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Exhibit 13

Helmerich & Payne, Inc.

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Helmerich & Payne, Inc. is the holding Company for
Helmerich & Payne International Drilling Co., an international
drilling contractor with land and offshore operations in the
United States, South America, Mexico, Trinidad and Africa.
Holdings also include commercial real estate properties in the
Tulsa, Oklahoma, area, and an energy-weighted portfolio of
securities valued at approximately $360 million as of
September 30, 2009.

FINANCIAL HIGHLIGHTS

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To the Co-owners
of Helmerich & Payne, Inc.:

         A year ago at this time, we understood that 2009 would be a challenging year for the drilling business, but we were still somewhat dismayed by the rapidity and extent of a decline that rivaled what the industry experienced in the early 1980s. In our largest segment, U.S. Land, the utilization rate fell from an average of 97 percent in October to a low of about 50 percent in June, which was significantly higher than that of our peer group. Customers seeing both the collapse in commodity prices and the implosion of the credit markets took drastic measures to conserve cash flow and protect their balance sheets by cutting drilling programs to the bone. Consequently, the Company received termination notices on term contracts representing 37 U.S. Land new build rigs, each of which had begun work prior to fiscal 2008. The option for the early termination fee was built into each of our term contracts to provide our customers with the flexibility to change their plans in mid-stream while at the same time protecting the Company for the significant financial commitments it made to build new high efficiency rigs. Although our capital risk was mitigated, we would have much preferred to continue the contracts and keep our people intact and fully engaged.

         While we are encouraged by the improvement in the energy markets since the low point early last year, we remain cautious about current supply and demand dynamics and what they mean for natural gas pricing during 2010.

         Prospects for any sustained price improvement will depend on natural gas demand in 2010. Industrial demand was hammered this past year and the size of the rebound will be tied to achieving real economic recovery. Weather related demand, aided by a winter with above average heating days, could also play an important role. Longer term opportunities for improved natural gas demand are plentiful, including inroads into the transportation fuel market.

         Of course, on the supply side of the equation, caution abounds, especially in the short-term. In addition to the well known gas shale potential, all-time high gas inventory levels are currently buttressed by a sizeable backlog of uncompleted wells. Some estimate there are approximately 1,500 of these deferred wells in the U.S.

         Future LNG imports are an ongoing source of added supply potential with worldwide capacity having jumped by a third in the last two years. It is uncertain how much of this new capacity will land in the U.S.

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         While these concerns set up a possible "2^nd bottom," we believe the more likely outcome is that they act to somewhat flatten the curve and push it to the right. In many respects, avoiding some of the typical volatility even on the upside would be a good thing. Arguably, the worst thing for the industry would be another price spike.

         One silver lining of this past year was that lower utilization created opportunities for us to appeal to new customers, who may not have tried a FlexRig before for lack of availability. Six FlexRigs began working in Mexico under a Schlumberger Integrated Project Management contract and we also moved four rigs to the Marcellus in Pennsylvania, which is fast becoming a key natural gas basin in the lower 48. All told, we have initiated work with 25 first time FlexRig users and all of them had cheaper alternatives in terms of dayrates. Winning new customers speaks to a larger point of gaining market share in good times and bad. Not long ago, we were number five in terms of market share in U.S. Land Drilling. This calendar year, while we still don't have the largest fleet, we achieved the highest amount of drilled footage through October in the lower 48 land market. As we've gained market share, we have also maintained premium margins to our peer group, becoming the U.S. land drilling industry's most profitable contractor during our fiscal year.

         As the industry slowly recovers, we have no illusions about the environment we're faced with. Keeping our focus on the customer's need for efficiency and safety in the field will continue to drive our long-term success. Of course that success is earned every day, 24-7. It requires hard work, a focus on safety, and is often conducted under challenging conditions. As the Company begins its 90^th year as the industry's oldest land contractor, I am reminded that it is the strong values of our past, combined with a drive for innovation and improved performance that secures our future. In that spirit, I feel a deep sense of gratitude toward the H&P men and women whose commitment and loyalty continue to make that possible.

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Financial & Operating Review

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Management's Discussion and Analysis of Financial Condition and Results of Operations

Helmerich & Payne, Inc.

RISK FACTORS AND FORWARD-LOOKING STATEMENTS

The following discussion should be read in conjunction with Part I of our Form 10-K as well as the Consolidated Financial Statements and related notes thereto. Our future operating results may be affected by various trends and factors, which are beyond our control. These include, among other factors, fluctuations in oil and natural gas prices, unexpected expiration or termination of drilling contracts, currency exchange gains and losses, changes in general economic conditions, disruptions to the global credit markets, rapid or unexpected changes in technologies, risks of foreign operations, uninsured risks, changes in domestic and foreign policies, laws and regulations and uncertain business conditions that affect our businesses. Accordingly, past results and trends should not be used by investors to anticipate future results or trends.

With the exception of historical information, the matters discussed in Management's Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements. These forward-looking statements are based on various assumptions. We caution that, while we believe such assumptions to be reasonable and make them in good faith, assumed facts almost always vary from actual results. The differences between assumed facts and actual results can be material. We are including this cautionary statement to take advantage of the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by us or persons acting on our behalf. The factors identified in this cautionary statement and those factors discussed under Risk Factors beginning on page 6 of our Form 10-K are important factors (but not necessarily all important factors) that could cause actual results to differ materially from those expressed in any

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forward-looking statement made by us or persons acting on our behalf. We undertake no duty to update or revise our forward-looking statements based on changes of internal estimates or expectations or otherwise.

EXECUTIVE SUMMARY

Helmerich & Payne, Inc. is primarily a contract drilling company which owned and operated a total of 254 drilling rigs at September 30, 2009. Our contract drilling segments include the U.S. Land segment in which we had 201 rigs, the Offshore segment in which we had 9 offshore platform rigs, and the International Land segment in which we had 44 rigs at September 30, 2009. As oil and natural gas prices steeply declined and the credit markets tightened in late calendar 2008, customers aggressively reduced drilling budgets. As a result, we experienced a decline in rig utilization in the U.S. Land segment and in some countries in the International Land segment. We believe that utilization has stabilized and is now slowly improving. During this cycle, we have had the opportunity to attract new customers. Additionally, we are seeing opportunities for expansion in international markets as we entered Mexico and placed a second rig in Africa during the fiscal year. We have also penetrated new markets in the U.S. Drilling has become more challenging with growing unconventional plays, requiring more highly capable rigs which are expected to be in short supply as demand improves. With our fleet that includes 183 FlexRigs with advanced technology, we are well positioned to meet the long-term needs of our customers and compete successfully for opportunities in an improving market.

RESULTS OF OPERATIONS

All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Our net income for 2009

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was $353.5 million ($3.32 per share), compared with $461.7 million ($4.34 per share) for 2008 and $449.3 million ($4.27 per share) for 2007. Included in our net income were after-tax gains from the sale of investment securities of $13.5 million ($0.13 per share) in 2008 and $40.2 million ($0.38 per share) in 2007. Net income also includes after-tax gains from the sale of assets of $3.6 million ($0.04 per share) in 2009, $8.6 million ($0.08 per share) in 2008 and $26.5 million ($0.25 per share) in 2007. Included in net income in 2009 and 2008 are after-tax gains of $0.3 million and $6.5 million ($0.06 per share), respectively, from involuntary conversion of long-lived assets that sustained significant damage as a result of Hurricane Katrina in 2005. Also included in net income is our portion of income from an equity affiliate, Atwood Oceanics, Inc. (Atwood), of $0.09 per share in 2009, $0.16 per share in 2008 and $0.09 per share in 2007. Effective April 1, 2009, we determined we no longer had the ability to exercise significant influence over operating and financial policies at Atwood and discontinued accounting for Atwood using the equity method. The investment in Atwood is now recorded at fair value with changes deferred as a component of other comprehensive income.

