SEI-2012.12.31-10K
Table of Contents



 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
____________________________________________
FORM 10-K
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission File Number: 001-10165
_______________________________________________
 SEITEL, INC.
(Exact name of registrant as specified in its charter)
Delaware
  
76-0025431
(State or other jurisdiction of incorporation or organization)
  
(I.R.S. Employer Identification No.)
 
 
10811 S. Westview Circle Drive, Building C, Suite 100
Houston, Texas
  
77043
(Address of principal executive offices)
  
(Zip Code)

(Registrant’s telephone number, including area code)    (713) 881-8900
Securities registered pursuant to Section 12(b) of the Act:     None
Securities registered pursuant to Section 12(g) of the Act:     None

Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act).
Yes  ¨    No  ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes  ¨    No  ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes  ý    No   ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “ accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
¨
Accelerated filer
¨
Non-accelerated filer
ý
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes  ¨    No  ý
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant at February 19, 2013 was zero. On February 19, 2013 there were a total of 100 shares of common stock outstanding.
 


Table of Contents



TABLE OF CONTENTS

 
 
 
 
 
PART  I
 
 
 
Item 1
 
Item 1A.
 
Item 1B.
 
Item 2.
 
Item 3.
 
Item 4.
PART  II
 
 
 
Item 5.
 
Item 6.
 
Item 7.
 
Item 8.
 
Item 9.
 
Item 9A.
 
Item 9B.
PART  III
 
 
 
Item 10.
 
Item 11.
 
Item 12.
 
Item 13.
 
Item 14.
PART  IV
 
 
 
Item 15.

2

Table of Contents



CAUTIONARY STATEMENTS CONCERNING FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K (this “Annual Report”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Statements contained in this report about our future outlook, prospects, strategies and plans, and about industry conditions, demand for seismic services and the future economic life of our seismic data are forward-looking. All statements that express belief, expectation, estimates or intentions, as well as those that are not statements of historical fact, are forward looking. The words “proposed,” “anticipates,” “will,” “would,” “should,” “estimates” and similar expressions are intended to identify forward-looking statements. Forward-looking statements represent our present belief and are based on our current expectations and assumptions with respect to future events. While we believe our expectations and assumptions are reasonable, they involve risks and uncertainties beyond our control that could cause the actual results or outcome to differ materially from the expected results or outcome reflected in our forward-looking statements. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Annual Report may not occur. Such risks and uncertainties include, without limitation, actual customer demand for our seismic data and related services, the timing and extent of changes in commodity prices for natural gas, crude oil and condensate and natural gas liquids, conditions in the capital markets during the periods covered by the forward-looking statements, the effect of economic conditions, our ability to obtain financing on satisfactory terms if internally generated funds and our current credit facility are insufficient to fund our capital needs, the impact on our financial condition as a result of our debt and our debt service, our ability to obtain and maintain normal terms with our vendors and service providers, our ability to maintain contracts that are critical to our operations, changes in the oil and gas industry or the economy generally and changes in the exploration budgets of our customers. Also note that we provide a cautionary discussion of risks and uncertainties under the captions “Item 1A. Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report.
The forward-looking statements contained in this report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason. All forward-looking statements attributable to Seitel, Inc. or any person acting on its behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this Annual Report and in our future periodic reports filed with the Securities and Exchange Commission (“SEC”).
PART I

Item 1. Business
General

We are a leading provider of onshore seismic data to the oil and gas industry in North America. We own an extensive library of proprietary onshore and offshore geological data that we have accumulated since our inception in 1982. We believe our data library is the largest onshore three-dimensional (“3D”) database available for licensing in North America and includes leading positions in oil and liquids-rich unconventional plays.
As of February 2013, we own 37,350 square miles of onshore 3D data, consisting of 24,400 U.S. square miles (65%) and 12,950 Canadian square miles (35%). We have a leading market position in key geographies that benefit from the ongoing growth in North American unconventional onshore oil and gas activity. Approximately 46.7% of our onshore 3D library is comprised of data located in unconventional plays, and currently we have an additional 2,400 square miles of onshore 3D data in progress in those areas. Since 2008, we have embarked upon a campaign to acquire data in key unconventional plays, including oil-focused and liquids-rich North American plays such as the Eagle Ford/Woodbine and Niobrara/Bakken, where we own a combined 7,350 square miles of 3D unconventional data. Our library also includes data in other oil and liquids-rich plays including, in the U.S., Utica/Marcellus and Granite Wash (Panhandle Plays) and, in Canada, the Montney and Cardium. Including data in progress, we have grown our onshore 3D unconventional library by 12.3% compounded annually since the beginning of 2008.
Our business model is to acquire data selectively in geological formations that we believe will support drilling from a variety of oil and gas producers over an extended period of time. We design and manage new surveys and license them to initial clients which typically fund a significant portion (50% - 70%) of the total cost of each survey (referred to as “client underwriting”). Seitel owns 100% of the acquired data and licenses (“resells”) to additional parties on a non-exclusive basis. Such resales are unlimited in both time and amount and require minimal incremental cash costs, leading to a rapid payback period on new investments of typically less than three years and high returns thereafter. Our long-lived, diverse data library built over three decades continues to provide value to our customers, with 52% of our 2012 3D onshore resale revenue coming from data over five years old, including resales of data from vintages as early as 1994.

3

Table of Contents



We believe that we have low fixed costs and a highly flexible operating model, as we do not own any seismic survey equipment or directly employ field personnel. Instead, we outsource those functions by contracting with third-party specialists, as required, in various facets of the data acquisition process in order to complete surveys to expand our data library. We also use sales commissions to create incentives for our sales force while matching our costs to our achieved sales. We believe this business model provides enhanced flexibility, allowing us to optimize our level of investment for the market environment and resulting in substantially lower cash flow volatility by enabling us to respond quickly to changes in demand and shifts in client geographic focus.
We serve a market which includes over 1,600 companies in the oil and gas industry. Our customers include large independent and major integrated oil and gas companies as well as small and mid-cap exploration and production companies. The importance of geological data in the exploration and development process drives demand for data in our library. Specifically, our customers use seismic data to identify geographical areas where subsurface conditions are favorable for oil and gas exploration and to optimize development and production of oil and gas reserves. Seismic data provides valuable insight for operators including a target zone's thickness, as well as faulting pattern complexity, helping with the design of horizontal drilling programs and minimizing the potential for uneconomic wells.

To support our seismic data licensing business and our clients, we maintain warehouse and electronic storage facilities at our Houston, Texas headquarters and our Calgary, Alberta location. Through our Solutions business unit, we offer the ability to access and interact with the seismic data we own and market via a standard web browser and the Internet.

In each of fiscal 2012, 2011 and 2010, approximately 98% of our revenues were attributable to revenue generated from customers underwriting data acquisitions and revenue from licensing of seismic data. Other revenues during these years were primarily derived from Solutions for reproduction and delivery of seismic data licensed by our clients. See Note M to Notes to Consolidated Financial Statements for information about our revenue by geographical area.
We are a private company controlled by ValueAct Capital Master Fund, L.P. (“ValueAct”) and funds managed by affiliates of Centerbridge Partners, L.P. (“Centerbridge”). We are incorporated under the laws of the State of Delaware. Our principal executive offices are in Houston, Texas.
Description of Operations
Seismic Data
Oil and gas companies consider seismic data an essential tool in finding and exploiting hydrocarbons. Oil and gas companies use seismic data in oil and gas exploration and development efforts to increase the probability of drilling success. Further, seismic data analysis can increase recoveries of reserves from existing, mature oil fields by optimizing the drilling location of development wells and by revealing additional, or “stepout,” locations that would not otherwise be apparent. With the shift to unconventional plays, E&P companies now use seismic data in the unconventional plays as a development tool to better identify efficient drilling plans and maximize production by identifying and understanding a series of critical characteristics of the targeted resource. The cost of seismic data is less than 1% of the total cost of exploration for most projects, but provides substantial benefits to operators. 3D seismic data provides a graphic depiction of the earth’s subsurface from two horizontal dimensions and one vertical dimension, rendering a more detailed picture than two-dimensional "2D" data, which presents a cross-sectional view from one vertical and one horizontal dimension. The more comprehensive geophysical information provided by 3D surveys significantly enhances an interpreter’s ability to evaluate the probability of the existence and location of oil and gas deposits. However, the cost to create 3D seismic data is significantly more than the cost to create 2D seismic data. As a result, 2D data continues to be used by clients for preliminary, broad-scale exploration evaluation, as well as in determining the location and design of 3D surveys. 3D surveys can then be used for more detailed analysis to maximize actual drilling potential and success.

Although we amortize our seismic data over a maximum period of four years, much of our seismic data has continued to generate licensing revenue past the amortization period. Assuming the data is sampled and gathered adequately in the field recording phase, it is amenable to re-evaluation and re-presentation multiple times, using new or alternate processing techniques or updated knowledge of the Earth model.

4

Table of Contents



Management believes the level of resales from various vintages of our investment in seismic data is useful in order to assess the resiliency and value of our seismic data library. Management considers estimated longevity of and foreseeable demand for data in determining whether to undertake new data acquisition projects. For the year ended December 31, 2012, resale revenue from 3D onshore data was recognized from net historical investments made in the indicated periods (in thousands):
 
 
 
Resale
Revenue
 
Percentage
 
Net
Investment (1)
 
Percentage
Investments prior to 2008
 
$
63,142

 
52
%
 
$
439,197

 
66
%
Investments 2008 through 2012
 
58,150

 
48
%
 
223,101

 
34
%
Total 3D onshore
 
$
121,292

 
100
%
 
$
662,298

 
100
%
 
(1) 
Net investment reflects total data cost less client underwriting before fair value adjustments resulting from the 2007 merger between Seitel Acquisition Corp. with and into Seitel, Inc. (the "Merger").
The following presents a reconciliation of resale revenue for 3D onshore to total revenue for the year ended December 31, 2012 (in thousands): 
Total resale revenue – 3D onshore
$
121,292

Other revenue components:
 
Other resale revenue (principally 2D and offshore)
6,239

Acquisition revenue
107,254

Solutions and other revenue
5,673

Total revenue
$
240,458

The following presents a reconciliation of net historical investment for 3D onshore data (a non-GAAP financial measure) to net book value at December 31, 2012 (the most directly comparable GAAP financial measure) (in thousands):
 
Net historical investment in seismic data – 3D onshore
$
662,298

Add:
 
Acquisition revenue – 3D onshore
694,780

Other seismic data investment (principally 2D and offshore)
384,803

Foreign currency translation
41,306

Seismic projects in progress
84,907

Fair value adjustment resulting from Merger
275,235

Less:
 
Historical impairment charges
(112,923
)
Accumulated amortization (including historical amounts pre-Merger)
(1,850,289
)
Net book value
$
180,117

Data Library Overview
We believe our data library is the largest onshore 3D database available for licensing in North America. We have built our onshore 3D library over more than 20 years with approximately $1.5 billion in gross investments and we view our library as an asset that would be time- and cost-prohibitive for others to replicate. Approximately 46.7% of our onshore 3D library is comprised of data located in unconventional plays, and we currently have over 2,400 square miles of onshore 3D data in progress in those areas. We believe we are well positioned in oil-focused and liquids-rich plays such as the Eagle Ford/Woodbine, Niobrara/Bakken, Utica/Marcellus, Granite Wash (Panhandle Plays), Montney and Cardium with over 17,450 miles of data in unconventional areas.
Our library also consists of data targeted at conventional plays and shot before we embarked on our current strategy of targeting data from unconventional plays. We also own a library of 3D offshore data covering parts of the shelf and certain deep water areas in the Western and Central U.S. Gulf of Mexico. In addition, we own or manage approximately 1.1 million linear miles of 2D data concentrated primarily in North America, both onshore and offshore.

5

Table of Contents



The following table describes our 3D seismic data library as of February 19, 2013:
  
 
Completed Surveys
 
Surveys in
Progress
3D Data Library
 
Square
Miles(1)
 
Percentage
of  Subtotal
 
Square
Miles (1)
 
 
 
 
 
 
 
Eagle Ford/Woodbine
 
4,750

 
19
%
 
1,000

Niobrara/Bakken
 
2,600

 
11
%
 

Haynesville
 
1,350

 
6
%
 

Utica/Marcellus
 
400

 
2
%
 
850

Granite Wash (Panhandle Plays)
 
300

 
1
%
 
450

Conventional 3D
 
15,000

 
61
%
 

Total U.S. Onshore
 
24,400

 
100
%
 
2,300

 
 
 
 
 
 
 
Montney
 
3,750

 
29
%
 

Cardium
 
3,250

 
25
%
 
100

Horn River
 
1,050

 
8
%
 

Conventional 3D
 
4,900

 
38
%
 

Total Canada
 
12,950

 
100
%
 
100

 
 
 
 
 
 
 
Total 3D Onshore
 
37,350

 
78
%
 
2,400

 
 
 
 
 
 
 
U.S. Offshore
 
10,500

 
22
%
 

 
 
 
 
 
 
 
Worldwide Total
 
47,850

 
100
%
 
2,400

 
(1)Square miles reflect mileage net to our revenue interest.

Our data library is a highly valuable asset that has historically generated strong returns on capital. As of March 2012, the appraised value of our data library was $467.0 million. Since then, we have committed approximately $50.0 million net investment and $120.0 gross investment towards acquiring approximately 2,000 square miles of additional data. The technical and informational usefulness of our data has generally not declined over time. Demand for data is driven by the level and location of customer exploration and development activity and not the age of the data. Because of our positioning in favorable geographies and the long life of the data, there is significant built-in potential for repeat licensing of data at little or no marginal cost. The existing library is highly defensible as the customer's cost of licensing data is typically much lower than the cost of creating a new survey, thus there is little incentive for competitors to survey areas where we already have data.
Virtually all capital expenditures are additive to our library, as we have minimal true “maintenance” capital expenditure requirements. However, we estimate that approximately $25.0 million of net cash capital expenditures are required annually to offset declines in contribution from older data, depending on the areas in which customers are focusing their exploration and production activity. In 2012, we invested $87.5 million of net cash capital expenditures (defined as total capital expenditures net of client-funded cash underwriting and non-cash additions to the library) to grow our 3D data library and for 2013, our budgeted net cash capital expenditures are $60.0 million. We have $36.8 million net cash capital expenditures in our data acquisition backlog as of February 2013. In 2012, we completed approximately 2,800 square miles of 3D data that was added to our library. In 2013, we expect to add approximately 2,000 square miles to our library.
Onshore U.S. and Canada: Since 2008, our capital investment in both the U.S. and Canada has been focused on unconventional plays, initially in the shale gas areas and, since 2011, shifting towards oil-focused and liquids-rich objectives. These shifts in focus are made in accordance with the activity of our clients and our ability to serve them is an important component of our growth strategy.
The U.S. onshore 3D conventional sector of our seismic data library is mainly comprised of our Gulf Coast Texas and southern Louisiana/Mississippi components, which we began accumulating in 1993. We also have relatively small amounts of 3D

6

Table of Contents



seismic data in other areas, such as Alabama, California, Michigan, Northern Louisiana and West Texas as well as an extensive 2D data library that continues to contribute to our licensing sales.
The Canadian onshore 3D conventional sector of our seismic data library is mainly comprised of data within the Western Canadian Basin, which we began accumulating in 1998. We also have an extensive 2D data library that continues to contribute to our licensing sales.
Offshore U.S. Gulf of Mexico: Our library of offshore data covers parts of the U.S. Gulf of Mexico shelf and certain deep water areas in the Western and Central U.S. Gulf of Mexico. We have accumulated our U.S. Gulf of Mexico offshore 3D data since 1993. Although we have not shot new offshore surveys since 2002, on occasion, we add offshore Gulf of Mexico data through non-monetary exchanges.
Data Library Growth
We regularly add to our library of seismic data by: (1) recording new data, (2) buying ownership of existing data for cash, (3) acquiring ownership of existing data through non-monetary exchanges or (4) creating new value-added products from data existing within our library.
Underwritten Data Acquisitions: We design and manage new seismic surveys that are specifically suited to the geology and environmental conditions of the area using the most appropriate technology available. Typically, one or more customers will underwrite or fund a significant portion of the direct cost in exchange for a license or licenses to use the resulting data. Under the terms of these licenses, the customers may occasionally have a limited exclusivity period. We consider the contracts signed up to the time we make a firm commitment to create the new seismic survey as underwriting or pre-funding. Any subsequent licensing of the data while it is in progress or once it is completed is considered a resale license. All of our data acquisition activity during 2012 occurred in unconventional plays, primarily the Eagle Ford/Woodbine in Texas, Utica/Marcellus in Pennsylvania and West Virginia, Niobrara in Colorado, Granite Wash (Panhandle Plays) in North Texas and Oklahoma and both Montney and Cardium in Western Canada. All field work on these projects is outsourced to subcontractors. A significant percentage of the data processing for our U.S. projects is processed by our wholly-owned subsidiary Seitel Data Processing, Inc. Until 2012, all of the data processing for our Canadian projects had been outsourced to local subcontractors. In 2012, we formed an internal data processing group in Canada that began processing data acquired in Canada and will continue to undertake a high percentage of the processing work on our Canadian projects. We employ experienced geoscientists who design seismic programs and oversee field acquisition and data processing to ensure the quality and longevity of the data created.
Cash Purchases: We purchase data for cash from oil and gas companies, other seismic companies or financial investors in seismic data when opportunities arise and that meet our investment criteria.
Non-Monetary Exchanges: We grant our customers a non-exclusive license to selected data from our library in exchange for ownership of seismic data from the customer. The data that we receive is distinct from the data that is licensed to the customer. These transactions will tend to be for individual surveys or groups of surveys, rather than whole libraries. Occasionally, we also use non-monetary exchanges in conjunction with data acquisitions and cash purchases. In addition, we may receive advanced data processing services on selected existing data in exchange for a nonexclusive license to selected data from our library.
Value-Added Products: We create new products from existing seismic surveys in our library by extracting a variety of additional information from these surveys that was not readily apparent in the initial products. Opportunities to extract such additional information and create such additional products may result from information from secondary sources, alternative conclusions regarding the initial products and applying alternate or more complex processes to the initial products, or some combination of these factors. Additional products may include Pre-Stack Depth Migration volumes, Amplitude Versus Offset volumes, Complex Attribute volumes, and Rock Property volumes. Typically, one or more customers will underwrite a portion of the direct cost involved in these products in exchange for a license or licenses to use the resulting data. Under such licenses, the customers may have exclusive access to the newly acquired data for a limited term. After this limited term of exclusivity, the data is added to our library for licensing to the industry on a non-exclusive basis. Work on these projects may be performed by our internal processing groups, outsourced to specific specialists in the arena or conducted under an alliance with a particular specialist. We employ experienced geoscientists who design these value-added products and oversee the processing to ensure the quality and longevity of the data created.

