		(2,979	)
Administrative expenses		(1,889	)		(2,308	)		(2,931	)
Impairment of goodwill		—			(950	)		—
Impairment of oil and gas properties		—			—			—
Income tax (expense) benefit		1,302			(344	)		(1,237	)
Results of operations from producing activities (excluding corporate overhead and interest costs)	$	(2,035	)	$	522		$	1,936
	Years Ended January 31,
(Per Mcf)	2013			2012			2011
Revenues	$	2.47		$	3.82		$	5.38
Production taxes		(0.04	)		(0.11	)		(0.13	)
Lease operating expenses		(1.42	)		(1.29	)		(1.94	)
Depletion		(0.98	)		(0.89	)		(1.27	)
Depreciation and amortization		(0.51	)		(0.64	)		(0.67	)
Administrative expenses		(0.63	)		(0.50	)		(0.66	)
Impairment of goodwill		—			(0.21	)		—
Income tax (expense) benefit		0.43			(0.07	)		(0.28	)
Results of operations from producing activities (excluding corporate overhead and interest costs)	$	(0.68	)	$	0.11		$	0.43

Proved Oil and Gas Reserve Quantities

Proved oil and gas reserve quantities as of January 31, 2012, are based on estimates prepared in accordance with requirements of the SEC. All of the Company’s reserves were located within the United States.

Proved oil and gas reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates are made. Proved developed reserves are those reserves expected to be recovered through wells, equipment and operating methods existing when the estimates are made. Proved undeveloped reserves are those reserves expected to be recovered through new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The Company cautions that there are many inherent uncertainties in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures, and such estimates are subject to change.

As of January 31, 2012, we had total proved reserves of 22,465 MMcf, including proved developed reserves of 19,294 MMcf and proved undeveloped reserves of 3,171 MMcf. The proved developed reserves included 398 MMcfe gas equivalents of oil.

Estimated quantities of total proved oil and gas reserves were as follows:

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	Years Ended January 31,
Proved Developed and Undeveloped Reserves (MMcf)	2013			2012
Balance, beginning of year		22,465			19,097
Purchases of reserves in place		—			—
Revision of previous estimates		—			2,904
Extensions, discoveries and other additions		—			5,095
Production		(3,009	)		(4,631	)
Sale of reserves		(19,456	)
Balance, end of year		—			22,465
Proved Developed Reserves:
Beginning of year		19,294			19,097
End of year(1)		—			19,294
Proved Undeveloped Reserves:
Beginning of year		3,171			—
End of year		—			3,171

(1) Proved developed reserves as of January 31, 2012, included 398 gas equivalents of oil (MMcfe).

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities

The price used in determining future cash inflows for purposes of the standardized measure of discounted future net cash flows is the unweighted arithmetic average of the first-day-of-the-month spot price for each month within the 12-month period to the end of the reporting period. The future cash inflows also incorporate the effect of contractual arrangements such as fixed-price physical delivery, forward sales contracts. The price used in our determinations at January 31, 2012, was $3.82 per Mcf. Future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory rates to pre-tax cash flows relating to the Company’s estimated proved reserves and the difference between book and tax basis of proved properties.

This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used. The following table sets forth unaudited information concerning future net cash flows for oil and gas reserves, net of income tax expense:

(in thousands)	Year Ended January 31, 2012
Future cash inflows	$	89,752
Future production costs		(40,600	)
Future development costs		(5,848	)
Future income taxes		(10,956	)
Future net cash flows		32,348
10% annual discount for estimating timing of cash flows		(8,506	)
Standardized measure of discounted future net cash flows	$	23,842

The principal sources of change in the standardized measure of discounted future net cash flows were:

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	Years Ended January 31,
(in thousands )	2 013			2012
Balance, beginning of year	$	23,842		$	25,888
Sales of oil and gas produced, net of production costs		(3,020	)		(11,210	)
Net changes in prices, net of future production costs		—			(1,819	)
Net changes in estimated future development costs		—			—
Extensions and discoveries, less related costs		—			3,346
Purchase of reserves in place		—			—
Net change due to revisions in quantity estimates		—			4,431
Accretion of discount		3,133			2,531
Net changes in timing and other		—			2,691
Net change in income taxes		7,486			(2,016	)
Previously estimated development costs incurred		—			—
Sale of reserves		(31,441	)		—
Aggregate change in standardized measure of discounted future net cash flows for the year		(23,842	)		(2,046	)
Balance, end of year	$	—		$	23,842

Layne Christensen Company and Subsidiaries

Schedule II: Valuation and Qualifying Accounts

			Additions
(in thousands )	Balance at Beginning of Period		Charges to Costs and Expenses		Charges to Other Accounts		Deductions			Balance at End of Period
Allowance for customer receivables :
Fiscal year ended January 31, 2011	$	7,425	$	1,392	$	1,335	$	(1,524	)	$	8,628
Fiscal year ended January 31, 2012		8,628		39		352		(878	)		8,141
Fiscal year ended January 31, 2013		8,141		1,790		584		(2,688	)		7,827

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