Reader Advisory, Risks and Forward Looking Statements

This FWD Primer is presented as a brief company overview for the information of investors, analysts and other parties with an interest in Input/Output, Inc. (herein referred to as “the Company” and by its abbreviation, “I/O”). The information included herein contains certain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements include statements concerning expected future financial positions, segment sales, results of operations, cash flows, funds from operations, financing plans, gross margins, business strategy, budgets, projected costs and expenses, capital expenditures, competitive position, product offerings, technology developments, access to capital and growth opportunities, future sales and market growth, and other statements that are not of historical fact. Actual results may vary materially from those described in these forward-looking statements. All forward-looking statements reflect numerous assumptions and involve a number of risks and uncertainties. These risks and uncertainties include the timing and development of the Company’s products and services and market acceptance of the Company’s new and revised product offerings; risks associated with competitor’s product offerings and pricing pressures resulting therefrom; the relatively small number of customers that the Company currently relies upon; the fact that a significant portion of the Company’s revenues is derived from foreign sales; the Company’s ability to successfully manage the integration of its acquisitions into the Company’s operations; the risks that sources of capital may not prove adequate; the Company’s inability to produce products to preserve and increase market share; collection of receivables; and technological and marketplace changes affecting the Company’s product line. Additional risk factors, which could affect actual results, are disclosed by the Company from time to time in its filings with the Securities and Exchange Commission, including its Annual Report on Form 10-K for the year ended December 31, 2004.

Many risks, uncertainties and assumptions are associated with I/O, its operations and the oil and gas production industry it serves. Before making any investment decision, the Company urges the reader to closely consider the variety of risks to its business which are described in greater detail under the heading “Risk Factors” in its SEC filings, most notably beginning page 32 in its most recent Form 10-K, filed March 16, 2005.

Use of EBITDA & Regulation G Reconciliation

This FWD Primer contains references to the non-GAAP financial measure of Earnings (net income) before Interest, Taxes, Depreciation, and Amortization, or EBITDA. This term, as used and defined by Input/Output, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. However, the Company believes EBITDA is useful to an investor in evaluating I/O’s operating performance because:

• It is widely used by investors in the energy industry to measure a company’s operating performance without regard to items such as interest expense, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired; and

• It helps investors more meaningfully evaluate and compare the results of the Company’s operations from period to period by removing the impact of the Company’s capital structure and asset base from Input/Output’ operating results.

• It is used by Input/Output’s management as a measure of operating performance, in presentations to its board of directors, as a basis for strategic planning and forecasting, as a component for setting incentive compensation and to assess compliance in financial ratios, among others.

Reconciliations of this financial measure to the most directly comparable GAAP financial measure are provided in the table below. Management’s opinion regarding the usefulness of such measure to investors and a description of the ways in which management uses such measure can be found in the Company’s most recent Annual Report on Form 10-K filed with the Securities and Exchange Commission.

Reconciliation of EBITDA to GAAP Net Income (Loss)

($MM)	Historical Results												Guidance
Year Ended December 31,	2001			2002			2003			2004			2005E(1)

Net income (loss)	$	9.3		$	(118.7	)	$	(23.2	)	$	(3.0	)	$12.0-$32.0
Interest expense	0.7			3.1			4.1			6.2			7.2
Other income	(4.7		)	(2.3		)	(1.9		)	(1.3		)	(1.4	)
Income tax (benefit) expense	3.1			56.8			0.3			0.7			1.0
Depreciation and amortization expense	17.5			13.2			11.4			24.7			34.0
EBITDA	$	26.0		$	(47.9	)	$	(9.2	)	$	27.3		$52.8-$72.8
Reserve for Russian receivables	—			—			—			5.2			—
Impairment of long-lived assets/Goodwill	—			21.4			1.1			—			—
Adjusted EBITDA	$	26.0		$	(26.5	)	$	(8.1	)	$	32.5		$52.8-$72.8

(1) Represents 2005 Company EPS guidance of $0.15-$0.40 based on average 80.0 million common shares outstanding, the utilization of the Company’s net operating losses and internal targets of interest expense, other income and depreciation and amortization assuming no change in capital structure or future acquisitions.

May 2005
FWD Primer

INPUT/OUTPUT, INC.
NYSE: IO

Giving Seismic a Whole New Image ^TM

www.i-o.com

Input/Output has transformed from an OEM supplier to an industry leading seismic solutions company. Our focus is on providing seismic contractors and oil and gas companies alike the twin benefits of a better image and greater productivity. We encourage investors to imagine over the next five years what could be, and what we believe will be as the Full-Wave Era unfolds.

• The Third Wave. All indications are that the global oil and gas industry has entered a new stage of seismic technology – the era of Full-Wave Digital (FWD).

• Benefits of Full-Wave. Full-wave equipment, such as I/O’s VectorSeis, and associated technology promises to generate significantly higher resolution images with less equipment in less time. This in turn should mean better decisions are made faster by oil and gas companies, ultimately leading to higher returns on capital employed.

• Adoption Gaining Momentum. While greater than 90% of all seismic acquisition is still being done with analog technologies, spending on FWD is increasing as Oil Majors move from successful 2-D full-wave testing to 3-D FWD implementation. Input/Output believes that within five to ten years, 50%-70% of all seismic imaging done onshore will utilize FWD technology.

• Input/Output is a New Company for a New Era. Combined with its industry-leading VectorSeis sensor, the 2004 strategic acquisitions of Concept Systems (CSL) and GX Technology (GXT) has created a complete FWD toolkit, transforming I/O from an OEM provider to a full seismic solutions company. In the process, I/O has strategically expanded its customer base, now deploying its technology solution directly to oil and gas companies, the seismic end-user, as well as seismic contractors. Underscoring this transition, it is estimated that greater than 50% of 2005 revenues will be generated from businesses that did not exist or contribute in 2002.

• Visible Growth. With GXT and CSL, I/O believes it is now set to capture the market benefits and opportunities of FWD. By 2009, total revenues could potentially range from $750-$850 million (less than 30% of which is estimated to be from the OEM legacy business), which would translate to average annual growth of 25%.

• The Right Team. Starting with Bob Peebler who joined as CEO in 2003 (who successfully built Landmark Graphics in the midst of the burgeoning 3-D Era before selling to Halliburton in 1996), I/O is building a management team specifically tailored to execute the Company’s break-out strategy.

Price (May 5, 2005)

6.24

Stock Data

Fiscal Year end:		December
Symbol / Exchange:		IO / NYSE
52-Week Range:		$5.28-$11.22
Common Shares O/S (1):		78.7 MM
Market Capitalization:		$491.2 MM
Total Enterprise Value (TEV) (2):		$577.5 MM
Avg. Daily Stock Volume (2005):		1,088,942
Insider Ownership (1):		12.6%
Public Float:		87.4%
Top 20 Institutional Owners (3):		78.0%

Financial Data & Guidance (3/31/05 data, unaudited)

Select Income Statement: ($MM)	2004			2005E
Revenues:	$	247.3		$320-$365
Gross Margin:	29		%	30%-35	%
EBITDA (4):	$	32.5		$52.8-$72.8
EPS:	$	(0.05	)	$0.15-$0.40
TEV / EBITDA (5):	17.8		x	9.2	x
P / E (5):	NM			22.7	x

Select Balance Sheet: ($MM)	2004			1Q05
Total Cash:	$	14.9		$	27.6
Total Debt:	$	85.9		$	83.9
Total Stockholders’ Equity:	$	314.5		$	311.3
Net Debt / Net Capital:	18.4		%	15.3		%

Business Composition

Revenues	2004		2005E (5)
Traditional OEM	$	157mm	$	165mm
FWD Sales	$	31mm	$	45mm
GXT & CSL Services	$	59mm	$	133mm

Stock Price (latest twelve months)

(1)		As disclosed in SEC Form 14A, Definitive Proxy filed April 1, 2005.
(2)		Total Enterprise Value (TEV) is defined as current Market Capitalization plus $30 million in preferred stock issued February 2005, plus Total Debt less Total Cash as of latest fiscal quarter end.
(3)		As tracked by Thomson Financial.
(4)		EBITDA is a non-GAAP financial measure; see inside front cover for GAAP reconciliation.
(5)		Based on midpoint of 2005E company guidance.

THE TRANSFORMATION OF I/O

First Mover Advantage. By completing the acquisitions of Concept Systems and GX Technology in 2004, I/O moved beyond its 35-year legacy of equipment manufacturing for the global seismic contracting industry. After integrating Concept Systems and GXT into the I/O family, the Company has collectively created the world’s first, technology-focused seismic solutions company. Management is committed to leading the global oil & gas industry into the next era of seismic imaging – Digital Full-wave – by developing the solutions needed to address the most difficult geophysical challenges worldwide.

With the successful commercial development of the VectorSeis digital sensor coupled with the transformational acquisitions of 2004, I/O has compiled a substantial full-wave toolkit to lead the E&P industry into the Full-Wave Era. These include:

• Software and services for designing customized 2-D, 3-D, and 4-D seismic surveys;

• High vector fidelity digital sensors for advanced, full-wave imaging on land and on the seabed;

• Seismic acquisition platforms and data management software that have the potential to provide step-change improvements in field operational efficiencies onshore and offshore;

• Processing solutions that enhance the quality and resolution of the final seismic image; and

• Services across the seismic workflow that enable oil and gas companies and seismic acquisition contractors to better apply, and gain a competitive advantage from, I/O’s broad portfolio of technologies at all stages of the reservoir lifecycle.