Consolidated operating revenues were $1,894.0 million in 2009, $2,036.5 million in 2008, and $1,629.7 million in 2007. During 2007 and 2008, U.S. land revenues increased due to the addition of FlexRigs combined with continued increases in dayrates since 2005. In 2009, as oil and natural gas prices declined and uncertainty in the capital markets increased, customers reduced spending on exploration and development drilling causing a reduction in rig utilization. Our U.S. land rig utilization was 68 percent in 2009, 96 percent in 2008 and 97 percent in 2007. The average number of U.S. land rigs available was 194 rigs in 2009, 171 rigs in 2008 and 134 rigs in

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2007. Revenue in the Offshore segment increased over the three-year period primarily as a result of rig utilization for offshore rigs increasing to 89 percent in 2009, compared to 75 percent in 2008 and 65 percent in 2007. International rig revenues decreased in 2009 after increasing in 2008 from 2007. Contributing to the decrease in revenue in 2009 was the discontinuation of recording revenue in Venezuela for the last three fiscal quarters of 2009. Additionally, rig utilization in 2009 declined to 68 percent as we discontinued work in Venezuela as contracts expired. For further detail regarding Venezuela, see the International Land segment below and Note 14 of the Consolidated Financial Statements. The increase in revenue in 2008 from 2007 was due to increases in dayrates even though rig utilization declined in 2008 to 82 percent from 90 percent in 2007.

We did not sell any investment securities in 2009, but recorded gains of $22.0 million in 2008 and $65.5 million in 2007. Interest and dividend income was $5.0 million in 2009 and 2008 and $4.2 million in 2007.

Direct operating costs in 2009 were $1,011.6 million, compared with $1,086.7 million in 2008 and $862.3 million in 2007. Direct operating costs for all three years were 53 percent of operating revenues.

Depreciation expense was $236.4 million in 2009, $210.8 million in 2008 and $146.0 million in 2007. Included in depreciation are abandonments of equipment of $5.3 million in 2009, $13.3 million in 2008, and $4.1 million in 2007. Depreciation expense, exclusive of the abandonments, increased over the three-year period as we placed into service 25 new rigs in 2009, 29 in 2008 and 48 in 2007. Depreciation expense in 2010 is expected to increase from 2009 from

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new rigs placed into service during 2009 and additional rigs placed into service during 2010. (See Liquidity and Capital Resources)

As conditions warrant, management performs an analysis of the industry market conditions in each drilling segment. Based on this analysis, management determines if any impairment is required. In 2009, 2008 and 2007, no impairment was recorded.

General and administrative expenses totaled $59.4 million in 2009, $57.1 million in 2008, and $47.4 million in 2007. The $2.3 million increase in 2009 from 2008 is primarily due to an increase in banking and legal fees associated with obtaining new debt, increased pension expense and services associated with the FCPA investigation and settlement discussed further in Item 3 Legal Proceedings of our Form 10-K. These increases were partially offset with a decrease in current year employee bonus accruals. The increase in 2008 from 2007 was primarily a result of increases in expenses associated with employee labor and employee benefits due to increases in the number of employees.

Interest expense was $13.5 million in 2009, $18.7 million in 2008, and $10.1 million in 2007. The interest expense is primarily attributable to the fixed-rate intermediate debt outstanding in each year and advances on the senior credit facility in 2009 and 2008. Interest expense decreased in 2009 from 2008 primarily as a result of reduced interest rates. Interest expense in 2008 increased from 2007 due to higher outstanding debt balances during 2008. Capitalized interest was $6.6 million, $4.7 million and $9.4 million in 2009, 2008 and 2007, respectively. All of the capitalized interest is attributable to our rig build program. The higher capitalized interest

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in 2007 was due to a higher number of new rigs being constructed during that year.

The provision for income taxes totaled $232.4 million in 2009, $255.6 million in 2008, and $251.0 million in 2007. The effective income tax rate increased to 40 percent in 2009 from 37 percent in 2008, and 36 percent in 2007. The increase in the effective tax rate is primarily due to Venezuelan income taxes being calculated using the accrual method of accounting for financial purposes while we are recognizing revenue in Venezuela using the cash basis method of accounting. Deferred income taxes are provided for temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. Recoverability of any tax assets are evaluated and necessary allowances are provided. The carrying value of the net deferred tax assets is based on management's judgments using certain estimates and assumptions that we will be able to generate sufficient future taxable income in certain tax jurisdictions to realize the benefits of such assets. If these estimates and related assumptions change in the future, additional valuation allowances may be recorded against the deferred tax assets resulting in additional income tax expense in the future. (See Note 3 of the Consolidated Financial Statements for additional income tax disclosures.)

On May 21, 2008, we acquired a private limited partnership, TerraVici Drilling Solutions (TerraVici) in a transaction accounted for under the purchase method of accounting. Under the purchase method of accounting, the assets and liabilities of TerraVici were recorded as of the acquisition date, at their respective fair values, and consolidated with our financial statements. The operations for TerraVici are included with all other non-reportable business segments.

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TerraVici is developing patented rotary steerable technology to enhance horizontal and directional drilling operations. We acquired TerraVici to complement technology currently used with FlexRigs. The process of drilling has become increasingly challenging as preferred well types deviate from simple vertical drilling. By combining this new technology with our existing capabilities, we expect to improve drilling productivity and reduce total well cost to the customer.

We paid a total purchase price of $12.2 million, including acquisition related fees of $1.2 million. In conjunction with the acquisition, we recorded an in-process research and development (IPR&D) charge of $11.1 million in 2008. The IPR&D represents rotary steerable system (RSS) tools under development by TerraVici at the date of acquisition that had not yet achieved technological feasibility, and would have no future alternative use. The $11.1 million estimated fair value of the IPR&D was derived using the multi-period excess-earnings method. The terms of the transaction provide for future contingency payments up to $11 million based on specific commerciality milestones and certain earn-out provisions based on future earnings being met.

During 2009 and 2008, we incurred $9.7 million and $1.8 million, respectively, of research and development expenses related to ongoing development of the RSS. We anticipate research and development expenses to be approximately $2.5 million in each quarter during 2010.

The following tables summarize operations by reportable operating segment.

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COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2009 AND 2008

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $86,297 and $75,519 for 2009 and 2008, respectively.
Rig utilization excludes seven FlexRigs completed and ready for delivery at September 30, 2009.

Operating income in the U.S. Land segment decreased to $573.7 million in 2009 from $605.7 million in 2008. Included in U.S. land revenues for 2009 is approximately $169.4 million from early termination revenue and revenue from customers that requested delivery delays for new FlexRigs. The average revenue per day for 2009 increased $3,672 of which $3,524 is attributable to the early termination related revenue and customer requested delivery delay revenue for new FlexRigs.

During 2009, we received 37 early termination notices from customers corresponding to the new rig build program. All 37 rigs released had been deployed to the field prior to fiscal 2008.

Direct operating expenses decreased 12.4 percent from 2008 to 2009, and the expense as a percentage of revenue declined to 46 percent in 2009 from 49 percent in 2008. The average rig expense per day, however, increased during 2009 due to fixed expenses incurred on

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idle rigs including property taxes and insurance as well as labor and other expenses associated with stacking rigs.