7

Table of Contents



Competitive Strengths
We believe we have the following competitive strengths:
Large and Diverse Data Library with Leading Market Position in Key Oil and Gas Producing Regions: We believe we have the largest onshore 3D seismic data library available for licensing in North America. Our onshore 3D library has been built through a gross investment of approximately $1.5 billion, $700 million net of underwriting, since 1994. Our data covers a diverse range of oil and gas producing regions in the United States and Canada and we believe it provides us with leading positions in oil and liquids-rich unconventional plays. As of February 2013, we have 17,450 square miles of unconventional 3D data, and all of our data acquisition backlog as of February 2013 is directed to oil and liquids-rich unconventional plays. We have grown our onshore 3D unconventional library by 12.3% compounded annually since the beginning of 2008, including surveys in progress. Moving forward, further development of existing plays as well as exploration of new unconventional plays, including the Mowry, Point Pleasant, Woodbine in the U.S. and Duvernay in Canada, represent areas of key growth potential.
The size and coverage of our seismic data library enables us to capitalize on the favorable trends in the North American oil and gas exploration market. Our competitive advantage is driven by our ability to:
Successfully bid for new seismic surveys that are in our areas of focus as a result of our knowledge of data return characteristics for similar data in our existing library;
Creatively market our data library with an innovative strategy, which includes tailoring licenses to meet our client's needs;
Generate client trust by delivering surveys on time that meet oil and gas client requirements particularly those clients that are early participants; and
Retain and grow valuable client relationships.

Significant Market Opportunity: We believe we are positioned to benefit from the expected long-term growth in North American onshore oil and gas exploration and production activity. Because of their favorable production economics, unconventional plays have attracted substantial long-term investment from high quality E&P companies, including major oil companies, large independents and national oil companies. Seismic data is critical to oil and gas exploration and development in unconventional plays since it provides a wealth of insight into the structure and properties of producing formations. Such insight enhances customers' ability to design efficient and productive horizontal drilling programs.
Continued improvement in technology is expanding the size of producible formations in the unconventional plays and making previously undeveloped plays economically viable for production. Many of these areas have little to no 3D data available, setting the stage for long-term future demand for our services and growth of our data library. Furthermore, many of our top acquisition and resale customers are active in the growing and emerging unconventional plays, positioning us for new survey opportunities with existing customers. We believe we are well positioned to acquire new data selectively in emerging unconventional plays where there is limited existing data. We are able to utilize our proprietary information gathering tools, expertise, customer relationships and insights gained from licensing activity in the existing library to identify and select surveys that have attractive return potential. In addition, several major North American resource plays, including the Eagle Ford, have emerged in areas that were historically targets for conventional production of oil and gas. In such areas, our existing library of data has generated substantial customer demand and allowed us to identify adjacent areas for further data acquisition.
With one of the largest onshore seismic data libraries in the active North American oil and natural gas basins, we have an established competitive position within this growing market. Since 1994, we have invested approximately $1.8 billion to build our data library. Over 80% of this investment has been in onshore 3D data. We believe that the current replacement cost of our seismic library significantly exceeds our original investment, and that our broad geographic coverage and strong presence in the active North American onshore oil and gas basins coupled with our domain expertise creates significant barriers to replication and a defensible market position. We believe competitors will generally not shoot over areas already in our library because it is not economically viable to do so.
Multiple Revenue Opportunities Lead to Strong Returns on New and Existing Data: We derive revenue from the non-exclusive licensing of our data. Importantly, data within our library can be licensed on a non-exclusive basis multiple times over a span of many years. Several factors lead to multiple licensing of our data which drives high returns on our investments over time. An area captured by a 3D survey may have multiple mineral holders within a particular stratigraphic layer as well as vertically across layers. Also, new oil and gas field discoveries, new drilling technologies and pipeline and oil and gas infrastructure expansion can cause renewed exploration activity in a previously assessed surrounding area. Due to the capital intensive nature of developing unconventional plays, many oil and gas companies seek partners to share in the cost of

8

Table of Contents



development and these partners will often need to purchase licenses for their own use. In addition, merger and acquisition activity often requires re-licensing of data following a change in field ownership. Moreover, prospective developers and investors without mineral rights may seek our data.
Our payback on investments in unconventional plays has been very short and we have proven our ability to license onshore data for extended periods after creation. For the year ended December 31, 2012, 52% of total resale revenue for 3D onshore data came from data acquired before 2008, and we are still reselling data from 1994, our first onshore 3D onshore vintage year. For new data, we have a rapid payback period of less than three years on average, with annual returns on investments averaging approximately 38% in the first three years of an investment.
Ability to Adjust Quickly to E&P Industry Cycles: Our variable operating structure allows us to curtail overhead costs quickly during cyclical downturns in the industry, and most of our capital expenditures are discretionary additions to our seismic data library with significant underwriting commitments from customers. During the downturn in 2008 and 2009, because we had no fixed overhead costs related to maintaining seismic equipment or crews and because of our commission-based, bonus-centric employee compensation structure, we were able to reduce cash operating expenses by approximately 30%. Also from 2008 to 2009, we were able to react quickly to reduce net cash capital expenditures. As distinct from our business model, the majority of seismic companies own and operate seismic equipment and crews, creating fixed operating expenses and less flexible cost structures.
We operate with a low cost structure by maintaining an efficient base of assets and employees. We do not own seismic acquisition equipment or employ seismic acquisition crews, but engage, as required, third-party contractors with qualified equipment to shoot new data. In addition, the majority of our capital expenditures for data acquisitions are discretionary. We believe this minimizes ongoing capital requirements and results in substantially less volatility in cash flows by enabling us to respond quickly to changes in demand. In addition, the creation of new surveys provides cost-effective growth opportunities since we impose strict capital investment thresholds with targeted underwriting levels averaging 60% to 65% and typically do not start work on new acquisition programs without an underwriting commitment. On occasion, when our underwriting customer owns other attractive seismic data that we want to obtain, we may decide to take ownership in this data to cover part of the customer's underwriting obligation. For the years 2012, 2011 and 2010, we achieved 61%, 56% and 68% average underwriting levels, respectively, for new seismic acquisition projects.
Seismic Data Has an Attractive Value Proposition Among Our Blue Chip Customer Base: Our data is critical to oil and gas exploration and development activity. Understanding geological structure maximizes production and returns on client investments; however, seismic data purchases represent a small fraction of total drilling and completion costs, generally less than 1%. Our customer base ranges from some of the largest independent oil companies in the world to small, single-basin E&P companies, with very little customer concentration. As we have grown our presence in unconventional plays, our customer base has shifted towards larger producers, which are better positioned to maintain a consistent seismic spending plan. In addition, our revenue stream remains highly diversified. No single customer accounted for more than 10% of revenue for 2010 or 2012, while in 2011 our top customer accounted for approximately 11% of revenue. Cumulatively over our three most recent fiscal years, our top customer represents 6.7% of our total revenue.
We serve a market which includes over 1,600 companies in the oil and gas industry and our customers range from small exploration and production companies and private prospecting individuals to large independent oil and gas companies and also include global oil and gas companies. We believe that the quality of our data, the breadth of its coverage in the major active onshore basins in North America and our longstanding commitment to client service enables us to attract top-tier clients and maintain and grow existing client relationships. These relationships also create access to additional data surveys and sales opportunities.
Experienced Management Team: Our senior management team is comprised of individuals with an average of over 30 years of relevant experience. Robert Monson, our President and CEO has over 28 years of industry experience, while Marcia Kendrick, our CFO, joined us in 1993 and has over 22 years of industry experience. Kevin Callaghan, our Chief Operating Officer, joined Seitel in 1995 and has over 40 years of relevant industry experience. Our expertise is in the selection, design and management of seismic surveys. We also believe we maintain the largest sales and marketing group in the industry.
Corporate Strategy
Underwritten Data Acquisitions: We add data to our library primarily by contracting with third-party specialist service providers to create new subsurface geological data, which we design and own. Typically, one or more customers will underwrite or fund a significant portion of the direct cost of a seismic survey in exchange for a license or licenses to use the resulting data. The relatively high level of underwritten acquisition costs, typically 50-70% of the cost of the survey, lowers our

9

Table of Contents



initial capital requirements and enhances our return on investment. We will maintain a disciplined return on investment approach to operating and capital expenditures. We only intend to pursue new acquisition projects if we believe that conditions exist for repeated licensing of the same data over an extended period of time. We typically seek significant underwriting commitments before undertaking new acquisition projects as underwriting levels are generally a predictor of long-term demand for seismic data. We target an average of 60% to 65% underwriting level for all new seismic acquisition projects on an aggregate basis. For the years 2012, 2011 and 2010, we achieved 61%, 56% and 68% average underwriting levels, respectively, for new seismic acquisition projects. Additionally, when acquiring 3D surveys, we consider the proximity to 3D surveys already in the library. We believe that there is greater value in contiguous data, or reasonably close concentrations of surveys in a single area.
Seitel owns 100% of acquired data and licenses (or “resells”) it to additional parties on a non-exclusive basis. Such resales are unlimited in both time and amount and require minimal incremental cash costs, leading to a rapid payback period on new investments of typically less than three years, with high returns thereafter. Our long-lived, diverse data library built over three decades continues to provide value to our customers, with 52% of our 2012 3D onshore resale revenue coming from data over five years old, including resales of data from vintages as early as 1994.
Provide Value to Customers through Deep Industry Knowledge and Technical Expertise: As a provider of multi-client data services, we deliver value to our clients through several aspects of our business. Our extensive expertise and local intelligence in designing and managing surveys is not generally available to our client base. We also create value-added products from the data in our library, primarily by applying complex imaging technology, such as complex depth imaging. These value-added products enhance the useful information that can be extracted from a given data set. As a large onshore data library owner, we have an existing data “footprint,” often providing further cost efficiencies and higher-quality data for new surveys. Clients are disposed to underwrite our surveys as the cost to license multi-client data is significantly less than the cost to commission a proprietary survey. Finally, our clients maintain anonymity both within the local community and amongst competitors through contracting with Seitel.
Continue to Grow and Increase Library Footprint in Unconventional Plays: We focus our data acquisition efforts on oil and natural gas producing areas that we believe are well suited to benefit from current and emerging trends in the E&P industry. In 2008, we began making strategic investments in unconventional plays which substantially contributed to our cash resales in 2010, 2011 and 2012. We have expertise and data in key unconventional plays including the Eagle Ford/Woodbine, Niobrara/Bakken, Utica/Marcellus, Granite Wash (Panhandle Plays), Montney and Cardium. We work closely with our customers to determine specific areas of interest and future investment and, when suitable, grow with them into emerging unconventional plays. We believe our leading position in many unconventional plays, compared with our competitors, positions us to continue to be the seismic data provider of choice in these plays. Including data in progress, we have grown our onshore 3D unconventional library by 12.3% compounded annually since the beginning of 2008, an average increase of 1,615 square miles per year.
Expand Library in a Disciplined and Cost-effective Way: The substantial majority of our library additions come from new seismic data creation. We also grow our data library through cash purchases of existing seismic data, non-monetary data exchanges and new value-added products created from existing data. The decision to make capital investments is weighed against the estimated length of the payback period and projected return on capital. Additionally, when acquiring 3D surveys, we consider the proximity to 3D surveys already in our library as we believe that there is greater value in contiguous data, or close concentrations of surveys in a single area. We believe the continued expansion of North American onshore oil and gas activity provides a substantial white space opportunity for new data acquisition, and we use proprietary information tools and apply our management expertise to select among our pipeline of new survey opportunities. We typically pursue a new acquisition project only if it has a significant underwriting commitment from our customers and if we believe that conditions exist for repeated licensing of the data over an extended period of time. We are thorough in our evaluation of survey opportunities and are selective in adding prospective surveys to our pipeline and therefore not all surveys will meet our return requirements.
Leverage Internal Geophysical and Operations Management Expertise while Outsourcing Lower Margin Services: Our strong geophysical, technical and field operating management expertise is essential in maintaining our leadership through our ability to design surveys with attractive return potential and manage their creation. We will continue to outsource the non-core, fixed-cost intensive services, including surveying, permitting and data capture involving field equipment and crews. This strategy enables us to select vendors that we believe offer the best price, equipment and skill sets for a particular environment, geographical location or geophysical objective and provides us with access to state-of-the-art equipment and emerging technologies. We believe this operating model also gives us the flexibility to control costs to respond appropriately to changing market conditions, thus contributing to more stable performance.

10

Table of Contents



Maintain a Strong Balance Sheet and Ample Liquidity: We believe a strong balance sheet and ample liquidity are critical elements to positioning the business for future growth given the substantial market opportunity. We intend to fund data acquisitions with the cash flow generated from operations.
Industry Overview
Overview of Seismic Data: Oil and gas companies consider seismic data an essential tool in finding and exploiting hydrocarbons. Companies use seismic data in oil and gas exploration and development efforts to increase the probability of drilling success. Further, seismic data analysis can increase recoveries of reserves from existing, mature oil fields by optimizing the drilling location of development wells and by revealing additional, or “step-out,” locations that would not otherwise be apparent. Historically, seismic data was tied to exploration capital expenditures, which are significantly more volatile, as E&P companies used seismic data to increase the success rate of discovering hydrocarbon deposits. With the shift to unconventional plays, E&P companies now use seismic data in unconventional plays as a development tool to better identify efficient drilling plans and maximize production by identifying and understanding a series of critical characteristics of the targeted resource. Therefore, seismic data is increasingly tied to relatively stable development capital expenditures. The cost of seismic data is less than 1% of the total cost of drilling and completion for most projects, but provides substantial benefits to operators, including minimizing potential for uneconomic wells.
Drivers of Ongoing Demand for Seismic Data: There are many drivers which cause seismic data to be licensed repeatedly by different customers over a long time period, including fractured mineral positions, stratified mineral interests, partnerships, lease and option turnover, correlation to well analogs, commodity pricing, improvements in data processing techniques and developments in drilling and production technology.
Additionally, the explosion of activity in unconventional plays has generated opportunities for further resales of data that was created in the search for conventional resources. For example, in Texas we have a number of surveys that were initially created for the Austin Chalk or the Central Edwards Reefs but are ideally positioned for Eagle Ford applications. Similarly in British Columbia, our surveys in conventionally-directed areas later proved ideally positioned for applications in the Montney formation.
Increased M&A activity, including joint ventures, also generates increased licensing fees for seismic data providers. Licenses to seismic data are generally structured such that they do not transfer in the case of a change of control and they are not accessible to partners. Both circumstances require additional payments for new licenses.
Long-Term Growth Trend in North American Oil and Gas Production: The emergence of shale and other unconventional plays has brought about fundamental changes for the North American E&P industry, which we believe is driving a favorable long-term outlook for seismic data demand. Because of advancements in horizontal drilling and fracturing technologies, unconventional plays are more economically viable at lower commodity prices than most conventional basins in North America, which has led to a resurgence in North American production of oil and natural gas. According to Wall Street research, E&P spending in North America is expected to grow 6% compounded annually through 2016, having grown 7% compounded annually between 2006 and 2012.
The majority of land drilling activity in North America in 2012 was focused on areas with oil and liquids-rich hydrocarbons, with oil directed rigs representing approximately 75% of the activity at the end of 2012. The focus on oil and liquids-rich activity is expected to continue in 2013 in North America. Drilling activity in dry gas areas continues to be depressed until demand and gas prices strengthen.
The Energy Information Administration (“EIA”) expects a loosening of world oil markets over the next two years. Based on the EIA’s Short-Term Energy Outlook dated January 8, 2013, world oil consumption grew by an annual average of 0.9 million barrels per day in 2012. This growth is expected to remain about the same in 2013 before increasing to 1.3 million barrels per day in 2014 due to a moderate global economic recovery. The EIA expects that global supply will increase by 1.0  million barrels per day in 2013 and 1.7 million barrels per day in 2014, which will more than offset higher global consumption. The report states that most of this increase in supply will come from outside the Organization of the Petroleum Exporting Countries (OPEC), with North America accounting for much of the growth. Based on its January 8, 2013 report, the EIA predicts the price of West Texas Intermediate crude oil to average about $90 per barrel in 2013 before increasing to an average of $91 per barrel in 2014, as compared to the average of $94 in 2012.
In this same report, the EIA projects that total U.S. natural gas consumption in 2013 and 2014 will be relatively unchanged from 2012. The EIA expects U.S. production growth to continue in 2013 and 2014, largely driven by onshore production in unconventional areas. The EIA expects natural gas working inventories to remain at high levels, after setting a record high in November 2012. The EIA predicts that natural gas spot prices will gradually rise but remain relatively low through 2014, with an average of $3.74 per million British thermal units (MMBtu) in 2013 and $3.90 per MMBtu in 2014 as compared to the average of $4.00 per MMBtu in 2011 and $2.75 per MMBtu in 2012.