In short, I/O fundamentally sells a better image and greater productivity. All of the Company’s efforts are focused on providing one end goal: a higher return on capital employed for both our oil company and seismic contractor customers.

I/O is a new company poised to tackle the challenges and capture the opportunities from a new era in seismic imaging.

FULL-WAVE PRIMER

Given the importance of the emerging full-wave digital market, I/O recognizes that broad education on the merits and benefits of FWD compared to traditional analog seismic is necessary for both its customers and investors. To further this effort, this first installment of I/O’s Company Profile aims to provide a more thorough understanding of the Company’s long term vision, strategy and products in the new Full-Wave Era.

I/O’S VISION FOR FULL-WAVE

I/O’s core vision is to lead the oil and gas industry into the next era of seismic imaging – digital full-wave.

Since modern seismology began in the 1920’s, there have been two main eras. The 2-D era was the first, lasting from the 1920’s through the early 1980’s when the second era – the era of 3-D seismic – began. Each of these eras have been underpinned by a myriad of innovations in acquisition equipment, software and seismic data processing, all supported by complementary innovations in computing and interpretation systems.

I/O believes the third emerging era, the Full-Wave Digital Era, will have a similarly dramatic long term impact on both the oil and gas business and the seismic industry as a whole. E&P companies will experience the benefits of better hydrocarbon identification and extraction as new, deeper reservoirs are discovered while mature basins will be better managed and optimized. Greater operational efficiencies will reduce full cycle times which in turn will free up dollars currently spent on logistics-intensive operations (which can comprise over 80% of seismic acquisition costs). As these investment dollars are redirected to higher value technology services such as processing and interpretation, even better images will result, magnifying the benefits of switching to FWD over analog.

Just as the 3-D era created new market opportunities for emerging technology companies in the 1990’s such as Landmark Graphics, GXT, Geoquest, GECO, and PGS, the shift to full-wave is also likely to spawn the development and growth of an entirely new market segment as geology increasingly pushes into the realm of physics. New software and technology capabilities will be required to manage and effectively utilize the step-function increase in both quantity and complexity of seismic data. Specialized data analysis, interpretive processing and other new services will be provided by I/O and new boutique technology companies alike, some of which have yet to be formed.

While the Full-Wave Era will take several years to unfold, I/O is leading this shift with its digital sensor, VectorSeis, which the Company estimates has captured 70% of all FWD surveys done to date. VectorSeis is I/O’s “secret sauce,” but the Full-Wave Era will not be defined by equipment alone. I/O’s vision for full-wave is a complete seismic solution, including how surveys are designed, how the data is acquired and how the data is processed. I/O intends to be at the forefront of this chain of new industry activities, services and revenue streams.

Looking out over the next five years, I/O believes this market could drive future I/O revenues to potentially over $700 million, nearly three times the level of 2004.

If you believe in the new era of full-wave digital, then we encourage you to take a closer look at Input/Output.

1. History of the Seismic Industry

IN THE BEGINNING

Economic success in the oil field has and always will depend on a company’s ability to minimize risk and uncertainty. This core tenet has underlined the seismic industry from the beginning.

Seismic instruments were first developed during the mid-19th century to record and measure movements of the ground during earthquakes. John Karcher eventually developed the formula that underlies reflection seismology, whereby subsurface formations are mapped by measuring the time it takes for acoustic pulses generated at the surface to return to the surface after reflecting off interfaces between geological formations with different physical properties.

In the early 1900’s, Reginald Fessenden used sound wave reflections to measure water depths and to detect icebergs. By World War I, Ludger Mintrop invented a portable seismograph for the German army to calculate the location of Allied artillery based on the acoustic noise generated when the guns were fired. After the war, Mintrop reversed the process by setting off explosions a known distance from the seismograph and measuring the return time of subsurface reflections to estimate the depths of formations. On March 25, 1925, Dabney Petty, Associate State Geologist for the Texas Bureau of Economic Geology, wrote about the application of Mintrop’s method by his new company, Seismos, on the Texas coast. In the mid-1920’s, the discovery of an oil field beneath the Nash salt dome in Brazoria County, Texas, was the first to be based on single-fold seismic data. In so doing, a new era was ushered in where using applied seismic technology could successfully locate and reduce the risk of finding oil – a dynamic which still drives the global oil industry more than 80 years later.

The First Wave: 1930-1980 – The 2-D Era

In 1930, Karcher and others founded Geophysical Service Inc. (GSI). Following World War II, GSI acquired a license to build transistors that ultimately resulted in the birth of Texas Instruments, of which GSI then became a subsidiary. The move to transistorized equipment dramatically lightened the load for field crews.

The next revolution came in the 1950’s and 1960’s. The major advancement was the recording of seismic signals onto a magnetic tape. Changing from paper to taped records ultimately gave way to machine processing, development of the analog processor, and a total change in the way seismic data was collected and processed. By the early 1960’s, computers had arrived. In a joint effort with Texas Instruments and several oil companies in 1961, GSI introduced the first digital acquisition system (which converted the analog output from geophones into digital data for recording) and computer for seismic-data processing. By 1963, the first digital recording had been made, and in 1964 IBM introduced its 360 series, making digital computers a commercial reality.

Signals detected by sensitive geophones could be read at millisecond intervals and recorded on a data tape. Computer filing, storage, database management and algorithms used to process the raw data all quickly grew more sophisticated. In short, the amount of subsurface seismic information increased dramatically. For the first time, computers allowed geophysicists to model the Earth’s properties with nonlinear characteristics, improving resolution and the ability to locate oil.

Timeline of the Seismic Industry

The Second Wave: 1980 – 2000’s the 3 D Era

By the early 1970’s, the seismic industry had developed a data-processing arsenal that included programs for single and multi-channel processing, deconvolution, velocity filtering, automated statics, velocity analysis, migration, inversion, and noise reduction. While all of these processing/software accomplishments advanced seismic prospecting by an order of magnitude, the primary imaging method still used was 2-D.

The first 3-D seismic survey was shot by Exxon over the Friendswood field near Houston in 1967. In 1972, GSI enlisted the support of six Major oil companies – Chevron, Amoco, Texaco, Mobil, Phillips, and Unocal – for a major research project to evaluate 3-D seismic. The site selected for the experiment was the Bell Lake field in southeastern New Mexico, a structural play with nine producers and several dry holes. The seismic acquisition phase took only about 1 month, but processing the half million input traces required another 2 years. Nonetheless, the project was a defining event in seismic history because the resulting maps confirmed the field’s nine producers, condemned its three dry holes, and revealed several new drilling locations in a mature field.

The commercial development of three-dimensional (3-D) seismic was one of the most important technological breakthroughs in an industry in which profitability is closely tied to innovation and technology. While the concept of 3-D seismic has existed since the earliest days of geophysics, the ability to implement that concept was limited by both the acquisition cost and the computing power necessary to process, display and interpret the data. All that changed in just over one decade, as the 1980’s ushered in the era of 3-D commercial viability.

The Spawning of an Industry

The rise of 3-D seismic to wide commercial acceptance not only allowed the oil and gas industry to discover new reservoirs of hydrocarbons, significantly reduce finding and development costs and lower overall exploratory risk, but also drove 3-D to becoming the new imaging standard in turn created a whole new seismic industry.

The demand for new 3-D equipment and related services created new market opportunities for emerging technology companies in the 1990’s such as Landmark Graphics, GXT, Geoquest and Geco, and PGS. By some investor accounts, demand for 3-D seismic data became so strong that the seismic industry was considered one of, if not the, most exciting subsectors of the oilfield services industry in the mid to late 1990’s. While severe oil price shocks and seismic industry missteps subsequently created a very challenging business environment, I/O believes the seismic industry as a whole may be now positioned to benefit from a multi-year upcycle, driven by both record commodity prices, the changing needs of oil and gas companies, and the emergence of the third era of seismic technology, the Full-Wave Era.

Going forward, a similar evolution in the current seismic sector is expected to occur as geology increasingly pushes into the realm of physics, and full-wave digital becomes the new seismic imaging standard in the years ahead. In addition to the digital equipment available today, new technology-heavy tools will be needed such as new processing algorithms and new interpretation workflows. New software and technology capabilities will be required to manage and effectively utilize the step-function increase in both quantity and complexity of seismic data. Specialized data analysis, interpretive processing and other new services will be provided by I/O and new boutique technology companies alike, some of which have yet to be formed.

I/O’s fundamental vision is to lead this industry change, and capture the early investment opportunities afforded by a first mover advantage.

2005E Industry Revenue – A $7 Billion Sector

The Third Wave: Full-Wave Digital Era Begins

Hallmarks of previous seismic revolutions have provided either dramatic advances in simplifying logistics or extreme improvements in images and data quality, both of which have led to greater economic benefits for the ultimate end-user, the oil and gas exploration and production company. The third seismic revolution – full-wave digital – promises to deliver all three benefits as the industry pushes into the 21^st century.

Section 2 of this Profile explains the industry drivers, benefits and implications of this secular shift now occurring in more detail.

THE SIZE OF THE SEISMIC SECTOR

While only encompassing less than 5% of oil and gas companies’ total worldwide capital expenditures, the global seismic industry in 2005 is expected to reach approximately $6.9 billion in revenues. The bulk of this estimated market (51%) is comprised of marine equipment and services, followed closely (34%) by land equipment and services. Notably, equipment alone is estimated to be $770 million, or 11% of the market, vastly limiting the opportunities of any company focusing solely on the highly-commoditized OEM market.