Rig utilization decreased to 68 percent in 2009 from 96 percent in 2008. The total number of rigs at September 30, 2009 was 201 compared to 185 rigs at September 30, 2008. The net increase is due to 22 new FlexRigs having been completed and placed into service, 7 rigs completed and ready for service, 7 transferred to the International Land segment with customer commitments, 5 transferred to the International Land segment to be used for bidding prospective work, and 1 rig removed and held for sale. Depreciation includes charges for abandoned equipment of $4.9 million and $13.2 million in 2009 and 2008, respectively. Excluding the abandonment amounts, depreciation in 2009 increased 23 percent from 2008 due to the increase in available rigs.

We expect to complete and deliver another seven new FlexRigs by the end of the third fiscal quarter of 2010. Like those completed in fiscal 2009, each of these new rigs is committed to work for an exploration and production company under a fixed term contract, performing drilling services on a daywork contract basis. As a result of the new FlexRigs added in 2009 and additional rigs scheduled for completion in 2010, we anticipate depreciation expense to continue to increase in fiscal 2010.

During 2009, the economic recession, including the decrease in oil and natural gas prices and deterioration in the credit markets, had a significant effect on customer spending and drilling activity. As a result, the industry's active land drilling rig count in the U.S. land market declined by over fifty percent from the Fall of 2008 to the Summer of 2009. Although not as severe as that experienced by most

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of our peers, we experienced a significant decline in drilling activity. Since June 2009, however, the industry's U.S. land rig count has been experiencing a slight recovery. At September 30, 2009, 122 out of 201 existing rigs in the U.S. Land segment were generating revenue. Of the 122 rigs generating revenue, 94 were under fixed term contracts, and 28 were working in the spot market. At November 19, 2009, the number of existing rigs under fixed term contracts in the segment increased to 96, and the number of rigs working in the spot market increased to 31.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2009 AND 2008

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $34,125 and $16,330 for 2009 and 2008, respectively. Also excluded are the effects of offshore platform management contracts and currency revaluation expense.

Segment operating income in our Offshore segment increased 66 percent in 2009 from 2008 due to higher activity including a rig that began work in Trinidad during 2008.

Currently, we have seven of our nine platform rigs working. One of the seven rigs is expected to become idle during the first quarter of

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fiscal 2010 and one of the two idle rigs began work under a new contract in November 2009.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2009 AND 2008

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $18,755 and $26,431 for 2009 and 2008, respectively. Also excluded are the effects of currency revaluation expense.
Rig utilization at September 30, 2009 excludes one FlexRig completed and ready for delivery and two FlexRigs delivered waiting on customer location. Rig utilization at September 30, 2008 excludes four FlexRigs completed and ready for delivery.

The International Land segment had an operating loss of $7.2 million for 2009 compared to operating income of $70.0 million for 2008. As further discussed in Note 14 of the Consolidated Financial Statements, we determined that as of the beginning of the second quarter of fiscal 2009 and forward, services to our customer in Venezuela, Petroleos de Venezuela, S.A. (PDVSA), no longer met the revenue recognition criteria as collectability became uncertain. As a result, $57.9 million of revenue was not recorded during 2009. Primarily because of this change, revenue and average revenue per day decreased in 2009 compared to 2008. Revenues not recognized in 2009 will be recognized in future periods when cash is collected.

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Rig utilization for international land operations decreased to 68 percent in 2009 from 82 percent in 2008. The ability to collect accounts receivables in U.S. dollars from PDVSA deteriorated to the point that during the second fiscal quarter of 2009, we decided to discontinue work as contracts expired. All of our eleven rigs in Venezuela were active at the end of 2008. At the end of 2009, one rig remained active and has since become idle. During 2009, 12 rigs were transferred to the International Land segment from the U.S. Land segment. Of those twelve, seven are under contract and the remaining five are being used for bidding prospective work. The reduced activity in Venezuela and rigs transferred to the segment that are not yet working contributed to the decrease in utilization. The total number of rigs at September 30, 2009 was 44 compared to 30 rigs at September 30, 2008. The increase is due to two FlexRigs completed and ready for delivery and 12 rigs transferred from the U.S. Land segment. Three of the FlexRigs completed in 2008 were placed into service in 2009. The fourth rig completed in 2008 is under contract and will be sent to a location to be determined by the operator.

The average rig expense per day increased in 2009 from 2008 primarily due to labor and stacking expenses related to rigs that became idle during 2009.

We will continue to pursue future drilling opportunities in Venezuela, but do not expect to commit to new contracts until additional progress is made on unpaid invoices and converting local currency to U.S. dollars.

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COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2008 AND 2007

Operating statistics for per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $75,519 and $59,035 for 2008 and 2007, respectively.
Rig utilization excludes one FlexRig completed and ready for delivery at September 30, 2007.

Operating income in the U.S. Land segment increased to $605.7 million in 2008 from $467.0 million in 2007. Improvement in revenue was primarily the result of increased revenue days and increased dayrates for new rigs placed in service during 2008. Rig utilization decreased to 96 percent in 2008 from 97 percent in 2007. At September 30, 2008, two conventional rigs and one highly mobile rig were stacked. The total number of rigs at September 30, 2008 was 185 compared to 157 rigs at September 30, 2007. The increase was due to 28 new FlexRigs being completed and placed into service. Depreciation included charges for abandoned equipment of $13.2 million and $2.3 million in 2008 and 2007, respectively. Excluding the abandonment amounts, depreciation in 2008 increased 43.2 percent from 2007 due to the increase in available rigs.

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COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2008 AND 2007

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $16,330 and $14,328 for 2008 and 2007, respectively. Also excluded are the effects of offshore platform management contracts and currency revaluation expense.

Segment operating income in our Offshore segment increased 51.2 percent in 2008 from 2007 due to increased activity and a rig beginning work in Trinidad.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2008 AND 2007

Operating statistics of per day revenue, expense and margin do not include reimbursements of "out-of-pocket" expenses of $26,431 and $40,113 for 2008 and 2007, respectively. Also excluded are the effects of currency revaluation expense.
Rig utilization excludes four FlexRigs completed and ready for delivery at September 30, 2008.

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Segment operating income for our International Land segment decreased 33.5 percent from 2007 to 2008. Depreciation and operating income for 2008 were negatively impacted by an adjustment of approximately $5.9 million related to prior years' depreciation. Rig utilization for international land operations decreased to 82 percent in 2008 from 90 percent in 2007. Direct operating expenses increased in 2008 from 2007 as oilfield cost inflation pressures and labor cost increases in the international markets were experienced.

LIQUIDITY AND CAPITAL RESOURCES

Our capital spending was $880.8 million in 2009, $705.6 million in 2008, and $894.2 million in 2007. Net cash provided from operating activities was $897.3 million in 2009, $610.8 million in 2008 and $561.1 million in 2007. Our 2010 capital spending estimate is approximately $225 million, a decrease from the $881 million incurred during 2009. The primary reason for the decrease in estimated capital expenditures is that only seven contracted new FlexRigs are scheduled to be completed during 2010, a significant reduction in the number of new rigs built compared to 2009.

Historically, we have financed operations primarily through internally generated cash flows. In periods when internally generated cash flows are not sufficient to meet liquidity needs, we will either borrow from available credit sources or, if market conditions are favorable, sell portfolio securities. Likewise, if we are generating excess cash flows, we may invest in short-term investments. In 2009, we purchased $12.5 million of short-term investments.