11

Table of Contents



Continued improvement in technology is expanding the size of producible formations in the unconventional plays and making previously undeveloped plays economically viable for production. There are multiple new unconventional plays emerging in North America which are becoming increasingly economical to develop.
Early activity in the unconventional plays was concentrated in shale gas areas such as the Barnett, Woodford and Fayetteville. Increased confidence in the industry's ability to extract gas from unconventional plays such as these led to a dramatic increase in the number of exploration and production companies participating in new plays, such as the Eagle Ford, Haynesville, Marcellus, Southern Montney and Horn River. Strong oil and natural gas liquids prices, along with increased sophistication of simulation and extraction techniques, drew industry attention towards oil-weighted unconventional plays, such as the Upper Eagle Ford/Woodbine, Utica, Niobrara/Bakken, Granite Wash (Panhandle Plays), Northern Montney and Cardium with several additional plays emerging, including Mowry and Point Pleasant in the U.S. and Duvernay in Canada. Continued development of extraction techniques and increased geological understanding of the targets has also led to the expansion of the areal extent of the active unconventional plays as well as additional prospective plays. The area defined by these plays, along with the pace of defining additional ones presents a tremendous opportunity for creating new 3D seismic programs. The majority of the land on which these new plays are located has little to no 3D data available which is expected to create significant demand over the mid- to long-term. Further exploration and development within known plays is also expected to generate demand for our existing library as well as for new surveys.
Seitel Uniquely Positioned to Benefit from Growth in North American Production: We believe the use of 3D seismic data will continue to be an important part of oil and gas companies' exploration and development spending as they are continually looking to reduce drilling risk, decrease oil and natural gas finding costs and increase the efficiencies of reservoir location, delineation, completion and management. In addition, we believe that seismic data is an essential component of oil and gas production activity in the unconventional plays. Seismic data can provide a wealth of insight into the targeted resource, including areal extent, depth, thickness, faulting patterns and a number of complex rock properties. Such insights enhance our customers' ability to design efficient and productive horizontal drilling and fracking programs. Understanding these unique features is critical for our customers as they develop their horizontal drilling plans, which can result in lateral drilling that reaches over one mile in each direction.
The continued expansion of exploration and production activity in North America has revealed objectives in areas where little seismic data had previously existed, such as Utica/Marcellus, as well as areas where we had extensive existing data available, such as Eagle Ford/Woodbine and Montney. In either case, we have utilized our unique industry position to generate cash resales from existing data as well as acquire new, high-return surveys. Continued growth in North American production will enable us to generate further returns on its existing library as well as provide numerous opportunities for new data acquisition.
Licenses and Marketing
We actively market data from our library to customers under non-exclusive license agreements using a well-developed marketing strategy combined with strong geophysical expertise. Our licenses are generally non-assignable and typically provide that in the event of a change of control of a customer-licensee, the surviving entity must pay a fee to maintain a license for any data it seeks to continue to use and for which such entity previously did not have a license. We employ an experienced sales force and it is our operating philosophy to actively market our seismic library. Our team of dedicated marketing specialists seeks to maximize license sale opportunities and create innovative methods of contracting opportunities by monitoring petroleum industry exploration and development activities through close interaction with oil and gas companies on a daily basis.

Licenses generally are granted for cash, payable within 30 days of invoice, although we occasionally permit a customer to make an initial payment upon inception of the license followed by periodic payments over time, usually not more than 12 months. Some licenses provide for additional payments to us if the licensee acquires additional mineral leases, drills wells or achieves oil or gas production in the areas covered by the licensed data.
Fundamental to our business model is the concept that once seismic data is created it is owned by us and added to our library for licensing to customers in the oil and gas industry on a non-exclusive basis. Since the data is a long lived asset, such data can be licensed repeatedly and over an extended period of time to different customers at the same time.
Backlog
At February 19, 2013, we had capital expenditure commitments related to data creation projects of approximately $103.0 million of which we have obtained approximately $66.3 million of underwriting. We anticipate that the majority of this backlog will be recognized over the next 12 months. This is compared to capital expenditure commitments at March 7, 2012 of $165.7 million with underwriting of approximately $100.9 million.

12

Table of Contents



Seitel Solutions
To support our seismic data licensing business and our clients, we maintain warehouse and electronic storage facilities at our Houston, Texas headquarters and our Calgary, Alberta location. Through our Solutions business unit, we offer the ability to access and interact with the seismic data we own and market via a standard web browser and the Internet. Using proprietary technology, we store, manage, access and deliver data, tapes and graphic cross-sections to our licensees. In addition, Solutions offers use of its proprietary display and inventory software to certain customers, and the use of its proprietary quality control software to the seismic brokerage community principally in Calgary, Alberta, Canada. We also offer data management services to select clients.
Customers
We market our seismic data to a varied customer base. Our customers include independent oil and gas companies, major integrated oil and gas companies and national oil companies, as well as small and mid-cap exploration and production companies and private prospect generating individuals. During the years ended December 31, 2012 and 2010, no one customer accounted for more than 10% of revenue. One customer accounted for approximately 11% of our revenue during the year ended December 31, 2011. We believe that the quality of our data, the breadth of its coverage in the major active North American basins and our longstanding commitment to client service enables us to attract top-tier clients. Because we do not acquire data speculatively, strategic relationships with our customers have been and will continue to be critical to our growth. We do not believe that the loss of any single customer would have a material adverse impact on our seismic business, cash flows or results of operations.
Competition
The creation and licensing of seismic data is competitive. Customers consider several factors, including location of data, price, technological expertise and reputation for quality and dependability, when choosing a service provider. There are a number of geophysical companies that create, market and license seismic data and maintain seismic data libraries. Rather than outsourcing their seismic data activities, some oil and gas companies create their own seismic data libraries, which they license to others. Our largest competitors, many of whom are engaged in acquiring seismic data, as well as maintaining a data library, are CGG; Geokinetics, Inc.; Global Geophysical Services, Inc.; Pulse Seismic Inc.; Seismic Exchange, Inc. (a private company based in New Orleans, Louisiana); TGS Nopec; and WesternGeco. Many of our competitors have substantially larger revenues and resources than we do.
Regulation
Our operations are subject to a variety of federal, provincial, state, foreign and local laws and regulations, including environmental and health and safety laws. We invest financial and managerial resources to comply with these laws and related permit requirements. Various governmental authorities have the power to enforce compliance with these regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. In addition, failure to timely obtain required permits may result in delays in acquiring new data for our data library or cause operating losses. Because these laws and our business may change from time to time, we cannot predict the future cost of complying with these laws, and expenditures to ensure our compliance could be material in the future. Modification of existing laws or regulations or adoption of new laws or regulations limiting exploration or production activities by oil and gas companies could adversely affect us by reducing the demand for our seismic data. Specifically, hydraulic fracturing has become the subject of increased regulation due to public concerns that the practice may adversely affect drinking water supplies, increase emissions of perceived greenhouse gases, and/or adversely affect local communities. The adoption of legislation or regulations imposing reporting obligations or placing restrictions on hydraulic fracturing activities could burden operators and adversely affect the production of crude oil and natural gas, which would, in turn, adversely affect our revenues and results of operations by decreasing the demand for our seismic data and related services. For more information on hydraulic fracturing, see "Risk Factors" beginning on page 14.
Seasonality and Timing Factors
Our results of operations fluctuate from quarter to quarter due to a number of factors. Our results are influenced by oil and gas industry capital expenditure budgets and spending patterns. These budgets are not necessarily spent in equal or progressive increments during the year, with spending patterns affected by individual oil and gas company requirements as well as industry-wide conditions. In addition, under our revenue recognition policy, revenue recognition from data licensing contracts is dependent upon, among other things, when the customer selects the data or when the data becomes available for delivery. As a result, our seismic data revenue does not necessarily flow evenly or progressively during a year or from year to year. Although the majority of our data licensing transactions provide for fees to us of under $750,000 per transaction, occasionally a single data license transaction from our library, including those resulting from the merger and acquisition or property sales activity of

13

Table of Contents



our oil and gas customers, may be substantially larger. Such large license transactions, the completion and delivery of data or an unusually large number of, or reduction in, data selections by customers can materially impact our results during a quarter, creating an impression of a revenue trend that may not be repeated in subsequent periods. In our data creation activities, weather-related or other events outside our control may impact or delay surveys during any given quarter.
Employees
As of December 31, 2012, we and our subsidiaries had 128 full-time employees, including six executive officers, 18 marketing staff and 38 geotechnical staff. None of our employees are covered by collective bargaining agreements, and we consider our relationship with our employees to be good.
Raw Material and Proprietary Information
We are not dependent on any particular raw materials, patents, trademarks or copyrights for our business operations. Our seismic data library is proprietary confidential information, which is not generally available to the public and is subject to confidentiality agreements with our employees and customers. We believe that our seismic data library is also protected by common law copyright.
Available Information
We make available free of charge, or through the "Investor Relations" section of our website at www.seitel.com, access to our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such material is filed with, or furnished to, the SEC. Our Code of Business Conduct and Ethics is also available through the "Investor Relations-Corporate Governance" section of our website or in print to anyone who requests them.
The public may read and copy any materials filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549 and may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.

Item 1A. Risk Factors

RISKS RELATED TO OUR BUSINESS
Our industry is cyclical and our business could be adversely affected by the level of capital expenditures by oil and gas companies and by the level and volatility of oil and natural gas prices.
Our industry and the oil and gas industry generally are subject to cyclical fluctuations. Demand for our services depends upon spending levels by oil and gas companies for exploration, production, development and field management of oil and natural gas reserves and, in the case of new seismic data creation, the willingness of these companies to forgo ownership in the seismic data. Capital expenditures by oil and gas companies for these activities depend upon several factors, including actual and forecasted prices of oil and natural gas and those companies’ short-term and strategic plans. Oil and natural gas prices in turn depend on local, regional and global events or conditions that affect supply and demand for the relevant commodity. These events or conditions are generally not predictable and include, among other things:
levels of demand for, and production of, oil and natural gas;
worldwide political, military and economic conditions, including social and political unrest in Africa and the Middle East;
weather, including seasonal patterns that affect regional energy demand as well as severe weather events that can disrupt supply;
the level of oil and natural gas reserves; and
government policies regarding adherence to OPEC quotas.

Oil and natural gas prices are subject to significant volatility and there can be no assurance that oil and natural gas prices and demand will not decline in the future. Low oil and natural gas prices and demand could result in decreased exploration and development spending by oil and gas companies, which could, in turn, affect our seismic data business. Our customers may adjust their exploration and development spending levels very quickly in response to any material change in oil and natural gas prices. Continued political instability (especially in the Middle East and other oil-producing regions) may lead to further significant fluctuations in demand and pricing for oil and gas or seismic data. Any future decline in oil and natural gas prices,

14

Table of Contents



sustained downturn in the oil and gas or seismic data industries, or sustained periods of reduced capital expenditures by oil and gas companies as a result of factors which are beyond our control could have a material adverse effect on our results of operations and cash flow.

Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact our revenues by decreasing the demand for our seismic data and related services.
Hydraulic fracturing is a process used by oil and gas exploration and production operators in the completion of certain oil and gas wells whereby water, proppants (typically sand) and chemicals are injected under pressure into subsurface formations to stimulate gas and oil production. Due to public concerns that hydraulic fracturing may adversely affect drinking water supplies, increase emissions of perceived greenhouse gases, and/or adversely affect local communities (e.g., through increased truck traffic), hydraulic fracturing has become the subject of opposition by certain environmental groups, the subject of additional private and government studies, and the subject of increased regulation. A bill known as the Fracturing Responsibility and Awareness of Chemicals Act (the “FRAC Act”) was introduced in the 111th U.S. Congress and re-introduced in the 112th U.S. Congress, but was not enacted. If re-introduced and enacted by the 113th U.S. Congress, the FRAC Act would amend the Safe Drinking Water Act to require the energy industry to disclose the chemical additives used in hydraulic fracturing fluid, thus repealing an existing exemption for most hydraulic fracturing wells and imposing additional regulations on such wells. The U.S. Environmental Protection Agency (“EPA”) has published a draft guidance document suggesting new permitting requirements under its underground injection control program for those wells where diesel is used in hydraulic fracturing, announced plans to develop standards for discharges of hydraulic fracturing wastewaters, adopted air standards for certain hydraulic fracturing operations, which require the use of “reduced emission completion” technology, and announced plans to solicit public comment on a possible federal reporting requirement for fluids used in hydraulic fracturing pursuant to the Toxic Substances Control Act. Separately, the U.S. Department of the Interior has proposed new rules for hydraulic fracturing on public lands that would address disclosure of chemicals used in the process, wellbore integrity and handling of flowback water. Aside from these federal initiatives, several state and local governments have moved to require disclosure of fracturing fluid components or otherwise to regulate their use more closely, including through limiting where and how hydraulic fracturing wells may be installed. In certain areas of the country (e.g., the State of New York and within the Delaware River Basin), new drilling permits for hydraulic fracturing have been put on hold pending development of additional standards. Some municipalities have banned hydraulic fracturing. The EPA is currently undertaking a research study to investigate any potential adverse impact that hydraulic fracturing may have on water quality and public health. The study results are expected to be available no earlier than 2014. If the EPA study results demonstrate that hydraulic fracturing adversely impacts water quality or public health, the study results could prompt the U.S. Congress, EPA, other federal agencies, and/or state and local governments to impose additional restrictions on where and how hydraulic fracturing is permitted. Adoption of legislation or regulations imposing reporting obligations or placing restrictions on hydraulic fracturing activities could adversely affect the number of new hydraulic fracturing wells installed, impose operational delays and/or increase operating costs and additional regulatory burdens on operators, which could reduce their production of crude oil and natural gas and, in turn, adversely affect our revenues and results of operations by decreasing the demand for our seismic data and related services.
Economic conditions could adversely affect demand for our seismic data and related services and may increase our credit risk of customer non-payment.
Prices for oil and natural gas have been volatile. Commencing in late 2008, commodity prices for oil and natural gas declined significantly. Crude oil prices recovered during 2010 while natural gas prices improved but continue to be low. A return to lower crude oil prices and continuing low natural gas prices could result in many oil and gas companies significantly reducing their levels of capital spending, which could result in reduced demand for our seismic data and related services as our customers' operating cash flow decreases and the borrowing bases under their oil and gas reserve-based credit facilities are reduced. Lower commodity prices could also result in decreases in our customers’ liquidity and capital resources which could increase our credit risk of non-payment from such customers.
We are dependent on the availability of internally generated cash flow and financing alternatives to cover the costs of acquiring and processing seismic data for our data library that are not underwritten by our customers.
We continue to invest additional capital in acquiring and processing new seismic data to expand our data library and as our business grows, we expect these investments to increase. A significant portion of these costs is underwritten by our customers, while the remainder is financed through the use of internally generated cash flow and other financing sources. We may use bank or commercial debt, the issuance of equity or debt securities or any combination thereof to finance these costs. There can be no assurance that our customers will continue to underwrite these costs at historical levels, or that we will have available internally generated funds or will be successful in obtaining sufficient capital through additional financing or other transactions, if and when required on terms acceptable to us, to continue to invest in acquiring new seismic data. Any substantial alteration

15

Table of Contents



of or increase in our capitalization through the issuance of debt securities may significantly increase our leverage and decrease our financial flexibility. If we are unable to obtain financing if and when needed, we may be forced to curtail our business objectives and to finance business activities with only internally generated funds as may then be available.
Our working capital needs are difficult to forecast and may vary significantly, which could require us to borrow under our existing revolving credit facility and/or seek additional financing that we may not be able to obtain on satisfactory terms, or at all.