Comprising the remaining 21% of the global seismic market is the higher margin “processing” segment. Looking forward, I/O believes that it is this sub-segment that will experience the greatest growth and expansion in this new era, driven by the need to understand and economically benefit from the enormous amounts of new and complex data generated by FWD seismic.

It is for this fundamental reason why I/O has pursued a break-out strategy from the rest of the seismic herd, assembling the industry’s first technology-focused full-wave digital seismic solutions company.

			Major Seismic Players at a Glance

		• Has the dominant market share position of analog geophones on land (34%) • Pioneering Full-Wave Era with VectorSeis sensor • Positioning to be the industry’s leading FWD seismic solutions company • Breaking down old OEM paradigm by focusing both on its traditional seismic contractor base and on marketing its technology solution directly to the end-user E&P firms

		• Full-service contractor – both field acquisition and processing • Considered to be highly capable (“good bang for the buck”) in both land and marine acquisition • Strong in advanced imaging – with GXT at the top of the market • Proponent of full-wave technologies • Prefers to integrate technology components developed by others

		• Full-service joint venture contractor owned by Schlumberger and Baker Hughes • Favors proprietary “closed” systems based on internally-developed technologies • Developed the “Q” system, an end-to-end approach to acquisition and processing based on the theroy of high density, highly repeatable surveys • Q-Marine has proven to be successful technically, but oil & gas customers complain about high prices, captive WG-controlled data, and “black box” nature of the approach • Q-Land and Q-Seabed still seeking broad commercial acceptance

		• Rapidly growing Chinese full-service contractor owned by China National Petroleum Company • Fields the largest “fleet” of land crews in the world • Seeking to expand marine acquisition presence, both streamer and seabed • Increasing capital expenditures to outfit / highgrade crews – major customer of both I/O and Sercel • Strong relationships with the national oil companies and, increasingly, with the Western super-majors and super-independents

		• Integrated, full-service seismic firm with an arm’s length equipment business (Sercel) • The acquisition side of CGG has come under pressure in both the land and marine segments, although utilization and financial performance are improving • CGG processing considered to be strong in 4-D and multi-component imaging • Sercel has been delivering record financial performance, drive by the success of the 408 land recording platform and selective in-fill acquisitions

Worldwide Finding & Development Costs (Major Integrated Oils)

Note: Figure based on study group of 12 integrated oil companies using “fully loaded” finding and development costs as defined by Banc of America Securities.

Source: Banc of America Securities; 2004 Operating Trends and Finding Cost Study (April 2005)

2. Defining Full-Wave Digital

INDUSTRY DRIVERS

The surge in worldwide hydrocarbon demand and record commodity prices have intensified the oil and gas industry’s quest to find and develop new supplies. With most of the world’s more obvious reservoirs already discovered and in production, emphasis in the oil field is increasingly focusing on ways to optimize recovery in existing fields and develop new fields as quickly as possible. This, in turn, is driving the seismic industry to provide oil and gas companies with more sophisticated tools. For I/O, this means offering the best FWD seismic solution available to minimize customers’ risk profile.

In general, several industry trends have developed over the last few years which should help drive new seismic activity, both on land and offshore. This activity will not only require more technology content and data per survey, but will also subsequently require the most advanced processing available to maximize this new data’s economic benefit. Chief among these trends:

• New hydrocarbon provinces appear on the brink of reopening with the application of new technology, including Commonwealth of Independent States (former Soviet Union), Libya and Iraq.

• Evidence is building that oil companies are now accepting the need for custom designed surveys that target specific reservoir challenges. Such specificity is well beyond typical multi-client libraries, requiring new data acquisition.

• Many of the remaining reservoir challenges require improved resolution and greater information content to be overcome, data typically not available with current analog 3-D technology.

• Finding & development (F&D) costs have risen dramatically from the late 1990’s. One recent study shows worldwide F&D costs for 12 U.S. and European integrated oil and gas companies (the Majors) to have reached $9.57 per barrel of oil equivalent (BOE), a 36% rise from 2003 and nearly double the 10-year average. In effect, every $100 million the Majors spent in 2004 found 85% fewer barrels than the average found over the last 10-years.

• Higher prices. Forward commodity prices have effectively doubled over the last three years, with 5-year WTI crude oil futures currently approximating $50/bbl and 5-year domestic natural gas prices approximating $6.75/MMbtu.

• As shown below, expected global oil demand is far outstripping increases in supply. Upward commodity pressure is further exacerbated by persistent geopolitical uncertainties in the Middle East and former Soviet Union.

• E&P companies are projected to spend 10%-12% more in 2005 than in 2004, which should translate into increasing seismic expenditures for the industry.

Projected Oil & Gas Demand

Source: McKinsey & Co.

The goal of full-wave digital recording is to measure true seismic ground motion by making use of 100% of the seismic signal.

WHY FULL-WAVE?

To better understand why we believe we are in a fundamental (albeit early) secular shift to adopting full-wave digital throughout the oil and gas industry, investors need to first aware of the constraints of current convention. While there have been significant enhancements to the underlying analog technologies since the 3-D era began nearly 25 years ago, conventional 3-D seismic suffers from several broadly acknowledged limitations, including:

• Conventional sensors are fundamentally based on a mechanical, coil-spring geophone, the technology for which was developed in the 1920’s.

• These sensors capture only a portion of the full seismic bandwidth (frequency in hertz) returned by the Earth, and

• These sensors need to be routinely calibrated and wear over time.

• Single component geophones measure ground motion in a single direction (up and down), even though reflected energy is coming from all directions.

• This means it captures only a portion of the full seismic wavefield, specifically the vertical pressure wave (a.k.a P-wave).

• If the geophone is not placed on its true vertical axis (due to terrain or human error), the resulting P-wave data will be “contaminated,” creating image distortions.

• Current design techniques under-sample the subsurface because of equipment and economic constraints

• Conventional acquisition and processing techniques assume that the Earth is isotropic (homogeneous), an exceptionally broad assumption made to simplify the processing of the data, and because in most cases conventional survey design did not sample the Earth well enough to make an accurate picture of the subtle changes in azimuthally varying velocities in the subsurface.

• Source-generated and other surface “noises” are removed by mechanical filters that introduce averaging which can cause the loss of valuable signal.

While these limitations do not necessarily constrain the utility of the seismic image when looking for large, well-defined structures (the focus of the domestic oil and gas industry up to the mid-1990’s), when the hunt for hydrocarbons extends to deeper and harder-to-image targets, when there is a need to delineate rock and fluid properties within reservoirs, or when specific challenges exist, conventional 3-D seismic is not likely to suffice.

2 Key Benefits of Full-wave Digital

The limitations and assumptions made by conventional 3-D analog geophones obscure the geologic detail of the Earth. FWD imaging, however, overcomes each of these operating shortfalls. While there are many advantages that FWD imaging provides, they can generally be categorized into two key overarching benefits:

1. Superior Image. Even before accounting for the benefits of shear wave data, FWD produces a higher resolution P-wave versus conventional analog 3-D. A better image in turn translates to better understanding; uncertainty risk is reduced and better decisions are made.

2. Improved Operating Efficiencies. FWD is quicker. Lower cycle times will not only benefit individual customers, it is expected to have a profound industry impact on the way seismic dollars are ultimately spent. Approximately 90% of seismic acquisition (and 75% of the full project) is directed to logistics, a highly inefficient use of capital. As efficiencies are gained, I/O believes industry dollars “freed up” will be redirected towards technology, further amplifying FWD’s benefits to the customer and driving further seismic industry growth.

The goal of full-wave recording is to measure true ground motion by making use of 100% of the seismic signal.

The VectorSeis FWD sensor is comprised of three sensor packages in titanium housing.

WHAT IS FULL-WAVE DIGITAL IMAGING?

Made possible by the advancement of computers, microchips and miniaturization, full-wave digital seismic replaces the conventional analog geophone with MEMS (micro-electromechanical system) technology.

Unlike conventional single-component analog devices, these advanced multi-component seismic sensors are able to record the full seismic wave field with high accuracy. The full-wave field consists of both pressure waves (P-waves) and shear waves (S-waves). Both wave types carry important structural and geological information needed to understand the reservoir. By capturing the full-wave field, a more complete image of the geology can be developed.

While multi-component sensors have been around for nearly 20 years, it has only been with the recent advancements in MEMS technology and computer processing power that FWD is now economically ready for “prime-time.”

Some of the requirements to achieve full-wave imaging are:

• Multi-component single-point receivers. Whereas conventional 3-D is recorded with single-component receivers which only capture the vertical portion of the wave field, multi-component receivers can capture all the seismic signal.

• Faithfully record all the frequency content that the Earth returns. Conventional geophones in array configurations can not capture the low frequencies (below 5Hz) or the very high frequency seismic signals. MEMS technology makes it possible to capture all the frequencies that the Earth returns.

• Wide-azimuth survey designs (receivers are set up in square “grid”) to maximize sampling for all data points around the receivers.

• Obtain an unaliased image of the reservoir for both P-wave and S-wave images. Surveys must be carefully designed so that the reservoir can be imaged without gaps or holes.

In short, full-wave can deliver a more accurate geologic picture of the reservoir than conventional seismic acquisition and processing techniques. This allows geophysicists to more confidently identify subtle structural and stratigraphic changes, map fluid locations, and create fracture density maps from the seismic data. FWD is effectively the HDTV of the oil business.