We manage a portfolio of marketable securities that, at the close of fiscal 2009, had a market value of $359.5 million. Our investments

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in Atwood and Schlumberger, Ltd. made up 95 percent of the portfolio's market value on September 30, 2009. The value of the portfolio is subject to fluctuation in the market and may vary considerably over time. Excluding our investments in limited partnerships carried at cost, the portfolio is recorded at fair value on our balance sheet.

We generated cash proceeds from the sale of portfolio securities of $25.5 million in 2008 and $73.4 million in 2007. We did not sell any portfolio securities in 2009.

The following table reconciles cash proceeds from the sale of portfolio securities stated above to proceeds from sale of investments shown in the Consolidated Statements of Cash Flows in our Consolidated Financial Statements:

In 2008, proceeds were from the sale of 170,000 shares of Schlumberger, Ltd. and all other available-for-sale securities we owned. In 2007, proceeds were primarily from the sale of 1,012,500 shares of Schlumberger, Ltd. Proceeds in both years were primarily used to fund capital expenditures.

Our proceeds from asset sales totaled $8.7 million in 2009, $22.9 million in 2008 and $51.6 million in 2007. In 2008, two international land rigs were sold generating $13.0 million in

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proceeds. Income from asset sales in 2008 totaled $13.5 million. In 2007, one U.S. land rig and two offshore rigs were sold generating $36.7 million in proceeds. Income from all asset sales in 2007 totaled $41.7 million. The rigs sold in each year were idle at the time of the sales and, with our emphasis on FlexRig technology, we took advantage of the opportunity to sell older rigs. In each year we also had sales of old or damaged rig equipment and drill pipe used in the ordinary course of business.

In 2009, 2008 and 2007, we received insurance proceeds of approximately $0.2 million, $5.3 million and $19.2 million, respectively, for damages sustained to our offshore Rig 201 during Hurricane Katrina. During the fourth quarter of fiscal 2007, our Rig 178 was lost when the well it was drilling had a blowout. During 2009 and 2008, we received gross insurance proceeds of approximately $0.3 million and $8.7 million, respectively, in connection with the loss of Rig 178. We recorded a net gain from involuntary conversion of approximately $0.5 million in 2009, $10.2 million in 2008 and $16.7 million in 2007. The proceeds, shown in the Consolidated Statements of Cash Flows under investing activities, were used to rebuild Rig 201 and replace Rig 178. The costs for both rigs were capitalized with Rig 201 returning to work in the fourth fiscal quarter of 2007 and the replacement rig returning to work in 2008. We have settled both claims and no additional insurance proceeds are expected.

From March 2005 through November 2008, we announced commitments with exploration and production companies to build a cumulative total of 140 new FlexRigs under fixed term contracts to perform drilling services on a daywork basis. Eight of these 140 new rigs were contracted for work in International Land operations and

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the remaining 132 in U.S. Land operations. We completed 133 of the 140 rigs through fiscal 2009 and have seven remaining new FlexRigs to complete by the end of the third fiscal quarter of 2010. The total estimated construction cost of all 140 rigs, including tubular and other ancillary equipment, is currently $2.2 billion, most of which was spent by the end of fiscal 2009.

We have $150 million of intermediate-term unsecured debt obligations with staged maturities of $75 million in August, 2012 and $75 million in August, 2014. The annual average interest rate through maturity will be 6.50 percent. The terms of the debt obligations require that we maintain a minimum ratio of debt to total capitalization.

On July 21, 2009, we closed a private placement of our senior unsecured fixed rate notes maturing in July 2016 and received proceeds of $200 million. Interest on the notes will be paid semi-annually based on an annual rate of 6.10 percent. We will make five equal annual principal repayments of $40 million starting on the third anniversary of the closing date. Financial covenants require that we maintain a funded leverage ratio of less than 55 percent and an interest coverage ratio (as defined) of not less than 2.50 to 1.00. The note purchase agreement also contains additional terms, conditions, and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality. The $200 million of proceeds from this facility were used to reduce our $400 million senior credit facility by $105 million and the remainder was used to fund capital expenditures and for other general corporate purposes.

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We have an agreement with a multi-bank syndicate for a five-year, $400 million senior unsecured credit facility expiring December 2011. We have the option to borrow at the prime rate for maturities of less than 30 days but anticipate the majority of all of the borrowings over the remaining life of the facility will accrue interest at a spread over the London Interbank Bank Offered Rate (LIBOR). We pay a commitment fee based on the unused balance of the facility. The spread over LIBOR and the commitment fee are determined according to a scale based on the ratio of our total debt to total capitalization. The LIBOR spread ranges from .30 percent to .45 percent depending on the ratio. Based on the ratio at the close of the 2009 fiscal year, the LIBOR spread on borrowings was .35 percent and the commitment fee was .075 percent per annum. The advances bear an interest rate of .60 percent. At September 30, 2009, we had two letters of credit totaling $21.9 million under the facility and had borrowed $70 million against the facility with $308.1 million remaining available to borrow. Subsequent to September 30, 2009, we reduced the debt by $30 million and had $338.1 million available to borrow.

In January 2009, we closed an agreement with a multi-bank syndicate for a $105 million unsecured line of credit that matures January 2010. We committed to fully fund this facility for the entire term at a spread over 30 day LIBOR. The spread over LIBOR is determined according to the same scale of debt to total capitalization used in our $400 million facility which is described in the preceding paragraph. The spread over LIBOR for the new facility has increased to a range of 2 percent to 2.75 percent. At September 30, 2009, the spread on the borrowing was 2.25 percent over LIBOR. Simultaneous with the closing of this facility, we entered into an interest-rate swap with the same maturity and a notional amount of $105 million. We believe that the swap will act to fix the annualized interest rate of the facility at approximately 3.17 percent assuming the spread remains at 2.25 percent over LIBOR. The interest rate swap qualifies as a

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derivative and was not designated as a hedging instrument and, as such, we have not applied hedge accounting. At the end of an accounting period, the interest rate swap is recorded in the Consolidated Balance Sheet at fair value, either in other current assets or accrued liabilities, and any related gains or losses are recognized on our Consolidated Statement of Income within interest expense. The fair value of the interest rate swap liability at September 30, 2009 was $0.2 million and is included in accrued liabilities in the Consolidated Balance Sheet. Interest expense on the interest rate swap was $0.6 million during 2009.

Financial covenants in both facilities require that we maintain a funded leverage ratio (as defined) of less than 50 percent and an interest coverage ratio (as defined) of not less than 3.00 to 1.00. Both facilities contain additional terms, conditions, and restrictions that we believe are usual and customary in unsecured debt arrangements for companies that are similar in size and credit quality.

At September 30, 2009, we were in compliance with all debt covenants.

At September 30, 2009, we had unsecured letters of credit totaling $3.2 million which were used to obtain surety bonds for our international operations.

At September 30, 2009, we had 107 existing rigs with contracts under fixed terms with original term durations ranging from twelve months to seven years, with some expiring in fiscal 2010. The contracts provide for termination at the election of the customer, with an early termination payment to be paid if a contract is terminated prior to the expiration of the fixed term. The 2009 economic slowdown, including the decrease in oil and natural gas prices and deterioration in the credit markets had a significant effect on customer spending. As a result, during 2009 some of our

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customers exercised termination provisions and elected to pay the early termination fee in lieu of continued drilling. While most of our customers are primarily major oil companies and large independent oil companies, a risk exists that a customer, especially a smaller independent oil company, may become unable to meet its obligations and may exercise its early termination election in the future and not be able to pay the early termination fee. Although not expected at this time, our future revenue and operating results would be negatively impacted if this were to happen.