Our working capital needs are difficult to predict with certainty as they fluctuate from quarter to quarter based on the level of activity of our business. This difficulty is due primarily to the timing of our projects, our clients' budgetary cycles and our receipt of payment. We may therefore be subject to significant and rapid increases in our working capital needs that could require us to borrow under our existing revolving credit facility and/or seek additional financing sources. Restrictions in our debt agreements may impair our ability to borrow under our existing revolving credit facility and/or obtain other sources of financing, and access to additional sources of financing may not be available on terms acceptable to us, or at all.

We have invested, and expect to continue to invest, significant amounts of money in acquiring and processing seismic data for our seismic data library without knowing precisely how much of this seismic data we will be able to license or when and at what price we will be able to license such data.

We invest significant amounts of money in acquiring and processing seismic data for our seismic data library. By making such investments, we are exposed to the following risks:
We may not fully recover our costs of acquiring and processing seismic data through future licensing of data that we own. The amounts of these data sales are uncertain and depend on a variety of factors, many of which are beyond our control.
The timing of these sales is unpredictable and can vary greatly from quarter to quarter. The costs of each survey are capitalized and then amortized over the expected book life of the data. This amortization will affect our earnings and when combined with the sporadic nature of sales, will result in increased earnings volatility.
Regulatory changes that affect companies' ability to drill, either generally or in a specific location where we have acquired seismic data, could materially adversely affect the value of the seismic data contained in our library. Technology changes could also make existing data sets less desirable or obsolete.
The value of our data could be significantly adversely affected if any material adverse change occurs in the general prospects for oil and gas exploration, development and production activities.
The cost estimates upon which we base our pre-commitments of funding could be incorrect, which could result in losses that have a material adverse effect on our financial condition and results of operations.
Underwriting commitments of funding are subject to the creditworthiness of our clients. In the event that a client refuses or is unable to pay its commitment, we could lose a material amount of money.

We rely on developing and acquiring proprietary data which we keep confidential.

To protect the confidentiality of our proprietary and trade secret information, we require employees, consultants, contractors, advisors and collaborators to enter into confidentiality agreements. Our customer data license agreements and acquisition agreements also identify our proprietary, confidential information and require that such proprietary information be kept confidential. While these steps are taken to strictly maintain the confidentiality of our proprietary and trade secret information, it is difficult to ensure that unauthorized use, misappropriation or disclosure will not occur. If we are unable to maintain the secrecy of our proprietary, confidential information, we could be materially adversely affected.

Our business could be adversely affected by the failure of our customers to fulfill their obligations to reimburse us for the underwritten portion of third-party contractor costs.

A substantial portion (approximately 50% - 70%) of our seismic acquisition project costs, including third-party project costs, are underwritten by our customers. We target an average of 60% to 65% underwriting levels for new seismic acquisition projects on an aggregate basis. On occasion, when our underwriting customer owns other attractive seismic data that we want to obtain, we may decide to take ownership in this data to cover part of the customer’s underwriting obligation. In the event that underwriters for such projects fail to fulfill their obligations with respect to such underwriting commitments, we would continue to be obligated to satisfy our payment obligations to third-party contractors.


16

Table of Contents



We rely on third-party contractors to shoot new data.

We do not employ seismic crews or own any seismic survey equipment but contract, as needed, multiple third-party contractors with qualified equipment, personnel and expertise to shoot new data. However, any failure by these third-party contractors to meet the requisite industry quality, safety and environmental standards may result in our liabilities to third parties and have a material adverse effect on our business, reputation, financial condition and results of operations. Moreover, if we fail to retain our third-party contractors or obtain replacements on favorable terms or at all, our business and operating results may be materially and adversely affected.

We may be held liable for the actions of third-party contractors.

We often engage a number of third-party contractors to perform specific services and provide products and qualified personnel in connection with our operations. There can be no assurance we will not be held liable for the actions or inactions of these contractors. In addition, contractors may cause damage or injury to our personnel and property or third-party personnel or property, that is not fully covered by insurance.

Competition for the acquisition of new seismic data is intense.

There are a number of geophysical companies that create, market and license seismic data and maintain seismic libraries. Competition for acquisition of new seismic data among geophysical service providers historically has been, and we expect will continue to be, intense. Certain competitors have significantly greater financial and other resources than we do. These larger and better-financed operators could enjoy an advantage over us in a competitive environment for new data.

Our operating results and cash flows are subject to fluctuations due to circumstances that are beyond our control.

Our operating results and cash flows from operations have in the past, and may in the future, vary in material respects from period to period. Factors that have and could cause variations include (1) timing of the receipt and commencement of contracts for data acquisition, (2) our customers’ budgetary cycles and their effect on the demand for geophysical products and services, (3) seasonal factors, (4) the timing of sales of licenses and selections of significant geophysical data from our data library, which are not typically made in a linear or consistent pattern and (5) technological or regulatory changes. These revenue fluctuations could produce unexpected adverse operating results in any period.

Reduced demand for our seismic data may result in an impairment of the value of our seismic data library.

Reduced demand, future sales or cash flows may result in a requirement to increase amortization rates or record impairment charges to reduce the carrying value of our data library. Such increases or charges, if required, could be material to operating results in the periods in which they are recorded. For purposes of evaluating potential impairment losses, we estimate the future cash flows attributable to a library component by evaluating historical and recent revenue trends, oil and gas prospectivity in particular regions, general economic conditions affecting our customer base, expected changes in technology and other factors that we deem relevant. As a result of these factors, among others, estimations of future cash flows are highly subjective, inherently imprecise and can fluctuate materially from period to period. Accordingly, if conditions change in the future, we may record impairment losses relative to our seismic data library, which could materially affect our results of operations in any particular reporting period.

Failure to meet cash flow projections may result in goodwill impairment charges.

We perform an annual assessment of the recoverability of goodwill by applying qualitative procedures. Additionally, we assess goodwill for impairment whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If required to perform a goodwill impairment test, we rely on discounted cash flow analysis, which requires significant judgments and estimates about our future operations, to develop our estimates of fair value. If these projected cash flows change materially, we may be required to record impairment losses relative to goodwill which could be material to our results of operations in any particular reporting period.

Our Canadian operations subject us to currency translation risk, which could cause our results to fluctuate significantly from period to period.

A portion of our revenues are derived from our Canadian activities and operations. As a result, we translate the results of our operations and financial condition of our Canadian operations into U.S. dollars. Therefore, our reported results of operations and financial condition are subject to changes in the exchange rate between the two currencies. Fluctuations in foreign currency

17

Table of Contents



exchange rates could affect our revenue, expenses and operating margins. Assets and liabilities of Canadian operations are translated from Canadian dollars into U.S. dollars at the exchange rates in effect at the relevant balance sheet date, and revenue and expenses of Canadian operations are translated from Canadian dollars into U.S. dollars at exchange rates as of the dates on which they are recognized. Translation adjustments related to assets and liabilities are included in accumulated other comprehensive income (loss) in stockholder's equity. Realized gains and losses on translation of the Canadian operations into U.S. dollars are included in net income (loss). Currently, we do not hedge our exposure to changes in foreign exchange rates.
We may be unable to attract and retain key employees.
Our success depends upon attracting and retaining highly skilled geophysical professionals and other technical personnel. A failure to continue to attract and retain these individuals could adversely affect our ability to compete in the geophysical services industry. We may confront significant and potentially adverse competition for key personnel, particularly during periods of increased demand for geophysical services.
Our success also depends to a significant extent upon the abilities and efforts of members of our senior management, the loss of whom could adversely affect our business. Senior executives, which include our President and Chief Executive Officer, Chief Operating Officer, Chief Financial Officer, General Counsel, President of Seitel Data, Ltd. and President of Olympic Seismic Ltd., have employment agreements with us. We cannot be certain that our senior executives will continue to be employed by us for an indefinite period of time and, if they do, how long they will remain so employed. Our inability to attract and retain key management personnel could have a material adverse effect on our ability to manage our business properly.
Current and future government regulation may negatively impact demand for our products and services and increase our cost of conducting business.
The conduct of our business and the use of our products and services are subject to various laws and regulations administered by federal, state and local governmental agencies in the United States and Canada. These laws and regulations may impose numerous obligations that are applicable to our operations including:
the acquisition of permits before commencing regulated activities; and
the limitation or prohibition of seismic activities in environmentally sensitive or protected areas such as wetlands or wilderness areas.
Failure to comply with laws, regulations, permits, and Indian First Nations protocol may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. Additionally, these laws and regulations may change as a result of political, economic or social events. Changes in laws, regulations or governmental policy may alter the environment in which we do business and the demand for our products and services and, therefore, may impact our results of operations or increase our liabilities. Current and future laws, regulations and policies concerning perceived greenhouse gas emissions and the use of renewable energy sources rather than fossil fuels could adversely impact the operations of our customers. Changes in these and other laws and regulations or additional regulation could cause the demand for our products to decrease. Moreover, complying with increased or changed regulations could cause our operating expenses to increase, which could adversely affect our business.
Technological changes not available to us could adversely affect our business.
New data acquisition or processing technologies may be developed. New and enhanced products and services introduced by one of our competitors may gain market acceptance and, if not available to us, may adversely affect us.

Our internal controls for financial reporting and our disclosure controls and procedures may not prevent all possible errors that could occur.
Our Chief Executive Officer and Chief Financial Officer evaluate on a quarterly basis our internal controls for financial reporting and our disclosure controls and procedures, which includes a review of the objectives, design, implementation and effect of the controls in respect of the information generated for use in our periodic reports. In the course of our controls evaluation, we seek to identify data errors, control problems and to confirm that appropriate corrective action, including process improvements, are being undertaken. The overall goals of these various evaluation activities are to monitor our internal controls for financial reporting and our disclosure controls and procedures and to make modifications as necessary. Our intent in this regard is that our internal controls for financial reporting and our disclosure controls and procedures will be maintained as dynamic systems that change (including with improvements and corrections) as conditions warrant.
A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be satisfied. Our management has concluded that our internal controls for financial reporting

18

Table of Contents



and our disclosure controls and procedures are designed to give a reasonable assurance that they are effective to achieve their objectives. We cannot provide absolute assurance that we have detected all possible control issues. These inherent limitations include the possibility that judgments in our decision-making could be faulty, and that isolated breakdowns could occur because of simple human error or mistake. The design of our system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed absolutely in achieving our stated goals under all potential future or unforeseeable conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud could occur and not be detected. Breakdowns in our internal controls and procedures could occur in the future, and any such breakdowns could have an adverse effect on us.

RISKS RELATED TO OUR INDEBTEDNESS

Our level of indebtedness could adversely affect our financial condition and our ability to fulfill our obligations and operate our business.

As of December 31, 2012, we had approximately $278.1 million of total outstanding indebtedness, including $3.1 million of capital leases. In addition, we have $20.0 million available for borrowing under our revolving credit facility, none of which was drawn at December 31, 2012. Our 2013 consolidated annual debt service requirements are expected to aggregate approximately $27.3 million. We may also incur additional indebtedness in the future.
Our level of indebtedness could have negative consequences to us, including:
we may have difficulty satisfying our obligations with respect to our debt;
we may have difficulty obtaining financing in the future for working capital, capital expenditures, acquisitions or other purposes;
we may need to use all, or a substantial portion, of our available cash flow to pay interest and principal on our debt, which will reduce the amount of money available to finance our operations and other business activities;
our vulnerability to general economic downturns and adverse industry conditions could increase;
our flexibility in planning for, or reacting to, changes in our business and in our industry in general could be limited;
our amount of debt and the amount we must pay to service our debt obligations could place us at a competitive disadvantage compared to our competitors that have less debt;
our customers may react adversely to our significant debt level and seek or develop alternative licensors or suppliers;
we may have insufficient funds, and our debt level may also restrict us from raising the funds necessary to repurchase all of the notes tendered to us upon the occurrence of a change of control, which would constitute an event of default under the notes; and
our failure to comply with the restrictive covenants in our debt instruments which, among other things, limit our ability to incur debt and sell assets, could result in an event of default that, if not cured or waived, could have a material adverse effect on our business or prospects.
Our level of indebtedness requires that we use a substantial portion of our cash flow from operations to pay principal of, and interest on, our indebtedness, which will reduce the availability of cash to fund working capital requirements, capital expenditures, research and development and other general corporate or business activities, including future acquisitions.
In addition, our revolving credit facility bears interest at variable rates. If market interest rates increase, debt service on our credit facility will rise, which would adversely affect our cash flow. Although we may employ hedging strategies such that a portion of the aggregate principal amount of this credit facility carries a fixed rate of interest, any hedging arrangement put in place may not offer complete protection from this risk. Additionally, the remaining portion of this credit facility may not be hedged and, accordingly, the portion that is not hedged will be subject to changes in interest rates.
The indenture governing our $275.0 million aggregate principal amount of 9.75% senior notes due 2014 ("the 9.75% Senior Notes") contains a number of restrictive covenants which limit our ability to finance future operations or capital needs or engage in other business activities that may be in our interest.
The indenture governing our 9.75% Senior Notes imposes, and the terms of any future indebtedness may impose, operating and other restrictions on us and our subsidiaries. Such restrictions affect or will affect, and in many respects limit or prohibit, among other things, our ability and the ability of certain of our subsidiaries to:
incur additional indebtedness;
create liens;
pay dividends and make other distributions in respect of our capital stock;
redeem our capital stock;
make investments or certain other restricted payments;

19

Table of Contents



sell certain kinds of assets;
enter into transactions with affiliates; and
effect mergers or consolidations.
The restrictions contained in the indenture governing our 9.75% Senior Notes could:
limit our ability to plan for or react to market or economic conditions or meet capital needs or otherwise restrict our activities or business plans; and
adversely affect our ability to finance our operations, acquisitions, investments or strategic alliances or other capital needs or to engage in other business activities that would be in our interest.
A breach of any of these covenants could result in a default under the indenture governing our 9.75% Senior Notes. If an event of default occurs, the lenders could elect to:
declare all borrowings outstanding, together with accrued and unpaid interest, to be immediately due and payable; or
require us to apply all of our available cash to repay the borrowings.
If we were unable to repay or otherwise refinance these borrowings when due, we cannot assure you that sufficient assets will remain to repay the 9.75% Senior Notes.

Item 1B. Unresolved Staff Comments
None.

Item 2. Properties
Our corporate headquarters are located at 10811 South Westview Circle Drive, Suite 100, Building C, Houston, Texas 77043, which also serves as administrative and financial offices, warehouse space and storage. We maintain domestic marketing offices in Denver, Colorado; Irving, Texas; New Orleans, Louisiana and Oklahoma City, Oklahoma. We recently opened data processing and marketing offices in Pittsburgh, Pennsylvania. We also lease office and warehouse space in two separate locations in Calgary, Alberta, Canada, where our Canadian operations are headquartered. We consider our business facilities adequate and suitable for our present and anticipated future needs, but may seek to expand our facilities from time to time.
The following table sets forth the locations of our offices and warehouses, the approximate square footage of space we maintain at such locations, our use of such space and whether it is owned or leased by us. 
 
 
Approximate
 
 
 
 
 
 
Square
 
 
 
 
Location
  
Footage
  
Use
 
Owned/Leased
Houston, Texas
  
80,125
  
Administrative; Financial; Marketing; Operations; Warehouse
 
Leased
Denver, Colorado
  
1,513
  
Marketing
 
Leased
Irving, Texas
 
610
 
Marketing
 
Leased
New Orleans, Louisiana
  
364
  
Marketing
 
Leased
Oklahoma City, Oklahoma
  
234
  
Marketing
 
Leased
Pittsburgh, Pennsylvania
 
290
 
Marketing; Data Processing
 
Leased
Calgary, Alberta, Canada
 
14,909
 
Administrative; Financial; Marketing; Operations
 
Leased
Calgary, Alberta, Canada (a)
  
23,270
  
Not currently utilized. The lease on this facility terminates in May 2013.
 
Leased
Calgary, Alberta, Canada
  
42,985
  
Warehouse
 
Leased
 
(a) 
We have subleased 11,635 square feet of this office space to a third party through the end of our lease term.

Item 3. Legal Proceedings
We are involved from time to time in ordinary, routine claims and lawsuits incidental to our business. In the opinion of management, uninsured losses, if any, resulting from the ultimate resolutions of these matters should not be material to our financial position, results of operations or cash flows. However, it is not possible to predict or determine the outcomes of the legal actions brought against us or by us, or to provide an estimate of all additional losses, if any, that may arise. At December 31, 2012, we have recorded the estimated amount of potential exposure we may have with respect to litigation and claims. Such amounts are not material to the financial statements.