I/O’s VectorSeis FWD Sensor

Fractures, Fractures, Fractures

Fractured reservoirs, especially those that are associated with tight, unconventional gas, are becoming increasingly important sources of hydrocarbons worldwide. Shear waves provide unsurpassed data on identifying fractures, their density and orientation which is often key to maximizing production.

Differences in P-Waves and S-Waves

The Ratio of P-Waves and S-Waves can help identify gas pockets

Superior Image = Superior Decisions

FWD provides an image that has greater resolution, more accurately delineates subsurface structures and gives greater reservoir characterization (such as lithology, reservoir plumbing, fluid type and fluid movement). To better illustrate why FWD can generate such data, we continue to contrast FWD imaging with conventional analog methods, beginning with their geophysical drivers:

• True ground motion is captured by measuring three directions.

By accurately recording the P-wave and the S-wave at the same time with the same sensor, reflected energy can be more accurately mapped to the “right place” in the subsurface. This translates into an economic and geologic benefit.

• FWD can capture and preserve lower and higher frequency data, which translates to greater resolution.

Frequency data is analogous to pixel resolution on a digital camera – the wider the spectrum, the greater the detail, or resolution. Unlike the limitations of a mechanical geophone which typically range between 10-90 hertz (Hz), the digital sensors can record a much greater range of frequencies within the same power band, from a low of approximately 1.5 Hz up to 375 Hz for the purposes of seismic recording.

• High vector fidelity which delivers the ability to accurately determine the direction of energy arrival at the surface.

The full-wave field consists of many wave forms. In seismic imaging we are primarily interested in pressure waves and shear waves. P-waves are compression wave forms where particle motion is parallel to travel direction. S-waves have a similar travel direction as P-waves but the particle motion is perpendicular to the travel direction. Because of the differing particle motion the two wave forms react to the same geology in different manners. Therefore, by capturing both wave forms as they return to the surface, we gain additional insight into geology that the P-wave could not bring alone. Specifically, S-waves can help distinguish between different rock types, determine the type of fluid being imaged with seismic (is it oil or is it gas?) and improve structural imaging through areas that are saturated with natural gas (that P-waves can not effectively penetrate).

Because of these differences in interactions, the ratio between P-waves and S-waves (lower left, top panel) can be used to identify features in the subsurface that traditional P-wave seismic alone would be unable to detect. These differences mean S-waves can help in exploration by better defining drilling targets and estimating reservoir size while, in a production context, they can be used to locate bypassed oil in the reservoir.

While the industry is still in the early stages of utilizing shear wave data, I/O believes it leads the industry in processing and understanding S-wave effects.

One other interesting feature of S-waves is that they can’t travel through a completely elastic medium like water (which does not shear the way a solid would). As a result, traditional towed streamer technology is relegated by physics to be a P-wave only tool. If geoscientists hope to acquire shear wave data, their recording equipment must be on the ocean bottom. In part, the requirement for full-wave imaging becomes a driver of increased seabed acquisition activity as well.

Geophone array relies on mechanical filtering/averaging to remove noise

The unique characteristics of VectorSeis allow field noise to be suppressed in processing

• Better survey designs, utilizing wide azimuth and long offsets.

Driven primarily be recording technology and economic considerations, seismic acquisition has traditionally been executed with an array of geophones in a narrow rectangular pattern. While this grid has widened in many contemporary acquisition programs since the mid 1990’s, the shoe-box design still remains. Due to this narrow design, the industry never really saw or understood the effects of anisotropy (the heterogeneity of the Earth).

Custom Tailored Surveys. A key reason to move away from the shoebox design is to be better able to account for subtle anisotropy (the variation of seismic velocity depending on the direction measured.). Anisotropy is caused by natural fractures along a geologic surface. With the FWD equipment and processing capability now available, we no longer have to assume the layers of the Earth are 100% homogenous. Wide-azimuth acquisition with a signal-point receiver is the only way to accurately measure and solve for the full-wave effect of azimuthally varying velocity. In effect, a more “square” survey design is necessary to ensure optimum data sampling at each FWD sensor, which in turn will generate the most accurate subsurface image.

Better Survey Design – Moving to Wide Azimuth Surveys

Going Deep. Increasingly, domestic oil and gas companies are shifting their focus to deeper and deeper reservoirs. While FWD’s ability to preserve low frequencies greatly improves the resolution of deeper targets, long offsets (survey size) in the design are also needed to yield improved imaging at greater depths. The dimensions of the survey are directly proportional to the depth at which the seismic image is generated. For instance, if a survey design is 10,000 feet by 10,000 foot, data will be generated of the subsurface down to 5,000 feet, but the image will be incomplete. Longer offsets and, ideally, more square survey designs are necessary to generate a true image as target depths increase.

• Better at characterizing and isolating noise

Two seismic sections are shown in gray to the left. The top section shows noise created by ground roll (noise that travels straight from the source to the receiver along the surface) that geophone arrays typically cancel by mathematical averaging in the field. The problem with using the array is that it leads to poor velocity analysis which in turn translates to loss of resolution. Its mechanical noise filtering effectively works by “stacking” or averaging the data across the array, which results in the loss of geologic detail.

Since VectorSeis records the full wavefield, geophysicists can isolate ground roll and other noises in processing by determining their arrival directions and successfully suppress the noise without losing geologic detail. To illustrate the differences, the bottom seismic section (in gray) shows the still raw record after the noise has been removed, now ready for processing.

Perhaps most importantly, by spending the same amount of project dollars, higher quality images come back faster so that better decisions can be taken quicker. This means a higher return on capital employed for our customer.

Improved Efficiencies = Higher Returns

In addition to delivering a superior image to the oil and gas company, the era of full-wave digital also promises a second major benefit: improved logistics and greater operating efficiencies. More specifically, FWD imaging should allow:

• More acquisitions per crew per season

• Less personnel per crew

• Less health, safety and environmental (HSE) exposure; and

• Lower per survey costs

As a result, the full cycle time of seismic will be driven lower, both saving the client time and money while increasing the industry’s overall productivity. The end goal: better image for the same (or lower) total investment.

In a conventional analog 3-D seismic land survey, hundred of arrays are cabled together, and each array typically has anywhere from 6-24 geophones (and can have as much as 128 geophones per array in the Middle East). The average land crew has to consequently deal with over 20,000 geophones translating to over 50 tons of equipment. This can take a crew of 150 people weeks to lay out thousands of cables.

Given the significant amount of equipment required and the extent of the arrays’ footprint, conventional 3-D seismic can also create notable HSE risk, particularly in environmentally sensitive areas such as Alaska and in the Rocky Mountains. Moreover, to maintain its productivity, it is estimated that 40% of field operational time is spent on cable repair and maintenance (due to bad lines, cables chewed on by animals, etc.) after the initial setup.

Given all the crew support that such an endeavor requires, it is no surprise that of the estimated $7 billion global seismic market, as much as 70% goes to logistics support and other low-valued added necessities: labor, food, lodging, hauling, repairing – all factors that are directly tied to the weight of the equipment.

Less equipment is key. Because full-wave imaging uses single-point sensors, there is less gear (and less weight) involved than using complex arrays of geophones. Given that one VectorSeis sensor can replace between 6-24 geophones, what had taken 20,000 units now takes approximately 3,000. That means nearly an order of magnitude drop in the equipment required.

The single-point sensors are also easier to plant and orient and, in the case of VectorSeis, are “self orienting” so they know which way is true vertical – thus the equipment operates as designed regardless of how the sensor is placed. Consequently, not only is there less equipment overall, but that equipment can be placed faster on a per-unit basis.

On the surveys that I/O have been involved with, fewer field personnel are needed to accomplish any given job. Full-wave crews get through more “patch” each season. Less weight and less gear also helps to improve HSE performance. Both of these factors translate into lower per survey costs overall.

Perhaps most importantly, by spending the same amount of project dollars, higher quality images come back faster so that better decisions can be taken quicker. All of this means a higher return on capital employed for the oil and gas company customers.

As it did from the 2-D Era to the 3-D Era, I/O believes it is feasible that the processing market could double once again in the Full-Wave Digital Era as low value-add logistics dollars are “freed up” and redirected to higher value operations.

The Magnification Effect of Reduced Cycle Times

Given the stark logistical contrast to conventional 3-D surveys, the era of full-wave digital promises to fundamentally change the way investment dollars in the seismic industry are spent.

Tremendously Inefficient. In tracking how the billions of seismic dollars were allocated in 2004, the vast majority were inefficiently spent in the deployment of equipment in the field. As illustrated below, an average land survey costs approximately $2.7 million and takes 280 days, or approximately nine months, to travel the full cycle from planning through interpretation (delivery). Greater than 80% of this cost lies in the planning and acquisition phase. Of this amount, effectively 90% is directed towards logistics, which translates to 70%-75% of an oil and gas company’s seismic project dollar is consumed by low value-add logistics. Only approximately 20% of seismic dollars invested actually goes to the processing and interpretation technology that create the image.

Breaking Down the Cycle – an Average Land Survey

The best way to convert inefficient logistics dollars is to use technology to make field crews more productive. If more technology can be used in the field to increase productivity, the cycle time for the entire seismic solution – from acquisition to processing – will be reduced, providing greater economic benefit. In time, I/O believes that total logistics costs can be driven down by an order of magnitude. In shifting to single-point receivers, I/O has already witnessed a 30% improvement in crew efficiency to date. As FWD becomes increasingly embraced, future industry innovations are likely to drive crew efficiencies even further.