Our operating cash requirements and estimated capital expenditures, including completion of the remaining rig construction, for fiscal 2010 will be funded through current cash, cash provided from operating activities, funds available under the current credit facilities, funds available under any new credit facility and, possibly, sales of available-for-sale securities. We anticipate that we will be able to utilize working capital as well as available borrowing capacity under our $400 million line of credit to pay off the $105 million facility when it matures in January 2010.

The current ratio was 1.7 at September 30, 2009 and 2.2 at September 30, 2008. The long-term debt to total capitalization ratio was 14 percent and 17 percent at September 30, 2009 and 2008, respectively. The decrease is due to equity increasing, primarily from earnings and a decrease in long-term debt.

During 2009, we paid dividends of $0.20 per share, or a total of $21.1 million, representing the 37th consecutive year of dividend increases.

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STOCK PORTFOLIO HELD

MATERIAL COMMITMENTS

We have no off balance sheet arrangements other than operating leases discussed below. Our contractual obligations as of September 30, 2009, are summarized in the table below in thousands:

(a)  The estimated future interest payments on our variable-rate credit facilities were based on the interest rate and principal balance at September 30, 2009. Interest on fixed-rate debt was estimated based on principal maturities. See Note 2 "Debt" to our Consolidated Financial Statements.
(b)  Estimated interest was calculated based on the interest rate at September 30, 2009 and includes the value of an interest rate swap liability at September 30, 2009. See Note 2 "Debt" to our Consolidated Financial Statements.
(c)  See Note 15 "Commitments and Contingencies" to our Consolidated Financial Statements.

The above table does not include obligations for our pension plan or amounts recorded for uncertain tax positions.

In 2009, we contributed $0.8 million to the pension plan. Based on current information available from plan actuaries, we estimate contributing at least $3.0 million in 2010 to meet the minimum contribution required by law. We expect to make additional contributions to fund distributions in lieu of liquidating pension assets. With the unpredictability in the equity, debt and global markets, it is possible that contributions in fiscal 2010 will be greater

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than expected. Future contributions beyond 2010 are difficult to estimate due to multiple variables involved.

At September 30, 2009, we had $6.9 million recorded for uncertain tax positions and related interest and penalties. However, the timing of such payments to the respective taxing authorities cannot be estimated at this time. Income taxes are more fully described in Note 3 to the Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The Consolidated Financial Statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. These estimates and assumptions are evaluated on an on-going basis. Estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. The following is a discussion of the critical accounting policies and estimates used in our financial statements. Other significant accounting policies are summarized in Note 1 to the Consolidated Financial Statements.

Property, Plant and Equipment Property, plant and equipment, including renewals and betterments, are stated at cost, while maintenance and repairs are expensed as incurred. Interest costs applicable to the construction of qualifying assets are capitalized as a component of the cost of such assets. We account for the depreciation of property, plant and equipment using the straight-line method over the estimated useful lives of the assets considering the estimated salvage value of the property, plant and equipment. Both the estimated useful lives and salvage values require the use of management estimates. Certain events, such as unforeseen changes in

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operations, technology or market conditions, could materially affect our estimates and assumptions related to depreciation. Management believes that these estimates have been materially accurate in the past. For the years presented in this report, no significant changes were made to the determinations of useful lives or salvage values. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in the results of operations.

Impairment of Long-lived Assets Management assesses the potential impairment of our long-lived assets whenever events or changes in conditions indicate that the carrying value of an asset may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand for a specific asset, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, completion of specific contracts, and/or overall changes in general market conditions. If a review of the long-lived assets indicates that the carrying value of certain of these assets is more than the estimated undiscounted future cash flows, an impairment charge is made to adjust the carrying value to the estimated fair market value of the asset. The fair value of drilling rigs is determined based on quoted market prices, if available, otherwise it is determined based upon estimated discounted future cash flows and rig utilization. Cash flows are estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on each rig's marketability, any cash investment required to make a rig marketable, suitability of rig size and makeup to existing platforms, and competitive dynamics due to lower industry utilization. Use of different assumptions could result in an impairment charge different from that reported.

Fair Value of Financial Instruments Fair value is defined as an exit price, which is the price that would be received upon sale of an asset

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or paid upon transfer of a liability in an orderly transaction between market participants at the measurement date. The degree of judgment utilized in measuring the fair value of assets and liabilities generally correlates to the level of pricing observability. Financial assets and liabilities with readily available, actively quoted prices or for which fair value can be measured from actively quoted prices in active markets generally have more pricing observability and require less judgment in measuring fair value. Conversely, financial assets and liabilities that are rarely traded or not quoted have less price observability and are generally measured at fair value using valuation models that require more judgment. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency of the asset, liability or market and the nature of the asset or liability. The carrying amounts reported in the statement of financial position for current assets and current liabilities qualifying as financial instruments approximate fair value because of the short-term nature of the instruments. Marketable securities are carried at fair value generally determined by quoted market prices. We have categorized financial assets and liabilities measured at fair value into a three-level hierarchy in accordance with Accounting Standards Codification 820-10. (See Note 7 of the Consolidated Financial Statements for disclosures.)

Self-Insurance Accruals We self-insure a significant portion of expected losses relating to worker's compensation, general liability, employer's liability, and auto liabilities. Generally, deductibles are $1 million or $2 million per occurrence depending on whether a claim occurs inside or outside of the United States. We maintain certain other insurance coverage with deductibles as high as $5 million. Insurance is purchased over deductibles to reduce our exposure to catastrophic events. Estimates for incurred outstanding liabilities for worker's compensation, general liability claims and for claims that are incurred but not reported are recorded. Estimates are based on historic experience and statistical methods that we believe are reliable.

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Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs.

Our wholly-owned captive insurance company, White Eagle Assurance Company, provides a portion of our physical damage insurance for company-owned drilling rigs and reinsures international casualty deductibles. With the exception of "named windstorm" risk in the Gulf of Mexico, we insure rig and related equipment at values that approximate the current replacement cost on the inception date of the policy. We self-insure a $1 million per occurrence, as well as 10 percent of the estimated replacement cost of offshore rigs and 30 percent of the estimated replacement cost for land rigs and equipment. We have two insurance policies covering six offshore platform rigs for "named windstorm" risk in the Gulf of Mexico. The first policy covers four rigs and has a $55 million insurance limit over a $20 million deductible. We have been indemnified by a customer for $17 million of this deductible. The second policy covers two rigs and has a $40 million limit and a $3.5 million deductible. We maintain certain other insurance coverage with deductibles as high as $5 million. Excess insurance is purchased over these coverages to limit our exposure to catastrophic claims, but there can be no assurance that such coverage will respond or be adequate in all circumstances. Retained losses are estimated and accrued based upon our estimates of the aggregate liability for claims incurred, and, using adjuster's estimates, our historical loss experience or estimation methods that are believed to be reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development, and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense and related liabilities.