Item 4. Mine Safety Disclosures

20

Table of Contents



Not applicable.
PART II

Item 5. Market for Registrant's Common Equity, Securities Related Stockholder Matters and Issuer Purchases of Equity
Market Information
Our common stock is privately held and there is no established public trading market for our common stock. As of December 31, 2012, there was one holder of record of our 100 shares of common stock, $0.001 par value.
Dividend Policy
We have not declared or paid any cash dividends on our common stock during our two most recent fiscal years. We do not intend to declare or pay any cash dividends on our common stock in the foreseeable future. Covenants within our revolving credit facility and our 9.75% Senior Notes restrict our ability to pay cash dividends on our capital stock. Future declaration and payment of cash dividends, if any, on our common stock will be determined in light of factors deemed relevant by our board of directors, including our earnings, operations, capital requirements and financial condition and restrictions in our financing agreements.

Item 6. Selected Consolidated Financial Data

The following table summarizes certain historical consolidated financial data of Seitel and is qualified in its entirety by the more detailed consolidated financial statements and notes thereto included herein (in thousands, except shares).
 
 
Year Ended December 31,
 
2012
 
2011
 
2010
 
2009
 
2008
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Revenue
$
240,458

 
$
218,008

 
$
175,556

 
$
115,345

 
$
172,403

Expenses and costs:
 
 
 
 
 
 
 
 
 
Depreciation and amortization
139,754

 
142,963

 
175,592

 
150,199

 
168,629

Impairment of intangible asset

 

 

 

 
225

Cost of sales
464

 
100

 
97

 
290

 
462

Selling, general and administrative
29,088

 
31,649

 
31,831

 
25,090

 
36,316

Merger

 

 

 

 
357

 
169,306

 
174,712

 
207,520

 
175,579

 
205,989

Income (loss) from operations
71,152

 
43,296

 
(31,964
)
 
(60,234
)
 
(33,586
)
Interest expense, net
(29,011
)
 
(34,767
)
 
(40,536
)
 
(40,696
)
 
(40,017
)
Foreign currency exchange gains (losses)
681

 
(726
)
 
441

 
1,008

 
(4,059
)
Loss on early extinguishment of debt

 
(7,912
)
 

 

 

Gain on sale of marketable securities
230

 
2,467

 
4,188

 

 

Other income
780

 
250

 
446

 
151

 
40

Income (loss) before income taxes
43,832

 
2,608

 
(67,425
)
 
(99,771
)
 
(77,622
)
Provision (benefit) for income taxes
6,782

 
392

 
(4,008
)
 
(2,974
)
 
(3,548
)
Net income (loss)
$
37,050

 
$
2,216

 
$
(63,417
)
 
$
(96,797
)
 
$
(74,074
)
 

21

Table of Contents



 
As of December 31,
 
2012
 
2011
 
2010
 
2009
 
2008
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
61,891

 
$
74,894

 
$
89,971

 
$
26,270

 
$
42,678

Seismic data library, net
180,117

 
120,694

 
106,104

 
200,389

 
279,257

Total assets
550,744

 
500,330

 
491,009

 
522,019

 
643,825

Total debt
278,142

 
278,256

 
405,604

 
405,732

 
405,499

Stockholder’s equity (deficit)
150,358

 
109,840

 
(7,022
)
 
46,361

 
115,785

Common shares outstanding
100

 
100

 
100

 
100

 
100



Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read in conjunction with our consolidated financial statements and the related notes to the financial statements included elsewhere in this document.
Overview
General
Our products and services are used by oil and gas companies to assist in oil and gas exploration and development of hydrocarbon reserves. Historically, seismic data was tied to exploration capital expenditures as exploration and production ("E&P") companies used seismic data to increase the success rate of discovering hydrocarbon deposits. With the shift to unconventional plays, E&P companies now use seismic data as a development tool to better identify efficient drilling plans and maximize production by identifying and understanding a series of critical characteristics of the targeted resource. We own an extensive library of onshore and offshore seismic data that we offer for license to oil and gas companies. We believe that our library of onshore seismic data is the largest available for licensing in North America. We generate revenue primarily by licensing data from our data library and from new data creation products, which are substantially underwritten or paid for by our clients. By participating in underwritten, nonexclusive surveys or purchasing licenses to existing data, oil and gas companies can obtain access to surveys at reduced costs as compared to acquiring seismic data on a proprietary basis.
Our primary areas of focus are onshore United States and Canada and, to a lesser extent, offshore U.S. Gulf of Mexico. These markets continue to experience major changes. Major integrated oil and gas companies and national oil companies have become more active in the North American market, primarily in the unconventional plays, through joint ventures, asset purchases and corporate transactions. The larger independent oil and gas companies continue to be responsible for a significant portion of current U.S. drilling activity. Our offshore seismic data is primarily located in the shallow waters of the U.S. Gulf of Mexico and generates a small percentage of our revenue.
Our clients continue to seek our services to create data in the United States and Canada. On February 19, 2013, our clients' commitment for underwriting on new data creation projects was $66.3 million. Licensing data “off the shelf” does not require the longer planning and lead times like new data creation and thus is more likely to fluctuate quarter to quarter.
Principal Factors Affecting Our Business
Our business is dependent upon a variety of factors, many of which are beyond our control. The following are those that we consider to be principal factors affecting our business.
Demand for Seismic Data: Demand for our products and services is cyclical due to the nature of the oil and gas industry. In particular, demand for our seismic data services depends upon exploration, production, development and field management spending by oil and gas companies and, in the case of new data creation, the willingness of these companies to forgo ownership in the seismic data. Capital expenditures by oil and gas companies depend upon several factors, including actual and forecasted oil and natural gas commodity prices, prospect availability and the companies' own short-term and strategic plans. These capital expenditures may also be affected by worldwide economic or industry-wide conditions. With the shift to unconventional plays, seismic data is increasingly tied to relatively stable development capital expenditures.
Merger and Acquisition/Joint Venture Activity: Merger and acquisition activity continues to occur within our client base. This activity could have a negative impact on seismic companies that operate in markets with a limited number of participating clients. However, we believe that, over time, this activity could have a positive impact on our business, as it should generate re-licensing fees, result in increased vitality in the trading of mineral interests and result in the creation of new independent customers through the rationalization of staff within those companies affected by this activity.

22

Table of Contents



Exploiting unconventional plays is a capital intensive endeavor and many technically proficient E&P companies remain capital constrained. They find themselves needing to sell their positions to, or create partnerships with, large well-capitalized companies in order to develop their recoverable resource base. These joint venture partners or new owners will often need to purchase licenses to our seismic data for their own use.

North America Drilling Activity: Drilling activity has shifted to areas with liquids-rich hydrocarbons, such as the Eagle Ford/Woodbine, Niobrara/Bakken and Utica/Marcellus in the U.S. and Montney and Cardium in Canada with several emerging plays, including the Granite Wash (Panhandle Plays), Sussex, Mowry and Point Pleasant in the U.S. and Duvernay in Canada. Horizontal drilling rigs in oil and liquids-rich areas have leveled off in recent months due to drilling efficiencies and weaker crude oil prices, while activity in dry gas areas continues to be depressed until demand and gas prices strengthen.

Availability of Capital for Our Customers: Some of our customers are independent oil and gas companies and private prospect-generating companies that rely primarily on private capital markets to fund their exploration, production, development and field management activities. Reductions in cash flows resulting from lower commodity prices, along with the reduced availability of credit and increased costs of borrowing, could have a material impact on the ability of such companies to obtain funding necessary to purchase our seismic data.
Government Regulation: Our operations are subject to a variety of federal, provincial, state, foreign and local laws and regulations, including environmental and health and safety laws. We invest financial and managerial resources to comply with these laws and related permit requirements. Modification of existing laws or regulations and the adoption of new laws or regulations limiting or increasing exploration or production activities by oil and gas companies may have a material effect on our business operations.
Non-GAAP Key Performance Measures
Management considers certain performance measures in evaluating and managing our financial condition and operating performance at various times and from time to time. Some of these performance measures are non-GAAP financial measures. Generally, a non-GAAP financial measure is a numerical measure of a company's performance, financial position or cash flows that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with United States generally accepted accounting principles, or GAAP. These non-GAAP measures are not in accordance with, nor are they a substitute for, GAAP measures. These non-GAAP measures are intended to supplement our presentation of our financial results that are prepared in accordance with GAAP.
The following are the key performance measures considered by management.
Cash Resales
Cash resales represent new contracts for data licenses from our library, including data currently in progress, payable in cash. We believe this measure is important in assessing overall industry and client activity. Cash resales are likely to fluctuate quarter to quarter as they do not require the longer planning and lead times necessary for new data creation.

The following is a reconciliation of this non-GAAP financial measure to the most directly comparable GAAP financial measure, total revenue (in thousands): 
 
Year Ended December 31,
 
2012
 
2011
 
2010
Cash resales
$
136,234

 
$
134,497

 
$
137,605

Other revenue components:
 
 
 
 
 
Acquisition underwriting revenue
107,254

 
77,406

 
40,500

Non-monetary exchanges
1,554

 
7,609

 
4,678

Revenue recognition adjustments
(10,257
)
 
(5,856
)
 
(11,005
)
Solutions and other
5,673

 
4,352

 
3,778

Total revenue
$
240,458

 
$
218,008

 
$
175,556


Cash EBITDA
Cash EBITDA represents cash generated from licensing data from our seismic library net of recurring cash operating expenses. We believe this measure is helpful in determining the level of cash from operations we have available for debt service and funding of capital expenditures (net of the portion funded or underwritten by our customers). Cash EBITDA includes cash

23

Table of Contents



resales plus all other cash revenues other than from data acquisitions, plus gains on sales of marketable securities and cash distributions from investments obtained as part of licensing our seismic data, less cost of goods sold and cash selling, general and administrative expenses (excluding non-recurring corporate expenses such as severance and legal, financial and other expenses related to corporate and strategic transactions).
The following is a quantitative reconciliation of this non-GAAP financial measure to the most directly comparable GAAP financial measure, operating income (loss) (in thousands):
 
 
Year Ended December 31,
 
2012
 
2011
 
2010
Cash EBITDA
$
115,347

 
$
112,031

 
$
117,252

Add (subtract) other revenue components not included in cash EBITDA:
 
 
 
 
 
Acquisition underwriting revenue
107,254

 
77,406

 
40,500

Non-monetary exchanges
1,554

 
7,609

 
4,678

Revenue recognition adjustments
(10,257
)
 
(5,856
)
 
(11,005
)
Solutions non-cash revenue
20

 
71

 

Less:
 
 
 
 
 
Gain on sale of marketable securities
(230
)
 
(2,467
)
 
(4,188
)
Cash distributions from investments
(400
)
 

 

Depreciation and amortization
(139,754
)
 
(142,963
)
 
(175,592
)
Non-recurring corporate expenses
(1,228
)
 
(1,792
)
 
(176
)
Non-cash operating expenses
(1,154
)
 
(743
)
 
(3,433
)
Operating income (loss)
$
71,152

 
$
43,296

 
$
(31,964
)
Growth of our Seismic Data Library
We regularly add to our seismic data library through four different methods: (1) recording new data, (2) buying ownership of existing data for cash, (3) obtaining ownership of existing data sets through non-monetary exchanges and (4) creating new value-added products from existing data within our library. For the years ended December 31, 2012, 2011 and 2010, we completed the addition of approximately 2,800 square miles, 2,200 square miles and 900 square miles, respectively, of seismic data to our library. For the period from January 1, 2013 to February 19, 2013 we completed the addition of approximately 100 square miles and as of February 19, 2013 we had approximately 2,400 square miles of seismic data in progress.

Critical Accounting Policies
We operate in one business segment, which is made up of seismic data acquisition, seismic data licensing, seismic data processing and seismic reproduction services.
We prepare our financial statements and the accompanying notes in conformity with GAAP, which requires management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition and results of operations and the degree of difficulty, subjectivity and complexity in their deployment. Notes A and B of the notes to the consolidated financial statements include a summary of the significant accounting policies used in the preparation of the accompanying consolidated financial statements. The following is a brief discussion of our most critical accounting policies.
Revenue Recognition
Revenue from Data Acquisition
We generate revenue when we create a new seismic survey that is initially licensed by one or more of our customers to use the resulting data. We consider the contracts signed up to the time we make a firm commitment to create the new seismic survey as underwriting. Underwriting revenue is recognized throughout the creation period using the proportional performance method based upon costs incurred and work performed to date as a percentage of total estimated costs and work required. Management believes that this method is the most reliable and representative measure of progress for our data creation projects. The customers paying for the initial licenses receive legally enforceable rights to any resulting product of the specific activities required to complete the survey. The customers also receive access to and use of the newly acquired, processed data.    

24

Table of Contents



Revenue from Non-Exclusive Data Licenses
We recognize a substantial portion of our revenue from licensing of data once it is available for delivery. Revenue from the non-exclusive licensing of seismic data is recognized when the following criteria are met:
we have an arrangement with the customer that is validated by a signed contract;
the sales price is fixed and determinable;
collection is reasonably assured;
the customer has selected the specific data or the contract has expired without full selection;
the data is currently available for delivery; and
the license term has begun.
Copies of the data are available to the customer immediately upon request.
For licenses that have been invoiced for which payment is due or has been received, but have not met the aforementioned criteria, the revenue is deferred along with the related direct costs (primarily sales commissions). This normally occurs under the library card, review and possession or review only license contracts because the data selection may occur over time. Additionally, if the contract allows licensing of data that is not currently available or enhancements, modifications or additions to the data are required per the contract, revenue is deferred until such time that the data is available.    
Revenue from Non-Monetary Exchanges
In certain cases, we will take ownership of a customer's seismic data or revenue interest (collectively referred to as “data”) or receive advanced data processing services in exchange for a non-exclusive license to selected seismic data from our library, as partial consideration for the underwriting of new data acquisition or, in some cases, services provided by Solutions. These exchanges are referred to as non-monetary exchanges. In non-monetary exchange transactions, we record a data library asset for the data received or processed at the time the contract is entered into or the data is completed, as applicable, and recognize revenue on the transaction in equal value in accordance with our policies on revenue from data licenses, which is, when the seismic data is selected by the customer, or revenue from data acquisition, as applicable, or as services are provided by Solutions. These transactions are valued at the fair value of the data received or delivered, whichever is more readily determinable.
Seismic Data Library
Costs associated with creating, acquiring or purchasing seismic data are capitalized and amortized principally on the income forecast method subject to a straight-line amortization period of four years, applied on a quarterly basis at the individual survey level.
Data Library Amortization
We amortize our seismic data library using the greater of the amortization that would result from the application of the income forecast method (subject to a minimum amortization rate) or a straight-line basis over the useful life of the data. Due to the subjectivity inherent in the income forecast amortization method, this amortization policy ensures a minimum level of amortization will be recorded if sales of the specific data do not occur as expected and ensures that costs are fully amortized at the end of the data’s useful life. With respect to each survey in the data library, the straight-line policy is applied from the time such survey is available for licensing to customers on a non-exclusive basis.
We apply the income forecast method by forecasting the ultimate revenue expected to be derived from a particular data library component over the estimated useful life of each survey comprising part of such component. We make this forecast annually and review it quarterly. If, during any such review, we determine that the ultimate revenue for a library component is expected to be significantly different than the original estimate of total revenue for such library component, we revise the amortization rate attributable to future revenue from each survey in such component.
The greater of the income forecast or straight-line amortization policy is applied quarterly on a cumulative basis at the individual survey level. Under this policy, we first record amortization using the income forecast method. The cumulative amortization recorded for each survey is then compared with the cumulative straight-line amortization. If the cumulative straight-line amortization is higher for any specific survey, additional amortization expense is recorded, resulting in accumulated amortization being equal to the cumulative straight-line amortization for such survey. This requirement is applied regardless of future-year revenue estimates for the library component of which the survey is a part and does not consider the existence of deferred revenue with respect to the library component or to any survey.
    

25

Table of Contents



Seismic Data Library Impairment
We evaluate our seismic data library for impairment by grouping individual surveys into components based on our operations and geological and geographical trends. We believe that these library components constitute the lowest levels of independently identifiable cash flows. We evaluate our seismic data library investment for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.
The impairment evaluation is based first on a comparison of the undiscounted future cash flows over each component's remaining estimated useful life with the carrying value of each library component. If the undiscounted cash flows are equal to or greater than the carrying value of such component, no impairment is recorded. If undiscounted cash flows are less than the carrying value of any component, the forecast of future cash flows related to such component is discounted to fair value and compared with such component's carrying amount. The difference between the library component's carrying amount and the discounted future value of the expected revenue stream is recorded as an impairment charge.
The estimation of future cash flows and fair value is highly subjective and inherently imprecise. Estimates can change materially from period to period based on many factors, including those described in the preceding paragraph. Accordingly, if conditions change in the future, we may record impairment losses relative to our seismic data library, which could be material to any particular reporting period.