As a result of this greater savings, dollars that are “freed up” from low value-add logistics will likely be redirected to the highest value-add technology. This important shift means the ability to drive down cycle times could have an enormously positive affect on the dollars spent towards processing. Indeed, the relative market for processing (as a percent of total seismic dollars) more than doubled from the 2-D Era to the 3-D Era. Given the step-function increase in the amount of data, the complexities involved and the reservoir challenges being addressed, I/O believes it is feasible that the relative processing market could double once again in the Full-Wave Digital Era. I/O has already witnessed specific examples of a seismic project where the total dollars spent on processing, reprocessing and interpretation outweighed the acquisition costs.

3. VectorSeis on Land & Sea

WHY VECTORSEIS?

Simply put, I/O’s VectorSeis is the industry’s most advanced and reliable digital receiver. The Company estimates that of all full-wave surveys done to date, 70% have been executed by VectorSeis systems.

To briefly summarize, VectorSeis provides all the benefits of full-wave digital imaging with industry leading technology. More specifically, VectorSeis gives:

• Enhanced P-wave Imaging

• Extremely accurate measurements of all ground motion and noise

• Ideal for recording velocity variations due to anisotropy

• Broad bandwidth, enhanced resolution

• Shear-wave imaging

• Joint use of P-wave and S-wave data to reduce uncertainty

• Better reservoir characterization; lithology/fluid prediction

• Fracture detection and mapping

• Improved Operational Efficiency

• Less equipment (weight and bulk) to deploy and transport; crews plant 1 sensor per station versus 6 to as many as 128 geophones in an array.

• Less field effort, manpower and associated HSE exposure

• VectorSeis can sense gravity, and is “self-orienting” to vertical (whereas geophones require the crews to ensure proper vertical alignment) – a key factor both onshore and especially in seabed acquisition.

• VectorSeis attaches to a purpose-built, full-wave recording platform with latest spread monitoring and troubleshooting features. As a land-based package, this product is known as “System Four.”

ON LAND OR AT SEA

In addition to its land based seismic applications, I/O is also one of the leaders in designing, manufacturing and servicing seismic imaging systems for both towed streamer and seabed acquisition, the latter of which can utilize full-wave digital.

Currently, streamer vessels are still the acquisition vehicle of choice for large, coarse surveys conducted over wide swaths of the ocean. However, oil and gas companies are increasingly showing a preference for data collected on the seabed in order to get an improved image – a preference that intensifies as major capital investment decisions get made during appraisal and field development.

Same Benefit; Different Deployment. While much has been discussed about the benefits of adopting full-wave digital on land surveys, the same benefits can also be directly applied to the marine environment. As S-waves do not travel through water, full-wave digital in the marine market can only be acquired through ocean-bottom cable (OBC) systems. Notably, OBC systems could become particularly large given the rise of 4-D seismic applications and the growing demand for precision and repeatability as oil and gas companies acknowledge that every 3-D survey may become the baseline for a future 4-D program.

“Investment of $35M in 4-D on Valhall is expected to return $600M in enhanced production and other benefits over the remaining life of the field.”

- BP

“4-D has delivered $500M of additional production in Gulfaks since inception in the 1990’s.”

- Statoil

VectorSeis Ocean (VSO). In 2004, I/O introduced VectorSeis Ocean, a breakthrough system for redeployable ocean-bottom seismic acquisition. VectorSeis Ocean integrates several proprietary I/O technologies including VectorSeis digital full-wave sensors, a buoyed recorder, and a patented noise-reducing cable system.

VSO supports cost-effective, full-wave data acquisition from the seabed by eliminating the mechanical challenges imposed by geophone-based gimbals used in other analog-based OBC systems. VectorSeis Ocean is purpose-built to ensure high fidelity recording of the full-wavefield achieving the cleanest and highest resolution P-wave and S-wave data possible. Moreover, an additional competitive benefit is that the buoyed recorder captures seismic data at the ocean’s surface, increasing system availability and reducing the costs of data retrieval compared to systems that require remote operated vehicles (ROVs) to access the data recorders on the seabed. I/O’s noise-reducing cable improves the quality of the acquired seismic data, enhancing image quality for the oil companies, while the cable’s spoolable design speeds deployment and retrieval compared to competing OBC systems and allows more cable to be deployed from smaller vessels.

VectorSeis Ocean (VSO)

Another significant driver of seabed imaging is expected to be the application of permanent monitoring 4-D. Permanently installed seismic systems deliver the benefits of shear wave capture from a lower noise environment, improved position certainty when repeating seismic shoots, and reduced survey-to-survey acquisition costs. Indeed, while 4-D has previously been considered a niche technology, the reality is that over the last three years there has been a growing body of very positive evidence and experience that suggests 4-D OBC systems are now on the verge of becoming a critical application in the reservoir management toolkit.

The main market obstacle facing OBC in general is that, depending on location, it can be several times more expensive than towed streamer acquisition, so OBC has been limited in its early applications. However, a number of efforts are underway to reduce both the capital costs as well as the costs to deploy and operate OBC systems. As economies of scale and better logistics take hold, it is estimated that within the next five years retrievable OBC systems should become much more cost competitive before accounting for the benefits of full-wave.

VectorSeis Early Adopters

Russia:

• TNK-BP

• Gazprom

• Lukoil

• Tatneft

• Bashneft

• Ministry of Natural Resources

Canada:

• Apache

• ConocoPhillips

• Encana

• MEG Energy

• Devon

• Nexen

China:

• Sinopec

• Southwest Gas

United States:

• Anadarko

• Apache

• ChevronTexaco

• Colorado School of Mines

• Samson

• Devon

Europe, Africa, India:

• POGC

• ONGC

GOING GLOBAL – BENEFITS SEEN AROUND THE WORLD

VectorSeis is a tool that improves image quality in most seismic acquisition environments. However, it finds special application in imaging situations where conventional 3-D is challenged. As discussed, this includes complex velocity modeling, in areas of heavy surface noise and when better reservoir characterization is needed. Velocity models are especially difficult to develop in arctic and desert environments given changes to the seismic ray paths as they travel through near surface layers. Since a large portion of the world’s hydrocarbon base are located in arctic and desert regions, VectorSeis should find significant application in areas like Russia, Canada and the Middle East.

VectorSeis has already been used around the world. Major geographic locations and clients are shown left, while listed below are the key reasons full-wave digital was chosen:

• Greater productivity associated with Single Point Receiver

• Imaging gas-filled reefs and imaging through natural gas

• Identifying fractures and fracturing analysis (especially carbonates and sands)

• High resolution P-wave

• Testing shear-wave transmission in area of interest

• Heavy Oil Plays (replacing stratigraphic wells with seismic for information)

• Deep structural plays (low frequency necessary for imaging)

• Backscattered noise removal with Vector Filtering

While initial logistics challenges have arisen from time to time in implementing its new technology, the data results and customer response that I/O has received to date have been extremely positive.

EARLY FEEDBACK ON FULL-WAVE DIGITAL TECHNOLOGY

“After you guys reprocessed the data and mapped the fracture networks using AZIM, we drilled our most productive well ever in this [25 year old] field.”

- Asset Team Geophysicist, BP Alaska

“This is the best data I’ve ever seen from Canada. VectorSeis delivered.”

- Steve Farris, President and CEO, Apache Corporation

“We’re getting some great pictures of the reservoir. VectorSeis Ocean and full-wave imaging are letting us see through the gas clouds and pinpoint drilling targets along the salt flank.”

- Asset Team Geophysicist, Super-Major

“By using System Four and VectorSeis, we deployed the largest number of live channels in the history of seismic land acquisition.”

- Senior Operations Advisor, BGP Inc.

With terrain like this, VectorSeis’ insensitivity to tilt is a major competitive advantage.

COMPETITIVE POSITION – HOW VECTORSEIS STACKS UP

In order to meet the demands of full-wave digital imaging, a customer would need reliable recording systems capable of high channel count acquisitions – like I/O’s System Four – and very accurate digital multi-component receivers – like VectorSeis. In fact, when using the strictest requirements, only I/O has the full range of equipment and software necessary to provide the purest full-wave digital image.

While the overall competitive landscape has shifted greatly over the last several years due to mergers, bankruptcies, new technologies and evolving strategies, the competitive comparison below is only directed at the emerging FWD segment. To date, at least two other major competitors provide products that are either similar to I/O’s FWD or represent other high-resolution methods that go beyond conventional 3-D seismic:

• I/O’s primary competitor is the contractor Compagnie Generale de Geophysique (CGG) and its wholly-owned OEM subsidiary, Sercel. Sercel provides the “408” recording system and the digital sensing unit (DSU). This combination is analogous to I/O’s System Four recording system and its VectorSeis digital sensor.

• The contractor WesternGeco, a subsidiary of Schlumberger. WesternGeco offers the proprietary Q-System, which is based on internal technologies developed at Schlumberger. Western is the only contractor that is allowed to use Q and no other contractor is allowed to buy.

Schlumberger’s Q technology was commercialized in 2001 when WesternGeco brought Q-Marine to market. The company subsequently developed Q-Land and Q-Seabed. This is a closed, proprietary system that is WesternGeco’s answer to the increasing need for higher signal fidelity, wider bandwidth, better noise reduction and in the case of marine, more accuracy in streamer positioning and repeatability. Both Q-Land and Q-Seabed are based on the promise of high density recording. However, they do not utilize digital MEMS based three-component sensors. Principally for this reason, the comparison and contrast is mainly with I/O’s principal full-wave digital competitor, Sercel.