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Pension Costs and Obligations Our pension benefit costs and obligations are dependent on various actuarial assumptions. We make assumptions relating to discount rates and expected return on plan assets. Our discount rate is determined by matching projected cash distributions with the appropriate corporate bond yields in a yield curve analysis. The discount rate was lowered from 7.25 percent to 5.42 percent as of September 30, 2009 to reflect changes in the market conditions for high-quality fixed-income investments. The expected return on plan assets is determined based on historical portfolio results and future expectations of rates of return. Actual results that differ from estimated assumptions are accumulated and amortized over the estimated future working life of the plan participants and could therefore affect the expense recognized and obligations in future periods. As of September 30, 2006, the Pension Plan was frozen and benefit accruals were discontinued. As a result, the rate of compensation increase assumption has been eliminated from future periods. We anticipate pension expense in 2010 to increase from 2009 by an estimated $2.1 million.

Stock-Based Compensation Historically, we have granted stock-based awards to key employees and non-employee directors as part of their compensation. We estimate the fair value of all stock option awards as of the date of grant by applying the Black-Scholes option-pricing model. The application of this valuation model involves assumptions, some of which are judgmental and highly sensitive. These assumptions include, among others, the expected stock price volatility, the expected life of the stock options and risk-free interest rate. Expected volatilities were estimated using the historical volatility of our stock, based upon the expected term of the option. We consider information in determining the grant date fair value that would have indicated that future volatility would be expected to be significantly different than historical volatility. The expected term of the option was derived from historical data and represents the period of time that options are estimated to be outstanding. The risk-free

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interest rate for periods within the estimated life of the option was based on the U.S. Treasury Strip rate in effect at the time of the grant. The fair value of each award is amortized on a straight-line basis over the vesting period for awards granted to employees. Stock-based awards granted to non-employee directors are expensed immediately upon grant.

The fair value of restricted stock is based on the closing price of our common stock on the date of grant. We amortize the fair value of restricted stock awards to compensation expense on a straight-line basis over the vesting period. At September 30, 2009, unrecognized compensation cost related to unvested restricted stock was $2.2 million. The cost is expected to be recognized over a weighted-average period of 1.5 years.

Revenue Recognition Revenues and expenses for daywork contracts are recognized daily as the work progresses. For certain contracts, payments are received that are contractually designated for the mobilization of rigs and other drilling equipment. Revenues earned, net of direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract. Other lump-sum payments received from customers relating to specific contracts are deferred and amortized to income as services are performed. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met.

NEW ACCOUNTING STANDARDS

Effective October 1, 2008, we adopted the disclosure requirements of Accounting Standards Codification (ASC) 820-10, Fair Value Measurements and Disclosures issued by the Financial Accounting Standards Board (FASB) in September 2006, which defines fair value,

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establishes a framework for measuring fair value and expands disclosures about fair value measurements required under other accounting pronouncements, but does not change existing guidance for carrying instruments at fair value. Our adoption of the required portions of ASC 820-10 as of October 1, 2008 did not have a material impact on our financial position, results of operations or cash flows. ASC 820-10-65, Transition related to FASB Staff Position FAS157-2, issued in February 2008, delays the application of ASC 820-10 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually), and will be adopted by us beginning the first quarter of fiscal 2010. Our adoption on October 1, 2009 is not expected to have a significant impact on the Consolidated Financial Statements.

ASC 825-10, Financial Instruments, permits choosing to measure certain financial assets and liabilities at fair value. We elected not to measure any assets or liabilities at fair value which were not being so measured prior to adopting ASC 820-10 on October 1, 2008.

In August 2009, the FASB issued Accounting Standards Update No. 2009-05, Measuring Liabilities at Fair Value (ASU 2009-05). This update provides amendments to ASC 820, Fair Value Measurements and Disclosure, for the fair value measurement of liabilities when a quoted price in an active market is not available. ASU 2009-05 is effective for reporting periods beginning after August 28, 2009, which means that it will be effective for our first quarter beginning October 1, 2009. We do not currently believe this update will have a significant impact on the Consolidated Financial Statements.

On October 1, 2009, we adopted the requirements regarding the accounting for income tax benefits of dividends on share-based payment awards. As a result of the adoption, we recognize a realized

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income tax benefit associated with dividends or dividend equivalents paid on nonvested equity-classified employee share-based payment awards that are charged to retained earnings as an increase to additional paid-in capital. The adoption did not have a material impact on our financial position, results of operations or cash flows.

In June 2008, the FASB issued guidance contained in ASC 260-10-45 to clarify that all outstanding unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities. An entity must include participating securities in its calculation of basic and diluted earnings per share pursuant to the two-class method pursuant to ASC 260-10-05, Earnings per Share. We will adopt ASC 260-10-45 October 1, 2009. All prior-period earnings per share data presented will be adjusted retrospectively to conform to the provisions of ASC 260-10-45. We expect the impact, if any, of adopting ASC 260-10-45 to be immaterial on our prior period earnings per share.

ASC 715-20-65, Transition related to SFAS 132R-1, Employers' Disclosures about Postretirement Benefit Plan Assets, was issued by the FASB in December 2008. The new guidance requires employers of public and nonpublic companies to disclose more information about how investment allocation decisions are made, more information about major categories of plan assets, including concentration of risk and fair-value measurements, and the fair-value techniques and inputs used to measure plan assets. The disclosure requirements are effective for years ending after December 15, 2009. We will adopt the disclosure requirements for the year ended September 30, 2010, on a prospective basis. We do not expect the adoption to have a material impact on the Consolidated Financial Statements.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Foreign Currency Exchange Rate Risk We have operations in several South American countries, Trinidad, Mexico and Africa. With the exception of Argentina and Venezuela, our exposure to currency valuation losses is usually immaterial due to the fact that virtually all invoice billings and receipts in other countries are in U.S. dollars. The exchange rate between the U.S. dollar and the Argentine peso stayed within a narrow range for seven years and then devalued 27 percent during fiscal 2009, resulting in the recording a $2.2 million currency loss.

We are exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar fuerte (Bsf) receivable balances and Bsf cash balances. We have an agreement with the Venezuelan state oil company, PDVSA, whereby 60 percent of our billings are in U.S. dollars and 40 percent are in the local currency, the bolivar fuerte. PDVSA has previously paid U.S. dollar invoices in Bsf which increases our exposure to foreign currency devaluation. In 2008, we received notification from PDVSA that exchange of those U.S. dollar invoices previously paid in Bsf would be made only when supporting documentation had been approved. The supporting documentation was delivered to PDVSA and is awaiting approval. The approval and subsequent payment would result in reducing the foreign currency exposure by approximately $37.5 million. We are unable to determine when payment will be received.

Since 2005, the Venezuelan government has had exchange controls that fix the exchange rate at 2.15 Bsf to one U.S. dollar and also prohibits us, as well as other companies, from converting the Bsf into U.S. dollars. Since that time, we have, in compliance with applicable regulations, submitted three separate requests to the Venezuelan government seeking permission to convert existing Bsf balances into U.S. dollars. All three requests were approved by the Venezuelan

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government and we were permitted to remit U.S. dollars as dividends from the Venezuelan subsidiary to the U.S. based parent. These dividends reduced our exposure to currency devaluation in Venezuela.

On July 22, 2008, we submitted another application with the Venezuelan government requesting the approval to convert Bsf cash balances to U.S. dollars. When and if we receive approval from the Venezuelan government, our Venezuelan subsidiary will remit approximately $28.4 million as a dividend to its U.S. based parent as cash balances permit. While we have been successful in obtaining government approval for conversion of Bsf to U.S. dollars, there is no guarantee that future conversion to U.S. dollars will be permitted. In the event that conversion to U.S. dollars would be prohibited, then Bsf cash balances could increase and we would be exposed to increased risk of devaluation.