Goodwill

Goodwill is not amortized to earnings but is assessed, at least annually, for impairment at the reporting unit level. We conduct a qualitative goodwill impairment assessment as of October 1 of each year by examining relevant events and circumstances which could have a negative impact on our goodwill such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, and other relevant entity-specific events. If after assessing the totality of events or circumstances described above, we determine that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, the two-step goodwill test is performed. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable.
Use of Estimates and Assumptions
In preparing our financial statements, a number of estimates and assumptions are made by management that affect the accounting for and recognition of assets, liabilities, revenues and expenses. These estimates and assumptions must be made because certain information that is used in the preparation of our financial statements is dependent on future events, cannot be calculated with a high degree of precision from data available or is not otherwise capable of being readily calculated based on generally accepted methodologies. In some cases, these estimates are particularly difficult to determine and we must exercise significant judgment.
The most difficult, subjective and complex estimates and assumptions that deal with the greatest amount of uncertainty are related to our accounting for our seismic data library and goodwill.
Accounting for our seismic data library requires us to make significant subjective estimates and assumptions relative to future sales and cash flows from such library. These cash flows impact amortization rates, as well as potential impairment charges. Any changes in these estimates or underlying assumptions will impact our income from operations prospectively from the date changes are made. To the extent that such estimates, or the assumptions used to make those estimates, prove to be significantly different than actual results, the carrying value of the seismic data library may be subject to higher prospective amortization rates, additional straight-line amortization or impairment losses.
Because we apply a minimum income forecast amortization rate of 70%, the effect of decreasing future sales by 10%, with all other factors remaining constant, would cause the range of amortization rates to be from 70% to 75% as of January 1, 2013. The effect of decreasing future sales by 20%, with all other factors remaining constant, would cause the range of amortization rates to be from 70% to 85% as of January 1, 2013.
In a portion of our seismic data library activities, we engage in certain non-monetary exchanges and record a data library asset for the seismic data received and recognize revenue on the transaction in accordance with our policies on revenue recognition. These transactions are valued at the fair value of the data received by us or licenses or services granted by us, whichever is more readily determinable. Our estimate of the value of these transactions is highly subjective and based, in large part, on data sales transactions between us and a limited number of customers over a limited time period.

We conduct a qualitative goodwill impairment assessment at least annually. If, based on our qualitative procedures, it is more likely than not that the fair value of a reporting unit is less than its carrying amount, we are required to perform a two-step

26

Table of Contents



impairment test to identify potential goodwill impairment and measure the amount of a goodwill impairment loss to be recognized. The impairment test involves a comparison of the fair value of a reporting unit with its carrying amount, including goodwill to identify if a goodwill impairment exists. For our estimates of the fair value of goodwill, we prepare discounted cash flow analysis, which requires significant judgments and estimates about our future performance. If these projected cash flows change materially, we may be required to record impairment losses relative to goodwill.
Actual results could differ materially from the estimates and assumptions that we use in the preparation of our financial statements. To the extent management's estimates and assumptions change in the future, the effect on our reported results could be significant to any particular reporting period.
Results of Operations
Revenue
The following table summarizes the components of our revenue for the years ended December 31, 2012, 2011 and 2010 (in thousands): 
 
Year Ended December 31,
 
2012
 
2011
 
2010
Acquisition underwriting revenue:
 
 
 
 
 
Cash underwriting
$
101,803

 
$
75,132

 
$
37,823

Underwriting from non-monetary exchanges
5,451

 
2,274

 
2,677

Total acquisition underwriting revenue
107,254

 
77,406

 
40,500

Resale licensing revenue:
 
 
 
 
 
Cash resales
136,234

 
134,497

 
137,605

Non-monetary exchanges
1,554

 
7,609

 
4,678

Revenue recognition adjustments
(10,257
)
 
(5,856
)
 
(11,005
)
Total resale licensing revenue
127,531

 
136,250

 
131,278

Total seismic revenue
234,785

 
213,656

 
171,778

Solutions and other
5,673

 
4,352

 
3,778

Total revenue
$
240,458

 
$
218,008

 
$
175,556

Total revenue for the year ended December 31, 2012 was $240.5 million, an increase of $22.5 million or 10%, from the year ended December 31, 2011 total revenue of $218.0 million. This increase was primarily due to an increase in acquisition underwriting revenue which increased to $107.3 million in 2012 compared to $77.4 million in 2011. Activity for new data acquisition remained strong in 2012 with our acquisition underwriting revenue occurring in the key active unconventional plays in North America focused on oil and liquids-rich hydrocarbons including Eagle Ford, Utica/Marcellus, Niobrara, Granite Wash (Panhandle Plays), Montney and Cardium. Total resale licensing revenue was $127.5 million in 2012 compared to $136.3 million in 2011. Cash resales were $136.2 million in 2012 compared to $134.5 million in 2011. In 2012, cash resales were distributed across most basins in which we have seismic data, including unconventional and conventional areas, with a focus on oil and liquids-rich areas. Non-monetary exchanges fluctuate year to year depending upon the data available for trade and totaled $1.6 million in 2012 compared to $7.6 million in 2011. Revenue recognition adjustments are non-cash adjustments to revenue and reflect the net amount of (i) revenue deferred as a result of all of the revenue recognition criteria not being met and (ii) the subsequent revenue recognition once the criteria are met. The change in revenue recognition adjustments between 2011 and 2012 which resulted in a decrease in revenue recognized of $4.4 million between periods was due to a decrease in revenue recognized on library card contracts (i.e., more deferrals than selections in the year) partially offset by an increase on direct licensing contracts because the revenue recognition criteria were met. Solutions and other revenue was $5.7 million in 2012 compared to $4.4 million in 2011. The $1.3 million increase was due to the types of products delivered and revenue from third-party data processing projects.
Total revenue was $218.0 million for the year ended December 31, 2011 compared to $175.6 million for the year ended December 31, 2010. This $42.5 million, or 24%, increase was primarily due to an increase in acquisition underwriting revenue. Acquisition underwriting revenue increased to $77.4 million in 2011 compared to $40.5 million in 2010 due to our campaign to acquire data in unconventional plays and client interest in participating in the new projects. All of our data acquisition underwriting revenue in 2011 occurred in the key active unconventional plays in North America, primarily the Eagle Ford, Marcellus, Niobrara, Montney and Cardium. Total resale licensing revenue was $136.3 million in 2011 compared to $131.3 million in 2010. Cash resales were $134.5 million in 2011 compared to $137.6 million in 2010. The decrease between years

27

Table of Contents



was primarily the result of a shift from gas-directed plays due to lower natural gas prices to areas focused more on oil and liquids production. Non-monetary exchanges fluctuate year to year depending upon the data available for trade and totaled $7.6 million in 2011 compared to $4.7 million in 2010. The increase of $5.1 million in revenue recognition adjustments from 2010 to 2011 was primarily due to an increase in recognition of revenue previously deferred as a result of new data acquisition projects being completed and delivered partially offset by an increase in the deferral of new licensing contracts. Solutions and other revenue increased $0.6 million in 2011 compared to 2010 due to the increase in total seismic revenue and the types of products delivered.
At December 31, 2012, we had a deferred revenue balance of $52.9 million compared to the December 31, 2011 balance of $48.8 million. The deferred revenue balance was related to (i) data licensing contracts on which selection of specific data had not yet occurred, (ii) deferred revenue on new data acquisition projects and (iii) contracts in which the data products are not yet available or the revenue recognition criteria has not yet been met. The deferred revenue will be recognized when selection of specific data is made by the customer, upon expiration of the data selection period specified in the data licensing contracts, as work progresses on the data acquisition contracts, as the data products become available for delivery or as all of the revenue recognition criteria are met. Deferred revenue will be recognized no later than the following, based on the expiration of the selection period or our estimate of progress on acquisition projects and the availability of data products, although some revenue may be recognized earlier (in thousands):
 
2013.............................................................
$
44,788

2014............................................................
6,570

2015 and thereafter.....................................
1,499

Depreciation and Amortization
Depreciation and amortization was comprised of the following (in thousands):
 
 
Year Ended December 31,
 
2012
 
2011
 
2010
Amortization of seismic data:
 
 
 
 
 
Income forecast
$
108,482

 
$
102,210

 
$
87,617

Straight-line
24,354

 
32,758

 
80,190

Total amortization of seismic data
132,836

 
134,968

 
167,807

Depreciation of property and equipment
1,127

 
2,167

 
2,081

Amortization of acquired intangibles
5,791

 
5,828

 
5,704

Total
$
139,754

 
$
142,963

 
$
175,592

Total seismic data library amortization amounted to $132.8 million, $135.0 million and $167.8 million in 2012, 2011 and 2010, respectively. The amount of seismic data library amortization fluctuates based on the level and location of specific seismic surveys licensed (including licensing resulting from new data acquisition) and selected by our customers during any period as well as the amount of straight-line amortization required under our accounting policy. Additionally, the step-up in our data library value resulting from the Merger became fully amortized in the first quarter of 2011 which resulted in a decrease in the level of straight-line amortization in 2011 and 2012.

Seismic data amortization as a percentage of total seismic revenue is summarized as follows:
 
 
Year Ended December 31,
Components of Amortization
2012
 
2011
 
2010
Income forecast
46
%
 
48
%
 
51
%
Straight-line
10
%
 
15
%
 
47
%
Total
56
%
 
63
%
 
98
%
The percentage of income forecast amortization to total seismic revenue was 46% for the year ended December 31, 2012; 48% for the year ended December 31, 2011; and 51% for the year ended December 31, 2010. In all three years, we had resale revenue recognized which was from data whose costs were fully amortized. In 2012, 63% of resales did not attract amortization, as compared to 50% in 2011 and 36% in 2010. Additionally, all acquisition revenue attracts amortization; thus, the increasing level of acquisition revenue between 2010 and 2012 impacted the overall percentage of income forecast amortization. Straight-line amortization represents the expense required under our accounting policy to ensure our data value is fully amortized within four years of when the data becomes available for sale. The $8.4 million decrease in straight-line

28

Table of Contents



amortization from 2011 to 2012 and the $47.4 million decrease from 2010 to 2011 was because a significant portion of our data library became fully amortized in the first quarter of 2011 due to such data reaching its four-year life after the Merger and due to the distribution of revenue among the various seismic surveys.
For each of the years ended December 31, 2012, 2011 and 2010, the rates utilized under the income forecast method was 70% for all components. The rate of amortization with respect to each component is decreased or increased if our estimate of future cash sales from such component is materially increased or decreased, subject to a minimum amortization rate of 70%. Additionally, certain seismic surveys have been fully amortized; consequently, no amortization expense is required on revenue recorded for these seismic surveys. As of January 1, 2013, the amortization rate to be utilized under the income forecast method is 70% for all components.
Selling, General and Administrative Expenses
Selling, general and administrative (“SG&A”) expenses were $29.1 million in 2012, $31.6 million in 2011 and $31.8 million in 2010. SG&A expenses are made up of the following cash and non-cash expenses (in thousands):
 
 
Year Ended December 31,
 
2012
 
2011
 
2010
Cash SG&A expenses
$
27,934

 
$
30,906

 
$
28,398

Non-cash compensation expense
761

 
453

 
3,157

Non-cash rent expense
393

 
290

 
276

Total
$
29,088

 
$
31,649

 
$
31,831

The decrease in cash SG&A expenses of $3.0 million from 2011 to 2012 was primarily due to (1) a decrease of $3.0 million in annual cash incentive compensation expense due to our cash EBITDA results falling in the range of minimum and target goals established for 2012, (2) a $0.5 million decrease in our bad debt expense primarily due to collection of previously reserved receivables and (3) a decrease of $0.6 million in non-recurring expenses mainly related to severance costs. These decreases were partially offset by an increase of $0.9 million in salaries and benefits due to merit increases on base salary and new hires and an increase of $0.2 million in various other expenses.
The increase in cash SG&A expenses of $2.5 million from the year ended December 31, 2010 to the year ended December 31, 2011 was primarily due to (1) an increase of $1.4 million in salaries and benefits, (2) an increase of $1.6 million in non-recurring expenses, mainly professional fees incurred with respect to evaluating debt restructuring alternatives and severance costs and (3) an increase of $1.0 million in various other expenses associated with our increased revenue and acquisition activities in 2011. These increases were partially offset by a $1.5 million decrease in our bad debt expense.
The increase in non-cash compensation expense of $0.3 million from 2011 to 2012 was due to amortization associated with 2012 stock option issuances offset by a reduction in expense related to prior period stock option issuances and our use of graded vesting to amortize the compensation expense. The decrease in non-cash equity compensation expense of $2.7 million between 2010 and 2011 was primarily due to the 2010 period including expense associated with the re-pricing of outstanding options granted to certain employees and non-employee directors. Additionally, there was a reduction in the expense related to stock options due to the expense being recognized using graded vesting and a significant portion of our options becoming fully vested in the first quarter of 2011.
The non-cash rent expense represents amortization of a favorable facility lease that was recorded as an intangible asset in connection with the Merger. As of December 31, 2012, this intangible asset has been fully amortized.
Other Income (Expense)
Interest expense was $29.1 million for the year ended December 31, 2012, $35.2 million for the year ended December 31, 2011 and $41.1 million for the year ended December 31, 2010. The decrease in interest expense in both 2012 and 2011 was due to the repayment of $125.0 million of our 9.75% Senior Notes on July 1, 2011.
The call premium incurred to repay $125.0 million of our 9.75% Senior Notes along with the write-off of the related unamortized issuance costs resulted in a $7.9 million loss on early extinguishment of debt in 2011.
During the years ended December 31, 2012, 2011 and 2010, we sold $0.2 million, $2.5 million and $4.2 million, respectively, of marketable securities through multiple transactions on an active international exchange. Total gains were equal to the proceeds received.

29

Table of Contents



Other income was $0.8 million, $0.3 million and $0.4 million for the years ended December 31, 2012, 2011 and 2010, respectively. The increase in other income of $0.5 million from 2011 to 2012 was primarily due to cash dividends received from investments.
During the years ended December 31, 2012, 2011 and 2010, we reported foreign currency transaction gains (losses) on U.S. denominated transactions of our Canadian subsidiaries totaling $0.7 million, $(0.7) million and $0.4 million, respectively.
Income Taxes
Tax expense (benefit) was $6.8 million, $0.4 million and $(4.0) million for the years ended December 31, 2012, 2011 and 2010, respectively. The 2012 expense was comprised of (i) an expense of $5.6 million related to our Canadian operations, (ii) a benefit of $0.4 million related to certain research and development tax credits received in Canada, (iii) an expense of $1.1 million related to U.S. state taxes, (iv) an expense of $0.3 million in U.S. Federal taxes and (v) an expense of $0.2 million related to interest on uncertain tax positions. Our current estimate of U.S. Federal taxable income for 2012 was offset against our net operating loss carryforward and the U.S. Federal tax expense recorded in 2012 related to our estimated alternative minimum tax liability as of December 31, 2012. The increase in U.S. state tax expense is a result of our geographic expansion in recent years.
The 2011 expense was comprised of (i) an expense of $1.0 million related to our Canadian operations, (ii) a benefit of $0.4 million related to certain research and development tax credits received in Canada, (iii) a benefit of $0.4 million related to U.S. state taxes and (iv) an expense of $0.2 million related to interest on uncertain tax positions. The Federal tax benefit of $0.2 million in 2011 resulting from our U.S. operations was offset by a valuation allowance because it was more likely than not that the deferred tax asset would not be realized.
The 2010 benefit was comprised of (i) a benefit of $3.7 million related to our Canadian operations, (ii) a benefit of $0.4 million related to certain research and development tax credits received in Canada and (iii) an expense of $0.1 million related to principal, penalties and interest on uncertain tax positions. The Federal tax benefit of $18.1 million in 2010 resulting from our U.S. operations was offset by a valuation allowance because it was more likely than not that the deferred tax asset would not be realized.
Liquidity and Capital Resources
As of December 31, 2012, we had $61.9 million in consolidated cash, cash equivalents and short-term investments, including $0.8 million of restricted cash. As of December 31, 2012, approximately $1.4 million of our cash was held by a foreign subsidiary which will be used to reinvest in our Canadian operations as our intent is to use this cash to, among other things, fund the operations and capital investments of our Canadian subsidiary. If we decide at a later date to repatriate those funds to the U.S., we may be required to provide taxes on certain of those funds based on applicable U.S. tax rates net of foreign taxes.
We maintain sufficient working capital to enable us to meet our obligations for new data acquisition projects. Our working capital practices are consistent with the general practices associated in the industry in which we operate.
In addition to the cash on our balance sheet, other sources of liquidity include our credit facility described below.
Credit Facility: On May 25, 2011, we entered into a credit agreement (“Credit Facility”) which provides us with the ability to borrow up to $30.0 million. The Credit Facility provides a $30.0 million revolving credit facility with a Canadian sublimit of $5.0 million, subject to borrowing base limitations. The Credit Facility expires on November 15, 2013, which date will be extended to May 25, 2016 upon the occurrence of certain refinancing of our existing 9.75% Senior Notes. As of December 31, 2012, no amounts were outstanding under the Credit Facility and there was $20.0 million of availability.
9.75% Senior Unsecured Notes: On February 14, 2007, we issued in a private placement $400.0 million aggregate principal amount of our 9.75% Senior Notes. On July 1, 2011, we redeemed $125.0 million aggregate principal amount of the 9.75% Senior Notes outstanding. Interest on these senior notes is payable in cash, semi-annually in arrears on February 15 and August 15. As of December 31, 2012, $275.0 million of the 9.75% Senior Notes remain outstanding.
We may from time to time, as part of various financing and investing strategies, purchase our outstanding indebtedness. These purchases, if any, could have a material positive or negative impact on our liquidity available to repay outstanding debt obligations or on our consolidated results of operations.