VectorSeis versus DSU

On the surface, these two sensors appear similar inasmuch as both are multi-component, single-point receivers, that use MEMS technology to record data. Beyond this surface comparison, however, there are many geophysical and operationally significant differences between the two that should provide I/O a competitive advantage as the Full-Wave Era develops.

The most notable differences:

• Works at Any Angle. Unlike Sercel’s DSU, VectorSeis was designed to measure gravity for operational checks, module tilt angle measurements and tilt change measurements between shots. This means:

• VectorSeis can be deployed at any angle and compensate to true vertical orientation.

• Data quality is not affected by deployment methods as there is no degradation of dynamic range with any degree of tilt with VectorSeis.

• In contrast, Sercel’s MEMS have a low tolerance to tilt, and dynamic range and vector fidelity degrade rapidly until ceasing to function once tilted beyond 27 degrees from vertical.

• VectorSeis sensors can thus be deployed and moved rapidly in the field with fewer people.

In one case study with its largest FWD competitor, I/O’s System Four with VectorSeis was 27% more efficient.

• Ensures Accurate Measurements. VectorSeis has three identical MEMS to ensure equal measurements on all axes. Key benefits:

• VectorSeis provides accurate data for single trace noise removal.

• VectorSeis provides accurate P-wave and shear wave recording.

• In contrast, Sercel’s DSU has two different styles of accelerometers. One type of MEM is used to measure the P-wave and a second type is used to measure the S-wave. Consequently, Sercel cannot ensure equal measurements on the axes.

• Superior Case Design. The VectorSeis MEMS are mounted orthogonally on an aluminum block and the case is designed to make burial of the sensor possible. Key benefits include:

• The VectorSeis mounting provides isolation of the MEMS to limit signal contamination across the three sensors and prevents the three sensors from moving relative to each other.

• Burying the VectorSeis case provides superior coupling for all three sensors with the ground (which helps ensure accurate signal detection for P-wave and S-wave), while providing better insulation from wind and surface noise.

• In contrast, the DSU MEMS are located in different parts of the module. If there is distortion in the case (for instance, caused by temperature changes in a desert or arctic acquisition environment), the sensors can move relative to each other which destroys recording accuracy. Additionally, the two S-wave MEMS sensors are located at the top of the case above the surface. This means there is poor contact between the shear sensors and the ground which can lead to poor data quality, and the shear data is more likely to be contaminated with surface noise.

• Superior System & Cable Design. VectorSeis modules are not directly attached to the line cable. Benefits of this include:

• Faster replacement of damaged line cables (no need to pull sensors out of the ground to replace cable)

• Better data quality as sensors are isolated from line transmitted noise.

• In contrast, DSU modules are tightly integrated into the line cable; thus:

• Sensors must be pulled up and re-deployed every time a line cable needs to be changed which slows the repair process.

• DSU must be leveled every time it is re-deployed.

• Data quality is affected because DSU records line noise, and ground coupling can be damaged if sensors are moved frequently.

A Critical Competitive Advantage: Efficiency. In one case study involving I/O’s System Four VectorSeis and CGG/Sercel’s 408/DSU combination, I/O’s System Four was 27% more efficient when measured in shots per project day. Both surveys were similar in size and acquired within “radio distance” at the same time, and both crews were dealing with the same weather conditions. The results were compelling:

• System Four achieved materially higher productivity;

• System Four could pinpoint any breaks in the system instantly;

• System Four helped crews achieve faster operations with a shorter learning curve given its intuitive Windows® interface; and

Full-wave digital is not just about a acquiring shear wave data, it is about acquiring a superior P-wave image and driving down full cycle times to reach one end goal: increase our customer’s return on capital employed.

Changing the Mindset

In order to accelerate the move up the “S-curve,” market education will be critical, both in what is possible today and what could be tomorrow. A key milestone involves developing detailed real-world examples of customers who have benefited from full-wave digital. One place to start is by clarifying and correcting several common misperceptions around FWD. Detailed below are some of the most common misunderstandings corrected by the current reality.

Common Misperceptions of FWD:

• Geophone arrays are needed to remove noise;

• Full-wave imaging requires multi-component processing; and

• Acquisition technology isn’t important; processing can extract all the relevant signal that is needed for a high quality image.

Reality of FWD:

• Single-point sensors + vector filtering are robust noise “removers”;

• Full-wave acquisition can deliver significantly enhanced “P-wave” data (along with shear wave data, which can be processed or “inventoried” for use at a later date); and

• If the surveys aren’t planned right and old technologies are used, relying on reprocessing will not be able to deliver an accurate image from a poor source.

Why the Disconnection?

• Most geophysicists are trained and experienced in legacy technologies (we estimate less than 5% have any relevant experience with FWD imaging);

• When full-wave came out (as multi-component) more than a decade ago, the acquisition / processing techniques were immature and many of the early surveys done in the industry evolved into high-cost “science projects.”

To capture the full benefits of full-wave imaging, geophysicists will need to reset their fundamental beliefs about the technologies and techniques used in seismic survey planning, sensor technology, data measurement, field acquisition methods, and processing. Just as the start of the 3-D era involved a revolution in the industry’s collective mindset, the start of the Full-Wave Era will involve another collective mindset shift.

Shown below are the assumptions that underpinned the 3-D era almost from the beginning, with little change in the belief system even as computing and other technologies evolved. The Full-Wave Era, by contrast, challenges almost every one of these beliefs. Given the amount of changes required in all areas – from survey planning through the sensor, the type of data that is measured and how it is processed – a true revolution in how this industry will operate is now underway.

Educating the Market to a Better Alternative

Conventional 3D		Full-Wave Era
• Narrow offsets / “shoebox” geometry		• Long offsets / 1.2:1 “square” geometry
• Modest station density		• High station density
• Analog arrays of geophones		• Digital, single-point recording sensors
• Particle motion measured in only one direction		• Particle motion measured in 3 directions (vector fidelity)
• Partial wavefield acquisition (p only)		• Full wavefield acquisition (p + shear + surface waves)
• Near-surface effects are an enemy		• Near-surface effects are information sources
• Field mechanical filtering for noise attenuation		• Mathematical filtering for noise attenuation
• Velocity assumed constant with azimuth		• Velocity assumed variable with azimuth
• Image in time		• Image in depth

“Full-wave imaging is now a tractable technology, and represents the best path forward in geophysics over the next decade.”

Technical Team Lead, Subsurface Imaging, ExxonMobil

“Digital, single-point sensors hold the greatest promise for delivering the improved image quality the industry needs. Geophone arrays are still cheaper, but they are unlikely to deliver as good an image.”

Director, Seismic Operations, TNK-BP

A New Era Underway

Evidence is building that companies are now starting to realize the long term potential of full-wave digital imaging. In addition to positive subjective feedback the Company has received from both its own customers and other oil and gas companies testing the merits of FWD, tangible progress was made towards greater market adoption in 2004, including:

• Full-wave market research shows spending rose more than five-fold to $36.9 million in 2004 versus $7.2 million in 2003. Moreover, in first quarter 2005, full-wave spending was estimated at approximately $21 million, and I/O believes that 2005 levels for the industry should be double that of 2004.

• There was a near 70% increase in FWD surveys performed in 2004, or approximately 40 surveys compared to 24 surveys in 2003. With 16 surveys executed in the first quarter of 2005, the total survey count this year is also expected to double over 2004.

• Companies have begun to move from 2-D FWD tests to more robust 3-D FWD surveys, with 3-D surveys up four-fold in 2004

• 38 oil companies have now acquired full-wave surveys to date

• 11 of those companies used full-wave repeatedly in 2004

• With the addition of two new contractors in 2005, ten worldwide contractors now have VectorSeis capabilities. The recent domestic addition was also notable as the Company has generated more full-wave demand than the previous single North American contractor could cover.

• I/O estimates that 70% of all full-wave digital surveys done have been performed by VectorSeis, giving the Company a leading market share position early-on.

FWD’s Sweet Spot: Regions that are Under-explored and Overdeveloped. Early adoption of FWD is mainly occurring in the international arena, most notably in Russia, China, India, North Africa, and the U.S. Gulf of Mexico. The Middle East, mainly Algeria, Libya and Iraq, are not likely to be far behind.

In North America, the oil and gas industry has turned its focus towards optimizing development of mature basins. As customers look to extend reservoir life and identify oil that has been left behind, the data requirements necessary to achieve such a task becomes far more demanding.

Looking forward, I/O believes that a large number of reservoirs will eventually be re-shot with full-wave digital technology. This will be driven both by identifying new sources of hydrocarbons in deeper horizons – such as in the deep shelf Gulf of Mexico where the current oversupply of analog 3-D barely scratches the surface of zones deeper than 15,000 feet – to maximizing production and better managing mature reservoirs.

Getting the most out of FWD. A major advantage to FWD is the ability to capture shear wave data. The industry’s ability to process and interpret that data to its fullest is still in its early stages. The rate of adoption of FWD will be directly impacted by the industry’s collective success in processing the new data, in particular shear waves. As the industry’s ability to process and interpret full-wave data grows, there will be a spill-over effect to the equipment manufactures and contractors for even more FWD surveys.