Past devaluation losses may not be reflective of the actual potential for future devaluation losses. Venezuela continues to operate under exchange controls and the Venezuelan Bsf exchange rate has remained fixed at 2.15 Bsf to one U.S. dollar since March 2005. The exact amount and timing of any future devaluations attributable to the Venezuelan Bsf exchange rate is uncertain. At September 30, 2009, we had $45.3 million in cash denominated in Bsf exposed to the risk of currency devaluation. Additionally, we have other current assets including accounts receivable exposed to currency devaluation.

While we are unable to predict future devaluation in Venezuela, if fiscal 2010 balance sheet components are similar to fiscal 2009 and if a 10 percent to 100 percent devaluation were to occur, we could experience potential currency devaluation losses ranging from approximately $6.6 million to $35.7 million.

We are not operating in any country that is currently considered highly inflationary, which is defined as cumulative inflation rates

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exceeding 100 percent in the most recent three-year period. The economy in Venezuela has not been considered to be highly inflationary in the past five years, but it is reasonably possible that Venezuela may be considered highly inflationary again at some time in the future. All of our foreign subsidiaries use the U.S. dollar as the functional currency and local currency monetary assets are remeasured into U.S. dollars with gains and losses resulting from foreign currency transactions included in current results of operations. As such, if a foreign economy is considered highly inflationary, there would be no impact on the Consolidated Financial Statements.

Credit Risk Typically, contract drilling revenues are recognized as services are performed. In U.S. generally accepted accounting principles, one of the basic revenue recognition criteria is that collectability of the revenue is reasonably assured. Our revenue in Venezuela is from providing drilling services to PDVSA, the Venezuelan state-owned petroleum company. We determined, as of the beginning of the second quarter of fiscal 2009 and forward, that the revenue recognition criteria in Venezuela is no longer met as collectability of revenue is not reasonably assured, primarily due to the uncertainty of the timing of collectability as discussed further below. As a result of this change, $57.9 million of revenue was not recorded in the International Land segment during fiscal 2009. Since the beginning of the second quarter of fiscal 2009, approximately $69.3 million (U.S. dollars and U.S. currency equivalent) was collected from PDVSA of which $61.4 million was applicable to the accounts receivable balance at the end of the first fiscal quarter of 2009. As of September 30, 2009, the Consolidated Balance Sheet reflected accounts receivable from PDVSA of $26.6 million. Subsequent to the end of fiscal 2009, additional payments of approximately $20.8 million (U.S. dollars and U.S. currency equivalent) were received through November 19, 2009. Approximately 73 percent of this corresponds to accounts receivable at the end of the first fiscal quarter and the remainder to invoices

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issued for work performed after the first fiscal quarter of 2009. We do not have enough information to conclude that the remaining receivable balance is not probable of collection. However, there is uncertainty regarding the timing of the collection due to the current political, economic and social instability in Venezuela, the dependence by Venezuela on oil to largely support its economy and the failure of PDVSA to pay many service companies working in Venezuela. The collection of receivables from PDVSA has historically been more difficult and slower than that of other customers in international countries in which we have drilling operations due to PDVSA policies and procedures.

Commodity Price Risk The demand for contract drilling services is a result of exploration and production companies spending money to explore and develop drilling prospects in search of crude oil and natural gas. Their appetite for such spending is driven by their cash flow and financial strength, which is very dependent on, among other things, crude oil and natural gas commodity prices. Crude oil prices are determined by a number of factors including supply and demand, worldwide economic conditions, and geopolitical factors. Crude oil and natural gas prices have been volatile and very difficult to predict. While current energy prices are important contributors to positive cash flow for customers, expectations about future prices and price volatility are generally more important for determining future spending levels. This volatility has led many exploration and production companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for contract drilling services is not always purely a function of the movement of commodity prices.

In addition, customers may finance their exploration activities through cash flow from operations, the incurrence of debt or the issuance of equity. The deterioration in the credit and capital markets in 2008 and the apparent slow, cautious recovery since, could make it

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difficult for customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices or a reduction of available financing may result in a reduction in customer spending and the demand for drilling services. This reduction in spending could have a material adverse effect on our business, financial condition or operations.

We attempt to secure favorable prices through advanced ordering and purchasing for drilling rig components. While these materials have generally been available at acceptable prices, there is no assurance the prices will not vary significantly in the future. Any fluctuations in market conditions causing increased prices in materials and supplies could impact future operating costs adversely.

Interest Rate Risk Our interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based, on borrowings from our commercial banks. We have reduced the impact of fluctuations in interest rates by maintaining a portion of our debt portfolio in fixed-rate debt. At September 30, 2009, the amount of our fixed-rate debt was approximately 83 percent of total debt.

The following tables provide information as of September 30, 2009 and 2008 about our interest rate risk sensitive instruments:

INTEREST RATE RISK AS OF SEPTEMBER 30, 2009 (dollars in thousands)

(a)  Advances bear interest rate of .60%

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INTEREST RATE RISK AS OF SEPTEMBER 30, 2008 (dollars in thousands)

(b)  Advances bear interest rates ranging from 2.84% to 4.06%

Equity Price Risk On September 30, 2009, we had a portfolio of securities with a total fair value of $359.5 million. The total fair value of the portfolio of securities was $384.0 million at September 30, 2008. Our investments in Atwood Oceanics, Inc. and Schlumberger, Ltd. made up 95 percent of the portfolio's fair value at September 30, 2009. Although we sold portions of our positions in Schlumberger in 2008 and 2007, we make no specific plans to sell securities, but rather sell securities based on market conditions and other circumstances. These securities are subject to a wide variety and number of market-related risks that could substantially reduce or increase the fair value of our holdings. Except for our investments in limited partnerships carried at cost, the portfolio is recorded at fair value on the balance sheet with changes in unrealized after-tax value reflected in the equity section of the balance sheet. At November 19, 2009, the total fair value of the portfolio of securities had increased to approximately $387.3 million. Currently, the fair value exceeds the cost of the investments. We continually monitor the fair value of the investments but are unable to predict future market volatility and any potential impact to the Consolidated Financial Statements.

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Report of Independent
Registered Public Accounting Firm

The Board of Directors and Shareholders
Helmerich & Payne, Inc.

We have audited the accompanying consolidated balance sheets of Helmerich & Payne, Inc. as of September 30, 2009 and 2008, and the related consolidated statements of income, shareholders' equity, and cash flows for each of the three years in the period ended September 30, 2009. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Helmerich & Payne, Inc. at September 30, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2009, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, effective October 1, 2007, the Company adopted the requirements for accounting for uncertainty in income taxes.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Helmerich & Payne Inc.'s internal control over financial reporting as of September 30, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated November 24, 2009 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
November 24, 2009

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Consolidated Statements of Income

The accompanying notes are an integral part of these statements.

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Consolidated Balance Sheets

ASSETS

The accompanying notes are an integral part of these statements.

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LIABILITIES AND SHAREHOLDERS' EQUITY

The accompanying notes are an integral part of these statements.

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Consolidated Statements of Shareholders' Equity

The accompanying notes are an integral part of these statements.

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Consolidated Statements of Cash Flows

The accompanying notes are an integral part of these statements.

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Notes to Consolidated Financial Statements

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of Helmerich & Payne, Inc. and its wholly-owned subsidiaries. Fiscal years of our foreign operations end on August 31 to facilitate reporting of consolidated results. There were no significant intervening events which materially affected the financial statements.