30

Table of Contents



Contractual Obligations: As of December 31, 2012, we had outstanding debt and lease obligations, with aggregate contractual cash obligations, including principal and interest, summarized as follows (in thousands):
 
 
 
 
 
Payments due by period
Contractual cash obligations
 
Total
 
2013
 
2014-2016
 
2017-2018
 
2019 and
thereafter
Debt obligations (1)(2)
 
$
315,249

 
$
26,843

 
$
288,406

 
$

 
$

Capital lease obligations (2)
 
4,144

 
446

 
1,288

 
895

 
1,515

Operating lease obligations
 
2,902

 
1,010

 
1,839

 
53

 

Total contractual cash obligations
 
$
322,295

 
$
28,299

 
$
291,533

 
$
948

 
$
1,515

 
(1)Debt obligations include the face amount of our 9.75% Senior Notes totaling $275.0 million.
(2)Amounts include interest related to debt and capital lease obligations.
Cash Flows from Operating Activities: Cash flows provided by operating activities were $171.5 million, $126.8 million and $108.9 million for the years ended December 31, 2012, 2011 and 2010, respectively. Operating cash flows for 2012 increased from 2011 primarily due to increased collections from our acquisition underwriting related receipts, lower interest payments on our 9.75% Senior Notes and lower income taxes paid. Operating cash flows for 2011 increased from 2010 primarily due to increased collections on acquisition underwriting partially offset by lower collections on cash resales and tax payments made to appeal the results of the tax audit of Olympic Seismic Ltd., a wholly-owned subsidiary, by Canada Revenue Agency.

Cash Flows from Investing Activities: Cash flows used in investing activities were $184.4 million, $127.2 million and $45.7 million for the years ended December 31, 2012, 2011 and 2010, respectively. Cash expenditures for seismic data were $183.2 million, $127.0 million, and $49.5 million for the years ended December 31, 2012, 2011 and 2010, respectively. The increase in cash invested in seismic data for 2012 compared to 2011 and 2011 compared to 2010 was due to increased data acquisition activity in both the U.S. and Canada and due to continuing strong activity in unconventional plays.
Cash Flows from Financing Activities: Cash flows used in financing activities were $0.3 million, $14.7 million and $0.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. In 2011, our financing activities primarily consisted of the following: (i) a $125.0 million cash capital contribution by Seitel Holdings, Inc. ("Holdings") in connection with the minority interest investment in Holdings by Centerbridge in May 2011, (ii) $131.1 million in principal and premium payments on our 9.75% Senior Notes, (iii) $6.3 million in costs paid in conjunction with our Credit Facility and the Centerbridge transaction and (iv) $2.0 million in principal payments on our 11.75% Senior Notes.
Anticipated Liquidity: Our ability to cover our operating and capital expenses, make required debt service payments on our 9.75% Senior Notes, incur additional indebtedness, and comply with our various debt covenants, will depend primarily on our ability to generate substantial operating cash flows. Over the next 12 months, we expect to obtain the funds necessary to pay our operating, capital and other expenses as well as interest on our 9.75% Senior Notes and principal and interest on our other indebtedness, from our operating cash flows, cash and cash equivalents on hand and, if required, from additional borrowings (to the extent available under our Credit Facility subject to the borrowing base). Over the next 12 months we expect to refinance the amount outstanding under our 9.75% Senior Notes. Our ability to satisfy our payment obligations depends substantially on our future operating and financial performance, which necessarily will be affected by, and subject to, industry, market, economic and other factors. If necessary, we could choose to reduce our spending on capital projects and operating expenses to ensure we operate within the cash flow generated from our operations. We will not be able to predict or control many of these factors, such as economic conditions in the markets where we operate and competitive pressures.
For a discussion of a number of factors that may impact our liquidity and the sufficiency of our capital resources, see – “Overview” and “Item 1A. Risk Factors” above.
Deferred Taxes
As of December 31, 2012, we had a net deferred tax liability of $2.5 million attributable to our Canadian operations. In the United States, we had a Federal deferred tax asset of $99.8 million, all of which was fully offset by a valuation allowance. The recognition of the U.S. Federal deferred tax asset will not occur until such time that it is more likely than not that some portion or all of the Federal deferred tax asset will be realized. As of December 31, 2012, it was more likely than not that all of the U.S. Federal deferred tax asset will not be realized. Additionally, in the United States, we had a state deferred tax asset of $730,000 of which $646,000 was offset by a valuation allowance. The remaining state deferred tax asset of $84,000 was recognized as it is more likely than not that the state deferred tax asset will be realized.

31

Table of Contents



Off-Balance Sheet Transactions
Other than operating leases, we do not maintain any off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenue or expense, results of operations, liquidity, capital expenditures or capital resources.
Capital Expenditures
During 2012, capital expenditures for seismic data and other property and equipment amounted to $192.6 million on a gross basis and $87.5 million on a net cash basis. Our capital expenditures for 2013 are presently estimated to be $196.4 million on a gross basis and $60.0 million on a net cash basis. Our 2012 actual and 2013 estimated capital expenditures are comprised of the following (in thousands): 
 
Year Ended December 31, 2012
 
Estimate for
Year Ending
December 31, 2013
New data acquisition
$
176,062

 
$
181,500

Cash purchases and data processing
11,678

 
5,600

Non-monetary exchanges
3,376

 
7,400

Property and equipment and other
1,517

 
1,900

Total capital expenditures
192,633

 
196,400

Less: Non-monetary exchanges
(3,376
)
 
(7,400
)
Changes in working capital
(4,591
)
 

Cash investment per statement of cash flows
$
184,666

 
$
189,000

Capital expenditures funded from operating cash flows are as follows (in thousands): 
 
Year Ended December 31, 2012
 
Estimate for
Year Ending
December 31, 2013
Total capital expenditures
$
192,633

 
$
196,400

Less: Non-cash additions
(3,376
)
 
(7,400
)
Cash underwriting
(101,803
)
 
(129,000
)
Capital expenditures funded from operating cash flow
$
87,454

 
$
60,000

As of February 19, 2013, we had capital expenditure commitments related to data acquisition projects of approximately $103.0 million of which we have obtained approximately $66.2 million of cash underwriting and $0.1 million of underwriting from non-monetary exchanges.
Recent Accounting Pronouncements
In June 2011, the Financial Accounting Standards Board ("FASB") issued revised guidance on the presentation of comprehensive income and its components in the financial statements. As a result of this guidance, companies are now required to report components of other comprehensive income in either a single continuous statement or in two separate but consecutive statements of net income and other comprehensive income. This accounting guidance does not change the items that must be reported in comprehensive income, how these items are measured, or when these items must be classified to net income. We have provided the required financial reporting presentation retrospectively beginning in 2012 in our consolidated financial statements.
In July 2012, the FASB issued revised guidance to simplify the testing of indefinite-lived intangible assets other than goodwill for impairment. The guidance permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test. An entity will have an option not to calculate annually the fair value of an indefinite-lived intangible asset if the entity determines that it is not more likely than not that the asset is impaired. The accounting guidance is effective for our company beginning in fiscal year 2013. We do not expect the adoption of this accounting guidance to have a significant impact on our financial statements or financial statement disclosures.
In February 2013, the FASB issued revised guidance on reporting amounts reclassified out of accumulated other comprehensive income (“AOCI”). The guidance does not change the current requirements for reporting net income or other

32

Table of Contents



comprehensive income in the financial statements. However, the amendments require an entity to provide information about the amounts reclassified out of accumulated other comprehensive income ("AOCI") by component. In addition, an entity is required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income, but only if the amount reclassified is required to be reclassified in its entirety in the same reporting period. For amounts that are not required to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional details about those amounts. This standard is effective prospectively for our company beginning January 1, 2013. We are evaluating the effect, if any, the adoption of ASU 2013-02 will have on our consolidated financial statements.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk, including adverse changes in interest rates and foreign currency exchange rates as discussed below.
Interest Rate Risk
We may enter into various financial instruments, such as interest rate swaps or interest rate lock agreements, to manage the impact of changes in interest rates. Currently, we have no open interest rate swap or interest rate lock agreements. Therefore, our exposure to changes in interest rates primarily results from our short-term and long-term debt with both fixed and floating interest rates. As of December 31, 2012 and 2011, we did not have any debt outstanding with floating interest rates. The following table presents principal or notional amounts by year of maturity (stated in thousands) and average interest rates for our debt obligations and their indicated fair market value at December 31, 2012:
 
 
2013
 
2014
 
2015
 
2016
 
2017
 
There-after
 
Total
 
Fair Value
Debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Rate
 
$
29

 
$
275,000

 
$

 
$

 
$

 
$

 
$
275,029

 
$
274,614

Average Interest Rate
 
9.75
%
 
9.75
%
 

 

 

 

 
9.75
%
 
 
The following table presents principal or notional amounts by year of maturity (stated in thousands) and average interest rates for our debt obligations and their indicated fair market value at December 31, 2011:
 
 
 
2012
 
2013
 
2014
 
2015
 
2016
 
There-after
 
Total
 
Fair Value
Debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Rate
 
$
66

 
$
29

 
$
275,000

 
$

 

 
$

 
$
275,095

 
$
273,024

Average Interest Rate
 
9.75
%
 
9.75
%
 
9.75
%
 
%
 

 

 
9.75
%
 
 

Foreign Currency Exchange Rate Risk
Our Canadian subsidiaries conduct business in the Canadian dollar and are therefore subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investing transactions in currencies other than the U.S. dollar. Currently, we do not have any open forward exchange contracts.

Item 8. Financial Statements and Supplementary Data
The financial statements and financial statement schedules required by this Item are set forth at the pages indicated in Item 15(a) (1) and (2) below.

Item 9. Change in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of December 31, 2012, our management carried out an evaluation, under the supervision and with the participation of our President and Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, our President and Chief Executive Officer along with our Chief Financial Officer concluded that our disclosure controls and procedures as of December 31, 2012 were designed to ensure, and were effective in ensuring, that our information required to be disclosed in the

33

Table of Contents



reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our President and Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining effective internal control over financial reporting (as defined in Rules 13a-15(f) or 15d-15(f) promulgated under the Exchange Act) for us. Even an effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change.
Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2012. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework. Based on this assessment and such criteria, management believes that, as of December 31, 2012, our internal control over financial reporting was effective.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to an exemption for non-accelerated filers set forth in the Dodd-Frank Wall Street Reform and Consumer Protection Act.
Changes in Internal Controls Over Financial Reporting
There have been no changes in our internal controls over financial reporting during the quarter ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
 
Item 9B. Other Information
None.
PART III

Item 10. Directors, Executive Officers and Corporate Governance
The information required by this Item is incorporated herein by reference from our Form 10-K/A to be filed within 120 days after December 31, 2012, under a similarly entitled caption.

Item 11. Executive Compensation
The information required by this Item is incorporated herein by reference from our Form 10-K/A to be filed within 120 days after December 31, 2012, under a similarly entitled caption.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this Item is incorporated herein by reference from our Form 10-K/A to be filed within 120 days after December 31, 2012, under a similarly entitled caption.

Item 13. Certain Relationships and Related Transactions and Director Independence
The information required by this Item is incorporated herein by reference from our Form 10-K/A to be filed within 120 days after December 31, 2012, under a similarly entitled caption.

Item 14. Principal Accountant Fees and Services
The information required by this Item is incorporated herein by reference from our Form 10-K/A to be filed within 120 days after December 31, 2012, under a similarly entitled caption.


34

Table of Contents



PART IV

Item 15. Exhibits and Financial Statement Schedules  
(a) Documents filed as part of this Report.
 
 
Page
(1) Financial Statements
 
Management’s Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Statements of Stockholder’s Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
(2) Schedule II - Valuation and Qualifying Accounts
(3) Exhibits:
 
 
 
2.1

 
Agreement and Plan of Merger by and among Seitel Holdings, LLC (now known as Seitel Holdings, Inc.), Seitel Acquisition Corp. and Seitel, Inc., dated October 31, 2006 (incorporated by reference from Exhibit 2.1 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on November 2, 2006) (Seitel, Inc. agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request).
 
 
 
3.1

 
Certificate of Incorporation of Seitel, Inc. (incorporated by reference from Exhibit 3.1 to the Registration Statement on Form S-4, No. 333-144844, as filed with the SEC on July 25, 2007).
 
 
 
3.2

 
Bylaws of Seitel, Inc. (incorporated by reference from Exhibit 3.2 to the Registration Statement on Form S-4, No. 333-144844, as filed with the SEC on July 25, 2007).
 
 
 
4.1

 
Supplemental Indenture by and among Seitel, Inc., the Guarantors named therein and UBS Securities LLC and Jeffries & Company, Inc., as Initial Purchasers, dated July 2, 2004 (incorporated by reference from Exhibit 4.5 to the Seitel, Inc. Post Effective Amendment No. 1 to the Seitel, Inc. Registration Statement on Form S-1, No. 333-113446, as filed with the SEC on July 2, 2004).
 
 
 
4.2

 
Indenture governing 9.75% Senior Notes due 2014 by and among Seitel, Inc., the Guarantors named therein and LaSalle Bank National Association, as Trustee, dated February 14, 2007 (incorporated by reference from Exhibit 4.6 to the Registration Statement on Form S-4, No. 333-144844, as filed with the SEC on July 25, 2007).
 
 
 
4.3

 
Form of 9.75% Senior Notes due 2014 (included in Exhibit 4.4) (incorporated by reference from Exhibit 4.7 to the Registration Statement on Form S-4, No. 333-144844, as filed with the SEC on July 25, 2007).
 
 
 
4.4

 
Supplemental Indenture by and among Seitel, Inc., the Guarantors named therein and LaSalle Bank National Association, as Trustee, dated January 31, 2007 (incorporated by reference from Exhibit 4.1 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on February 2, 2007).
 
 
 
10.1

 
Support Agreement by and among Seitel, Inc., Seitel Holdings, Inc. and ValueAct Capital Master Fund, L.P., dated October 31, 2006 (incorporated by reference from Exhibit 2.2 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on November 2, 2006).
 
 
 
10.2

 
Credit Agreement, dated May 25, 2011, by and among Seitel, Inc. and Olympic Seismic Ltd., as borrowers, and Wells Fargo Capital Finance, LLC and Wells Fargo Capital Finance Corporation Canada, as lenders (incorporated by reference from Exhibit 10.1 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on June 1, 2011).
 
 
 

35

Table of Contents



10.3

 
Security Agreement, dated May 25, 2011, by and among the Grantors listed on the signature pages thereto and Wells Fargo Capital Finance, LLC, as administrative agent and collateral agent (incorporated by reference from Exhibit 10.2 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on June 1, 2011).
 
 
 
10.4

 
Trademark Security Agreement, dated May 25, 2011, by and among the Grantors listed on the signature pages thereto and Wells Fargo Capital Finance, LLC, as administrative agent and collateral agent (incorporated by reference from Exhibit 10.3 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on June 1, 2011).
 
 
 
10.5

 
Amendment No. 1 to Credit Agreement, dated November 28, 2011, by and among Seitel, Inc. and Olympic Seismic Ltd., as borrowers, and Wells Fargo Capital Finance, LLC and Wells Fargo Capital Finance Corporation Canada, as lenders and agents (incorporated by reference from Exhibit 10.1 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on November 30, 2011).
 
 
 
10.6

 
Amended and Restated Advisory Agreement, dated May 23, 2011, by and among Seitel, Inc., Seitel Holdings, Inc., ValueAct Capital Management L.P., and Centerbridge Advisors II, L.L.C. (incorporated by reference from Exhibit 10.1 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on May 25, 2011).
 
 
 
10.7

 
Amended and Restated Securities Holders Agreement, dated May 23, 2011, by and among Seitel Holdings, Inc., ValueAct Capital Master Fund, L.P., Centerbridge Capital Partners II, L.P., Centerbridge Capital Partners SBS Il, L.P. and each of the Management Investors named therein (incorporated by reference from Exhibit 10.2 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on May 25, 2011).
 