Shear wave data already provides valuable insight today, and no doubt as the industry’s understanding evolves, FWD market penetration will be driven further. In fact, it is possible that over the next five years, S-wave processing will likely represent a major new sub-segment of seismic processing, beginning with:

• Today: The primary use of S-waves currently is to help generate image of nature gas clouds and importantly, hidden reservoirs beneath gas clouds;

• Tomorrow: Companies will increasingly use S-waves to identify fractures and create high resolution maps of the reservoir’s “plumbing” in order to maximize production; and

• Next Year: A key evolution of S-wave processing will be the eventual application of pre-stack depth migration (PSDM), or converting the velocity of reflected sound to depth measurements. Once both P-wave and S-wave data can be concurrently processed with respect to depth (and anisotropy), an even higher resolution image will be created.

FWD Market Today and 2009

The development of the Full-wave Era will likely be marked along a sliding scale of increasing technical capabilities rather than in a few discrete “Eureka” moments. The important point, however, is that despite a few false starts over the last ten years, we believe the Full-wave Era has now truly dawned.

In order to better track market acceptance and adoption, I/O has developed a metric termed the “geophone station count” (GSC), a measure of industry activity which is somewhat analogous to passenger seat miles used in the airline industry – a relative reference for utilization, growth and market share. The industry GSC is simply the number of crews employed in the industry multiplied by the number of stations each crew can deploy times the average number of surveys a crew can perform in one year. This can be further split by an estimated percentage of how much work is analog versus full-wave digital.

Shown below are GSC metrics for land acquisition as estimated for 2005 and 2009. Importantly, this is not meant to convey the market to a known degree of certainty as much as it is to illustrate the potential market size, growth and expected activity shift flow analog to FWD over the next five years.

Introducing the Geophone Station Count “GSC”

(Land Market Only)

	2005		2009		% Growth

# Crews employed	300		350		17	%
# Stations/crew	1,500		5,000		233	%
# Surveys/crew/year	5		8		60	%
GSC	2,250,000		14,000,000		522	%
% Analog Mix	90	%	50	%	(44	)%
% FWD Mix	10	%	50	%	400	%

Full-Wave GSC	225,000		7,000,000		3,000	%

The critical drivers over the next five years will be the ability to reduce full cycle times in the seismic chain, and oil and gas companies desire to increase station count to achieve the best image possible. While it first may appear aggressive for the number of stations deployed per crew to rise to 5,000 from 1,500, we would note that at the end of 2004 a major Chinese contractor deployed in one acquisition over 18,000 channels, or approximately 6,000 stations in this multi-component system. Such a trend towards a higher count for better resolution is only expected to increase, a belief underscored by several leading oil company geophysicists.

Estimated Share of Land Acquisition using Digital Multi-Component Accelerometers

I/O estimates that the FWD technology market will likely approximates $350-$400 million in annual revenues by 2009.

Driven by greater efficiencies and oil and gas companies need for better data, I/O believes that the industry will be deploying six times as many station-equivalents over the next 5 years. When taking into consideration the expected shift in mix to full-wave, the amount of full-wave technology in use on land could increase by a factor of 31x. While a much smaller market, these figures do not include the upside generated from greater adoption of full-wave OBC seabed systems as well.

Expected Growth in Redeployable OBC Market

Looking shorter term over the next two to three years, market research focused on the up-take of FWD suggests the market share of land acquisition using digital multi-component sensors could double from approximately 13% in 2004 to nearly 25% by 2007. Potentially growing even faster than land might be the adoption of FWD in the seabed market, driven by increasing use of 4-D seismic. Although a smaller market in total, positive experience in the marine environment could in turn drive knowledge and demand for FWD land systems.

Can you Imagine?

A New Industry? I/O estimates that the FWD technology market will likely approximate $350-$400 million in annual revenues within five years. However, the Full-Wave Era goes far beyond the deployment of better equipment, including how surveys are designed, how the data is acquired, and most importantly, how the data is processed and interpreted. Like the secular shift from 2-D to 3-D, the shift from 3-D to full-wave 3-D/4-D is expected to fundamentally change the seismic landscape over the next five years. Imagine:

• A seismic industry where FWD will be the standard and many reservoirs will eventually be re-shot

• An order of magnitude improvement in data quality

• An order of magnitude lower in logistics costs

• Lower full-cycle project timelines that ultimately will reach a real time acquisition-to-processing product.

• Creation of a new realm of processing, algorithms and software design

• Creation of an entirely new set of interpretation workstations for the customer

• Creation of a new wave of digital products and technology that are only now being sketched on the drawing board

• The potential birth of new companies and industry sub-segments to serve the unique products and technology demands that will emerge

No where is this change embraced more fully than at Input/Output.

5. The New Input/Output

A NEW COMPANY FOR A NEW ERA

If you believe in the new seismic era of Full-Wave Digital, then we encourage you to take a closer look at I/O.

In 2003, we decided to “break from the herd”, believing the structure of the seismic industry to have been effectively broken. While the recent strength in oil and gas prices has prompted an overall increase in the level of seismic demand, over the last five years this industry has experienced severe work force reductions, mothballing of equipment, curtailment in capital spending, collapsing margins and financial distress (ranging from write-downs to bankruptcy). Given these challenges, maturing analog 3-D technologies and excess spec data inventory, the old paradigm needed to change. In 2003, with new management at the helm, I/O set out to change its course. The course was cemented with the ongoing development and commercialization of VectorSeis, and the subsequent acquisition of Concept Systems and GX Technology in 2004.

Concept Systems. Acquired in February 2004, Concept Systems Limited is a 21 year-old company based in Edinburgh, Scotland. CSL has 85 employees whose backgrounds span key disciplines such as geoscience, engineering, applied mathematics, and computer science. The inclusion of professionals with mathematics and computational science training reflects CSL’s original mission to provide advanced navigation solutions to operators of marine streamer vessels in a pre-GPS (global positioning system) world. With this foundation, CSL went on to develop the software and services to help streamer vessel operators acquire, quality control, and integrate data from all the disparate subsystems of streamer seismic in a highly reliable, cost-effective manner. The CSL software platform effectively acts as the “auto-pilot” for the entire 4-D marine operation.

Apart from having a leading market position in its expertise, one of the longer term strategic elements of acquiring CSL is its application to our other areas of seismic. The Company has already begun efforts in the streamer, seabed, and land segments to imbed key features of Concept Systems software into our acquisition platforms. I/O believes this tight integration between software and hardware will extend the functionality and appeal of our offerings in the marketplace. The analogy here is similar to the tight relationships that existed between Microsoft, Intel, and Compaq as the PC market took off in the late 1980’s and early 1990’s. All players were effectively open standards companies. But their tight alignment allowed them to develop products with additional functionality, which operated in a more seamless way, and which could be delivered more rapidly to the market than their competitors.

GX Technology. Acquired in June 2004, GXT is a 16 year-old company based in Houston, Texas. GXT has more than 150 full-time employees, many of whom are advanced degree holders in geophysics, supplemented by a team of technical contractors. Providing advanced depth imaging services to oil & gas companies operating in the Gulf of Mexico, GXT has become a leader in a realm of data processing known as pre-stack depth migration (PreSDM).

PreSDM is used to image complex subsurface structures by mapping reflected seismic energy into their right location in the subsurface. The technique involves building computationally-intensive complex velocity models that convert the reflected travel time of seismic waves to depth, and involves substantial expert intervention and iteration to perform properly.

Transformation Underway. By completing the acquisitions of Concept Systems and GX Technology, I/O has purposefully moved beyond its 35-year legacy as an OEM provider to the global seismic contracting industry. I/O is no longer an equipment manufacturer selling only hardware to the seismic acquisition contractors. Rather, I/O has become the industry’s leading technology-focused seismic solutions company positioned to address the most difficult geophysical challenges found worldwide.

To take full advantage of this market evolution, four main anchor points underscore the Company’s long term strategy. These include:

• Lead the emerging 3^rd wave of seismic technology (FWD adoption)

• Provide the full range of seismic imaging solutions, from planning to acquisition to processing to interpretation

• Reduce E&P companies’ full-cycle seismic imaging costs and time

• Form closer, more direct relationships with oil and gas companies, as they are the ones with the problem and the ultimate seismic end-user.

Looking Forward: Where can FWD Take Us?

Near term, I/O recognizes the tremendous cyclicality of the seismic industry, and in particular the volatility that frustrates many investors on a quarter-to-quarter basis. Even now in 2005, I/O’s earnings and financial performance are sometimes misconstrued as the Company not participating on the current rebound in the seismic industry. In truth, the performance improvement in the Company’s OEM legacy business has been partially obscured by the necessary strategic and R&D investment into FWD. I/O is in effect, strategically sacrificing near term gains for an enduring and greater benefit. As in any investment decision, the proof will be in long term performance.

Our future is full-wave. Once the shift in investment mindset is made to the long term, we believe the Company’s growth picture becomes far clearer, driven by the market evolution currently underway. Indeed, I/O believes that total revenues in five years (fiscal 2009) could be triple the levels recorded in calendar 2004 driven by the sale of FWD technology, and more importantly, the demand for new services (such as processing and interpretation) that goes with it. While the implementation of disruptive technologies rarely make for a smooth progression, the revenue objective in 2009 is between $750-$850 million. Achievement of such levels would translate to 5-year compound average annual revenue growth of between 25%-28%. From effectively 100% in 2002, revenues associated with I/O’s legacy businesses are expected to contribute less than 30% by 2009.