FOREIGN CURRENCIES

The functional currency for all our foreign subsidiaries is the U.S. dollar. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the year. Gains and losses from remeasurement of foreign currency financial statements and foreign currency translations into U.S. dollars are included in direct operating costs. Aggregate foreign currency remeasurement and transaction losses included in direct operating costs totaled $2.9 million and $1.6 million in fiscal 2009 and 2008, respectively, and gains of $1.0 million in fiscal 2007.

USE OF ESTIMATES

The preparation of our financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect 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.

RECENTLY ADOPTED ACCOUNTING STANDARD

In June 2009, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 168, The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162 ("SFAS 168"). SFAS 168 replaced all previously issued accounting standards and establishes the FASB Accounting Standards Codification™ ("ASC") as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with U.S. GAAP. The new standard, ASC 105-10, was effective for all interim and annual periods ending after September 15, 2009. The ASC is not intended to change existing U.S. GAAP. The adoption of this pronouncement only resulted in changes to our financial statement disclosure references. As such, adoption of this pronouncement had no effect on our consolidated financial position, results of operations, or cash flows. All references to U.S. GAAP within this report on Form 10-K are updated to reflect the new codification.

CASH AND CASH EQUIVALENTS

Cash equivalents consist of investments in short-term, highly liquid securities having original maturities of three months or less. The carrying values of these assets approximate their fair values. We primarily utilize a cash management system with a series of separate accounts consisting of lockbox accounts for receiving cash, concentration accounts for moving funds to, and several "zero-balance" disbursement accounts for funding

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payroll and accounts payable. As a result of our cash management system, checks issued, but not presented to the banks for payment, may create negative book cash balances. Checks outstanding in excess of related book cash balances are included in accounts payable where applicable and included as a financing activity in the Consolidated Statements of Cash Flows.

RESTRICTED CASH AND CASH EQUIVALENTS

We had restricted cash and cash equivalents of $13.9 million and $13.3 million at September 30, 2009 and 2008, respectively. Restricted cash is primarily for the purpose of potential insurance claims in our wholly-owned captive insurance company. Of the total at September 30, 2009, $2.0 million is from the initial capitalization of the captive company and management has elected to restrict an additional $10.9 million. The remaining restricted cash consists of $1.0 million held in escrow in conjunction with the 2008 acquisition of TerraVici Drilling Solutions. The restricted amounts are primarily invested in short-term money market securities.

The restricted cash and cash equivalents are reflected in the balance sheet as follows (in thousands):

INVENTORIES AND SUPPLIES

Inventories and supplies are primarily replacement parts and supplies held for use in our drilling operations. Inventories and supplies are valued at the lower of cost (moving average or actual) or market value.

INVESTMENTS

We maintain investments in equity securities of unaffiliated companies. The cost of securities used in determining realized gains and losses is based on the average cost basis of the security sold.

We regularly review investment securities for impairment based on criteria that include the extent to which the investment's carrying value exceeds its related fair value, the duration of the market decline and the financial strength and specific prospects of the issuer of the security. Unrealized losses that are other than temporary are recognized in earnings.

Investments in companies owned from 20 to 50 percent are accounted for using the equity method by recognizing our proportionate share of the income or loss of the investee. Effective April 1, 2009, Atwood Oceanics, Inc. (Atwood) was accounted for as an available-for-sale investment, as we determined that we no longer had the ability to exercise significant influence over operating and financial policies at Atwood and discontinued accounting for Atwood using the equity method. The investment in Atwood is now recorded at fair value with changes deferred as a component of other comprehensive income. We have no other equity method investments.

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DERIVATIVE FINANCIAL INSTRUMENTS

We are exposed to market risk in the normal course of business operations due to ongoing investing and financing activities. The risk of loss can be assessed from the perspective of adverse changes in fair values, cash flows and future earnings. ASC 815, Derivatives and Hedging, requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. We have not historically entered into derivative financial instruments for trading purposes or for speculation.

During fiscal 2009, we adopted the disclosure provisions contained in ASC 815 that provides companies with requirements for enhanced disclosures about derivative instruments and hedging activities to enable investors to better understand their effects on a company's financial position, financial performance and cash flows. For further information regarding the derivative instruments including our disclosures of our interest rate swap, refer to Note 2, Debt, and Note 7, Financial Instruments and Fair Value Measurement, of these Consolidated Financial Statements.

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are stated at cost less accumulated depreciation. Substantially all property, plant and equipment are depreciated using the straight-line method based on the estimated useful lives of the assets (contract drilling equipment, 4-15 years; real estate buildings and equipment, 10-45 years; and other, 2-23 years). Depreciation in the Consolidated Statements of Income includes abandonments of $5.3 million, $13.3 million and $4.1 million for fiscal 2009, 2008 and 2007, respectively. The cost of maintenance and repairs is charged to direct operating cost, while betterments and refurbishments are capitalized.

We lease office space and equipment for use in operations. Leases are evaluated at inception or at any subsequent material modification and, depending on the lease terms, are classified as either capital leases or operating leases as appropriate under ASC 840, Leases. We do not have significant capital leases.

CAPITALIZATION OF INTEREST

We capitalize interest on major projects during construction. Interest is capitalized based on the average interest rate on related debt. Capitalized interest for fiscal 2009, 2008 and 2007 was $6.6 million, $4.7 million, and $9.4 million, respectively.

VALUATION OF LONG-LIVED ASSETS

We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable in accordance with ASC 360-10. Changes that could prompt such an assessment include a significant decline in revenue or cash margin per day, extended periods of low rig utilization, changes in market demand for a specific asset, obsolescence, completion of specific contracts, and/or overall general market conditions. If a review of the long-lived assets indicates that the carrying value of certain of these assets is more than the estimated undiscounted future cash flows, an impairment charge is made to adjust the carrying value to the estimated fair value of the asset. The fair value of drilling rigs is determined based on quoted market prices, if available, otherwise it is determined based upon estimated discounted future cash flows and rig utilization. Cash flows are estimated by management considering factors such as prospective market demand, recent changes in rig technology and its effect on

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each rig's marketability, any cash investment required to make a rig marketable, suitability of rig size and makeup to existing platforms, and competitive dynamics due to lower industry utilization.

ACQUISITIONS

We account for acquired businesses using the purchase method of accounting which requires that the assets acquired and liabilities assumed be recorded at the date of acquisition at their respective fair values. Any excess of the purchase price over the estimated fair values of the net assets acquired is recorded as goodwill. Amounts allocated to acquired in-process research and development are expensed at the date of acquisition. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can materially impact results of operations. Accordingly, for significant items, assistance from third party valuation specialists is typically obtained. The valuations are based on information available near the acquisition date and are based on expectations and assumptions that have been deemed reasonable by management.

SELF INSURANCE ACCRUALS

We have accrued a liability for estimated worker's compensation and other casualty claims incurred. The liability for other benefits to former or inactive employees after employment but before retirement is not material.

DRILLING REVENUES

Contract drilling revenues are comprised of daywork drilling contracts for which the related revenues and expenses are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized on a straight line basis over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements received for out-of-pocket expenses are recorded as revenues and direct costs. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met.

RENT REVENUES

We enter into leases with tenants in our rental properties consisting primarily of retail and multi-tenant warehouse space. The lease terms of tenants occupying space in the retail centers and warehouse buildings range from one to eleven years. Minimum rents are recognized on a straight-line basis over the term of the related leases. Overage and percentage rents are based on tenants' sales volume. Recoveries from tenants for property taxes and operating expenses are recognized in other operating revenues in the Consolidated Statements of Income. Our rent revenues are as follows:

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