 
 
10.8

 
Amended and Restated Registration Rights Agreement, dated May 23, 2011 by and among Seitel Holdings, Inc., ValueAct Capital Master Fund, L.P., Centerbridge Capital Partners II, L.P., Centerbridge Capital Partners SBS II, L.P. and each of the Management Investors named therein (incorporated by reference from Exhibit 10.3 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on May 25, 2011).
 
 
 
10.9

 
Joinder to Securities Holders Agreement and Registration Rights Agreement of Philip B. Livingston, dated February 16, 2007 (incorporated by reference from Exhibit 10.9 to the Registration Statement on Form S-4, No. 333-144844, as filed with the SEC on July 25, 2007).
 
 
 
10.10

 
Joinder to Securities Holders Agreement and Registration Rights Agreement of Jay H. Golding, dated May 24, 2007 (incorporated by reference from Exhibit 10.10 to the Registration Statement on Form S-4, No. 333-144844, as filed with the SEC on July 25, 2007).
 
 
 
10.11

 
Joinder to Securities Holders Agreement and Registration Rights Agreement of John E. Jackson, dated August 1, 2007 (incorporated by reference from Exhibit 10.12 to the annual report on Form 10-K for the year ended December 31, 2007, as filed with the SEC on March 31, 2008).
 
 
 
10.12

Seitel Holdings, Inc. 2007 Non-Qualified Stock Option Plan, effective February 14, 2007, as amended as of June 30, 2008 (incorporated by reference from Exhibit 10.3 to the quarterly report on Form 10-Q for the quarter ended June 30, 2008, as filed with the SEC on August 13, 2008).
 
 
 
10.13

Amendment to the 2007 Non-Qualified Stock Option Plan of Seitel Holdings, Inc., dated May 23, 2011 (incorporated by reference from Exhibit 10.7 to the quarterly report on Form 10-Q for the quarter ended June 30, 2011, as filed with the SEC on August 12, 2011).
 
 
 
10.14

Form of Stock Option Agreement (incorporated by reference from Exhibit 10.12 to the Registration Statement on Form S-4, No. 333-144844, as filed with the SEC on July 25, 2007).
 
 
 
10.15

Form of Stock Option Agreement (incorporated by reference from Exhibit 10.1 to the quarterly report on Form 10-Q for the quarter ended June 30, 2010, as filed with the SEC on August 9, 2010).
 
 
 
10.16

Seitel Holdings, Inc. Amended and Restated 2008 Restricted Stock and Restricted Stock Unit Plan, dated July 24, 2012 (incorporated by reference from Exhibit 10.1 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on July 25, 2012).
 
 
 

36

Table of Contents



10.17

Form of Seitel Holdings, Inc. Restricted Stock Unit Award Agreement (incorporated by reference from Exhibit 10.2 to the quarterly report on Form 10-Q for the quarter ended June 30, 2008, as filed with the SEC on August 13, 2008).
 
 
 
10.18

Seitel Holdings, Inc. 2012 Non-Qualified Stock Option Plan, dated May 1, 2012 (incorporated by reference from Exhibit 10.1 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on May 7, 2012).
 
 
 
10.19

Amendment to the 2012 Non-Qualified Stock Option Plan of Seitel Holdings, Inc., dated May 30, 2012.
 
 
 
10.20

Form of Seitel Holdings, Inc. Stock Option Agreement for the 2012 Plan for Management Employees (incorporated by reference from Exhibit 10.2 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on May 7, 2012).
 
 
 
10.21

Form of Seitel Holdings, Inc. Stock Option Agreement for the 2012 Plan for Management Employees (incorporated by reference from Exhibit 10.2 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on May 7, 2012).
 
 
 
10.22

Summary of 2011 Long-Term Incentive Plan (incorporated by reference from Exhibit 10.19 to the annual report on Form 10-K for the year ended December 31, 2010, as filed with the SEC on March 16, 2011).
 
 
 
10.23

Employment Agreement by and between Seitel, Inc. and Robert D. Monson, dated January 30, 2007 (incorporated by reference from Exhibit 10.13 to the Registration Statement on Form S-4, No. 333-144844, as filed with the SEC on July 25, 2007).
 
 
 
10.24

Employment Agreement by and between Seitel, Inc. and Kevin P. Callaghan, dated January 30, 2007 (incorporated by reference from Exhibit 10.15 to the Registration Statement on Form S-4, No. 333-144844, as filed with the SEC on July 25, 2007).
 
 
 
10.25

Form of Amendment to Employment Agreement (incorporated by reference from Exhibit 10.1 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on June 8, 2009).
 
 
 
10.26

Form of Second Amendment to Employment Agreement (incorporated by reference from Exhibit 10.1 to the current report on Form 8-K, as filed with the SEC on January 27, 2010).
 
 
 
10.27

Third Amendment to Employment Agreement between Kevin P. Callaghan and Seitel, Inc., dated July 27, 2012 (incorporated by reference from Exhibit 10.1 to the Seitel, Inc. current reports on Form 8-K/A, as filed with the SEC on August 6, 2012, and Form 8-K, as filed with the SEC on July 31, 2012).
 
 
 
10.28

Employment Agreement by and between Seitel, Inc. and JoAnn Lippman, dated February 1, 2012 (incorporated by reference from Exhibit 10.1 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on February 7, 2012).
 
 
 
10.29

Employment Agreement by and between Seitel, Inc. and Marcia Kendrick, dated February 15, 2012 (incorporated by reference from Exhibit 10.1 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on February 17, 2012).
 
 
 
10.30

Employment Agreement by and between Seitel, Inc. and Randall Sides, dated February 15, 2012 (incorporated by reference from Exhibit 10.2 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on February 17, 2012).
 
 
 
10.31

Employment Agreement by and between Seitel, Inc. and David Richard, dated February 15, 2012 (incorporated by reference from Exhibit 10.3 to the Seitel, Inc. current report on Form 8-K, as filed with the SEC on February 17, 2012).
 
 
 
21.1

Subsidiaries of Seitel, Inc.
 
 
 
31.1

Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 302 Of The Sarbanes-Oxley Act of 2002

37

Table of Contents



 
 
 
31.2

Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 302 Of The Sarbanes-Oxley Act of 2002
 
 
 
32.1

** 
Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 Of The Sarbanes-Oxley Act of 2002
 
 
 
32.2

** 
Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 Of The Sarbanes-Oxley Act of 2002
 
 
 
101.INS

** 
XBRL Instance Document.
 
 
 
101.SCH

** 
XBRL Taxonomy Extension Schema Document.
 
 
 
101.CAL

** 
XBRL Taxonomy Extension Calculation Linkbase Document.
 
 
 
101.DEF

** 
XBRL Taxonomy Extension Definition Linkbase Document.
 
 
 
101.LAB

** 
XBRL Taxonomy Extension Label Linkbase Document.
 
 
 
101.PRE

** 
XBRL Taxonomy Extension Presentation Linkbase Document.

Management contract, compensation plan or arrangement.
*
Filed herewith.
**
Furnished, not filed.

38

Table of Contents



SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the Registrant has duly caused this report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.
 
SEITEL, INC.
 
 
 
 
 By: /s/
Robert D. Monson
 
 
Robert D. Monson
 
 
Chief Executive Officer and President
 
 
 
 
Date:
February 22, 2013
Pursuant to the requirements of the Securities Act of 1934, this Report on Form 10-K has been signed below by the following persons on behalf of the Registrant in the capacities and on the date indicated.
Signature
 
Title
 
Date
 





 
 
 
 
/s/
Gregory P. Spivy
 
Chairman of the Board of Directors
 
February 22, 2013
 
Gregory P. Spivy
 
 
 
 
 
 
 
 
 
 
/s/
Robert D. Monson
 
Chief Executive Officer, President and Director
 
February 22, 2013
 
Robert D. Monson
 
(Principal Executive Officer)
 
 
 
 
 
 
 
 
/s/
Marcia H. Kendrick
 
Chief Financial Officer
 
February 22, 2013
 
Marcia H. Kendrick
 
(Principal Financial Officer)
 
 
 
 
 
 
 
 
/s/
Allison A. Bennington
 
Director
 
February 22, 2013
 
Allison A. Bennington
 
 
 
 
 
 
 
 
 
 
/s/
Ryan M. Birtwell
 
Director
 
February 22, 2013
 
Ryan M. Birtwell
 
 
 
 
 
 
 
 
 
 
/s/
Dalton J. Boutte
 
Director
 
February 22, 2013
 
Dalton J. Boutte
 
 
 
 
 
 
 
 
 
 
/s/
Kevin P. Callaghan
 
Chief Operating Officer and Director
 
February 22, 2013
 
Kevin P. Callaghan
 
 
 
 
 
 
 
 
 
 
/s/
Kyle N. Cruz
 
Director
 
February 22, 2013
 
Kyle N. Cruz
 



 
 
 
 
 
 
 
 
/s/
Jay H. Golding
 
Director
 
February 22, 2013
 
Jay H. Golding
 
 
 
 
 
 
 
 
 
 
/s/
John E. Jackson
 
Director
 
February 22, 2013
 
John E. Jackson
 
 
 
 
 
 
 
 
 
 
/s/
Daniel R. Osnoss
 
Director
 
February 22, 2013
 
Daniel R. Osnoss
 
 
 
 

39

Table of Contents



MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The accompanying consolidated financial statements of Seitel, Inc. and its subsidiaries (Seitel) were prepared by management, which is responsible for their integrity, objectivity and fair presentation. The consolidated financial statements have been prepared in conformity with generally accepted accounting principles in the United States of America and, accordingly, include some amounts that are based on the best estimates and judgments of management.
Seitel’s management is also responsible for establishing and maintaining effective internal control over financial reporting. The system of internal control of Seitel is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America. This system consists of 1) entity level controls, including written policies and guidelines relating to the ethical conduct of business affairs, 2) general computer controls and 3) process controls over initiating, authorizing, recording, processing and reporting transactions. Even an effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of an internal control system in future periods can change with conditions.
The adequacy of financial controls of Seitel and the accounting principles employed in financial reporting by Seitel are under the general oversight of the Audit Committee of the Board of Directors. No member of this committee is an officer or employee of Seitel. Seitel’s independent registered public accounting firm has full, free, separate and direct access to the Audit Committee and meets with the committee from time to time to discuss accounting, auditing and financial reporting matters.
Seitel’s management assessed the effectiveness of Seitel's internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework. These criteria cover the control environment, risk assessment process, control activities, information and communication systems, and monitoring activities. Based on this assessment, management believes that, as of December 31, 2012, Seitel's internal control over financial reporting is effective based on those criteria.
 
 
 
 
 
 
/s/ Robert D. Monson
 
Robert D. Monson
 
Chief Executive Officer and President
 
 
 
 
 
 
/s/ Marcia H. Kendrick
 
Marcia H. Kendrick
 
Executive Vice President and
 
Chief Financial Officer
Houston, Texas
February 22, 2013


40

Table of Contents



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Audit Committee, Board of Directors and Stockholder
Seitel, Inc. and Subsidiaries
Houston, Texas
We have audited the accompanying consolidated balance sheets of Seitel, Inc. and Subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), stockholder's equity and cash flows for each of the years in the three-year period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. Our audits also included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Seitel, Inc. and Subsidiaries, as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
/s/ BKD, LLP
Houston, Texas
February 22, 2013



41

Table of Contents




SEITEL, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
 
December 31,
 
2012
 
2011
ASSETS
 
 
 
Cash and cash equivalents
$
61,891

 
$
74,894

Receivables
 
 
 
Trade, less allowance for doubtful accounts of $737 and $1,043, respectively
61,195

 
51,306

Notes and other, less allowance for doubtful accounts of $988 and $1,501, respectively
2,143

 
4,322

Due from Seitel Holdings, Inc. (Note K)
874

 
861

Seismic data library (Note B)
1,069,921

 
872,674

Less: Accumulated amortization
(889,804
)
 
(751,980
)
Net seismic data library
180,117

 
120,694

Property and equipment
18,279

 
16,921

Less: Accumulated depreciation and amortization
(13,461
)
 
(11,882
)
Net property and equipment
4,818

 
5,039

Investment in marketable securities

 
262

Prepaid expenses, deferred charges and other
10,774

 
10,244

Intangible assets, net (Note C)
20,828

 
26,814

Goodwill (Note C)
208,020

 
205,838

Deferred income taxes (Note D)
84

 
56

TOTAL ASSETS
$
550,744

 
$
500,330

LIABILITIES AND STOCKHOLDER’S EQUITY
 
 
 
Accounts payable
$
37,521

 
$
36,593

Accrued liabilities
19,569

 
16,856

Employee compensation payable
5,693

 
7,101

Income taxes payable
4,134

 
1,464

Debt (Note E)
 
 
 
Senior Notes
275,000

 
275,000

Notes payable
29

 
95

Obligations under capital leases (Note F)
3,113

 
3,161

Deferred revenue (Note A)
52,857

 
48,845

Deferred income taxes (Note D)
2,470

 
1,375

TOTAL LIABILITIES
400,386

 
390,490

COMMITMENTS AND CONTINGENCIES (Note G)

 

STOCKHOLDER’S EQUITY
 
 
 
Common stock, par value $.001 per share; 100 shares authorized, issued and outstanding at December 31, 2012 and December 31, 2011

 

Additional paid-in capital
398,772

 
398,011

Retained deficit
(272,135
)
 
(309,185
)
Accumulated other comprehensive income
23,721

 
21,014

TOTAL STOCKHOLDER’S EQUITY
150,358

 
109,840

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$
550,744

 
$
500,330


The accompanying notes are an integral part of these consolidated financial statements.

42

Table of Contents



SEITEL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands)
 
  
Year Ended December 31,
 
2012
 
2011
 
2010
REVENUE
$
240,458

 
$
218,008

 
$
175,556

EXPENSES:
 
 
 
 
 
Depreciation and amortization
139,754

 
142,963

 
175,592

Cost of sales
464

 
100

 
97

Selling, general and administrative
29,088

 
31,649

 
31,831

 
169,306

 
174,712

 
207,520

INCOME (LOSS) FROM OPERATIONS
71,152

 
43,296

 
(31,964
)
Interest expense
(29,143
)
 
(35,246
)
 
(41,094
)
Interest income
132

 
479

 
558

Foreign currency exchange gains (losses)
681

 
(726
)
 
441

Loss on early extinguishment of debt

 
(7,912
)
 

Gain on sale of marketable securities
230

 
2,467

 
4,188

Other income
780

 
250

 
446

Income (loss) before income taxes
43,832

 
2,608

 
(67,425
)
Provision (benefit) for income taxes
6,782

 
392

 
(4,008
)
NET INCOME (LOSS)
$
37,050

 
$
2,216

 
$
(63,417
)
The accompanying notes are an integral part of these consolidated financial statements.



43

Table of Contents



SEITEL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
 
  
Year Ended December 31,
 
2012
 
2011
 
2010
Net income (loss)
$
37,050

 
$
2,216

 
$
(63,417
)
Unrealized losses on securities held as available for sale, net of tax:
 
 
 
 
 
Unrealized net holding gains (losses) arising during the period
(32
)
 
(373
)
 
4,117

Less: Reclassification adjustment for realized gains included in earnings
(230
)
 
(2,467
)
 
(4,188
)
Foreign currency translation adjustments
2,969

 
(3,037
)
 
6,948

Comprehensive income (loss)
$
39,757

 
$
(3,661
)
 
$
(56,540
)
The accompanying notes are an integral part of these consolidated financial statements.


44

Table of Contents



SEITEL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
(In thousands, except share amounts)
 
 
 
 
Additional
Paid-In
Capital
 
Retained
Deficit
 
Accumulated
Other
Comprehensive
Income
 
Common Stock
 
 
Shares
 
Amount
 
Balance, December 31, 2009
100

 
$

 
$
274,331

 
$
(247,984
)
 
$
20,014

Amortization of stock-based compensation costs

 

 
3,157

 

 

Net loss

 

 

 
(63,417
)
 

Foreign currency translation adjustments

 

 

 

 
6,948

Unrealized gains on securities held as available for sale, net of tax

 

 

 

 
4,117

Reclassification adjustment for realized gains on securities held as available for sale included in earnings, net of tax

 

 

 

 
(4,188
)
Balance, December 31, 2010
100

 

 
277,488

 
(311,401
)
 
26,891

Investment by Parent, net

 

 
120,070

 

 

Amortization of stock-based compensation costs

 

 
453

 

 

Net income

 

 

 
2,216

 

Foreign currency translation adjustments

 

 

 

 
(3,037
)
Unrealized losses on securities held as available for sale, net of tax

 

 

 

 
(373
)
Reclassification adjustment for realized gains on securities held as available for sale included in earnings, net of tax

 

 

 

 
(2,467
)
Balance, December 31, 2011
100

 

 
398,011

 
(309,185
)
 </