I/O Revenue Growth: the 5-Year Plan

* 2005E based on midpoint of Company guidance

6. Glossary of Select Seismic Terms

2-D Seismic Data: A vertical section of seismic data consisting of numerous adjacent traces acquired sequentially.

3-D Seismic Data: A set of numerous closely-spaced seismic lines that provide a high spatially sampled measure of subsurface reflectivity. Typical receiver line spacing can range from 80 m to over 600 m, and typical distances between shotpoints and receiver groups is 25 m (offshore and internationally) and 34 m to 67 m (onshore USA). The resultant data set can be “cut” in any direction but still display a well sampled seismic section. Computer-based interpretation and display of 3-D seismic data allow for more thorough analysis than 2-D seismic data.

4-D Seismic Data: 3-D seismic data acquired at different times (time-lapse) over the same area to assess changes in a producing hydrocarbon reservoir with time. Changes may be observed in fluid location and saturation, pressure and temperature.

Accelerometer: A device used during surveying to detect ground acceleration in the Earth’s surface produced by acoustic (seismic) vibrations.

Acquisition: The generation and recording of seismic data.

Aliasing: The distortion of frequency introduced by inadequately sampling a signal, which results in ambiguity between signal and noise. An unaliased image is an undistorted image provided by a robust sampling.

Anisotropy: Predictable variation of a property of a material with the direction in which it is measured, which can occur at all scales. In rocks, variation in seismic velocity measured parallel or perpendicular to bedding surfaces is a form of anisotropy (non-uniformity).

Array: A geometrical arrangement of seismic sources (a source array, with each individual source being activated in some fixed sequence in time) or receivers (a geophone array) that is recorded by one channel.

Attenuate: The removal of undesirable features, such as multiple events, from seismic data.

Azimuth: The compass direction of a directional survey. The azimuth is usually specified in degrees with respect to the geographic or magnetic north pole The angle that characterizes a direction or vector relative to a reference direction (usually True North) on a horizontal plane.

Backscatter: A reflection phenomenon of energy in which a non-reflective surface, which is a surface that does not reflect energy coherently, randomly scatters energy.

Bright Spot: A seismic amplitude anomaly or high amplitude that can indicate the presence of hydrocarbons. Bright spots result from large changes in acoustic impedance and tuning effects, such as when a gas sand underlies a shale, but can also be caused by phenomena other than the presence of hydrocarbons, such as a change in lithology. The term is often used synonymously with hydrocarbon indicator.

Deconvolution: A step in seismic signal processing to recover high frequencies, attenuate multiples, equalize amplitudes, produce a zero-phase wavelet or for other purposes that generally affect the waveshape. Deconvolution, or inverse filtering, can improve seismic data that were adversely affected by filtering, or convolution that occurs naturally as seismic energy is filtered by the Earth.

Full-Wave Digital (FWD) Imaging: A seismic survey where single-point multi-component MEMS based sensors are deployed in a wide-azimuth design to record the full seismic wave field with high accuracy, the maximum frequency bandwidth and the long off-set information is captured and processed. Enough equipment must be used in order to ensure that the reservoir image is unaliased.

Geophone: A device used in surface seismic acquisition, both onshore and on the seabed, that detects ground velocity produced by seismic waves and transforms the motion into electrical impulses. Geophones detect motion in only one direction. Conventional seismic surveys on land use an array of geophones per receiver location to detect motion in the vertical direction.

Geophysics: The study of the physics of the Earth, especially its electrical, gravitational and magnetic fields and propagation of elastic (seismic) waves within it. Geophysics plays a critical role in the petroleum industry because geophysical data are used by exploration and development personnel to make predictions about the presence, nature and size of subsurface hydrocarbon accumulations.

Ground Roll: A type of coherent noise generated by a surface wave, typically a low-velocity, low-frequency, high-amplitude Rayleigh wave. Ground roll can obscure signal and degrade overall data quality.

Hertz (Hz): The unit of measurement of frequency, equivalent to one cycle per second. The unit is named after German physicist Heinrich Hertz (1857 to 1894), who discovered electromagnetic waves.

Image: The apparent source of a received wave. The image is the point in the subsurface that the rays would appear to have come from if they were not reflected, but were shot up from below.

Interpretation: Analysis of data to generate reasonable models and predictions about the properties and structures of the subsurface. Interpretation of seismic data is the primary concern of geophysicists.

Isotropy: A quality of directional uniformity in material such that physical properties do not vary in different directions.

Lithology: The macroscopic nature of the mineral content, grain size, texture and color of rocks.

MEMS: acronym standing for micro-electromechanical system. A form of accelerometers.

Multi-component: Sensors with the ability to capture seismic signals in all three dimensions rather than just one. As more data is recorded, the chances of determining where the reflected energy came from in the subsurface is improved, and a more accurate image can be developed.

Noise: Anything other than desired signal. Cultural noise is that generated by human activity, such as automobile traffic that interferes with seismic surveying, or electrical power lines or the steel in pipelines that can adversely affect electromagnetic methods.

Offset: The horizontal displacement between points on either side of a fault, which can range from millimeters to kilometers.

Pressure Wave (P-wave): A compression wave also known as a primary wave, a P-wave is a seismic wave that pushes and pulls rocks, contracting and expanding them as it moves through them.

Pre-Stack Depth Migration (PreSDM): The process of transforming seismic data from a scale of time (the domain in which they are acquired) to a scale of depth to provide a picture of the structure of the subsurface independent of velocity. Depth conversion, ideally, is an iterative process that begins with proper seismic processing, seismic velocity analysis and study of well data to refine the conversion.

Pre-Stack Time Migration (PreSTM): A migration technique for processing seismic data in areas where lateral velocity changes are not too severe, but structures are complex. Time migration has the effect of moving dipping events on a surface seismic line from apparent locations to their true locations in time. The resulting image is shown in terms of travel-time rather than depth, and must then be converted to depth (PSDM) with an accurate velocity model to be compared to well logs.

Processing: Alteration of seismic data to suppress noise, enhance signal and migrate seismic events to the appropriate location in space. Processing steps typically include analysis of velocities and frequencies, static corrections, deconvolution, normal moveout, dip moveout, stacking, and migration, which can be performed before or after stacking. Seismic processing facilitates better interpretation because subsurface structures and reflection geometries are more apparent.

Resolution: The ability to distinguish between separate points or objects, such as sedimentary sequences in a seismic section. High frequency and short wavelengths provide better vertical and lateral resolution. Seismic processing can greatly affect resolution: deconvolution can improve vertical resolution by producing a broad bandwidth with high frequencies and a relatively compressed wavelet.

Seismic: Pertaining to waves of elastic energy, such as that transmitted by P-waves and S-waves. Seismic energy is studied by scientists to interpret the composition, fluid content, extent and geometry of rocks in the subsurface.

Seismic Wave: Wave of energy that travels through the Earth as a result of seismic activity.

Seismograph: An instrument that measures and records vibrations within the Earth and of the ground.

Shear Wave (S-wave): Also known as converted wave and transverse, a shear wave is a seismic wave that moves rocks from side to side as it moves through them.

Stack: A processed seismic record that contains traces that have been added together from different records to reduce noise and improve overall data quality.

Statics: A bulk shift of a seismic trace in time during seismic processing. A common static correction is the weathering correction, which compensates for a layer of low seismic velocity material near the surface of the Earth. Other corrections may compensate for differences in topography among others.

Vector Fidelity: A multi-component sensors ability to make equal measurements on all three axes and to limit signal cross contamination between the three axes.

Wave: A disturbance that moves through a medium, transporting energy from one location to another as it goes.

Wavelet: A one-dimensional pulse, usually the basic response from a single reflector. Its key attributes are its amplitude, frequency and phase. The wavelet originates as a packet of energy from the source point, having a specific origin in time, and is returned to the receivers as a series of events distributed in time and energy. The distribution is a function of velocity and density changes in the subsurface and the relative position of the source and receiver.

Wave Velocity: The rate at which a wave travels through a medium, or the rate at which a body is displaced in a given direction. Its usage in geophysics is as a property of a medium-distance divided by travel time.

Input/Output, Inc.

Executive Officers

Robert (Bob) P. Peebler

President & Chief Executive Officer

Michael K. (Mick) Lambert

President, GX Technology

J. Michael Kirksey

Executive Vice President & Chief Financial Officer

Chris M. Friedemann

Vice President, Commercial Development

David L. Roland

Vice President, General Counsel &
Corporate Secretary

Michael L. Morrison

Controller & Director of Accounting

Board of Directors

James M. (Jay) Lapeyre, Jr.

Chairman of the Board

President, Laitram LLC

Bruce S. Appelbaum

Chairman, Mosaic Natural Resources

Theodore H. Elliott, Jr.

Chairman, Prime Capital Management Co.

Franklin Myers

Senior Vice President & Chief Financial Officer,
Cooper Cameron Corporation

S. James Nelson, Jr.

President, FSD Corporation

Retired Vice Chairman, Cal Dive International

Robert P. Peebler

President & Chief Executive Officer,

Input/Output

John Seitz

Co-CEO, Endeavour International Corp,

Sam K. Smith

Consultant, Private Investments

Executive Summary

History of the Seismic Industry		1.

Defining Full-Wave Digital		2.

VectorSeis on Land & Sea		3.

The Full-Wave Digital Market		4.

The New Input/Output		5.

Glossary		6.